Federal Briefs

A Senate committee posed pointed questions about the safety of the increasing number of decommissioned nuclear plants and stockpiles of used fuel, drawing attention to the lack of a permanent storage site.

spent nuclear fuel pool (Source: Nuclear Energy Institute)

The hearing of the Senate Environment and Public Works Committee last week called in a panel of experts to examine the issue. Chair Barbara Boxer (D-Calif.) questioned whether enough has been done to secure stockpiles being stored in pools and dry casks. She noted that in recent months, utility officials have announced the planned retirement of five more reactors.

“The reactors may be shut down,” Boxer said, “but the risks of an accident or attack have not gone away.”

Nuclear Regulatory Commission officials and utility industry leaders have consistently said they are satisfied with current storage and security arrangements. Senate leaders introduced a bill to jump-start the search process for a new site, but the measure didn’t gather House support. Some legislators are calling for a resumption of development and eventual operation of the Yucca Mountain site in Nevada.

More: The New York Times

Norris: Negative Prices Not Nukes’ Big Problem

Federal Energy Regulatory Commissioner John Norris said he has concluded that negative pricing is having a very small impact on the viability of the nuclear fleet and that the issue should not be part of the debate over an extension of the production tax credit used by wind developers. (See Who’s To Blame For Negative Prices?)

“I have concluded that the argument regarding the impact of negative pricing on nuclear viability is a distraction and not productive to the larger conversation regarding how to ensure that the existing nuclear fleet is maintained,” he said in a statement at last week’s commission meeting. “Transmission development is the better, and more proactive, solution to negative pricing rather than forcing that issue into the debate on the merits of the production tax credit (PTC).

“I believe the larger issue is not negative pricing but rather the additional supply of new, low-cost energy in recent years from both wind and low-cost gas that has contributed to lower energy prices and reduced revenues for the nuclear units,” he added.

More: FERC

Dominion Gains Crucial FERC Finding for LNG Export Plant

Dominion Resources’ attempts to gain support for its proposed liquefied natural gas export facility at Cove Point, Md., got a big boost last week when the Federal Energy Regulatory Commission ruled that the controversial project represents no environmental or safety risks.

The FERC review gave the go-ahead for further project development provided some conditions are met. The company wants to build a $3.8 billion facility that would give the existing import terminal the ability to export up to 5.75 metric tons of LNG annually.

The terminal is on the shores of the Chesapeake Bay at Cove Point in Calvert County, Md. The plan is the target of opposition from environmentalists and local citizen groups.

More: The Baltimore Sun

May 20, 2014

Company Briefs

Duke Energy last week announced plans to spend more than $1.5 billion to build a 1,600-MW natural gas-fired plant at its Crystal River site in Florida and said it will build another 750-MW gas-fired plant in South Carolina.

The company said the new Crystal River plant, on the same site as the soon-to-be decommissioned nuclear generating station and two coal-fired plants slated for retirement, will be in operation by late 2018. The site is about 90 miles northwest of Orlando.

The South Carolina combined cycle plant will be built on the site of the soon-to-be-retired Lee Steam Generating Station in Anderson County, S.C. The company gained approval from the Public Service Commission of South Carolina in April. Construction should start in early 2015. The company didn’t put a price tag on the South Carolina plant.

More: The Orlando Sentinel, Greenville News

Pump Inspections Delay PSEG’s Salem 2 Outage

The discovery of a “bolting issue” with one of the four reactor coolant pumps at Public Service Enterprise Group’s Salem Unit 2 will prolong the 1,160-MW station’s refueling outage period indefinitely, the company said last week.

PSEG said the problem was discovered during inspections conducted during the outage, which started in April. After the finding, which the company said did not pose a danger, a decision was made to check all four reactor coolant pumps. The outage, which usually takes about a month, will now extend past mid-May, but the company did not say when the unit would come back on line.

More: Reuters

PPL, IBEW Agree On 3-Year Deal

One day before the old contract expired, PPL Corp. and the International Brotherhood of Electrical Workers Local 1600 last week reached a tentative agreement for a three-year contract.

The new contract provides 7.75% in wage increases spread over three years, a revised retirement savings program for new hires, work rule changes and new health care benefit rules.

The union represents about 3,000 workers at PPL Electric Utilities, various corporate support operations and power plants. Both sides agreed to work under current contract rules while the new contract is finalized and put up for ratification.

More:Lehigh Valley Business

Beaver Valley Unit Trip Caused By Static Electricity

FirstEnergy officials and the Nuclear Regulatory Commission agreed that static electricity caused a transformer to fail at the Beaver Valley Nuclear Power Station in Shippingport, near Pittsburgh, during the polar vortex in January. The transformer failure caused one of the station’s reactors to trip.

Company officials said transformer oil pump procedures “did not provide proper guidance” for pump operation during such low temperatures, leading to static buildup and, in turn, the transformer failure. The discovery came after the company conducted a root cause analysis and reported to the NRC.

More: Greenfield Daily Reporter

PSE&G, PPL Give $66M To Del. Water Gap Park

Delaware Water Gap (Source: National Park Service)

The National Park Service last week said PPL and PSE&G provided $66 million in donations and project funding as remediation for building a transmission line that crosses part of the Delaware Water Gap National Recreation Area.

The compensation is part of the $1.42 billion Susquehanna-Roseland 500-kV line project, which crosses part of the park, linking Pennsylvania and New Jersey. It includes $20.5 million to purchase 288 more acres for the park, as well as $12 million for wetland restoration projects and $10 million for the Appalachian National Scenic Trail.

Work on the transmission line is about 75% complete, and it should go into service by June 2015. PSE&G’s portion of the project is budgeted at $790 million, while PPL’s portion is about $630 million, company officials said.

More: The Express-Times

Panda Power Starts Building 829-MW Shale Gas Plant

Panda Power last week broke ground on an 829-MW combined-cycle plant designed to take advantage of cheap gas from the Marcellus Shale formation.

Liberty Power Plant Rendering (Source: Panda Power)

The Liberty Generating Station is in Bradford County, near the Pennsylvania-N.Y. border. Pennsylvania Gov. Tom Corbett, during a ground-breaking ceremony last week, said the plant will contribute nearly $6 billion to the area economy during construction and its first 10 years of operation. The plant will use an air-cooled, closed-loop cooling system to avoid the need to draw water from the Susquehanna River. It is scheduled to be on line in 2016.

Panda, a Dallas private equity firm, has five combined-cycle power plants currently under construction in Texas and Pennsylvania with a total capacity of nearly 4,000 MW. It also has announced a 750-MW combined-cycle power plant in Northern Virginia and an 859-MW power facility in Southern Maryland.

More: Herald Online

NRC: Indian Point Workers Mishandled Fuel Bundle

Workers at Entergy’s Indian Point nuclear power plant in New York twice tried to place a bundle of spent fuel in a spot in a storage pool that was already holding a bundle, the Nuclear Regulatory Commission said last week. The incident, which took place in March, did not result in a radiation release and did not damage any of the spent fuel bundles involved, according to the agency.

The commission report pointed to an outdated computer program that tracks fuel bundle placement. While the NRC classified it as of “very low safety significance,” it ordered Entergy to take corrective actions.

More: The Journal News

May 20, 2014

State Briefs

Seeking Lower Bills Could Come At Cost

Customer advocates are warning that Chicago-area electricity customers seeking respite from a looming ComEd rate hike may find themselves paying even more.

The Citizens Utility Board is reporting that some alternative electricity suppliers are talking customers into plans that include higher rates. CUB spokesperson Jim Chilsen said Illinois’ electricity market “has become more expensive, confusing and treacherous.” He said CUB is seeing a spike in complaints from customers who thought they were signing up for a plan with rates lower than ComEd’s coming rates, only to find themselves locked into plans charging as much as 15 to 35 cents per kilowatt hour, compared to ComEd’s 7.6 cents.

“Illinois’ electricity market has become a buyer-beware market, and we just want consumers to look for red flags of rip-offs and be on the alert,” Chilsen said.

More: CBS Chicago

FutureGen Pipeline Route Approved by ICC

The Illinois Commerce Commission has approved a 28-mile planned pipeline to carry carbon dioxide from the proposed FutureGen coal-fired plant in Meredosia to wells near Jacksonville. The innovative carbon-capture project will be a showcase for that method of controlling greenhouse gases.

Although the commission approved the pipeline route, the FutureGen project still depends on further federal approvals for the entire $1.68 billion project. The project would inject 1.1 million metric tons of carbon dioxide a year.

More: The Southern

INDIANA

Regulators Give OK ForNew Gas Plant, Refits

The Indiana Regulatory Commission approved Indianapolis Power & Light’s plans to build a 650-MW combined cycle plant and convert two coal-burning units to natural gas.

IPL will retire six coal-fired units at Eagle Valley Generating Station near Martinsville and invest $631 million to build the gas-fired plant there.

The company also received approval to spend $36 million to retrofit two coal-fired units at the Harding Street plant in Indianapolis to natural gas. IPL said the projects will create 660 construction jobs and 25 permanent jobs.

The plan drew criticism from environmentalists. “Instead of jumping from one expensive and unsustainable fuel to another,” said Sierra Club representative Jodi Perras, “IPL should be investing in more wind, solar and energy-efficiency solutions that will put our city on a cleaner and stronger path.”

More: Indianapolis Business Journal

MARYLAND

O’Malley Vetoes Wind Turbine Moratorium

Gov. Martin O’Malley vetoed a 13-month ban on the construction of wind turbines within 56 miles of U.S. Naval Air Station Patuxent River. The bill called for a delay of construction until studies could show what effects the turbine towers could have on the radar at the base.

But O’Malley said it sent a “chilling message” to developers of renewable energy. “There are already safeguards in place to ensure that no renewable energy projects conflict with military facilities — those safeguards render this bill unnecessary,” O’Malley said in a statement.

Bill supporter Del. John Bohanan said the bill showed the legislature’s support of service members and the base. “I am disappointed by a veto that protects [wind] investors over the job security concerns of Maryland families who work at Pax River Naval Air Station,” Bohanan wrote in a statement. The base is a large employer in the area.

Lawmakers would need a three-fifths vote in each chamber to override the veto and would have to come back in a special session to do so.

More: The Washington Post

NORTH CAROLINA

Gov. McCory’s Ash Bill Hits Senate, Draws Critics

A bill that would require Duke Energy to file cleanup plans for four of its ash ponds and shorten incident-reporting times is being criticized as being too lenient. The bill, proposed by Gov. Pat McCrory, calls for Duke to file cleanup plans within 60 to 90 days for four plants — Riverbend near Charlotte, Sutton in Wilmington, Asheville and the Dan River facility, scene of this year’s massive coal ash spill. But the bill doesn’t set specific timelines for any of Duke’s other ash ponds.

Some see McCrory’s bill as being too easy on Duke. “This bill is a rehashing of the discredited sweetheart deal Duke Energy struck with the state last year and only requires what Duke Energy has already conceded in public statements,” said D.J. Gerken, an attorney with the Southern Environmental Law Center.

The bill would also eliminate a law that let Duke protect secret records about its ash dams and emergency action plans.

More: The Charlotte Observer

PENNSYLVANIA

Two Permits Issued For Trash-to-Steam

The state Department of Environmental Protection last week issued two permits for a proposed waste-to-steam plant in Center City, Allentown.

The project, proposed by Delta Thermo Energy of Bucks County, received an air quality plan approval and waste management permit. Delta Thermo wants to build a 4-MW plant on Kline Island that will turn garbage and wastewater treatment sludge to steam. It will be built next to the city’s wastewater treatment plant on Little Lehigh Creek.

More: Pa. Department of Environmental Protection

May 20, 2014

PJM, FERC: Grid is Ready for Summer

After a record-breaking winter in which it narrowly avoided load shedding, PJM says it is confident it can keep air conditioners running this summer. But forward prices suggest costs may be higher than last year.

“Our experience with extreme seasonal weather and conditions over the past couple of years has helped us to better prepare for hot summers [such as] the one we expect this year,” Mike Kormos, executive vice president for operations said in a press release last week.

PJM’s summer peak is forecast at 157,279 MW, a 1.3% increase over 2013’s forecast and virtually identical to last summer’s actual peak.

With 183,220 MW of installed generation capacity and 11,160 MW of demand response and energy efficiency, PJM says its reserve margin will exceed 25%, well above the required 16.2%. The RTO’s all-time peak was 165,492 MW in July 2011.

Transmission Upgrades

PJM said reliability will be enhanced by transmission upgrades completed since last summer, including two bulk electric system transformers and about 500 MVAR of shunt capacitors.

In its own summer assessment last week, the Federal Energy Regulatory Commission said congestion in PJM should be reduced thanks to two 500-kV projects scheduled to enter service in June, the Mount Storm-Doubs rebuild and the Hopatcong-Roseland segment of the Susquehanna-Roseland project.

National Outlook

FERC said forecast reserve margins are adequate across the country despite a net reduction of 10 GW in capacity since last summer, including a 2.5 GW cut in PJM. The commission said it is expecting a hotter than normal summer although some forecasters are predicting an El Nino, which could moderate temperatures.

The hurricane forecast is slightly below average, with 10-12 named storms expected, four or five of which are likely to become hurricanes.

Summer Electric Futures (Source: FERC, May 2014) — (Source: FERC)

Electric futures for the summer have jumped since November, with increases of 19% to 30% for the Mid-C, NYISO Hudson Valley and ISO-NE hubs. PJM-West is up by about 25%. [See chart]

FERC said the increases reflect the boost in natural gas futures resulting from winter demand, which left storage inventories below normal. Henry Hub summer futures averaged $4.81/MMBtu in early May, 84 cents above 2013. Prices in the Mid-Atlantic are up almost 20%. Prices in New York City are about equal to last summer, 58 cents below Henry Hub.

With gas futures more than $1/MMBtu higher than coal futures, coal generation is likely to exceed gas, FERC said. Some coal-fired generators had difficulties obtaining fuel deliveries during the winter due to ice on barge routes and congestion and equipment problems on the rails. Rail network congestion will continue in some areas this summer because of competing demand from oil shipments in the Dakotas and the Upper Midwest.

The North American Electric Reliability Corp.’s summer Reliability Assessment said that pipeline maintenance and storage refills during the summer could limit natural gas availability for generators lacking firm service.

NERC also forecast adequate reserve margins but warned of potential challenges in ERCOT and MISO.

Below is a snapshot of FERC’s and NERC’s regional assessments:

CAISO: Gas-fired generation is likely to increase to offset lower hydropower output due to a prolonged drought. This could result in pipeline congestion and high gas prices although increased solar generation may provide some relief.

ERCOT: ERCOT forecasts a 15% reserve margin, just above its 13.75% target, thanks to four new combined-cycle plants totaling 2 GW. The generation is expected to enter commercial service by August, when Texas load typically peaks. “However, an early season heat wave could stress the system before these new facilities are available,” FERC warned.

MISO, SPP: MISO and SPP should benefit from lower production costs this summer: MISO as a result of the addition of the MISO South region and SPP from the launch of new markets in March. SPP added a day-ahead market with transmission congestion rights, a real-time balancing market and a price-based operating reserve market. It also combined multiple areas into a single balancing authority.

MISO’s reserve margin is slightly above NERC’s 14.8% requirement but lower than last year’s 18.1% due to generation retirements and suspensions, and limits on transfers between MISO’s traditional footprint and MISO South.

NYISO, ISO-NE: Transmission improvements will help the Northeast. The Greater Springfield Reliability Project should reduce congestion in western Massachusetts and northern Connecticut while full service of the Neptune line will increase imports to Long Island. FERC expects increased interchange between PJM and NYISO following changes in congestion management on the Ramapo line. Demand response will also be important on peak days.

May 20, 2014

Dominion, PSEG Proposals Gain in Artificial Island Race

Dominion and PSE&G appear to have vaulted into contention in the Artificial Island contest following a design change by PJM planners.

In a special meeting of the Transmission Expansion Advisory Committee yesterday, PJM planners presented charts summarizing their analysis of 10 finalist proposals to fix stability problems at Artificial Island, home of the Salem and Hope Creek nuclear plants.

A 230-kV proposal by LS Power (proposal #5A), which PJM had previously identified as the cheapest among the 10, fared well in the analysis.

But two 500-kV proposals by Dominion Virginia Power (#1C) and PSE&G (#7K) that were in the middle of the pack in cost — and did poorly in the analysis in their original forms — had their standings improve dramatically when PJM reevaluated them after eliminating a second tie line between the two nuclear plants.

The proposals not only got the top two scores in the analysis but also saw their costs reduced by $34 million and $43 million, respectively. PJM estimates either revised project would cost between $211 million and $257 million, the same range it assigned to the LS Power plan.

The estimates do not include an additional $80 million for static VAR compensators (SVCs), which PJM determined were necessary to improve performance of each of the proposals.

Cost Allocation

The LS Power proposal, which would run a 230-kV line across the Delaware River to a new or expanded substation on the Delmarva Peninsula, could face opposition from Delaware regulators. PJM told stakeholders at the last TEAC meeting that its cost would be allocated entirely to the Delmarva Power and Light zone. (See Delaware Unhappy with Artificial Island Cost Allocation.)

PJM did not provide an allocation for the revised Dominion and PSE&G proposals, which would both add a 17-mile, 500-kV line paralleling an existing 500-kV line from Red Lion to Hope Creek. But officials indicated yesterday that the allocation would be similar to that of a proposal by Exelon and Pepco Holdings Inc. that would follow an identical route. Its cost would be spread among two dozen transmission zones and merchants.

PJM will accept written comments on its analyses through June 2. It plans to review stakeholder feedback and present planning staff’s recommendation for the project’s design and developer at a special TEAC meeting June 16. The planners are scheduled to present their recommendation to the PJM Board of Managers July 22.

Color-Coded Summary

PJM yesterday presented a chart summarizing its analyses of the proposals, assigning color codes for each of 25 attributes in seven categories: green (positive or limited impact); yellow (some impact) and salmon (negative impact). (See p. 197 of the presentation.)

Steve Herling, vice president of planning, said each of the finalist proposals solve the stability problem. “All of these other issues are going to be factored in because the performance is so close,” he said.

Herling cautioned that the three colors included in the chart could not capture the subtleties of the planners’ analyses. “It’s a visual” summary, he said. “We don’t want people to read too much into it.”

RTO Insider summarized the findings by assigning a score of 1 to green, zero to yellow and -1 to salmon.

The PSE&G 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.

Dominion’s 1C proposal received a -2 in its original form but improved to an 8, second-best, without the tie line.

LS Power’s proposal scored a 7, ranking it third.

Tie Line Eliminated

Deleting the second tie line from the Dominion and PSE&G proposals not only reduced their costs. It also eliminated the proposals’ negative grades in the project complexity and operational impacts categories. The only remaining negatives for the two proposals related to their wetlands impact and land permitting issues.

Supawna Meadows National Wildlife Refuge (Source: US Fish and Wildlife Service)

PJM estimates the proposals will affect 350 acres of wetlands. But one stakeholder questioned that, saying only 30 acres — the ground under the transmission towers’ foundations — would be affected.

LS Power’s proposal received three negative grades under the operational impact, and siting and permitting categories. PJM said its plan for an overhead crossing of the Delaware was likely to face more public opposition than submarine crossings. “Out of sight, out of mind, if you will,” said Paul McGlynn, general manager of system planning.

The PSE&G and Dominion proposals also employ an overhead design but would follow an existing Delaware River crossing.

Sharon Segner, vice president of LS Power, said PJM should leave the decision regarding the manner of crossing the river to the U.S. Army Corp of Engineers, which has jurisdiction over the river. LS Power’s nearly identical proposal for a submarine crossing (#5A) would add as much as $45 million to the project cost.

Segner said the PSE&G and Dominion proposals face potential permitting problems because the route is within a half mile of 350 homes and includes three miles through the Supawna Meadows National Wildlife Refuge and 10 miles of wetlands.

PSE&G may have an edge over Dominion because it already owns some of the right of way needed. Sister company PSEG Nuclear LLC is the operator of the Salem and Hope Creek plants.

In its favor, LS Power holds an option on the site of its proposed substation in Delaware.

May 20, 2014

PJM Proposes Changes to Capacity Auction Parameters for 2015

PJM proposed changing the demand curve to be used in the 2015 Base Residual Auction while recommending the RTO continue using a combustion turbine as the model for determining the Cost of New Entry (CONE).

Proposed VRR Curve for 2015 Auction (Source: PJM Interconnection, LLC)

PJM’s proposed parameters adopt many of the recommendations from a study by The Brattle Group but differ on some issues, notably rejecting Brattle’s recommendation that CONE be determined based on an average of combustion turbine and combined cycle plant costs.

Brattle recommended that the Variable Resource Requirement Curve be changed so that the price cap (point a) for the system curve is set to a quantity equaling a loss-of-load expectation (LOLE) of one event in five years. Brattle said the change would provide stronger price signals when capacity resources are reduced or become more expensive and would not increase long-term average prices. The study also recommended stretching the VRR curve into a convex shape, making it steeper at lower reserve margins and flatter at higher reserve margins.

PJM said it favored the convex curve but would right-shift it by 1%, setting the price cap to 150% of net CONE at an unforced capacity (UCAP) level 0.2% below the installed reserve margin (IRM). PJM would use the same system curve for locational deliverability areas.

CONE Model

Brattle recommended using an average of combustion turbine and combined cycle costs as the reference technology for calculating Net CONE rather than the current reference of the GE Frame 7FA model combustion turbine.

Brattle said the change would acknowledge that combined cycle plants are the favored choice of merchant generators while avoiding a complete switch away from the current CT reference. It also recommended switching from the Handy Whitman “Other” Index to the Bureau of Labor Statistics’ indices for wages, materials and turbines, which it said would provide more accurate escalation factors for CONE estimates.

PJM agreed with changing to the BLS index but is recommending continued use of the frame-model CT as the reference technology, saying it would provide “market stability and avoids perceived opportunistic switching to units with more favorable economics in any given year.” It noted that the New York ISO recently selected a CT as its reference technology.

PJM seeks to have final stakeholder input by Aug. 31, with changes submitted to the Federal Energy Regulatory Commission by Oct. 1.

PJM Opposes Auction “Re-Run”

In a related matter, PJM asked FERC on May 9 to reject a request from the North Carolina Electric Membership Corp. to require the RTO to develop a mechanism for “unwinding” Base Residual Auction results and rerunning the auction. The scenario envisioned by NCEMC would occur if FERC ruled after the auction and reduced supply curve parameters below those filed by PJM.

“The hypothetical series of events that NCEMC envisions as warranting such a mechanism includes a Commission determination on how best to apply any final rulings on RPM parameter changes resulting from a periodic review,” PJM said in its response. “That opportunity for Commission intervention invalidates any suggestion that PJM’s current Tariff could lead to unjust or unreasonable results.”

NCEMC made the request in response to PJM’s April 4 proposal (ER14-1660) to move up by two months the deadlines for filing changes to auction parameters. Proposed parameter changes would be due May 15 instead of the current July 15. PJM said the changes will allow stakeholders more time to assess the parameters before the Base Residual Auction.

May 20, 2014

FERC to Relax OATT Rules for Tie Lines

The Federal Energy Regulatory Commission said it intends to grant a blanket waiver from Open Access Transmission Tariff (OATT) requirements for utilities whose only transmission assets are generator tie lines. The revisions are detailed in a Notice of Proposed Rulemaking (RM14-11).

Current policy requires a tie line owner to make excess capacity available to third parties unless it can justify its plans for future use of the line. The NOPR would allow tie line owners to wait until a third-party request for service is made under sections 210 and 211 of the Federal Power Act before having to demonstrate their plans.

The proposed changes follow a technical conference and a Notice of Inquiry issued in April 2012.

May 20, 2014

Order 1000 Reversal: Reality Check or Surrender to Incumbents?

PJM’s transmission planning process may exclude consideration of non-incumbent proposals on projects subject to state rights of first refusal (ROFR), the Federal Energy Regulatory Commission ruled last week.

FERC had previously required PJM to remove language designating an incumbent transmission owner as the “Designated Entity” to build a transmission project, “when required by state law, regulation or administrative agency order with regard to enhancements or expansions or portions of such enhancements or expansions located within the state,” and when a transmission project is “proposed to be located on a Transmission Owner’s existing right of way and the project would alter the Transmission Owner’s use and control of its existing right of way under state law.”

But the commission ruled 3-1 Thursday that its previous position would require planners to evaluate nonincumbent proposals that had no chance of getting built because of state rules assigning them to incumbent utilities. The commission said it was persuaded by the arguments of North Carolina Utilities Commission, the Indiana Utility Regulatory Commission and others that the language merely acknowledged state jurisdiction and did not create a federal right of first refusal.

The commission made the change in Order 1000 compliance rulings for PJM (ER13-198, ER13-195, ER13-90), MISO and South Carolina Electric & Gas Co. (SCE&G).

Norris Dissents

In a dissent, Commissioner John Norris said the reversal undercuts Order 1000’s requirement eliminating federal rights of first refusal from FERC-jurisdictional tariffs or agreements.

Norris cited Order 1000-A, in which the commission said “[I]t would be an impermissible barrier to entry to require, as part of the qualification criteria, that a transmission developer demonstrate that it either has, or can obtain, state approvals necessary … to be eligible to propose a transmission facility.

“By excluding proposals from non-incumbents when the proposals are being evaluated based on a consideration of state law, we are effectively excluding non-incumbents from participating in the transmission planning process,” Norris wrote. “This is a fundamental change in direction that I cannot support. I simply cannot reconcile the language in the final rule with the approach taken in today’s orders.

“Clearly, incumbents already are well-positioned through their knowledge of the system, including issues related to reliability and congestion,” he continued. “Today’s orders give incumbents a further advantage over non-incumbents by limiting non-incumbents’ participation in the planning process.

“In my view, allowing non-incumbents to participate in the regional transmission planning process without consideration of potential state law restrictions does not infringe upon the state’s authority,” Norris said. “Using this language to exclude non-incumbents denies states and other stakeholders the opportunity to have all essential information regarding the more cost-effective and efficient transmission solutions.”

‘Coercive Pressure’

The Indiana Commission said that allowing a transmission provider to select a transmission developer that is ineligible to construct a transmission facility under state law would lead to increased litigation and “coercive pressure on state commissions.”

The North Carolina Utility Commission and its public staff agencies said the commission was acting inconsistently in requiring that PJM consider state renewable portfolio standards in its transmission planning process while insisting it ignore state rules restricting transmission development to state franchised utilities.

Other Challenges Rejected

While the commission reversed its position on acknowledging state rules, it largely rejected challenges to its previous orders regarding PJM.

It did, however, order PJM to make some additional Tariff changes and compliance filings, including one describing how local transmission owners incorporate public policy requirements into their transmission plans.

It also ordered PJM Transmission Owners to submit a compliance filing ensuring comparable treatment of AC and DC facilities.

May 20, 2014

Consumer Advocates to PJM: No More Changes, Please

CAMBRIDGE, Md. — Consumer advocates asked the PJM Board of Managers last week to assess the impact of recent capacity market changes before making any new ones and criticized what they called the RTO’s new “inflexibility.” Environmental groups, meanwhile, asked PJM to become “proactive” in addressing climate change and to do more to capture the role of energy efficiency in its planning.

The comments came at the board’s yearly meeting with consumer advocates and public interest groups on the first day of the PJM Annual Meeting here. The tone was a bit less rancorous than 2013’s meeting, with several activists praising PJM for its work maintaining electric service during January and for its response to generator retirements.

Still, the participants weren’t going to let their one shot to talk to the board — and it was almost entirely a one-way conversation — go to waste.

“Five major proposals in the capacity market in the last 12 months is a lot to digest,” said Assistant Pennsylvania Consumer Advocate Dave Evrard, who cited four changes that were approved by FERC and one that was rejected. Evrard noted that PJM had provided cost estimates on only one of the four proposals, a restriction on how demand response clears in the auction. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

“We watch somewhat nervously to see what the results of the current base residual auction will be,” Evrard said, noting that demand response offers dropped by 27% between the 2012 and 2013 base residual auctions. The question is whether the recent DR changes “[exacerbate] the decline or if that was simply an aberration,” he said.

Wil Burns, an attorney who represents environmental groups, echoed Evrard’s concerns, saying the board should not make any additional changes until it has analyzed the impact of the recent changes.

PJM’s `Inflexibility’

Brian Lipman, litigation manager at the New Jersey Division of Rate Counsel, criticized PJM for failing to discuss with stakeholders its position on a crucial capacity market rule before filing comments with the Federal Energy Regulatory Commission. PJM sided with FirstEnergy, which petitioned FERC on April 7 to change how the RTO calculates the maximum price generators can offer into capacity auctions (EL14-36).

“We didn’t find out about PJM’s position until it was filed,” he said. “That is concerning to us that we didn’t have any input into that decision.”

PJM’s “recent inflexibility” regarding rule changes “makes stakeholders worry about the future of consensus-building,” he added.

Lipman said PJM should take more time in stakeholder discussions, such as in the current discussions on the use of the Handy-Whitman building cost index in the calculation of the Cost of New Entry (CONE). “We could have been discussing that for a year now,” he said. “Decisions are happening before we have a chance to participate.” (See related story, PJM Proposes Changes to Capacity Auction Parameters for 2015.)

Role of DR, EE

Environmentalists, meanwhile, asked the board to incorporate demand response and energy efficiency into more of its planning efforts. DR and energy efficiency are “factored into one of your eight planning estimates only,” Burns said.

Yorktown Power Station (Source: Dominion Virginia Power)

For example, PJM should consider whether increased DR might allow Dominion Virginia Power to retire its Yorktown coal-fired generators as planned at the end of 2014 rather than continuing to operate temporarily to address reliability problems, Burns said.

Alison Clement, of the Sustainable FERC Project, said PJM could learn from ISO New England, where at least 90% of energy efficiency bids into the capacity market.

Rob Marmet, of the Piedmont Environmental Council, called on PJM to help states find the most effective ways to comply with pending EPA rules on greenhouse gas emissions for existing generators.

PJM Chairman Howard Schneider offered some brief remarks at the end of the session. “We value the issues you bring to us and the way you bring them to us,” Schneider said. “The relationship has improved vastly over the last several years.”

PJM CEO Terry Boston was the only other board member to offer feedback to advocates, saying he liked Burns’ idea of giving DR a bigger role in PJM’s winter reliability plans.

May 20, 2014

Monitor Suggests Price Gouging by Generators

Some generators may have taken advantage of January’s weather to boost their prices, the Market Monitor said in its quarterly State of the Market report Friday.

“The behavior of some participants during the high demand periods in January raises concerns about economic withholding,” the monitor said. “In particular, there are issues related to the ability to increase markups substantially in tight market conditions.”

The Monitor’s report cites the “markup index,” a measure of participant offer behavior. In the real-time energy market, 58% of marginal units had an average markup index at less than or equal to zero in the first quarter. But 14% of marginal units had average markups at or exceeding $150/MWh, compared to only 4% in the first three months of 2013.

In the day-ahead energy market, almost 87% of marginal units had average markups less than zero and an average markup index less than or equal to 0.03. “Nonetheless, some marginal units do have substantial markups,” the report said. Markups increased on days in January when demand was highest.

The markup index is calculated as (Price – Cost)/Price. The index ranges from -1.00, when the offer price is less than marginal cost, to 1.00, when the offer price is higher than marginal cost.

Competitive Offers Required

The Monitor said capacity resources should be required to make “competitive” offers into the energy market, an obligation that is not clear under current Tariff language.

“Selling capacity into the PJM capacity market but making energy offers daily of $999 per MWh would not fulfill the requirements of a capacity resource to make a competitive offer but would constitute economic withholding,” the Monitor explained in the 2013 State of the Market report. “This is one of the reasons that the rules governing the obligation to make a competitive offer in the Day-Ahead Energy Market should be clarified for both internal and external resources.”

The Monitor’s suggestion of economic withholding came a day after Federal Energy Regulatory Commissioner Tony Clark told PJM members that the commission had seen no evidence that market manipulation played a role in the high natural gas and electric prices in January.

In an interview yesterday, Market Monitor Joe Bowring said his staff will be interviewing generators with high markups and may refer the matter to FERC’s enforcement unit if it doesn’t receive satisfactory answers. “The Tariff requires us to refer potential enforcement matters to the commission,” he said.

January 2014 Outage Rates, Morning Peak (Source: PJM Interconnection, LLC)

Bowring said his staff is also investigating whether any generators engaged in physical withholding by improperly claiming outages. PJM saw as much as 22% of its generation out of service in early January, three times the normal winter outage rate.

Bowring said some gas-fired units took losses to operate in January. “We want to make sure that others also followed through” on their obligations, he said.

Inadequate Incentives

The Monitor’s report said the high generation outage rate in early January was an indication that the current balance of incentives and penalties is inadequate. “At present only half of capacity market revenues are at risk for failure to perform on high demand days. Gas-fired units with a single fuel are exempt from any capacity market revenue impact that results from lack of fuel outages on high demand days,” the report said.

The obligation of capacity resources to offer into the day-ahead energy market “exists regardless of whether gas procurement is difficult, regardless of whether gas prices are high and regardless of whether gas procurement is risky,” the Monitor said.

Stakeholders this month began work on developing potential winter testing requirements for generators. Consideration of incentives for generator performance and penalties for failures will be considered in a separate initiative, PJM said. (See PJM Seeks Action on Winter Lessons.)

Day-Ahead Scheduling Reserves

The Monitor also reported withholding in the day-ahead scheduling reserve (DASR) market, a problem it has cited before which worsened in 2014.

PJM uses the market to acquire supplemental, 30-minute reserves. Because the direct marginal cost of providing DASR is zero, offers greater than zero constitute economic withholding, the Monitor said.

In 2013, 12% of offers in the market exhibited evidence of withholding. The clearing price in the first three months of 2014 was $0.06 per MW, double the price for the first quarter of 2013.

About 74% of resources offered at less than $1 in the first quarter, with 11.5% of resources offered at more than $5 per MW.

The 2013 SOM report recommended incorporating the “three pivotal supplier” test in the market to prevent the exercise of market power during times of system stress, ranking it as a low priority item. PJM said it does not believe the change is warranted given the minimal impact of the market on consumer costs.