Page 1570 – RTO Insider

June 18, 2014

UPDATE: LaFleur to Remain Acting FERC Chair for up to 1 Year in Senate Deal with White House; Bay Wins Floor Vote

WASHINGTON — Cheryl LaFleur will likely remain acting chair of the Federal Energy Regulatory Commission for another year under a deal with the White House that won a Senate floor vote for Norman Bay.

A Senate panel voted June 18 to approve Bay’s appointment to FERC in a deal that will keep LaFleur in her leadership role for nine months after Bay’s confirmation by the full Senate.

The Senate Energy and Natural Resources Committee voted 13-9 to confirm Bay and 21-1 to grant LaFleur a second five-year term. With a floor vote not expected until September, LaFleur could remain in the top spot until June 2015.

LaFleur had sailed through her confirmation hearing May 20 while Bay was forced to defend his limited policy experience and his running of the commission’s enforcement division. The Department of Energy Organization Act gives the Senate authority to confirm members of FERC but gives it no say over which one of the commissioners is appointed chair by the president.

The president’s concession was enough to win the support of West Virginia Democrat Joe Manchin today but not that of ranking member Lisa Murkowski (R-Alaska) and most of her Republican colleagues. Murkowski said she wanted the president to remove the “acting” designation from LaFleur’s chairmanship so that she had full authority to act in a leadership role.

“I have not been given the assurance that she would be given the full authority as the chairman,” Murkowski said before casting her “no” vote.

Experience Questioned

Earlier in the hearing, Murkowski noted that lights in the Capitol were dimmed to conserve energy and said “there might be rolling brownouts this afternoon” as temperatures hit the 90s. She also cited FERC’s role in ensuring the grid’s reliability in the face of increasing environmental regulations on fossil fuel-fired generators.

“We need the best of the best running the commission,” Murkowski said.

While praising Bay as “a learned man,” she said the FERC chairmanship was not the place for “on-the-job training.”

Bay, who has served as director of FERC’s Office of Enforcement since 2009, is a former federal prosecutor and law school professor. Unlike most FERC commissioners in the last decade, he has never served as a state utility regulator.

Of the 15 FERC commissioners who have served since 2000, 10 served as commissioners or staffers at state regulatory agencies prior to their appointments. Four of the others worked in energy-related posts in state or federal legislative committees or executive agencies; one was a former utility executive.

The last five chairmen served a median of 30 months before becoming chair. Only one, Patrick H. Wood III, served less than a year on the panel before his promotion.

Murkowski and others also raised the issue of gender politics, questioning why Obama announced his intention to appoint the less experienced Bay directly into the chairmanship, “particularly when we have a woman … as the acting head of this commission. By all reports [LaFleur’s] been doing a good job,” Murkowski said. LaFleur is the only woman on the commission.

Among those who had expressed concern over Bay’s limited energy policy experience was Manchin, who helped sink the bid of Obama’s previous nominee, former Colorado regulator Ron Binz.

That sparked a flurry of negotiations over the last several days among the White House, Murkowski and Energy committee Chair Mary Landrieu (D-La.), which resulted in the president’s concession not to appoint Bay chairman immediately.

The lone vote against LaFleur apparently came from Vermont Sen. Bernie Sanders, an independent who caucuses with the Democrats. Sanders said he was not opposed to LaFleur’s second term but was protesting the delay in Bay’s ascension. “I think Mr. Bay would be an outstanding chair,” he said.

The committee’s vote sends the Bay and LaFleur nominations to the full Senate, where Bay has the backing of Senate Majority Leader Harry Reid (D-Nev.). In an interview with The Wall Street Journal June 8, Reid said bluntly, “I don’t want [LaFleur] as chair.”

Reid told the Journal he was concerned LaFleur would not adequately enforce market manipulation rules or support building transmission for renewable energy. Reid also said he feared LaFleur would undo initiatives of former chair Jon Wellinghoff, a Nevadan allied with Reid who retired last year.

“This is not the outcome Sen. Reid would have preferred but he accepts the compromise negotiated by Sen. Landrieu and he will move forward with confirming the nominees,” a Reid spokeswoman told The National Journal after the vote.

Enforcement Criticism

The criticism over Bay’s management of FERC’s Office of Enforcement was sparked by members of the energy bar, led by former FERC general counsel William Scherman. In a 49-page article in the Energy Law Journal, Scherman accused Bay of driving Wall Street banks out of energy trading with heavy-handed enforcement tactics. Several senators continued to probe the issue in post-hearing questions to Bay and LaFleur.

In her answers, LaFleur acknowledged differing with Bay and her fellow commissioners on procedural matters regarding seven investigations, including four in which the subjects were represented by Scherman. While LaFleur characterized the disagreements as “procedural” and not substantive, the disclosures did lend some credibility to Scherman’s critique.

June 16, 2014

PSEG Wins $300M Artificial Island Project

PJM planners today recommended Public Service Electric and Gas be awarded the contract to fix the Artificial Island stability problem with a new 500-kV line from Hope Creek, N.J. to Red Lion, Del. at a cost of about $300 million.

The planners recommended PSE&G construct the 18-mile line and upgrades to its Hope Creek 500-kV station. Pepco Holdings Inc. will upgrade its Red Lion 500-kV station at the other end of the line under the recommendation.

The stability fix for Artificial Island — home of the Salem and Hope Creek nuclear plants — is PJM’s first competitive transmission project under the Federal Energy Regulatory Commission’s Order 1000.

The competition attracted 26 proposals from five utilities and three independent developers, led by PSE&G with 14 alternatives. In May, planners identified a shortlist of 10 proposals, including the 500-kV proposal by PSE&G and a similar project by Dominion Virginia Power.

The two projects — which had been in the middle of the pack in cost and did poorly in their original forms in an analysis of risk factors and technical concerns — had their standings improve dramatically when PJM reevaluated them after eliminating a second tie line between the two nuclear plants.

The revised Dominion and PSE&G proposals got top scores in the analysis and also saw their costs reduced by $34 million and $43 million, respectively. PJM estimated either project would cost between $211 million and $256 million, the same range it assigned to a 230-kV proposal by LS Power that had been the cheapest proposal prior to the change. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.)

The estimates do not include an additional $80 million for a static VAR compensator (SVC), which PJM added to all of the proposals. In total, the winning project is expected to cost $291 million to $337 million.

Paul McGlynn, general manager of system planning, said that planners chose the 500-kV proposal because it provided greater transmission capacity than the 230-kV alternatives and would use an existing Delaware River crossing rather than a new southern crossing employed by the 230-kV proposals. PJM said the river crossing “represents the greatest component of schedule risk” for all proposals.

McGlynn said planners chose PSE&G over Dominion because PSE&G is a party to the Lower Delaware Valley (LDV) Transmission Service Agreement, which controls an existing 500-kV right of way in New Jersey that the new line will largely parallel. Although PSE&G will need expand the right of way for 8.5 miles, Dominion would have needed to acquire the right of way for the entire route, PJM said.

The planners will recommend the Board of Managers include the project in the Regional Transmission Expansion Plan at the board’s July 22 meeting. McGlynn said PJM will accept comments on the recommendation through July 16.

The winning project is a modification of PSE&G’s proposal (#7K), which was originally proposed at a cost of $1.066 billion. PJM planners reduced the cost by eliminating a 500-kV line between New Freedom and Deans, making changes to breaker configurations and eliminating the second tie line between the two nuclear plants. Eliminating the second tie line also eliminated the need for the 500-kV line to cross another 500-kV line, which would have created a risk of a multiple facility trip.

The SVC will be added at PSE&G’s New Freedom switching station. PJM added the SVC despite opposition from PSEG Nuclear LLC, the operator of the nuclear plants, which said SVCs have never been used to correct “transient angular stability.” PSEG Nuclear said the SVC would pose “unknown and potentially challenging regulatory risks,” including an “in-depth review” by the Nuclear Regulatory Commission.” (See Contestants Make Last Pitch for Artificial Island Prize.)

PJM acknowledged that the selected route faces land-permitting challenges because it will cross the Supawna Meadows National Wildlife Refuge, the Alloway Creek Watershed Wetland Restoration Site and the Abbotts Meadow and Mad Horse Creek Wildlife Management Areas. The New Jersey Board of Public Utilities said PJM’s analysis of the 500-kV option underestimated likely public opposition.

Sharon Segner, vice president at LS Power, said afterward that she was “profoundly disappointed” by PJM’s decision and predicted PSEG will be unable to win approvals to build the line across the New Jersey wetlands and wildlife areas.

McGlynn said the project’s cost allocation will be “very similar” to the allocation outlined in May, which spread the cost among two dozen transmission zones and merchants. The Jersey Central Power & Light zone would be responsible for about 27% of the project, with the Atlantic City Electric zone picking up almost 20%. No other zone was as high as 8%.

FERC Order 1000 eliminated incumbent utilities’ federal right of first refusal (ROFR) on new transmission projects, opening the business to competition from independent transmission developers.

Others submitting proposals in addition to PSE&G, Dominion and LS Power were Transource Energy, a partnership between American Electric Power and Great Plains Energy (owner of Kansas City Power & Light Co.); FirstEnergy Corp.; Atlantic Wind Connection; and a partnership between Pepco Holdings Inc. and Exelon Corp.

June 10, 2014

Planning Assumptions Debunked by Winter Outage Study

PJM will likely change its planning assumptions based on an analysis that found a strong correlation between wind chill indices and generator outages.

“Planning studies currently assume that forced outages are random and occur at a constant rate throughout the four seasons,” PJM’s Tom Falin told the Planning Committee last week. However, the analysis of generation outages from winters 2007/08 through 2012/13 found that the lower the wind chill, the more gas-fired capacity is lost to forced outages, including gas curtailments.

“We used to [consider] all unit forced outage rates as independent of each other, but we saw in January that they clearly are not. If you can’t get gas for one unit, you can’t get it for all units,” Falin said.

The analysis identified 9,244 MW of “chronically curtailed” gas plants — those that were curtailed an average of at least 12 hours per year. Jerry Bell of PJM explained that 2013/14 data was left out of the study because “we didn’t want to poison [the data] with the most recent winter.”

Under a worst-case scenario, which assumes the loss of all existing gas plants that were curtailed at least once over the last six winters and all “at-risk” future units (those likely to be “chronically curtailed” based on their pipeline supply), PJM could be forced to operate without 42,700 MW of gas capacity.

The analysis showed variability across zones. The ComEd zone, for example, had more than 2,600 MW of “chronically curtailed” gas generation while the JCPL zone had just 41 MW.

PJM officials said they will likely change their planning assumptions to recognize the increased risk of gas outages during extreme cold. The analysis may also result in new rules regarding the firmness of winter fuel supplies and calculation of winter Capacity Emergency Transfer Objectives and Capacity Emergency Transfer Limits.

“Clearly, the range of potential solutions is different for next winter than it is for 2019/20,” Vice President of Planning Steve Herling said. “Everything is on the table right now.”

Carl Johnson, of the PJM Public Power Coalition, said it may be necessary to develop both RTO-wide and zonal solutions. “In addition to studying why units were out, we should study why units weren’t out,” he said.

June 10, 2014

LaFleur Parts with Bay on Enforcement Procedures

To win confirmation as Federal Energy Regulatory Commission chair, Norman Bay will have to overcome both questions about his energy policy experience and criticism of the agency’s enforcement practices. His case wasn’t helped last week by the responses Acting Chair Cheryl LaFleur filed in response to questions from the Senate Energy and Natural Resources Committee.

LaFleur made clear she hasn’t always agreed with Bay or her fellow commissioners on FERC enforcement policy, detailing seven cases in which she issued separate concurrences or dissented from the majority. In four of the cases, the subjects were represented by former FERC general counsel William Scherman, who co-authored an Energy Law Journal article last month accusing FERC of heavy-handed enforcement tactics.

While LaFleur characterized the disagreements as “procedural” and not substantive, the disclosures could lend credence to Scherman’s criticism of the Office of Enforcement, which Bay has led since 2009.

In three cases, LaFleur said she disagreed with the way the commission applied its penalty guidelines, which she said “had the effect of double-counting the duration of the violations and unduly increasing the amount of the civil penalty range.” Commissioner John Norris joined her dissent in one of the cases.

She also dissented from a commission decision rejecting Barclays’ motion to quash a subpoena. The motion came after Bay’s office had issued an order to show cause, accusing the bank of market manipulation. Barclays had chosen to forego a hearing before an administrative law judge and instead have the commission assess a civil penalty for the alleged misconduct.

“In my view, the statutory directive that the commission `promptly assess’ a civil penalty could not be reconciled with further investigation into the conduct that was detailed in the order to show cause,” LaFleur wrote.

LaFleur said she also split with Bay and other commissioners in a non-public order related to the timing of an investigation subject’s access to deposition transcripts. “The commission’s regulations state that even if good cause exists to deny witnesses a copy of his or her deposition transcript, `[i]n any event, any witness or his counsel, upon proper identification, shall have the right to inspect the official transcript of the witness’ own testimony,’” LaFleur wrote. “I believe this regulation does not permit a delay in providing access to transcripts.”

Scherman had alleged that FERC “denied witnesses the right to procure copies of, or to inspect, the official transcripts of their own depositions” in “a number of nonpublic cases.”

Finally, LaFleur dissented with the commission’s decision to suspend J.P. Morgan Energy Venture’s market-based rate authority in response to the company’s alleged misrepresentations during a market manipulation investigation.

“I viewed such a suspension as inconsistent with the commission’s market-based rate regulations,” she wrote. “Instead, I believe that any misrepresentations should have been addressed as part of the ongoing investigation into J.P. Morgan’s bidding activities, either as separate counts of obstruction, or as aggravating circumstances factoring into the determination of a civil penalty.”

June 10, 2014

PJM Balks at Lowering QTU Credit Requirement

PJM objected last week to a transmission developer’s efforts to reduce credit requirements on Qualifying Transmission Upgrades (QTUs), saying the RTO lacks authority to compel construction of the projects.

QTUs are small transmission projects that can be offered into capacity auctions to relieve transmission constraints in locational deliverability areas (LDAs). Developer H-P Energy Resources LLC won stakeholders’ OK in February to reconsider the current credit requirements, which it contends are out of proportion to the costs and risks of such projects. (See Members OK Review of Qualifying Transmission Upgrades Credit Rules.)

Janine Durand, attorney for the developer, told the Market Implementation Committee last week that a $7 million reconductoring would require posting credit of about $32.5 million. Durand proposed a change that would limit the credit to 100% of the upgrade cost.

“This is unreasonable for Qualifying Transmission Upgrades and presents a barrier for entry for these types of projects,” she said, adding that the majority of QTUs “move ahead quickly” and are relatively low-risk compared with generation projects that offer into capacity auctions.

However, Durand and PJM disagreed over how the RTO could protect other market participants if a QTU is not completed before the delivery year for which it cleared a capacity auction.

Durand contended PJM could force a transmission owner to complete the project under its Tariff. “At the end of the day, we’re not talking about some kind of proposal out of the blue. It’s considered an obligation once everyone [developer, TO and PJM] signs the Interconnection Agreement,” she said.

PJM’s Hal Loomis disagreed. “PJM really doesn’t have authority to [demand] that a QTU has to be built,” he said. “Even if some sort of reliability issue is involved, there’s no link between the reliability issue and the QTU, and no assurance that it would be done. To dramatically reduce [the credit posted] seems inappropriate.”

Dave Pratzon of GT Power Group said he was concerned that “if a QTU isn’t built, other market participants will be affected in terms of reliability.”

The MIC is expected to vote on the proposed change at its next meeting on July 9.

June 10, 2014

Members Begin Work on Gas Dispatch Fixes

As temperatures soared into the 80s outside PJM offices last week, stakeholders began debating how to avoid a repeat of the operational problems from last winter.

Operating Committee members discussed a problem statement and issue charge on gas-unit-commitment coordination, a response to PJM’s problems in scheduling gas-fired plants in January.

About one quarter of PJM’s outages on Jan. 7 were the result of gas units’ inability to obtain fuel.

Gas pipeline rules caused delays in the starting of some units and restricted PJM’s ability to dispatch units as needed. The Operating Committee’s initiative will seek methods for gas generators to communicate such operating restrictions to PJM dispatchers.

It will also respond to complaints by about 10 companies that they were left with “stranded gas” when PJM failed to dispatch their units in January. Duke Energy has filed a claim in an effort to recoup $9.8 million in gas losses, and NextEra Energy Resources said it will make a similar claim to recoup $1.3 million. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim).

“We need to get some changes in prior to next winter, even if we need to segregate short-term [solutions] from long-term,” said Mike Bryson, executive director of system operations. The short-term solution may be a simple clarification of existing rules for RTO dispatchers and generators while PJM develops a long-term solution, he said.

The Operating Committee focused on education and interest identification in last week’s session. It will continue its work in a special meeting June 23.

June 10, 2014

EPA Rule Boosts Regional Compliance, Cap-and-Trade

States could cut their costs of complying with the Environmental Protection Agency’s carbon emission rule by more than one-quarter through 2020 by joining a regional compliance program similar to the Regional Greenhouse Gas Initiative (RGGI) cap-and-trade program.

The EPA estimates total compliance costs of $7.5 billion in 2020 (2011$) if states comply individually, versus $5.5 billion if all states take a regional approach.

Costs rise to $8.8 billion (2011$) in 2030 under state compliance, compared with $7.3 billion for the regional approach.

“States may choose to cooperate in order to achieve more cost-effective outcomes, since some states can reduce their emissions more easily relative to others,” the agency explained. It “expects this flexibility to reduce the cost of achieving the state goals and therefore expects it to be attractive to states. For example, the RGGI-participating states could choose to submit a multi-state mass-based plan that demonstrates emission performance by affected [electric generating unit (EGU)] on a multi-state basis. Additional states may also choose to join a multi-state plan.”

Individual state plans must be filed with the agency by June 30, 2017, with a one-year extension possible. Regional plans won’t be due until June 30, 2018.

The EPA’s regional analysis assumed five regions based on North American Electric Reliability Corp. (NERC) regions and RTO footprints. States that fall into more than one region were grouped in the region that comprised the majority of geography or generation. Thus, the EPA’s “East Central (PJM)” region included only seven states: Ohio, Pennsylvania, West Virginia, Maryland, Delaware, New Jersey and Virginia (see map.)

Regional Zones in EPA Proposed Carbon Rule (Source: EPA)

Mass- or Rate-Based Standards

The EPA’s default state emission limits are rate-based, setting limits measured in pounds of CO₂ per MWh of generation. States have the option of converting the rate-based standards to a mass-based limit measured in tons of CO₂. The regional plans also have the choice of a rate-based standard or the mass-based caps used by RGGI. (See related story, LaFleur, Bay: ‘Flexibility’ of EPA Rules Mitigates Reliability Concerns.)

The agency invited comment on suggestions that it develop a model rule for an interstate emissions credit trading program that could be easily adopted by states.

Nine states, including Maryland and Delaware in PJM, participate in RGGI. New Jersey withdrew from the program in 2011. (See related story, EPA’s Carbon Rules Attacked from Both Flanks.) California has established an economy-wide, market-based greenhouse gas emissions trading program, which requires the state to reduce its 2020 GHG emissions to 1990 levels.

RGGI, which was created in 2009, sets an overall limit on allowable CO₂ emissions from affected generators. Participating states issue carbon allowances based on their annual emission budgets.

At the end of each three-year compliance period, affected generators must submit CO₂ allowances equal to their reported carbon emissions. The allowances may be traded among both regulated and non-regulated parties, creating a market and price signal for emissions. The price signal factors into the economic dispatch of affected generators.

Between 2009 and 2012, the RGGI states invested auction proceeds of more than $700 million in programs to lower energy costs and reduce emissions, such as energy-efficiency programs.

Power sector carbon emissions in the RGGI-participating states fell by more than 40% between 2005, when RGGI was announced, and 2012. The EPA acknowledges RGGI was not the primary driver for these reductions — reduced electric demand following the 2008 recession was a big factor. In January, the group lowered its 2014 CO₂ emission cap by 45%.

PJM Role?

The EPA also is seeking comment on how PJM and other RTOs and ISOs could help states achieve efficiencies, a role suggested by the ISO/RTO Council.

“Just as the ISO/RTO regions today share the benefits and costs of efficient EGU dispatch across state boundaries, there are significant efficiencies that could be captured by coordinating individual state plans or implementing multi-state plans within a grid region,” the agency said. “Under one variant of this approach, states would implement a multi-state plan and jointly demonstrate CO₂ emission performance by affected EGUs across the entire ISO/RTO footprint.”

June 10, 2014

Federal Briefs

The Federal Energy Regulatory Commission didn’t follow environmental laws when it approved a natural gas pipeline in New Jersey, a federal appeals court ruled. FERC approved the Tennessee Gas Pipeline’s 40-mile Northeast Upgrade project, which would have followed an existing pipeline’s route, in 2012. The Delaware Riverkeeper Network, the New Jersey Highlands Commission and the New Jersey Sierra Club argued that FERC did not take into account other expansion projects under consideration at the same time.

The U.S. District Court of Appeals in the District of Columbia last week agreed, sending the matter back to FERC for another review. “In conducting its environmental review of the Northeast Project without considering the other connected, closely related and interdependent projects on the Eastern Leg, FERC impermissibly segmented the environmental review in violation of NEPA,” the three appellate judges wrote in their decision. Kinder Morgan, the company that built and maintains the pipeline, says it will reapply for the necessary permits.

Maya van Rossum, head of the Delaware Riverkeeper Network, said FERC has been allowing “illegal segmentation” by pipeline companies for years. “It is rewarding that a federal court has finally held FERC to account,” van Rossum said.

More: NJ.com

NRC Chair Tours Michigan Nuke Plants

Nuclear Regulatory Commission Chairwoman Allison M. Macfarlane toured two Michigan nuclear plants last week to view safety upgrades put in place after the Fukushima crisis in Japan. Macfarlane was accompanied by Michigan Rep. Fred Upton (R), chair of the House Energy and Commerce Committee. “A lot has changed since Fukushima,” Upton said. “It’s important that we learn from that.” They were shown additional safety equipment and other improvements taken in the wake of the nuclear incident in Japan.

More: MLive

NRC Staffers Fear Backlash if Critical

A recent internal Nuclear Regulatory Commission survey found that 75% of respondents said they were punished with poor performance reviews after objecting to agency decisions. The NRC Office of Enforcement conducted the survey last year.

In it, three-quarters of the employees who responded say they registered “non-concurrence” in certain situations and were later slapped with the poor performance reviews. Additionally, 63% said they felt they were excluded from certain tasks as a result of disagreeing with commission rulings, and 25% said they thought their criticisms had cost them a promotion. A quarter of respondents said they had been verbally abused by supervisors after objecting to certain decisions.

The report was released after Sen. Edward Markey (D-Mass.) cited it during a hearing last Wednesday. Markey said he was concerned that NRC staffers may be afraid to question established rules. “Especially post-Fukushima, it’s very important that we get this culture to change,” he said. He added that his staff has heard from other whistleblowers as well. “They feel that when they step forward to report safety, security or other problems, they are systematically retaliated against.”

More: Government Executive

Indian Point Spike in Tritium Worries NRC

Nuclear Regulatory Commission and Indian Point officials are searching for the source of a spike in tritium found in monitoring wells near the nuclear plant. The spike was found near Indian Point Unit 2 in March. Subsequent testing last month found that the levels had decreased 92%, but officials are still concerned.

NRC officials said the contamination exceeds Environmental Protection Agency standards but is not a public health concern because it was located in bedrock and not in water used for drinking. “The levels that we’re talking about here are very much on the low side,” NRC spokesman Neil Sheehan said. Tritium, a byproduct of nuclear power production, is a radioactive form of hydrogen.

An Associated Press review of NRC records in 2011 found 48 of 65 reactor sites had tritium leaks.

More: The Journal News

Federal Scientists Eyeing Oyster Creek in Study

The National Academy of Sciences is studying rates of cancer and other illnesses in the communities surrounding Exelon’s Oyster Creek nuclear plant and six other nuclear generators. The academy is conducting the study at the request of the Nuclear Regulatory Commission to see if a broader analysis of all plants is needed.

Earlier studies failed to find a link between commercial nuclear plants and higher cancer rates, but some think that study was flawed because it only examined cancer deaths among men and didn’t include women and children.

More: Asbury Park Press

Feds Award Offshore Lease for Tidal Energy

Florida Atlantic University lease area (Source: Bureau of Ocean Energy Management)

The federal Bureau of Ocean Energy Management last week awarded a lease to Florida Atlantic University to test hydrokinetic energy equipment off the coast of Fort Lauderdale, the first time a lease has been awarded for such technology. The university’s Southeast National Marine Renewable Energy Center applied for the lease to test various demonstration devices in an area about 10 miles offshore.

The project involves anchoring several “test berths” to test ocean current turbine designs. The university will next submit a project plan for review. “This project is a potentially paradigm-shifting development in the global quest for clean energy,” FAU President John Kelley said.

More: Bureau of Ocean Energy Management

June 10, 2014

Members Seek Smarter Way to Measure Load Reduction

The Demand Response Subcommittee will seek ways to improve measurement and verification of emergency demand response under an issue charge approved last week by the Market Implementation Committee.

Existing procedures, which use the hour before an event as the default customer baseline (CBL), may be inaccurate for dispatches in the early morning and on days with multiple dispatches, PJM says. PJM’s Pete Langbein said the current process can also require a cumbersome administrative process requiring an electric distribution company review.

PJM estimates the work will take six months if only manual changes are needed and nine months if Tariff changes are required. The goal is to have all changes in place prior to start of the 2015/16 delivery year.

June 10, 2014

Contestants Make Last Pitch for Artificial Island Prize

Sea turtles, sturgeon, wetlands and shipping accidents — transmission developers seeking the contract to fix the Artificial Island stability problem invoked all of them and more last week in arguments against their competitors.

All five of the development teams identified as finalists filed comments with PJM, the last chance for contestants to make their case before PJM planners announce their selection next Monday.

State regulators also weighed in, as did PSEG Nuclear LLC, the operator of the Salem and Hope Creek nuclear plants at Artificial Island.

North or South

Each of the finalists has proposed a 500-kV line paralleling an existing 500-kV line to Red Lion, Del., including Delmarva Power’s Delaware River crossing north of Artificial Island.

Supporters say using an existing path could result in less public opposition than a new southern overhead crossing envisioned in 230-kV proposals by LS Power and Dominion. The two companies and Transource Energy, a joint venture of American Electric Power and Great Plains Energy, have also proposed southern routes with submarine crossings.

Environmental Concerns

Wetlands in New Jersey would be impacted by the northern 500-kV route. (Source: PSEG)

But the New Jersey Board of Public Utilities said the developers of the 500-kV proposals might have difficulty winning regulatory approvals because the path would cross the Supawna Meadows National Wildlife Refuge, the Alloway Creek Watershed Wetland Restoration Site and the Abbotts Meadow and Mad Horse Creek Wildlife Management Areas.

The BPU noted that the Susquehanna to Roseland 500-kV transmission line was delayed for three years because of problems obtaining approvals to cross federal lands even though it had been designated for “rapid response” by the Interior Department. The project “resulted in protests, delays and costs well above initial estimates for mitigation,” BPU said.

“PJM’s analysis of the five projects in the Red Lion 500-kV option group recognizes negative impacts for all as to wetlands and land permitting but only `some impacts’ as to public opposition,” the BPU continued. “In our experience, that is an optimistic view of the likely public response to these projects.”

LS Power agreed, citing an opinion from its outside counsel concluding that permitting of the northern route “is likely not obtainable,” due in part to the existence of the southern crossing options.

Transource argued that its submarine crossing proposal was preferable to an overhead line, noting the potential for shipping accidents, such as a 1987 crash that resulted in a nine-month outage to the Delmarva Power crossing. Transource also said an overhead crossing would require towers about 100 feet tall, which could increase the likelihood of public opposition.

PSE&G, which proposed a northern route, countered that the submarine crossing proposed for the southern route could impact a submerged dike “normally considered historic in nature,” an artificial reef created from sunken World War I ships (Sunken Ship Cove) or habitats for protected species, “including the shortnose sturgeon, the Atlantic sturgeon, the hawksbill sea turtle, the loggerhead sea turtle, Kemp’s ridley sea turtle and the leatherback sea turtle.”

Order 1000 Implications

Even before making a selection decision that is certain to disappoint all but one of the finalists, PJM is already receiving criticism for how it has managed the competition — the first in PJM under the Federal Energy Regulatory Commission’s Order 1000.

The Delaware Public Service Commission complained that the proposed cost allocation for the 230-kV solutions “displayed neither logic nor fairness” in assigning all of the cost to the Delmarva Power zone. In contrast, the cost of the 500-kV proposals would be spread among two dozen transmission zones and merchants. (See Delaware Unhappy with Artificial Island Cost Allocation.)

The commission requested PJM planners provide details on the distribution factor (DFAX) analyses for the 230-kV and 500-kV solutions and “explain how a transmission project to alleviate an operational issue in one transmission zone could be solely the cost responsibility of a different transmission zone.”

The Exelon-Pepco team criticized PJM planners’ modifications to developers’ plans, which included the addition of static VAR compensators (SVCs) to all projects and the removal from the Dominion and PSEG proposals of a second Hope Creek-to-Salem tie line. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.) “The tweaking of proposals eliminates the competitive nature intended by the FERC Order 1000 process,” said Exelon-Pepco.

Transource said PJM should make its decision based on the merits of the projects as proposed rather than comparing them after PJM’s modifications.

“This will send a strong signal to developers that the relative quality of their work will be rewarded in the PJM process and that the burden is on the developers, not PJM, to get the details right,” Transource said. “It would set a concerning precedent if PJM decided that none of the proponents `sponsored the selected project,’ based on the modifications made by PJM, and designated the project to the incumbent transmission owner(s).”

Nuclear Operator’s Concerns

PSEG Nuclear also criticized PJM planners’ decision to use SVCs, saying they have never been used to correct “transient angular stability” and would pose “unknown and potentially challenging regulatory risks.”

The company noted that Artificial Island is the “second-largest nuclear installation in the country with well-known stability challenges.”

“The worst case consequences that will result from a contingency-induced stability event coincident with an SVC failure include loss of all offsite power to the three co-located nuclear units at AI as well as potential collateral impacts to the offsite sources at neighboring regional nuclear plants,” the company said. “These consequences will influence the [Nuclear Regulatory Commission] to require an in-depth review.”