Page 1708 – RTO Insider

November 10, 2015

PJM Planning Committee TEAC Briefs

VALLEY FORGE, Pa. — The Planning Committee last week endorsed comprehensive revisions to Manual 19 to incorporate changes to the load forecast model.

The changes account for trends in equipment and appliance saturation and energy efficiency; revise weather variables; update weather station assignments to zones; and modify the weather normalization procedure.

Members decided to remove a change that would have added distributed solar generation to the model this year, saying they wanted to see more data on its predicted effect first.

PJM’s John Reynolds said that in response to requests for more information about how the new load model was developed, PJM will be producing a white paper on the subject early next year.

Steve Herling, PJM vice president for planning, encouraged the group to approve the changes, carving out the solar section, instead of holding them up.

“Our concern obviously is that we don’t want to get behind the curve, which we did to a degree with energy efficiency,” he said.

Panel Re-examining Reserve Requirement Study

The Resource Adequacy Analysis Subcommittee will be holding two education sessions as part of its effort to re-examine all modeling assumptions for the 2016 Reserve Requirement Study.

The first is scheduled for 1 to 4 p.m. on Nov. 24. The second is 9:30 a.m. to 12:30 p.m. on Dec. 9. Both will be held in person at the Valley Forge campus and via WebEx.

The subcommittee will schedule meetings as needed through the first quarter of next year in order to finalize RRS assumptions and bring them to the committee for endorsement in April.

PJM’s Tom Falin said it is the first re-evaluation of the process in about seven years. Planners are focusing on the full study to underscore that the installed reserve margin “is not the most important output from the study,” Falin said. Members had questioned the recent increase in the IRM, saying it seemed counterintuitive under the new Capacity Performance model. (See “IRM, FPR Rising; PJM Methodology Challenged” in PJM Planning Committee Briefs.)

Falin said the RAAS discussion will focus on three drivers: the selection of PJM and world load models, the development of capacity models and the representation of the world area. It also will consider the impact of CP on RRS assumptions.

Two More Units Headed for Deactivation

Two generating units have applied for deactivation in January.

Perryman Unit 2, a 51-MW facility in the BGE transmission zone, will be deactivated Jan. 1.

Interim operating measures have been identified until a baseline upgrade is completed there by June 2017. That upgrade, a new 115-kV switching station, is expected to cost $26 million, the cost of which is being designated to Baltimore Gas and Electric.

The second unit to be decommissioned is the 2-MW Pottstown landfill, in the PECO transmission zone. Landfill owner Waste Management said that flows of landfill gas have declined significantly since the landfill was closed in 2005 and that there is no longer enough gas to drive the turbine. It will be deactivated Jan. 15. No reliability impacts have been identified by the closure.

— Suzanne Herel

November 10, 2015

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — The Market Implementation Committee last week unanimously approved a problem statement to consider revisions to the parameter limited schedule (PLS) exemption process.

Bob O’Connell, who presented the issue on behalf of PPGI Fund A/B Development, said Tariff changes made in 2012 have made it more difficult to obtain exceptions to default PLS values, limitations imposed on generators’ minimum run times or other elements of cost-based offers.

O’Connell took issue with the “inflexible deadline” for long-term exceptions, which, he said, “does not recognize various changes that may take place on the market participant’s side that may result in the need to get around the Feb. 28 deadline.”

For example, he said, he has clients currently testing units that might not be ready by Feb. 28. “They don’t know if they should apply for anything,” he said.

There also are challenges with the resolution that has been proposed, he said, which is to seek a waiver from FERC. First, there is no guarantee the commission will rule, he said.

“Second, if a market participant is seeking an exception, right now the market participant works with the Market Monitor and PJM to determine whether, one, the exception is merited and, two, what the numbers should be,” he said. Once FERC is approached, he said, “Everybody can be involved, even if they don’t have the information.”

“What we’re seeking to do is start up the stakeholder process to rethink what’s on the table right now and come up with something that provides an administratively efficient process.”

Debate Continues over Confidentiality of Information

The committee continued to debate allowing PJM to make public certain types of data, such as uplift payments, demand response deployments, generator outages and cleared capacity resources. The changes would modify Manual 33: Administrative Services. (See PJM Stakeholders to Study Relaxing Confidentiality Rules.)

Jim Benchek of FirstEnergy said his company is most concerned with two of the six categories: details about individual generation outages and cleared capacity resources.

Regarding the outages, he said, “As a resource owner, we believe that is our data, and we really don’t want to release it to make it public.”

If PJM, the market seller and the Independent Market Monitor agree the information is not confidential, he said, “then it would be OK to release that data.”

In addition, he said, outages carry a variety of implications, including Capacity Performance penalties, and information about them might lead some to speculate about the health of a company. Likewise, releasing information about cleared capacity resources provides a window into a company’s position in the market, he said.

A number of suppliers echoed his concerns.

Monitor Joe Bowring said he had concerns about proposed changes to the capacity resource section of the manual, which would allow PJM to release the identities of resources that clear the third Incremental Auction.

“We don’t think supply curves in the capacity market should be made public,” Bowring said. “The information is very persistent from year to year. It supports collusion.”

Compromise Offered on Masking FTR Ownership

DC Energy’s Bruce Bleiweis, who has been leading a rocky effort to mask the ownership of financial transmission rights, said he was willing to offer a compromise: that they be kept private for 90 days.

At a September meeting of the MIC, Bleiweis garnered only 61% approval of his problem statement — an indication that he may have trouble winning the two-thirds majority needed for a rule change. (See “PJM to Consider Masking FTR Ownership” in PJM Market Implementation Briefs.)

At that meeting, Bleiweis had asked PJM to look into whether it discloses the ownership of its other market products. PJM’s Tim Horger confirmed last week that the RTO does not.

“In other types of markets, participant info is not posted out there,” Horger said. “PJM can support a change for removing it, but [we] want what the stakeholders want. We don’t have a strong interest one way or the other.”

Bowring reiterated his support for the status quo.

“We think the current release of ownership information makes sense, and we don’t see a reason for your additional compromise proposal,” he said.

Bleiweis said FTR owners should be able to expect the same treatment as other market participants.

“We’re not looking for less transparency; we’re looking for consistency,” he said.

“Our biggest concern is there are instances where you have multi rounds of auctions, and we were hoping that the membership, the Market Monitor and PJM would agree that releasing that information intraround — so that you see the ownership after round one, before round two — that you shouldn’t reveal that kind of confidential information.”

— Suzanne Herel

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

ISO-NE and NEPOOL on Transparency

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.

¹FERC 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.

November 8, 2015

White House Seeks to Mend Fences with Struggling Nuclear Industry

By Rich Heidorn Jr.

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.

Exelon on Oct. 29 cited the CPP, and MISO’s commitment to changing its capacity market in Illinois, in granting a one-year reprieve to its money-losing Clinton reactor. (See related story, Exelon Defers Clinton Closure as MISO Hints at Capacity Changes in Illinois.)

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.

November 8, 2015

NiSource Rebounds as a ‘Pure-Play’ Utility

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.

– Amanda Durish Cook