State Briefs

State, Railroads Mum on Bakken Crude Shipments

State officials know when large shipments of potentially explosive Bakken crude are shipped by rail to a refinery in the state but won’t release that information to the public because of security concerns, The News Journal reported.

CSX Corp. and Norfolk Southern Corp. have begun reporting oil train shipments in compliance with an emergency order issued in May by the U.S. Department of Transportation. Delaware safety officials, however, signed confidentiality agreements to share the information only with state and local emergency management agencies. Other states, including Oklahoma and Pennsylvania, also keep quiet about crude oil shipping details.

At an investor meeting in the spring, a PBF Energy official said its Delaware City refinery receives about 102,400 barrels of crude via rail shipments daily. A Sierra Club of Delaware member has resorted to compiling a map of oil shipments in Delaware based on reports she receives from volunteer observers in order to inform the public. Last July, 47 people were killed and much of a small town in Quebec was destroyed when a train carrying crude derailed.

More: The News Journal

Newark Councilman Faults UD on Data Center Plan

A Newark city councilman said the University of Delaware could have saved everybody a lot of time and trouble had it vetted a data center and power plant plan better earlier in the process. Noting that the 279-MW power plant that was part of the data center plan was what ultimately doomed the project, Councilman Stu Markham said the university could have reached the “no” point long before the city and other groups invested so much time in investigating the plan.

A university official said the plan looked like a good fit at first, but it later became apparent that the data center, with the large power plant, didn’t fit in with the university’s plans. The site is still open for development, but any power plant built there will be smaller, university officials have said.

More: Delaware Online

DISTRICT OF COLUMBIA

PSC Member, Chairman Confirmed in Recent Session

The city council last week confirmed new Public Service Commission member Willie L. Phillips and reconfirmed Betty Ann Kane as chairman. The confirmations mean that for the first time since December, all three commission seats are filled.

Kane was first named to the commission in 2007 and became chairman in 2009.

Phillips, an attorney, comes to the commission with a background in utility regulation and compliance enforcement. He was previously assistant general counsel for the North American Electric Reliability Corp.

More: D.C. Public Service Commission

ILLINOIS

Alternative Suppliers Provide Savings 3 Years Running

The state Commerce Commission’s Office of Retail Market Development issued its annual report, saying that retail electric competition continues to provide savings for residential customers. The report said ComEd residential customers saved an estimated $39 million between June 2013 and May 2014. Residential switching continued in the last year, but at a slower rate than the previous two years, according to the report.

More: Illinois Commerce Commission

INDIANA

IURC Nominating Committee Gets 8 Names to Consider

The nominating committee of the state Utility Regulatory Commission has identified eight candidates to replace Commissioner James Atterholt and will interview them July 30. Nominated were: James L. Adams, Marline R. Breece, Karen E. Caswelch, Carole Sparks Drake, Eric M. Hand, Robert L. Hartley, James F. Huston and David R. Johnston. Atterholt’s seat opened up when Gov. Mike Pence tapped him as his chief of staff. Pence will be presented with three finalists following the interview.

More: Indiana Utility Regulatory Commission

KENTUCKY

Group Sues to Halt 2 Coal Plant Closings

A group of landowners and a coal industry group sued in federal court to block plans by the Tennessee Valley Authority to shutter a coal-fired generating plant. The TVA announced last year that it was going to close the two-unit Paradise Fossil Plant in Muhlenberg County and replace it with a new gas-fired generator.

This month, the Kentucky Coal Association filed suit in U.S. District Court in Owensboro arguing that the TVA didn’t follow federal rules in closing the plants. A group of landowners joined the suit, protesting the planned installation of a 24-inch natural gas pipeline to the proposed new generator. The TVA has said that it followed proper procedures, and the decision to convert to natural gas was designed to meet emissions guidelines.

More: Associated Press

MARYLAND

Somerset Wind Law Sent Back for Review

The Somerset County Commission asked county planners to review a draft ordinance aimed at regulating commercial wind farm development in anticipation of a vote by the commissioners this fall.

The draft was developed in 2012 but never voted on. Now, some landowners and others are taking a second look at it and suggesting revisions, including larger setbacks between proposed facilities and homes, schools and roads. Pioneer Green, a company with a proposal in the pipeline to develop a 50-turbine plant in the county, is urging the county to finalize the ordinance.

More: Delmarva Now

MICHIGAN

Chesapeake Energy to Go to Trial, Judge Says

A state judge ruled last week that the bid-rigging case against Chesapeake Energy will go to trial. Judge Maria Barton of Cheboygan County District Court ruled that there was enough evidence of alleged bid rigging between Chesapeake Energy and Encana Corp. at a 2010 land-lease auction. Barton cited emails between an Encana executive and a man bidding on the company’s behalf that said, in part, “This is a Chesapeake area and we will not be bidding.” Encana settled anti-trust charges against it with a $5 million civil payment to the state in May.

More: PennEnergy

NEW JERSEY

Planned Nuclear Co. Gets $260 Million in Tax Breaks

A company with plans to build nuclear reactors and related equipment at a future plant on the Camden Waterfront was given $260 million in tax credits and other economic subsidies in what is being described as the third-largest subsidy in state history. The state Economic Development Authority awarded the incentives to Holtec International based on its promises to create 235 new jobs and relocate 160 other jobs from other parts of the state.

Once the operation is set up it will get $26 million a year for 10 years. Holtec was also eyeing Charleston, S.C., as a location. It plans a 600,000-square-foot plant to build the reactors.

The award to Holtec, whose board includes Democratic powerbroker George Norcross, was decried by numerous lawmakers, with one calling it “crony capitalism.”

More: NJ.Com

OHIO

Chilicothe Prison Cells to be Warmed with Solar Heating

A $1.7 million solar-power system will heat cells and hot water in a state prison in southern Ohio, saving taxpayers about $245,000 a year. The system uses 400 panels installed on the roof of Ross Correctional Institution. Solar energy is used to heat an antifreeze-like liquid, which is then used to heat eight cell blocks at the prison, according to the Department of Rehabilitation and Correction. The system also produces hot water for prisoners. Ross was opened in 1987 and holds about 2,100 inmates.

More: Columbus Dispatch

PENNSYLVANIA

Court Upholds Towns’ Rights to Regulate Drilling

A state appellate court last week upheld a ruling that gave towns the right to regulate some oil and gas development. The court threw out an argument that the state Public Utility Commission has the authority to overrule local governmental action in regulating where well sites and other facilities can be located.

With its ruling, the court upheld an earlier decision by the state Supreme Court. That decision was challenged by state regulators who saw it as a challenge to their authority. “Local zoning matters will now be determined by the procedures set forth under the [Municipalities Planning Code] and challenges to local ordinances that carry out a municipality’s constitutional environmental obligations,” President Judge Dan Pellegrini wrote in the opinion.

More: Pittsburgh Post-Gazette

WEST VIRGINIA

Delegate Appeals for Fed Help Against AEP Rate-Hike Plan

State Delegate Clif Moore thinks Appalachian Power’s recent request to raise rates 17% is too much, and he is reaching out to federal officials for relief. “Please be advised this correspondence respectfully transmits my utter disdain, shock and amazement with American Electric Power in their quest to seek a 17% increase in already unaffordable electric costs,” Moore wrote. “It is, in my humble opinion, imperative for state and federal regulators to verify that current rates are within legal limits.” He has called on the Federal Trade Commission to intervene. Appalachian, an AEP subsidiary, filed the base rate request with the Public Service Commission, seeking a $226 million increase to go into effect in April 2015.

More: Energy Central

July 22, 2014

FERC: We’ll Have Last Say on Sabotage Rules

The Federal Energy Regulatory Commission tentatively approved a rule to protect the grid against physical threats last week after ordering changes to allow the commission to overrule transmission operators’ definition of “critical” facilities.

The Notice of Proposed Rulemaking (RM14-15) said the North American Electric Reliability Corp.’s draft “largely satisfies” the commission’s March 7 order, which called for developing the standard in an unusually short three months. The order, which was issued under pressure from members of Congress alarmed by the 2013 sabotage of a Pacific Gas and Electric substation.

It will require transmission owners and operators to provide protection for “critical” substations, but it allows each utility to determine what substations are critical.

Veto Rights

The commission ordered NERC to change the rules to allow “applicable governmental authorities” — including FERC, other federal agencies and Canadian provinces — to add or subtract facilities from an entity’s list of critical facilities. “It’s not something we expect to happen frequently but it’s authority that we thought we should have,” acting FERC Chair Cheryl LaFleur said Thursday.

Transmission operators will be required to have their critical facility lists reviewed by third parties; TOs that reject third-party recommendations would be noncompliant unless they provide a “written, technically justifiable” reason for doing so.

The commission also ordered NERC to eliminate references to “widespread” instability, saying the phrase “could, depending on the meaning of `widespread,’ narrow the scope [and number] of identified critical facilities under the proposed Reliability Standard beyond what was contemplated in the March 7 Order.”

It ordered NERC to submit an informational filing after one year evaluating resiliency measures for recovering from a loss of critical facilities.

The commission accepted NERC’s justification for excluding generator owners and operators from the rule, agreeing that a generation facility “does not have the same critical functionality as certain transmission stations and transmission substations due to the limited size of generating plants, the availability of other generation capacity connected to the grid and planned resilience of the transmission system to react to the loss of a generation facility.”

However, it required NERC to do a second informational filing to address whether “high impact” control centers for generators and other non-transmission entities should be covered by the rule.

Reliability Standard CIP-006-5 (Cyber Security—Physical Security of BES Cyber Systems) already requires primary and backup control centers of reliability coordinators, balancing authorities and generator operators to implement some physical security protections, including restrictions on physical access. But the commission said the existing rule “may not be sufficient to `deter, detect, delay, assess, communicate and respond to potential threats and vulnerabilities’” and does not require an unaffiliated third-party review as in the proposed standard.

Rejecting Sabotage Rule Not an Option

NERC stakeholders approved the draft rule in April despite criticism by some that the standard was rushed and poorly defined. (See Grid Security Rules Win NERC Stakeholder OK Despite Criticism.)

Commissioner Tony Clark acknowledged the criticism Thursday but said the standard was “a very solid first step” and that rejecting it was not an option.

“Some have noted that the proposed standard would not provide enough visibility across the interconnection given that the identification of facilities would be done as a `bottom-up’ exercise. I believe there is a grain of truth in those concerns,” he said in a statement issued after the commission meeting.

“I encourage all stakeholders to view this as an iterative process that will continue to be improved. I view our proposed modifications and informational filings as avenues for further discussion and development to ensure that total grid awareness is considered when selecting assets to be further protected by enhanced physical security.”

Comments on the standard will be due 45 days after publication in the Federal Register, with reply comments due 15 days after that.

“I just would plead with folks to be rational,” said Commissioner John Norris, who had expressed concern that the expedited deadline and the commission’s ex-parte rules would inhibit the development of intelligent rules. (See FERC Orders Rules on Grid’s Physical Security.) “We can’t barricade our way out of this.”

Other Standards OK’d

The commission also gave preliminary approval to the Protection System Maintenance Reliability Standard (RM14-8), which requires applicable entities to include certain autoreclosing relays as part of their protection system maintenance programs.

The NOPR requires NERC to submit a report in two years based on actual performance data and simulated system conditions from planning assessments to recommend whether the standard is covering all relays necessary to ensure reliability. It also requires NERC to amend the standard to include maintenance and testing of supervisory devices associated with applicable relays.

FERC also gave final approval to the Generator Relay Loadability reliability standard and revisions to the Transmission Relay Loadability standards (RM13-19-000 and RM14-3-000). The commission said the generator relay standard will reduce the likelihood of premature or unnecessary tripping of generators during system disturbances. The commission ordered revisions to the current standard governing transmission relay loadability to prevent “compliance overlap” by eliminating potential inconsistencies between the two standards.

July 22, 2014

Federal Briefs

The American Bird Conservancy is suing the Department of the Interior over an agency regulation that allows wind energy companies to obtain 30-year permits to kill eagles. The group told Interior and the Fish and Wildlife Service that it was going to sue based on what it saw as violations of the National Environmental Policy Act and the Bald and Golden Eagle Protection Act, among other laws.

The current rule replaced an earlier regulation allowing energy companies to kill eagles for five years.

“Eagles are among our nation’s most iconic and cherished birds. They do not have to be sacrificed for the next 30 years for the sake of unconstrained wind energy,” said Michael Hutchins, a conservancy spokesman. “Giving wind companies a 30-year pass to kill bald and golden eagles without knowing how it might affect their populations is a reckless and irresponsible gamble that millions of Americans are unwilling to take.”

More: Wisconsin Gazette

Feds Open 344K Acres Off Jersey to Wind Power

The Department of the Interior and the Bureau of Ocean Energy Management last week announced that more than 344,000 acres of sea floor will be open to commercial wind power. Federal authorities propose to auction off the lots, about seven miles off Atlantic City, in two designated areas. A 60-day public comment period will end Sept. 19, after which the lease sale date will be set. The Bureau of Ocean Energy Management estimates that the two areas could support up to 3.4 GW of wind energy.

More:North American Wind Power

East Coast Area Open To Seismic Testing

Federal regulators approved seismic testing in areas up to 400 miles offshore between Delaware and Florida, in a move hailed by oil and gas exploration proponents. The Department of the Interior announced the move, saying that it was time to update the 40-year-old seismic information on offshore oil and gas reserves. It said steps would be taken to protect marine life during the testing. Estimates based on earlier seismic studies point to 1.9 billion barrels of oil and 21.4 trillion cubic feet of natural gas in the Mid-Atlantic to South Atlantic coasts. Environmentalists are still concerned that seismic testing will disturb or kill marine life.

More: The Baltimore Sun

Louisiana LNG Plant Site Gets Next FERC OK

The Federal Energy Regulatory Commission has cleared the way for Sempra Energy to begin preliminary site clearance work for its proposed LNG facility near Lake Charles, La. The authorization allows preliminary work and equipment storage on the site. Sempra said construction on the $10 billion project is set for this fall. When completed, it will allow for the export of up to 12 million metric tons of LNG per year.

More: The Advocate

U.S. Electric Grid Fails More than Most Others

U.S. electric consumers experience more power interruptions than those in any other developed nation, according to a study by a University of Minnesota professor. Massoud Amin, director of the Technological Leadership Institute at the university, said data from the Department of Energy and the North American Electric Reliability Corp. show that the U.S. grid now loses power 285% more often than it did in 1984.

The interruptions cost businesses approximately $150 billion a year, he said. He said customers in Japan lose power for an average of four minutes per year while those in the American upper Midwest go dark for an average of 92 minutes. The analysis excluded interruptions caused by severe storms or fires.

More: International Business Times

New Energy Dev. Could Eat Up Area of Two Maines

Researchers for the environmental group North America Congress for Conservation Biology estimate that at its current rate, energy development in the U.S. could consume an area twice the size of the state of Maine by 2040.

They said new mines, oil and gas wells and solar and wind farms could consume 175,000 to 250,000 square kilometers, complicating efforts to preserve wildlife habitat. “There is going to be a very large challenge in siting all of this energy infrastructure,” said landscape ecologist Anne Trainor of Yale University.

More: Science Magazine

Energy Growth: 351 GW by 2040

The Department of Energy estimates that 351 GW of new generation will be constructed in the U.S. by 2040. That’s equivalent to 100 plants the size of NRG’s W.A. Parish plant near Houston. But while plants are still being built, the rate is slowing. DOE estimates that 16 GW of generation will be added per year through 2016, slowing to 9 GW per year through 2022, then rising again to 14 GW annually through 2040. Future plants will be 73% natural gas, 24% renewable and 3% nuclear, DOE projects.

More: Houston Chronicle

McCarthy: New Rules are Guides to Energy Investing

Environmental Protection Agency Administrator Gina McCarthy told a group of state regulators that they should see the EPA’s recently announced emissions rules as a guide to energy investment, rather than a set of pollution control rules. “We really wanted this to be an opportunity to look at a short- and long-term investment strategy, not a pollution control strategy,” she told a meeting of the National Associate of Regulatory Utility Commissioners in Dallas. Emissions “can be reduced in the electricity sector in ways that are very far from pollution-control technologies.”

More: E&E Publishing

July 15, 2014

Senate Confirms Bay, LaFleur

WASHINGTON — The Senate today narrowly confirmed Norman Bay to the Federal Energy Regulatory Commission while easily approving a new term for Acting Chair Cheryl LaFleur.

Bay cleared on a 52-45 party-line vote following a deal with the White House that will delay his ascension to the FERC chairmanship for nine months after he joins the panel.

The deal was a concession to those who questioned why Bay — who has served as director of FERC’s Office of Enforcement since 2009 but has never served as a state utility regulator — would be appointed directly to the chairmanship over LaFleur, a former utility executive who has served on the commission since 2010.

The compromise wasn’t enough to win the support of Republicans. Sen. Lisa Murkowski (R-Alaska), ranking member on the Senate Energy and Natural Resources Committee, questioned whether Bay would undermine LaFleur as a “shadow chairman.”

Senator Mary Landrieu — Sen. Mary Landrieu

“FERC is too important a commission … for appointees to be handled like this,” she said.

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.

Senate Minority Leader Mitch McConnell (R-Ky.) said Bay would be a “rubber stamp for the administration’s anti-coal agenda.”

Energy Committee Chair Mary Landrieu (D-La.) cited former committee chair Pete Domenici’s (R-N.M.) support for Bay, saying it was “very influential” in her own decision to support Bay.

LaFleur had sailed through her confirmation hearing May 20 while Bay was forced to defend his limited policy experience. (See LaFleur Cruises, Bay Bruises in Confirmation Hearing.)

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.

Bay also came under fire for what some energy lawyers and legislators called his heavy-handed running of the commission’s enforcement division.

LaFleur was confirmed today by a 90-7 vote, a bittersweet victory with the knowledge that she will be a lame duck as chair.

“I want to thank President Obama and the Senate for giving me the opportunity to serve another term,” she said in a statement immediately after the vote. “I look forward to continuing to work with my colleagues to maintain a reliable and secure grid and help ensure our energy markets and infrastructure adapt to the nation’s changing resource mix.”

July 15, 2014

Members OK Change Sought by Banks

Members last week gave initial approval to a manual change that will make it easier for banks to purchase capacity providers’ revenue streams. The Market Implementation Committee approved a change proposed by Citigroup Energy to allow auction-specific transactions to be entered into PJM’s eRPM system after the auction that initiated them.

Under current rules, such transactions cannot be submitted to PJM until after the third incremental auction for a delivery year. The MIC approved changes to Manual 18 by acclamation, sending the issue on to the Markets and Reliability Committee for final approval. (See Stakeholders Look to Expedite Auction-Specific Transactions.)

July 15, 2014

SCC: Dominion IRP Lacks Analysis of Nuclear Plans

Despite closing its Wisconsin nuclear plant prematurely last year, Dominion Resources wants to keep its options open in Virginia, where it is considering a third unit at its North Anna nuclear plant.

But it hasn’t done any analysis to compare the risks of a new plant against an increasing reliance on natural gas-fired generation, Virginia State Corporation Commission staff said in a filing last week.

Responding to Dominion Virginia Power’s 2013 Integrated Resource Plan, staff said such an analysis should be included in the company’s next IRP in 2015 in order to determine which option the company should follow in the future.

Dominion “believes that uncertainty associated with the price of natural gas over the long term is a greater risk than the development cost uncertainty of a nuclear unit. However, the company concedes that no analysis has been performed to support this assertion,” SCC staff said. Staff said Dominion has indicated a willingness to conduct the analysis.

Two Plans

In its 2013 IRP, Dominion presented two different plans, one it called the “Base Plan” that calls for the expansion of generating capacity through new natural gas-fired plants, and one it calls the “Fuel Diversity Plan,” which includes low-emission options and does not rely so heavily on natural gas.

Both plans are very similar in the short run, with the major difference being that the latter plan includes the construction of North Anna 3. The company has chosen to follow the Base Plan, the least cost option, but it will also continue to go “forward with reasonable development efforts of additional resources included in the Fuel Diversity Plan,” which “would preserve the company’s ability to implement these alternatives should future conditions warrant,” SCC staff noted.

While natural gas plant projects have low development cost risk, the historically volatile fluctuating fuel price creates the risk of high operating costs. Nuclear plants generally have low operating costs, but their construction is very complicated and prone to cost overruns.

“In other words, there is a risk trade-off of higher operating cost risks with the Base Plan and higher project development cost risks with the Fuel Diversity Plan,” SCC staff said. “Staff was unable to determine whether the Base Plan contains too much operating cost risk, or whether the development cost risk associated with the Fuel Diversity Plan is greater than or less than the reduction in operating cost risk the Fuel Diversity Plan would achieve, because the company did not perform an analysis of this risk trade-off in its IRP.”

Dominion, which applied for Nuclear Regulatory Commission approval of North Anna 3 in 2003, has not committed to building the unit. In its IRP, the company said it would make its final decision once it received a Combined Operating License from the NRC. The unit would be completed no earlier than 2024.

Risky Business

The recent boom in natural gas production, resulting in cheap prices, has not been kind to the nuclear industry. Dominion learned this the hard way last year, when the company was forced to close the 556-MW Kewaunee Power Station, which it had purchased in 2005 for $192 million. After utilities did not renew their power contracts with the Wisconsin plant and Dominion failed to buy other nuclear plants in the region, the company attempted to sell Kewaunee in 2011. When it became apparent there were no buyers, Dominion closed it.

Kewaunee, which opened in 1974, closed a year shy of its 40th birthday, when its license would have needed renewal. Staff at the plant are now beginning the long process of decommissioning it.

With North Anna 3, Dominion seeks to keep all of its options on the table. Mark Kanz, local affairs manager for Kewaunee, recently told Nuclear Power International magazine that the prospect of North Anna 3 “proves that the company sees the benefit of nuclear and is looking forward to continuing that into the future.”

SCC staff also wants the company to compare the costs of building a third unit with the costs of extending the operating licenses of the first two, along with the licenses of the two units at its Surry nuclear plant.

“Given that these units still provide extremely efficient and dependable baseload generation for the company, and given the extremely high costs of constructing new nuclear plants, staff believes that the company should engage in serious discussions with discussions with the NRC to determine whether renewing these licenses is possible.”

The staff noted that it is unknown whether the NRC would grant renewals to the current units. The units would be 60-years-old when their licenses — already extended by 20 years — expired. The NRC expects the first application for an extension beyond 60 years to be filed in 2018 or 2019. Without additional license extensions, the country would face a wave of nuclear plant retirements during the next decade.

July 15, 2014

Losing Bidders Blast Artificial Island Choice

Two losing bidders for the Artificial Island transmission project have issued harsh critiques of PJM’s handling of the solicitation, seeking to persuade the Board of Managers to reject planners’ recommendation that the project be awarded to Public Service Electric & Gas.

In letters to the board, Northeast Transmission Development, a unit of LS Power, and Atlantic Grid Development, whose backers include Google, allege the competition was tainted by favoritism and that the PSE&G project will have difficulty winning siting approval. The challengers also contend the technical design of the winning project is inferior to their own proposals.

Atlantic Grid’s proposal failed to make PJM’s list of finalists. LS Power’s project was the low-cost proposal among the 10 finalists until PJM planners revamped the PSE&G proposal and deemed it equal in cost to LS Power’s at $211 million to $257 million. The changes reduced PSE&G’s price tag by $832 million, a 78% reduction. The estimates do not include an additional $80 million for a static VAR compensator, which PJM added to all of the proposals. (See PSE&G Wins $300M Artificial Island Project.)

In his letter, Northeast Transmission President Paul Thessen said PJM’s cost estimate for his company’s project is too high. He said the company estimates its project at $149 million and will cap its recovery at $171 million, a savings of at least $40 million to $90 million over the PSE&G project.

The board is scheduled to consider the staff recommendation at a meeting July 22.

“After careful evaluation, PJM’s staff concluded that ours was the best proposal. We believe that is the correct choice,” PSE&G spokesman Mike Jennings said in a statement. “We have successfully completed transmission projects in environmentally sensitive areas and performed that work on time and on budget. We are committed to doing the same with this project.”

PJM spokesman Ray Dotter declined to comment on the critiques. “We can say in general that our approach, which was made clear all through the development of our Order 1000 filing and reiterated throughout the Artificial Island evaluation process, is that we would look for the most cost-effective transmission solution,” he said.

Unwarranted Preference

Atlantic Grid said PJM planners gave PSE&G an “unwarranted preference” based on its participation in the Lower Delaware Valley Transmission System Agreement (LDV), a 1977 compact that controls right of way along the recommended project path between the Hope Creek nuclear plant and Red Lion, Del. Other signatories are JCP&L, Delmarva Power & Light, Atlantic City Electric and PECO.

Crediting PSE&G for the LDV right of way ignores the fact that about half the route is over federal and state land, where it may be difficult to obtain siting approval, Atlantic Grid said. In addition, the LDV right of way, the route of an existing 500-kV circuit, will need to be widened by as much as 200 feet in some locations.

Atlantic Grid said the PSE&G project “has a high likelihood of being rejected” by state or federal permitting agencies because it crosses wildlife protection areas and about 59 water bodies and may adversely impact endangered or threatened species. As a result, the ultimate fix “will be substantially delayed because PJM has proceeded down a dead end,” wrote Atlantic Grid President Robert L. Mitchell.

The New Jersey Board of Public Utilities (NJBPU) submitted comments raising the same concerns before planners announced their recommendation last month.

Atlantic Grid said PJM and its engineering consultant, GAI Consultants Inc., failed to seek a pre-application review from the New Jersey Department of Environmental Protection, which could have provided an indication of the project’s chances of winning required permits. “If GAI had followed this process its report might well have raised stronger cautions,” Atlantic Grid said.

Reliability of Design

Atlantic Grid also said the planners’ choice does not provide black start support for Artificial Island and ignores Nuclear Regulatory Commission regulations requiring nuclear plant switchyards be served by two physically independent circuits to minimize the likelihood of simultaneous failure. The PSE&G project would add a 500-kV line paralleling LDV’s existing 500-kV circuit.

Home to the Hope Creek and Salem nuclear plants, New Jersey’s Artificial Island is one of the largest nuclear complexes in the country.

26 Proposals

PJM asked for solutions to a stability problem at the complex last year. Five utilities and three independent developers responded with 26 potential solutions ranging from $100 million to $1.5 billion.

Atlantic Grid’s proposal, which would have buried an HVDC transmission circuit in public road rights of way between Artificial Island and Cardiff, N.J., appears to have been rejected early in the process. PJM cited its $1.01 billion cost and said it failed stability performance tests.

PSE&G, whose sister company PSEG Nuclear LLC operates the Salem and Hope Creek nuclear plants, submitted 14 alternative solutions, more than any other competitor.

One PSE&G proposal, 7K, envisioned a new New Freedom-Deans 500-kV line and a new Salem-Hope Creek-Red Lion 500-kV line at a cost of $1.066 billion.

The 7K project PJM planners recommended last month included several major changes that PJM says reduced the price by more than three-quarters.

Atlantic Grid criticized planners for modifying proposals that initially failed the technical review to allow them to qualify. “Some proposals were modified more than others, and others were not modified at all, raising significant questions about why PJM discriminated in this manner and the fairness of the process,” Atlantic Grid said.

“It appears that PJM took the proposals and then re-engineered a solution it liked best by mixing and matching pieces from different project proposals. The result is that PJM’s recommended 7K Project looks almost nothing like the original 7K proposal submitted by PSE&G.”

PJM Review

PJM planners began reviewing the proposals in July. In October, planners told the Transmission Expansion Advisory Committee they had narrowed their focus to the lowest-cost projects, which proposed interconnecting with facilities in Delaware. They also said they intended to add static VAR compensators to all proposals to provide reactive support.

By February, the focus had narrowed to proposals using two routes to connect to Delaware: a northern path that would add a 17-mile 500-kV line that parallels the existing 500-kV line from Red Lion to Hope Creek, and a southern crossing using a 230-kV circuit. The northern crossings included PSE&G’s 7K proposal; among the southern crossings was LS Power’s proposal, 5A.

By the March TEAC meeting, PJM planners apparently had decided to eliminate the New Freedom-Deans 500-kV line from the PSE&G proposal, showing its cost as proposed reduced to $297 million.

At a special TEAC meeting in May, planners said they also had eliminated a second tie line between the two nuclear plants from proposals by PSE&G and Dominion Virginia Power.

That reduced the estimated cost of the PSE&G proposal by about $43 million, giving it the same range ($211 million to $257 million) planners had assigned to the LS Power proposal, which had previously had been listed as the lowest cost option.

The elimination of the tie line also improved the performance of the PSE&G proposal in the planners’ rankings of the proposals.

PJM presented a chart summarizing its analyses of the proposals, assigning color codes for each of 25 attributes: green (positive or limited impact); yellow (some impact) and salmon (negative impact). RTO Insider summarized the findings by assigning a score of 1 to green, zero to yellow and -1 to salmon.

PSE&G’s 7K proposal scored a 1 out of a possible 25 in its original form but received a 9 when the second tie line was removed — the best of all 12 proposals analyzed. LS Power’s proposal scored a 7, ranking it third. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.)

LS Power contends PJM planners underestimated the cost of the PSE&G proposal. The company said GAI Consultants estimated the cost of the 500-kV line at $5 million/mile while staff estimated only $3.6 million/mile. The consultants included an adder of $1 million/mile to account for construction in wetlands, which LS Power said PJM staff apparently did not consider.

LS Power also complains that PJM gave its proposal no credit for factors favoring its proposal, including rightofway, route diversity, black start, market efficiency, feasibility and system outage requirements.

Order 1000 Precedent

While LS Power wants PJM to accept its cost-capped proposal, Atlantic Grid asked the board to delay a decision until it evaluates the likelihood of the proposals to receive necessary siting approvals.

The challengers said the selection of PSE&G would set a bad precedent for future solicitations under the Federal Energy Regulatory Commission’s Order 1000, which was intended to open transmission development to competition.

“Unfortunately, if this RFP sets the pattern for the future, PJM will discourage participants from spending time, money and engineering resources to develop innovative, well-engineered RFP responses,” Atlantic Grid said.

July 15, 2014

MIC OKs Initiative on Gas Unit Offers

Members approved yet another initiative to address reliability concerns over gas-fired generators, agreeing to consider changes to the way such units submit energy and capacity market offers.

Under a problem statement approved by the Market Implementation Committee Wednesday, members will consider ways to reduce the confusion that occurred on the coldest days of last winter, when some gas-fired generators were unable to obtain fuel, some claimed costs above the $1,000/MWh offer cap and others ended up with “stranded” gas after PJM cancelled plans to dispatch them. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)

The effort will attempt to design rules that allow generators to submit offers that better reflect often volatile natural gas prices. Among potential changes: allowing generators to change their energy market offers during the operating day and submit differing hourly offers in the real-time market, as the New York ISO allows.

Carl Johnson, representing the PJM Public Power Coalition, expressed concern that stakeholders’ multiple gas-electric coordination initiatives could result in changes whose interactions are not well understood. “We have, at my count, six problem statements … on gas issues,” he said. “I’m concerned as we march forward … how these timelines will work together.”

Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), also expressed concern. “The expectation for compromise gets less and less as you get more and more complex,” he said.

John Horstmann of Dayton Power & Light Co. suggested the issue could be handled by one of the groups already dealing with gas-electric issues. PJM staff agreed to review work assignments and make a recommendation at next month’s MIC meeting, when stakeholders will consider a proposed Issue Charge.

July 15, 2014

Life without Demand Response: Higher Prices but No Reliability Crisis, Says Monitor

PJM capacity prices would increase sharply but reliability would not be threatened if a recent federal court ruling eliminated demand response from wholesale markets, according to a new report by the Independent Market Monitor.

Market Monitor Joe Bowring said the sensitivity analysis released last week is intended to help stakeholders evaluate the impact of the May 23 ruling by the D.C. Circuit Court of Appeals that sharply restricts the Federal Energy Regulatory Commission’s jurisdiction over demand response compensation. (See DR’s Future Unclear Following Court Ruling.)

Revenue in the May base residual auction would have more than doubled to $16.86 billion from $7.5 billion if no DR or energy efficiency cleared, the analysis found. Cleared resources would have dropped by 3,290 MW, reducing reserves to 2% above the Installed Reserve Margin (IRM) from 4.4%. Bowring said the analysis included energy efficiency as “another form of DR,” which could be vulnerable under the court ruling.

Disruptive Ruling

On July 7, PJM joined FERC in asking the Court of Appeals to reconsider its ruling. “Extricating demand response from markets in which it has had years to integrate will be inherently disruptive and will inevitably raise countless unforeseen complications,” PJM said. While Order No. 745 was limited to economic demand response in daily energy markets, its implications are “potentially boundless.”

PJM’s petition overstates the impact of DR on reliability and understates the ability of PJM markets to respond, Bowring said in an interview Friday.

“If there’s a decision to eliminate [DR and EE] the market will adapt,” Bowring said. “Once you allow for other offers to respond to all this we would expect the prices to equilibrate — balance out — to the cost of new entry.”

Capacity prices doubled for much of the RTO in May’s base residual auction following rule changes that reduced the volume of limited DR and external generation that could clear.

Annual resources cleared at $215/MW-day for the PSEG zone, while the rest of the RTO cleared at $120/MW-day, about one-third of the $351 net cost of new entry (net CONE).

2.5% Holdback

The IMM’s study also looked at the potential impact of Bowring’s recommendation to eliminate a rule that reduces the volume of capacity resources procured in the BRA by 2.5%. Stakeholders last year rejected calls to eliminate the 2.5% holdback, which is intended to be filled by short lead-time resources procured in incremental auctions closer to the delivery year.

Had the holdback been eliminated along with DR and EE for the May BRA, capacity revenues would have more than tripled to $23.87 billion, or $396/MW-day, 13% above net CONE. The quantity of resources acquired would fall but remain sufficient to meet the IRM, the Monitor’s analysis found.

With the removal of DR and EE and the elimination of 2.5% offset “prices would have risen to greater than net CONE but less than the maximum price [1.5 times net CONE] and PJM’s reliability target would have been maintained,” the Monitor said.

The analysis assumed that all other variables are held constant, meaning that the real impact would likely be less because additional generation resources would have cleared the auction. “In the absence of demand side resources, some generating resources that retired in prior years might not have retired, and some new generation resources that did not clear in prior years would have cleared and both would have affected prices in subsequent auctions.”

The Monitor made no predictions on where prices would settle.

Concerns over Court Ruling

The D.C. Circuit ruled 2-1 that FERC’s Order 745, which requires PJM and other RTOs to pay DR full locational marginal prices (LMP), violates state ratemaking authority.

In its petition seeking a rehearing, PJM cited “the considerable uncertainty this decision has engendered” for PJM, which has used DR since 2000. Although PJM opposes Order 745’s equal-compensation mandate, General Counsel Vince Duane said the RTO sought rehearing because of concerns over the loss of DR.

PJM said the ruling appears to “forbid any compensation (regardless of the level) to economic demand response from the wholesale daily energy markets, not just the compensation change addressed by Order No. 745.”

“PJM does not have good options for replacing demand response capacity commitments on very short notice for the current summer, and replacing demand response capacity commitments for the next three summers (to the extent they even can be fully replaced) would likely be very costly,” PJM said.

The filing cited DR’s role in maintaining reliability during last September’s unexpected heat wave, when PJM was forced to shed load in some areas and during the arctic cold in January, when it “received more megawatts as load reductions than it could obtain as generation from all but the very largest generating stations.”

The RTO called for load reductions on 13 days in 2013. DR providers are committed to provide more than 8,000 MW of load reduction this summer and more than 10,000 MW for the summers of 2015-2017.

PJM said the loss of the wholesale markets might result in the elimination of many DR resources because the retail market cannot compensate DR for providing regulation, spinning reserves and day-ahead scheduled reserves, as PJM does.

In addition, it is unclear how DR procured through state-run retail processes could compete on price with generation procure in wholesale markets, PJM said. “There should be no mistake that pulling voluntary demand resource offers out of the grid operators’ single-clearing price markets will significantly reduce competition in those markets.”

This would contradict Congress’ direction in the 2005 Energy Policy Act to encourage demand response and eliminate “unnecessary barriers to demand response participation in energy, capacity, and ancillary service markets,” PJM said.

July 15, 2014

PJM: Black Start Sources Ready to Replace Retiring Coal

PJM officials said last week they have acquired sufficient new black start capacity to replace coal-fired units that will retire over the next year due to environmental rules.

PJM’s black start capacity will decline to 8,070 MW (150 units) from 8,720 MW (195 units), PJM’s Dave Schweizer told the Market Implementation Committee Wednesday.

Schweizer said PJM will have adequate supplies despite the reduction because of a redefinition of “critical load” and a rule change allowing units in one zone to provide service to others.

The redefinition — which will include units with hot start times of four hours or less — will increase the number of critical load units to 600 from 475 while reducing the total capacity to 2,910 MW from 4,780 MW.

PJM’s black start costs for 2016-17 will total more than $72 million, a 1.8% increase over 2015-16, according to an analysis by the Independent Market Monitor. Some zones, such as Dominion (+39%) and DPL (+27%), will see large increases, while others, such as Commonwealth Edison (-30%), will see sharp drops.

The RTO completed a solicitation for new black start resources because the Environmental Protection Agency’s Mercury and Air Toxics rule (MATs), which takes effect next year, will result in the shuttering of dozens of coal-fired plants.

PJM will attempt to win stakeholder approval for limited changes to the compensation rules for black start units and for a plan for selecting “backstop” resources for regions that fail to secure service through competitive solicitations.

In February, stakeholders rejected two proposals that would have boosted payments to existing black start units by at least 40%. On July 31, the Markets and Reliability Committee will consider smaller compensation changes. (See PJM to Seek Smaller Black Start Changes.)