Page 1503 – RTO Insider

November 9, 2015

Energy Department OKs Canadian Hydro Line in New England

By William Opalka

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.)

November 9, 2015

FERC Finds ‘No Significant Impact’ from NE Pipeline Expansion

By William Opalka

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.

November 9, 2015

Algonquin Submits Pre-Filing Request for Access Northeast Pipeline

By William Opalka

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).

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.)

November 9, 2015

FERC Again Dismisses Challenge to 2014 ISO-NE Capacity Auction

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.

— William Opalka

November 9, 2015

Ahead of Most, Northeast Still Faces Clean Energy Challenges

By William Opalka

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.”

Also Heard at the Northeast Energy Summit:

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November 8, 2015

RTOs: ‘A Form Between Government and Business’

What is an RTO?

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.”

“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.

— Rich Heidorn Jr.

November 8, 2015

ERCOT Confirms Resource Adequacy for Winter

By Tom Kleckner

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.

November 8, 2015

FERC Asks for More Detail on Risk-Based Approach

By Rich Heidorn Jr.

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.”

November 8, 2015

WEC Energy Shows $183M Profit After Integrys Deal

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.

The expanded company now serves 4.4 million customers in Wisconsin, Illinois, Michigan and Minnesota. (See Michigan OKs Wisconsin Energy-Integrys Merger.)

“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%.

– Amanda Durish Cook

November 8, 2015

M2M Process Shows Continued Improvement

By Tom Kleckner

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.

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.