Page 1537 – RTO Insider

July 29, 2015

PJM Board OKs LS Power’s Artificial Island Project Despite Objections

By Suzanne Herel

The PJM Board of Managers today approved staff’s recommendation for the stability fix at New Jersey’s Artificial Island, despite numerous objections from spurned bidders and representatives of the Delmarva Peninsula, which will be allocated nearly the full cost of the project.

Winner LS Power’s proposal involves laying a 230-kV line under the Delaware River as well as expanding interconnection facilities at the nuclear complex, the latter task being assigned to Public Service Electric & Gas and Pepco Holdings Inc.

“These projects will resolve the operational performance issues around the Artificial Island area and provide important transmission support for the sub region,” said outgoing CEO Terry Boston in a letter to members following the private board meeting.

“The board also recognizes the valid concerns raised by [Delaware Gov. Jack] Markell, the Delaware Public Service Commission, the Maryland Public Service Commission and others regarding the allocation of costs associated with this project. PJM must follow its Tariff,” he said.

“With regard to the cost allocation provisions applicable to this project, PJM also must respect legal precedent in the Atlantic City case allocating specific rate filing responsibilities between PJM and its transmission owners. Nonetheless, we recognize that several parties have appropriately questioned the specific allocation in this case,” Boston continued. (See Officials Urge PJM to Reject Artificial Island Proposal.)

“Accordingly, PJM will continue to provide technical analysis and information to affected stakeholders in order to help [the Federal Energy Regulatory Commission] with its ruling on this particular cost allocation and its cost allocation rules in general.”

PJM planners outlined their rationale in a 44-page white paper, noting that $246.42 million of the $275.45 million total cost estimate will be assigned to the Delmarva transmission zone, with the remaining $29.03 million allocated to other transmission zones based on load ratio shares.

“This pilot case implementing Order 1000 principles and a competitive solicitation process will continue to be examined for a number of ‘lessons learned,’” Boston wrote. “The board thanks the Planning Committee for its thorough review, and we urge the adoption of changes that will improve the planning process.”

According to the Delaware Public Service Commission, the project could translate to a 25% increase in transmission costs in Delaware. Some of the state’s heaviest users could see their monthly bills surge by hundreds of thousands of dollars, Markell said.

In a statement Wednesday, Markell said, “I continue to have serious concerns about the cost distribution associated with the proposal approved by PJM, which would force Delawareans to bear a high cost for a project that provides little benefit to the state. I am working with the PSC and others concerned about this result to explore our options moving forward.”

A number of those dissatisfied with the cost allocation recalled the board’s rejection last summer of a Public Service Electric & Gas proposal to upgrade Artificial Island following outcry from losing bidders, environmentalists and New Jersey officials. (See PJM Board Puts the Brakes on Artificial Island Selection.) They urged the board to again halt the project.

PJM staff announced at a special April 28 meeting of the Transmission Expansion Advisory Committee that they would recommend LS Power’s plan to use horizontal directional drilling under the Delaware River to build a new 230-kV circuit from Salem, N.J., to a new substation near the 230-kV corridor in Delaware, tapping the existing Red Lion-Cartanza and Red Lion-Cedar Creek 230-kV lines. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.) LS Power’s proposal also includes the option of an overhead crossing.

Home to the Salem and Hope Creek nuclear reactors, Artificial Island is the second largest nuclear complex in the country.

PJM’s competitive solicitation process sought “transmission improvements to provide the ability to generate maximum power from all three Artificial Island nuclear units while maintaining transmission system voltage within limits during various contingencies and line outages.”

July 28, 2015June 15, 2023

SPP: State-by-State Compliance Would Hike Costs

By Tom Kleckner

SPP’s latest analysis of the Environmental Protection Agency’s draft Clean Power Plan indicates state-by-state compliance with the plan would result in nearly 40% higher costs than a regional approach.

According to SPP’s state-by-state compliance assessment released Monday, meeting the goals outlined in EPA’s draft rule would cost an estimated $3.3 billion annually in new generation capital investment and energy production costs. That is $900 million more than the $2.4 billion per year under a regional approach, on which SPP released a report in March. (See SPP: $45/ton Adder, Wind, Gas Meets EPA Carbon Rule.)

The assessment analyzed the rule’s impact on existing generation and resource-expansion plans. It did not include the cost of new transmission needed to maintain reliability, gas-infrastructure expansion, market-design changes or transmission congestion.

A final version of the rule is expected to be released in August. The draft version proposes reducing U.S. carbon dioxide emissions 30% from 2005 levels by 2030.

More Disruptive

Lanny Nickell, SPP’s vice president of engineering, told the RTO’s Regional State Committee on Monday that a state-by-state compliance approach would be more expensive to administer than a regional approach. He said a state-by-state solution “would be more disruptive … to the significant reliability and economic value that SPP provides to its members as a regional transmission organization.”

Nickell offered the example of one state taking a physical approach to carbon-reduction and limiting the amount of coal generation in November and December, only to have a neighboring state take a different approach and add renewable generation. That might force the first state to resort to additional coal generation to maintain grid reliability.

“All we look at in our market systems is price,” Nickell said. “The price offered into the market in [one state] could force the dispatch of more energy than planned elsewhere.”

A previous analysis predicted that SPP’s Integrated Marketplace, which went online in March 2014, would yield its participants $131 million in annual net savings in its first year. According to the latest report, SPP expects a reduction in the Integrated Marketplace’s savings to comply with the rule under any implementation strategy, but a state-by-state approach “would have a much more negative impact.”

SPP’s analysis was based on EPA’s proposed individual state-reduction goals in its draft rulemaking. SPP said its study does not take a position on the appropriateness of those goals or EPA’s supporting assumptions.

Apples-to-Apples

SPP’s state-by-state approach used the same analysis format as it did with March’s regional approach, using a $45/ton carbon-cost adder for an “apples-to-apples” comparison between the two plans. As before, the carbon adder was used as a mechanism to simulate the dispatch of lower carbon-emitting resources.

Coupled with modifications to current resource plans, the report said, that would “indicate the implications of meeting SPP’s regional and states’ emissions goals by 2030.”

The assessment says up to 15.1 GW of generation expected to continue running under current planning assumptions could be at risk of retirement under a state-by-state compliance approach. The study also added 5.5 GW of wind energy and 4 GW of gas-fueled resources above currently planned capacity, which already includes approximately 4 GW of new wind and 22 GW of new gas resources.

However, the assessment did not take into account renewable tax credits, currently being debated in Congress. The Senate Finance Committee last week voted 23-3 to approve extending tax credits for wind energy, along with subsidies for biodiesel and cellulosic ethanol.

“We did not assume renewable credits would be an option, because we interpreted the draft plan as they wouldn’t be allowed,” Lanny Nickell said. “Now the final plan may very well allow those credit exchanges over state boundaries.”

SPP did use wind as a reasonable abatement measure in both the regional and state-by-state compliance assessments, because of the high wind potential in most SPP states and the desire to maintain a consistent approach for comparisons.

The state-by-state compliance scenario’s analysis assumed approximately 4,700 MW of coal retirements incremental to those retirements already planned. SPP said this assumption could be conservative, as its analysis indicates nearly all the region’s existing coal-fired generation would operate above an 80% capacity factor in the business-as-usual model, but approximately 13,400 MW of coal-fired generation would operate below an 80% capacity factor after applying the $45/ton carbon-cost adder.

Three Models

The state-by-state assessment used three different models: a business-as-usual (BAU) case, a BAU model with the $45/ton carbon-cost adder, and a third model with a variable cost adder.

Incremental coal retirements were assumed using a tiered approach. The first tier came from additional information gathered in preparation for a 2017 transmission-planning study. Updated projections found an additional 300 MW of coal units expected to be retired by 2030. The next three tiers took an age-based approach, targeting units’ ages in 2030: over 60 years, 55-60 years and 50-55 years.

The state-by-state compliance plan is the third study SPP has conducted of the proposed Clean Power Plan. The RTO’s first study in October 2014 found that the rule did not allow enough time to build the generation and transmission infrastructure needed to maintain system reliability and avoid severe system overloads that could lead to cascading outages.

July 28, 2015June 15, 2023

Federal Briefs

Consumers in states that focus on carbon-free generation and energy efficiency to comply with the Clean Power Plan could see significant cost savings, according to a study by Synapse Energy Economics. The consultant estimated that residential consumers could see bills averaging $35 a month lower by 2030, according to the study.

The study shows savings greater than the Environmental Protection Agency estimates and counters those that predict the carbon-emissions mandates will increase energy costs. The U.S. Chamber of Commerce, for instance, said some states could see energy costs increase about $200 a year per family after the Clean Power Plan is adopted.

The report also predicted that compliance with the rule would reduce carbon emissions by 58% by 2030, nearly twice the reductions mandated.

More: The Hill

Jeb Bush Calls for End to Fed, State Energy Subsidies

Former Florida Gov. Jeb Bush told a crowd in New Hampshire that the United States should discontinue tax credits that have subsidized the growth of the wind and solar industries. And in what many could see as a break from his family’s oil-industry roots, he also advocated cutting oil and gas industry subsidies.

“I don’t think we should pick winners and losers,” said the Republican presidential candidate. “I think tax reform ought to be to lower the rates as far as you can and eliminate as many of these subsidies — all of the things that impede the ability for a more dynamic way to get where we need to get.”

Ben Schreiber, of Friends of the Earth Action, agrees that it is time to cut oil and gas subsidies, but he thinks tax breaks for renewable energy should stay in place. “We cannot suddenly decide that renewables can compete fairly after decades of taxpayer support privileging polluters,” he said.

More: The New York Times

Mass. Senate President Asks FERC for More Public Review on Pipeline

Massachusetts Senate President Stan Rosenberg, a Democrat from Amherst, thinks the public needs more time to review the Tennessee Gas Pipeline’s $3.3 billion natural gas pipeline proposal and he has asked the Federal Energy Regulatory Commission to postpone a scoping hearing.

Rosenberg joined other pipeline opponents in trying to postpone the meetings. The meetings are a step in an approval process that would allow the Kinder Morgan subsidiary to build the pipeline across northwestern Massachusetts, New Hampshire and terminating in Dracut, Mass. If the pipeline is approved, it would be allowed to obtain rights of way by eminent domain, bypass some building regulations and cross environmentally protected areas.

Several opposition groups have already tried, and failed, to get FERC to delay the process.

More: MassLive

FERC: 128 MW of Biomass Generation Added this Year

The Federal Energy Regulatory Commission’s Office of Energy Projects reported that biomass-fueled projects generating 128 MW have been added to the U.S. portfolio in the first six months of 2015.

Seven projects, including a 95 MW waste-to-energy project in Palm Beach, Florida, were added to the country’s generation fleet. That compares to a total of 137 MW of biomass projects in all of 2014. Biomass projects typically use wood as a fuel.

More: BioMass Magazine

NRC Closes Inspector’s Office at Vermont Yankee Plant

The Nuclear Regulatory Commission has closed its resident inspector’s office at Entergy’s Vermont Yankee nuclear generating station, which retired in December and is undergoing decommissioning. The NRC has had a resident inspector at the site since the Resident Inspector program was launched.

The regulatory agency will continue to conduct periodic inspections at the plant, however. And when a major decommissioning work is undertaken, such as spent-fuel removal, an on-site inspector will be on hand.

More: Brattleboro Reformer

Exelon’s Byron, Braidwood Stations Pass License Renewal Steps

The Nuclear Regulatory Commission says there are no environmental reasons to deny operating license renewals to Exelon Nuclear’s Byron Generating Station. A week ago, the NRC said there were no technical reasons to deny a similar extension for the company’s Braidwood Generating Station.

Exelon is seeking 20-year license extensions for both plants. If approved, Byron Unit 1 would receive a license good through Oct. 31, 2044, and Unit 2 would be good until Nov. 6, 2046.

More: Nuclear Street

Judge Orders US Government to Pay $20.6M to Entergy on Waste Issue

A federal claims judge in New York denied a U.S. government motion to appeal an order requiring it to pay $20.6 million to Entergy Nuclear Palisades for failing to meet its responsibility to dispose of the plant’s radioactive waste.

Judge Nancy Firestone of the U.S. Court of Federal Claims granted Entergy’s request for partial judgement of $20.6 million of a total damage claim of $36.4 million. She ruled the government had a duty to pick up and dispose of the plant’s spent fuel under a 1983 contract and never fulfilled it. Government attorneys didn’t dispute the breach of contract, but they argued that the amount should be determined during the upcoming trial in December.

“Because the government has already agreed that it owes plaintiff approximately $20.6 million in damages, the outcome of the remaining portion of the litigation will not have any effect on the government’s obligation to pay that amount,” Firestone wrote. The government has been unable to live up to any agreements to dispose of spent nuclear fuel because it has been unable to build a spent-fuel repository.

More: Law360 (subscription required)

BOEM Offering 22 Million Offshore Acres to Energy Exploration

The Bureau of Ocean Energy Management scheduled an auction for Aug. 19 on oil and gas leases on about 21.9 million acres in the Gulf of Mexico off Texas. The auction will include all available unleased areas in the Western Gulf of Mexico Planning Area.

The area is divided into 4,038 blocks, from nine to 250 nautical miles offshore, according to Abigail Ross Hopper, bureau director. She said the water depths of the areas range from 16 feet to more than 10,975 feet.

It will be the eighth sale in BOEM’s current five-year program. The first seven auctions generated nearly $2.9 billion in revenue for the federal government.

More: WorldOil.com

July 28, 2015June 15, 2023

PJM Stakeholders to Study Relaxing Confidentiality Rules

By Suzanne Herel

WILMINGTON, Del. — PJM members agreed last week to consider relaxing confidentiality rules, despite reservations from several utilities.

Current rules allow the release of sensitive data only if it includes information about at least three market participants and is no more specific than a PJM transmission zone. PJM also is prohibited from discussing confidential information that has been made public elsewhere.

PJM’s Tom Zadlo said the problem statement represented an effort to strike a “reasonable balance between transparency and confidentiality.”

For example, he said, the cold weather events during the 2014 polar vortex and the hot weather events from 2013 “both were instances where PJM was interested in releasing more data. We would not have been releasing data in a harmful way, but it was prevented.” (See PJM Considering Release of Uplift, Outage Data.)

Neal Fitch of NRG Energy questioned whether PJM was presenting a problem statement or presenting a solution.

“All problem statements, according to doctrine, are the question, not the answer,” Zadlo said. “But if you’ve got a pretty simple problem with a pretty simple solution, you can have a solution when you come forward. That’s why PJM took the unusual step of proposing a solution along with the problem statement.”

That said, stakeholders will be free to consider the areas as they see fit, he said.

They are:

Making the list of generators that cleared in the Reliability Pricing Model available at the close of the auction instead of the start of the delivery year three years later. This potential change concerned stakeholders from Exelon and Dominion Resources, who said the knowledge that a generator did not clear an auction could lead to concern about the future of generators that fail to clear, threatening to disrupt relations with labor unions and vendors.
Demand response supply in small areas. “We’re not talking about dollars. We’re not talking about providers,” Zadlo said. “We’d just like to be able to [talk about] demand response in an area smaller than a transmission zone.”
Information about concluded generator outages. This would not include planned or maintenance outages. “PJM is not interested in systemic disclosure,” he said.
Confidential data that has been made public elsewhere. Currently, Zadlo said, “Even if everyone in the world knows about it, we can’t talk about it.”
Data regarding uplift, in order to encourage informed decision-making.
To the initial list of five categories, Market Monitor Joe Bowring added for consideration the idea of publishing summary results of the Three Pivotal Supplier test, a measure of market power.

Susan Bruce, representing the PJM Industrial Customer Coalition, recommended that some degree of “symmetry” be used as a guideline in addressing each of the areas in order not to unfairly expose one part of the market. For example, she said, “If there is some sort of pullback on some of those areas [such as generator information] and DR moves forward, that would give us concerns over comparable treatment.”

July 28, 2015

Fourth Time the Charm? Brayton Point Union Again Challenges ISO-NE Auction

The union representing workers at a Massachusetts power plant slated for closure is again asking federal regulators to reconsider its protest of capacity auction results in New England (ER15-1137).

Utility Workers Union of America Local 464 last week asked the Federal Energy Regulatory Commission to rehear its order accepting results from the ninth Forward Capacity Auction from February, citing “errors” in a June order affirming the results.

The union has tried three times without success to persuade FERC that recent capacity auctions in New England have been tainted by generators illegally withholding the Brayton Point generating station from the last two FCAs to boost prices paid to other assets. (See FERC Accepts ISO-NE Capacity Auction Results.)

“The June 18 order errs by failing to place the burden of proving just and reasonableness and compliance with the Tariff with respect to the FCA 9 results on ISO-NE, as required by Federal Power Act … and the ISO-NE Tariff, and by failing to expressly find that ISO-NE failed to meet that burden in reaching its finding approving the FCA 9 results, and particularly by failing to require the submission of substantial evidence affirmatively demonstrating that the attempted withdrawal or ‘retirement’ of Brayton Point by its owner announced in early 2014 was economic, and therefore in conformity with the ISO-NE Tariff provisions,” the filing says.

— William Opalka

July 28, 2015June 15, 2023

Iberdrola Profits Rise; Refiling on UIL Acquisition Soon

Iberdrola reported net income of 1.5 billion euros in the first six months of 2015, up 7.4% on the same period last year, as increased revenue in its U.S. and other overseas operations offset declines in Spain.

Gross operating profit increased by 5.7% in the first half to 3.8 billion euros, thanks to the strong performance of its international business, which grew by 20%, compared to a 6.5% drop in Spain, the company said in a statement.

The company also reiterated plans to refile with regulators in Connecticut and Massachusetts its proposed acquisition of UIL Holdings, which was derailed earlier this month. (See Iberdrola Withdraws UIL Acquisition; Plans to Refile.)

The company only briefly mentioned its proposed acquisition of Connecticut-based UIL, which has gas and electric operations in New England. Iberdrola expects to close the deal in the fourth quarter of the year.

The company said it has received approvals from all four federal agencies required and expects to close the transaction in the fourth quarter.

— William Opalka

July 28, 2015June 15, 2023

MISO Gets OK to Add 10th Zone in Miss.

By Chris O’Malley

The Federal Energy Regulatory Commission has conditionally granted a request by MISO to create a 10th local resource zone, in Mississippi (ER15-1771).

The state currently is part of MISO Zone 9, which also consists of Louisiana and part of Texas.

MISO’s Tariff requires that the RTO must develop new zones by Sept. 1 of each year if necessary to ensure adequate planning resources to meet demand and loss-of-load-expectation requirements.

MISO said its analysis showed the need for a separate, stand-alone zone for Mississippi.

MISO will use the zone to allocate costs of new market efficiency projects. It will not affect the cost allocation transition period for the MISO South region, the order stated.

The RTO defines zones by several criteria, including state and local balancing authority boundaries and the strength of transmission interconnections between BAs.

FERC said MISO’s re-evaluation was consistent with such criteria and that no parties opposed creating the new zone. “MISO states that with the new Mississippi zone, MISO will continue to appropriately balance the granularity in the calculation of benefits from market efficiency projects and the uncertainty of these calculations at a more granular level,” FERC wrote.

New Zone Rests on Resolving Another Dispute

But FERC said its approval would be conditional on resolution of a pending case involving proposed revisions to MISO’s resource adequacy construct. The RTO filed the changes to comply with FERC orders addressing concerns about deliverability of capacity resources throughout MISO’s footprint (ER11-4081).

MISO won commission approval to impose a zonal deliverability charge on load-serving entities that meet their resource adequacy requirements through resources located outside of the zone where their loads are located.

MISO proposed two types of hedges against deliverability charges, including a “grandmother agreement” for market participants that secured firm transmission rights prior to July 20, 2011.

But FERC ordered MISO to terminate the grandmother agreements after a two-year period, saying it would unreasonably allow LSEs to avoid using deliverability as part of their resource planning analysis — negating the purpose and reliability benefits of the proposed locational market mechanisms.

Parts of that 2011 FERC order are still being slugged out at the commission. Among those trying to convince FERC to rehear the elimination of the grandmother clause is Great River Energy, which said it has been exposed to significant pancaked costs for capacity since the two-year phase out of the waiver.

Dynegy Case Indicative of Broader Zone Problem?

In a filing last month, Great River referred to a dispute involving zonal boundaries: the complaint filed in May by Public Citizen and the Illinois Attorney General about the nine-fold increase in Zone 4 prices in MISO’s Planning Resource Auction last April (EL15-70).

Great River said that case illustrates “that commission action is needed to address problems in the implementation” of zones.

Great River said the Zone 4 complaints also demonstrate significant price separation that can occur between zones. “Some of this price separation could have been hedged from grandmother agreement treatment if firm transmission service existing from non-Zone 4 generation to Zone 4 load.”

In Great River’s case, it told FERC it is likely to incur even more capacity costs through the islanding of its load in Zone 3. Great River said MISO’s “improper” application of the zone criteria had the effect of islanding its load in southern Minnesota by carving it out of Zone 1, where all of its generation is located.

July 28, 2015

ISO-NE Tariff Changes Make Renewables More Easily Dispatchable

By William Opalka

The Federal Energy Regulatory Commission has accepted revisions to the ISO-NE Tariff that make wind and hydropower resources more readily dispatchable (ER15-1509).

The changes “will minimize the need to use manual curtailment processes and thus, provide for a more economically efficient use of these resources,” FERC wrote.

The recent increase in the integration of variable renewable resources in relatively remote areas of the transmission system has caused increased congestion, ISO-NE said. These resources do not have direct control over their net power output, are not currently electronically dispatchable and must be manually curtailed to manage congestion, which is inefficient.

ISO-NE said the new method would manage localized congestion through Do Not Exceed (DNE) Dispatch Points — the lesser of the maximum output level at which the resource would operate in economic dispatch, or a reliability limit representing the maximum output consistent with reliability constraints.

FERC said the changes are particularly important as these resources are increasing in New England. While there are 878 MW of wind and 321 MW of hydro generation operating in the region, there are more than 4,000 MW of these renewables in the RTO’s interconnection queue.

“We agree with ISO-NE that these changes will improve price formation, particularly in areas that have a high penetration of renewable resources and limited transmission capacity, and system reliability because of the reduced reliance on manual curtailments,” the commission said.

FERC, however, rejected Tariff language that would have excluded wind resources from participating in regulation and reserves markets, agreeing with renewable energy developers that a “blanket exclusion” was not justified. “Eligibility for providing these services should be based on capability and performance characteristics rather than categorical exclusions,” according to the order. Rules should be developed through a stakeholder process, the commission said.

FERC also gave hydro resources that do not currently have remote terminal units an additional year to comply because they have to undertake additional steps to become DNE Dispatchable Generators, compared with resources that already have the equipment.

ISO-NE’s proposed Tariff revisions are conditionally accepted effective April 10, 2016, with a compliance filing due in 30 days.

July 28, 2015

Officials Urge PJM to Reject Artificial Island Proposal

By Suzanne Herel

Delaware Gov. Jack Markell has joined regulators, consumer advocates and industrial customers representing the Delmarva Peninsula in lobbying the PJM Board of Managers to reject planners’ recommended reliability fix for Artificial Island, barring a new look at why virtually all of the project’s $275 million price tag will be charged to Delaware and Maryland customers.

“As the project is currently structured, Delaware consumers would bear over $100 million of costs associated with the project in exchange for a very small portion of the value it would create,” Markell wrote in a July 13 letter to board Chairman Howard Schneider.

According to the Delaware Public Service Commission, that could translate to a 25% increase in transmission costs in the state. Some of the state’s heaviest users could see their monthly bills surge by hundreds of thousands of dollars, Markell said.

‘Neither Reasonable nor Equitable’

“It seems patently unfair that electricity users in the Delmarva Peninsula would bear almost the entirety of the costs of a project for which the principal benefit is not expanded energy transmission in Delaware, but maximizing power from generating units in New Jersey that serve customers throughout the PJM region,” Markell said.

“Allocating to Delaware and Maryland consumers the bulk of those costs for a project not necessitated by demand in this area is neither reasonable nor equitable.”

Paul McGlynn, PJM’s general manager of system planning, said in an interview that cost allocations for Order 1000 projects are formulaic and governed by PJM’s Tariff as approved by the Federal Energy Regulatory Commission.

When the 10-member board meets Wednesday in closed session, it could take a position anywhere on a wide spectrum, from approving the project as-is, to directing staff to develop Tariff changes regarding cost allocation, he said.

Previous Board Action

“The board displayed leadership and courage in July 2014 to defer decision on the Artificial Island proposal selected,” a group of end-use businesses said a July 17 letter.

“We respectfully submit that similar leadership and courage is necessary again now with respect to Artificial Island to ensure that the project selected by PJM staff and the cost allocation produced by PJM’s solution-based DFAX [distribution factor] do not undercut PJM’s important efforts to implement Order No. 1000 in a just and reasonable manner,” said the group, which includes Linde, E.I. du Pont de Nemours and Co., Delaware Racing Association, Kuehne Chemical Co., Delaware City Refining Co. and Christiana Care Health System.

LS Power Plan

PSE&G and Transource Energy, two other finalists, were tapped to build necessary connection facilities.

Home to the Salem and Hope Creek nuclear reactors, Artificial Island is the second largest nuclear complex in the country. Special operating procedures that historically have been used to maintain stability in the area have become increasingly difficult to implement while respecting the system’s other operational limits.

Beneficiary Analysis Sought

In their letters, the Delaware Public Service Commission, the Maryland Public Service Commission and Old Dominion Electric Cooperative requested that PJM provide a detailed beneficiary analysis justifying the project’s cost allocation.

ODEC went further, requesting a breakdown of cost allocation and benefits for all four project finalists. (See Artificial Island Finalists Face Off in Tense Meeting.)

ODEC noted that the cost of PSE&G’s alternative 500-kV project would have been divided among all PJM zones on a load-ratio share basis, with 50% allocated using the solution-based DFAX method.

“In other words, two transmission upgrades designed to address the same operational performance issues and both costing approximately the same would be allocated to widely varying groups of customers,” it said.

“ODEC believes that, in this specific situation, the cost allocation of the proposed Artificial Island solutions is highly relevant to the determination of whether the proposal is ‘the more efficient and cost-effective solution.’”

It noted that FERC is considering a number of similar challenges to certain DFAX cost allocations.

Environmental Challenge

The board received another letter opposing the Artificial Island project, but on environmental grounds, from the Delaware Riverkeeper Network. It urged the board to seek out an alternative with fewer environmental impacts that does not include crossing the Delaware River.

Riverkeeper Maya K. van Rossum noted that the project’s route will traverse the Augustine Wildlife Area and the Appoquinimink River, which include large expanses of wetlands that are part of the largest preserved coastal marshland on the East Coast.

Several endangered bald eagles breed in the area, which also supports the similarly endangered northern harriers, she said.

“Furthermore, species such as the federally endangered Atlantic Sturgeon — of which there are less than 300 spawning adults each year of the river’s genetically unique population — can ill afford additional harm to their population, spawning capabilities or juvenile survival.”

If PJM proceeds with the LS Power proposal, she said, the group will request federal agencies to prepare a full environmental impact statement.

“In addition to potential time delays, any environmental impacts will raise the cost of the project through the need for mitigation projects,” she said.

July 28, 2015June 15, 2023

Price Tag Likely to Rise for Northern Pass Transmission Line

By William Opalka

The price tag on the proposed Northern Pass transmission line in New Hampshire appears likely to rise after a draft environmental impact statement released last week showed the cheapest route would also have the greatest environmental impact.

The draft EIS by the U.S. Department of Energy evaluates various alternatives for the 187-mile route that would connect Canadian hydropower with the wholesale energy markets in New England.

The developers’ preferred route would require the creation of a new, 40-mile right of way measuring 150 feet wide. Identified as Alternative 2, the route “would impose the greatest environmental impacts as compared to the other action alternatives primarily because of visual impacts, vegetation removal and ground disturbance required,” according to the department.

It “would also have the least cost of construction (approximately $1.06 billion).” The department also said it would cost an additional $564.1 million in “economic impacts from construction.”

Only 8 miles of the northernmost section would be buried under the cheapest scenario, but the developer appeared to leave open the possibility that more of the route could be laid underground, saying it is reviewing the reaction to the document and giving “further consideration” of the “potential view impacts related to overhead lines.”

“These and other conclusions in the DEIS will help inform our forthcoming proposal to the state of New Hampshire’s Site Evaluation Committee,” Northern Pass Transmission, an Eversource Energy subsidiary, said in a statement. “As we’ve stated, we plan to propose a new, balanced plan in the near future that incorporates the feedback we’ve heard in discussions across the state and will address those concerns while providing substantial economic benefits to New Hampshire.”

William Hinkle, a spokesperson for Gov. Maggie Hassan, reiterated her opposition to Alternative 2, saying “the project must fully investigate burying more sections of the lines.”

“She will continue to encourage the company to listen to the concerns of Granite Staters, and if it is going to move forward, propose something that ensures lower costs for New Hampshire ratepayers and that protects our scenic views and beautiful natural resources, which are critical to our economy,” Hinkle said.

Environmental advocates, outdoorsmen and elements of the tourism industry have lobbied for burial of the entire route — the most expensive alternative.

“The Department of Energy’s alternatives analysis provides strong evidence that the overhead transmission line proposed by Northern Pass or just partial burial in the vicinity of the White Mountain National Forest would cause considerable environmental and scenic damage compared to total burial of the project,” Kenneth Kimball, director of research for the Appalachian Mountain Club, said in a statement.

The department said its draft EIS concluded that “the alternatives that would be constructed underground along existing roadways … would impose the fewest environmental impacts due to the lack of visual impacts and use of already disturbed roadway corridors. However, all of the underground alternatives … would have the highest construction costs (between approximately $1.83 billion and approximately $2.11 billion).”

The 1,200-MW project is a joint venture of Eversource Energy and Hydro Quebec. It was proposed in 2010 and, if the current schedule holds, would be completed in 2019. (See Eversource: Northern Pass Delayed Until ’19; Earnings Up.)

According to the report, the company’s preferred route, and a similar 1,200-MW alternative, would provide the greatest benefit for the wholesale energy markets. It would decrease wholesale electricity costs by $22 million in New Hampshire and by $149 million across ISO-NE. Other alternatives with a 1,000-MW capacity would only save $18 million and $134 million, respectively.

The department also said that the preferred route is the only alternative inconsistent with the existing White Mountain National Forest Plan. Overhead transmission would be seen from “historic architectural resources and thus could adversely affect the historic context of these sites more than the underground alternatives.”

A 90-day comment period will begin once the study is published in the Federal Register.