The EPA’s cooling water rule resulted from a settlement following years of litigation with environmental groups including Riverkeeper Inc., Natural Resources Defense Council and the Sierra Club. Based on environmentalists’ reaction yesterday, the legal battles may not be over.
Reed Super, legal director for the Waterkeeper Alliance, said the EPA abdicated its responsibility “to state agencies that are simply not equipped to make these decisions alone.
“Unfortunately, EPA’s rule will perpetuate the unacceptable status quo that has allowed antiquated plants to withdraw nearly 100 trillion gallons of fresh and sea water each year, and indiscriminately kill fish and wildlife instead of recycling their cooling water or use dry cooling technology, as modern plants have done for the past three decades,” Super said. “We are beyond disappointed with this new rule.”
The energy industry’s initial review was more positive. “The Environmental Protection Agency, to its credit, has taken into account many viewpoints and made improvements to this rule based on the scientific data and procedural analysis that has been brought to its attention,” the Nuclear Energy Institute said in a statement. “We’re hopeful those improvements are included in the final rule.”
NEI said enforcement must recognize the impacts on electric reliability and include cost-benefit analyses to balance increases in electricity costs against environmental benefits.
“Cooling towers consume twice as much water from the aquatic habitats we want to protect compared to once-through cooling systems,” NEI continued “This fact is very important given projections that much of our country will face a water-constrained future. Technology-based solutions at a power plant’s cooling water intake structure can be highly effective in protecting fish and can accommodate the ecological diversity of the various sites. As the EPA has pointed out previously, solutions like traveling screens, with a collection and return system, are comparable to cooling towers in protecting aquatic life in water bodies used for cooling power plants.”
Tom Kuhn, president of the Edison Electric Institute, said the association was “pleased that EPA had avoided imposing a categorical one-size-fits-all approach to compliance; has embraced significant elements of flexibility; and has acknowledged the importance of weighing costs with environmental protection.”
WASHINGTON — PJM could lose as much as 7,000 MW of generation by 2018 under long-awaited cooling-water regulations approved late yesterday by the Environmental Protection Agency.
The rule will require steam generators in PJM to take steps to reduce the volume of fish and other aquatic life sucked into their cooling water intakes.
The final rule affects about 544 power plants, including nuclear-, coal-, gas- and oil-fired steam generators. More than 500 industrial sites, including pulp and paper mills; chemical, iron, steel and aluminum manufacturing plants; refineries; and food processors, are also covered by the rule.
The EPA said about 40% of affected units are already using the “best available technology” as required by the regulations, which were issued under section 316(b) of the Clean Water Act.
The EPA estimates that 2.1 billion fish, shrimp and crabs are killed annually by being pinned against cooling water intake structures (impingement) or being drawn into cooling water systems (entrainment).
Industry officials were relieved in 2011 when the EPA announced its proposed rules, which did not include a requirement that all generators install expensive closed-loop cooling systems employing cooling towers. The EPA is also delegating enforcement largely to state environmental officials. (See related stories,What’s Covered by EPA Cooling Water Rule?)
PJM spokesman Ray Dotter said the RTO has not done any studies to evaluate the potential impact of the regulations but will review the final rule. “We did look at the proposed EPA rule and believe it provided flexibility to the states to conduct unit-specific determinations, which would minimize the impact to generation,” Dotter said.
The North American Electric Reliability Corp. published an analysis of the proposed rule in November 2011, which projected at least 25,000 MW of retirements or deratings nationwide by 2018 under a “moderate” regulation, including about 7,000 MW in PJM (1,300 MW of deratings and 5,700 MW of retirements).
The moderate case is estimated to cost $170 to $440 per gallon per minute (GPM).
The moderate case assumed only “more aggressive” states would require closed-loop systems. NERC said those states — including Delaware and New Jersey in PJM — are home to three-quarters of affected generation.
NERC projected PJM generators installing cooling towers would lose an average of 1.6% of their energy output.
NERC’s analysis, and a 2011 analysis by ReliabilityFirst Corp., assumed no nuclear plants would retire as a result of the rule, although RFC said retrofits would cut nuclear capacity by 3.5%. That, however, was before nuclear operators began threatening to shutter units because of low capacity and energy revenues.
Oyster Creek Generating Station (Source: Exelon)
PJM is already losing Exelon’s Oyster Creek nuclear plant by the end of 2019 — 10 years before its license expires — under a settlement with the New Jersey Department of Environmental Protection.
NERC predicted PJM would need more generation or additional demand response by 2018 under the moderate case and by 2015 under the “strict” case. The strict case, which would have required closed-loop systems and boosted generators’ costs by 25%, could have caused 35,000 MW in retirements and deratings nationwide, NERC estimated.
In its 2013 10-K filing, Public Service Enterprise Group said it was “unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material.”
Exelon’s 2013 10-K filing, issued in February, said that under a final rule that did not require cooling towers, and allowed states’ permitting agencies to apply cost-benefit tests and consider site-specific factors, “the impact of the rule would be minimized even though the costs of compliance could be material.”
Exelon said its generators without closed-cycle recirculating systems include the Clinton, Dresden, Peach Bottom, Quad Cities, Salem, Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna nuclear plants in addition to Oyster Creek. Also affected in PJM are the Eddystone, Gould Street, Riverside and Schuylkill fossil fuel plants as well as the Fairless Hills plant, which burns landfill gas.
The North American Electric Reliability Corp.’s 2011 review of EPA’s cooling water regulations had assumed that the rule would affect 1,200 generators with once-through cooling systems. EPA’s announcement of the final rule yesterday said it would affect less than half as many plants, however.
Covered are:
Existing facilities that withdraw more than 2 million gallons per day (MGD) of water from waters of the U.S. and use at least 25% of their withdrawals exclusively for cooling. They are required to reduce fish impingement using one of seven options.
Facilities that withdraw at least 125 MGD, which must conduct studies to determine whether controls will be required to reduce entrainment.
New units at an existing facility that are built to increase its generating capacity of the facility. They will be required to reduce the intake flow to a level similar to that of a closed-cycle system.
CAMBRIDGE, Md. — The Federal Energy Regulatory Commission may need to rethink its fuel-agnostic policies to preserve coal and nuclear generation threatened by environmental rules and market forces, Commissioner Tony Clark told the PJM Annual Meeting last week.
Clark said the threats to baseload coal and nuclear resources and the increasing reliance on natural gas-fired generation – “which has traditionally been our nation’s most volatile fuel source” – are exposing “cracks in the foundation of the system.”
“The loss of that traditional backbone, especially nuclear … is something to which we should probably give more than just a passing shrug,” Clark said. “It’s something we need to come to grips with.
“We have to acknowledge this would be … a major shift in what FERC has traditionally defined as its role, and it leads us down some corridors we’ve been very reluctant to get into because it gets straight into the heart of this very grey area of the states’ prerogative over integrated resource planning and FERC’s oversight of wholesale markets and bulk power system reliability.”
Clark noted that governors in New England are formulating a proposal regarding lack of pipeline cap. “The answer that we seem to be hearing from the New England region is ‘We’d like to see if FERC can build those natural gas infrastructure costs into our electricity markets.’”
He also noted initiatives by Maryland and New Jersey to contract with new gas-fired generators — efforts that were rejected by federal courts.
“At this point I probably have more questions than answers,” he said. “These are discussions we [states and federal officials] have to have because we are in this together.”
Winter Repeat Could Undermine Markets
A repeat of the price volatility and operational problems that occurred in January could undermine competitive markets in PJM, Clark said.
“If reliability suffers or we have a continuing cycle of [high] electricity prices, especially in the Eastern markets because of lack of infrastructure or fuel-source security, then it becomes an existential threat to these markets themselves,” Clark said Wednesday. “If you have repeated problems … there will be a call, make no doubt about it, in a number of these states to significantly rethink how these markets are structured.”
The Market Monitor raised a similar concern in its State of the Market report for the first quarter, saying that “non-market solutions may appear attractive,” when markets are stressed.
“Top-down, integrated resource planning approaches are tempting because it is easy to think that experts know exactly the right mix and location of generation resources and the appropriate definition of resource diversity and therefore which technologies should be favored through exceptions to market rules,” the Monitor said.
Pennsylvania Reacts
In Pennsylvania, one of the first states to adopt electric competition, officials are considering regulatory and legislative changes as a result of winter price spikes.
Through March, more than 9,100 consumers had contacted the state Public Utility Commission over electric prices that quadrupled in some cases. More than 5,700 customers filed formal complaints, while at least 50,000 customers have dropped competitive suppliers and returned to their local utilities’ default service since March.
The PUC last month proposed regulations that would require contracts to be more transparent about the volatility of variable rates and provide customers better access to historical pricing data. The PUC also has proposed reducing the time it takes to change electricity suppliers.
A bill that would cap variable rate hikes at 30% made it out of a Pennsylvania House committee but didn’t make it to the floor before the House recessed earlier this month.
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.
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.
Dominion Gains Crucial FERC Finding for LNG Export Plant
Cove Point (Source: Dominion)
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.
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.
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.
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.
Beaver Valley Unit Trip Caused By Static Electricity
Beaver Valley Unit 2 (Source: NRC)
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.
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.
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.
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.
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.
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.
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 Plant (Source: IPL)
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.”
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.
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.
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.
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.
(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.
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.
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.
