PJM will begin measuring the demand response performance of some residential customers through sampling of interval-meter data under a rule change approved by the Operating Committee Wednesday.
The new procedure will apply to residential customers on non-interval meters and under direct load control of a curtailment service provider. The measurements will be used to evaluate the performance of resources participating in synchronized reserve, economic energy and load management programs.
The sampling would replace outdated studies dating back to 2001. Sampling is a way to improve accuracy without the cost of installing one-minute meters on every participating household, PJM said. The rule would take effect June 1, 2015, with a transition mechanism for resources that cannot meet new requirements for delivery years 2016 through 2018. (See MIC Briefs, Sept. 9.)
The OC approved the proposal with 14 abstentions and 19 objections, 15 from FirstEnergy. FE’s Jim Benchek said PJM shouldn’t take action on the issue given the uncertainty over DR’s role in wholesale markets as a result of the EPSA ruling and FE’s complaint seeking to prevent DR from clearing in capacity markets. (See EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans.)
Benchek said the change represents a “carve out” for residences while generators must use interval meters. “If we make an exception here, where does it stop?” he asked. “They should have interval metering like anyone else if they want to sell synchronized reserves.”
Consultant Tom Rutigliano of Achieving Equilibrium said the committee’s action will have no impact on the ultimate fate of DR in wholesale markets, which may be decided by the Supreme Court. To avoid legal problems, PJM has proposed eliminating DR as a capacity supply resource, suggesting load-serving entities instead offer DR and energy efficiency to reduce their capacity obligations.
“This is still just a good measurement technique, no matter who’s doing DR,” Rutigliano said.
Day-Ahead Scheduling Reserve Set at 5.93%; Winter Reserve: 27%
The OC endorsed PJM’s recommendation to set the 2015 day-ahead scheduling reserve requirement at 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%). The changes will be reflected in Manual 13: Emergency Operations.
The committee also endorsed PJM’s proposed 2014/15 winter reserve target of 27%, unchanged from last winter. The 27% target, a percentage of the forecasted weekly peak load, is based on unit summer ratings.
PJM’s Tom Falin said the target does not include data from January 2014. “When we get to extreme conditions, I don’t know how binding this is anyway,” Falin said, noting that PJM would cancel maintenance outages if it anticipated a generation shortage. He said there were about 1,000 MW on maintenance on PJM’s all-time winter peak day in January.
TOs Asked to Update Load Dump Ratings
PJM is asking transmission owners to revise their ratings methodology to address facilities for which the long-term emergency (LTE) ratings are equal to the load dump (LD) measures.
TOs that are unable to make the changes through PJM’s rating methodology guideline should reduce the LTE rating by 3% of the LD rating. PJM wants the changes made by Dec. 1 so that it can determine their impacts on markets and planning before the revised ratings take effect June 1.
Concern over facilities with identical ratings arose as a result of the September 2013 hot-weather event, when PJM discovered that the normal, emergency and LD ratings on the Industrial-Summit 138-kV line were the same. “The impact of all the ratings being the same is there is no time for the dispatcher to perform anything but the most extreme action that must be taken once the load dump rating is reached,” PJM said in its heat wave analysis.
No Votes Gained on Interchange Volatility
A working group meeting last week failed to win any converts to PJM’s plans to limit interchange volatility, OC Chairman Mike Bryson said.
The Energy and Reserve Pricing & Interchange Volatility Sub-Group met on the issue last Tuesday in an attempt to reach consensus. “We tried to beat some votes out of people, but it didn’t really work,” Bryson said.
PJM officials said they intended to recommend operating under the new rules, which require only a manual change, with or without the two-thirds mandate. The rule is intended to prevent markets and operations from being whipsawed by large swings in imports.
Judge Rules Energy Future Can Auction its Oncor Holdings
A state bankruptcy court judge has ruled that Energy Future Holdings can begin accepting bids for its majority stake in Texas transmission company Oncor.
Energy Future, which has declared bankruptcy, is selling off its 80% share in Oncor, which has 120,000 miles of transmission lines and 3 million residential customers in Texas. The winning bidder will then have the right to own that equity when Energy Future exits bankruptcy.
According to Reuters, expected bidders include NextEra Energy, Hunt Consolidated of Dallas and CenterPoint Energy, also of Dallas. Energy Future’s stake is estimated to be worth about $18 billion.
Fracking Rules to be Unveiled Soon, Permit Rush Expected to Follow
The Joint Committee on Administrative Rules last week took a final step toward setting rules to govern fracking in the state.
The committee approved the regulations after months of public hearings, comments and committee work. The exact rules are expected to be released to the public Nov. 15. Until then, outside parties — environmental groups, energy companies and local governments — are in the dark.
“We don’t know if our concerns have been taken into account because we don’t know what changes were made,” said Jack Darin, director of the state chapter of the Sierra Club. The rules are likely to face legal challenges.
Unveiling the rules is expected to spur initial permit applications, local public hearings and test well drilling. The Department of Natural Resources has hired 32 people to help with the initial application process.
Commissioners Get Answers on IPL’s August Blasts, Blackout
Indianapolis Power and Light officials told state regulators last week that the utility will spend $15 million in the next three to five years to replace 137 aging underground circuit breakers that were linked to a network failure in August.
At a hearing held by the Utility Regulatory Commission, the utility said the sounds of a series of underground network disruptions that shook Indianapolis in August were not explosions but the sound of tripping circuit breakers. Those circuit breakers, some dating to the 1950s, were identified as a problem in 2011. Since then, IPL has replaced 10 of the 58 aging breakers that were shown to be susceptible to corrosion.
IPL said that within 30 days it would submit a plan to the IURC to replace 137 vulnerable breakers.
Proposed Law Would Protect Large Wind Farm Operators
The state Senate is considering two bills that would limit nuisance lawsuits against operators of industrial wind turbines by exempting operations that are in compliance with state and local regulations. One measure would impose a “loser pay” requirement on plaintiffs who do not prevail.
“There are a number of lawsuits being filed and families being paid damages,” said state Sen. Howard Walker, author of the bills. “When that happens, the additional costs are passed on to the ratepayers. To me, this is a property rights issue. If someone is complying with local ordinances and state law, I believe they have the right to harvest wind energy on their property.”
Some wind opponents were displeased. “Wind development is becoming much harder to sell to rural communities,” said Kevon Martis of the Interstate Informed Citizens Coalition. “Turbines are no longer a novelty. They are pervasive and wind developers are having a much harder time convincing people that 50- or 60-story tall turbines are scarcely noticeable in our quiet farming communities.”
Pipeline Company Threatens to Sue Homeowners Who Deny Access
A company planning to build a petroleum products pipeline through the state’s north is threatening property owners who deny access to surveyors, but some environmental groups say that Pilgrim Pipeline doesn’t have that right.
A homeowner in Parsippany received a letter from Pilgrim saying their representatives had the right to go on the property for surveys, and if refused access, Pilgrim would go to court to force the issue. The letter said that Pilgrim is a “pipeline company established under New Jersey law” with the “power to condemn private property.” Because of that, Pilgrim’s consultants have “the ability to enter on private land to perform surveys and investigations,” the letter read.
Not so fast, say environmental groups. “It’s wrong legally, it’s wrong factually,” said Aaron Kleinbaum, legal director of the Eastern Environmental Law Center. “They do not have the right to go onto private property without permission.” Pilgrim has proposed a 178-mile pipeline to carry refined products such as gasoline, diesel and heating oil from the New York Harbor to upstate New York.
Tricia Caliguire, a former energy and environmental policy advisor to Gov. Chris Christie and the chief counsel for the Board of Public Utilities, is leaving government and returning to private law practice.
Caliguire, who has been with the BPU since 2012, will specialize in energy, utility and environmental matters as special counsel in McCarter & English’s Newark office. She started her law career with McCarter & English in 1987.
A state Mining and Energy Commission report proposes allowing unannounced inspections at oil and gas drilling sites. It was just one of the recommendations culled from nearly 220,000 public comments on draft rules. The surprise inspection rule was developed to remove language that would have mandated notice to site operators.
The report, prepared by three of the 14 commission members, also suggested a minimum setback of 1,500 feet to each oil or gas well, tank, tank battery, pit or production facility from the edge of any waterway that leads to a drinking water supply.
The proposals will go to the full commission for a vote and then to the legislature during its January session.
Recycling Plant Partner in Default on Construction Payments
A private developer building a project to remove recyclable material from trash and to produce energy from landfill waste has defaulted on payments, putting the project in jeopardy.
The Solid Waste Authority of Central Ohio said Florida-based Team Gemini, which was to build a recyclables sorting and recovery facility at the Franklin County landfill, is more than $1.1 million behind in construction payments and hasn’t paid its $342,850 rent.
Team Gemini is under contract to complete the facility by June 2016. The plant would be powered by a generation station fueled by the landfill’s organic waste. The authority can pull out of the project if Team Gemini doesn’t come up with the payments within 60 days.
Voters in three of four towns rejected anti-fracking measures on their ballots in last week’s election.
About 58% of voters in Youngstown rejected a measure to ban oil and gas drilling, the fourth time an anti-fracking measure was rejected in the northeast city. The towns of Kent and Gates Mills also rejected anti-drilling measures.
Only voters in Athens, home of Ohio University, supported a measure prohibiting fracking for shale gas and oil. The “Community Bill of Rights and Water Supply Protection Ordinance” passed with 78% of the vote. (See related story, GOP Majority Unlikely to Thwart EPA Carbon Plan.)
PGW Sale to UIL Holdings May Still be Alive, Mayor Says
Philadelphia Mayor Michael Nutter’s administration is still campaigning to keep alive a $1.86 billion sale of the city’s gas utility to UIL Holdings, despite the city council’s refusal to take up the measure.
“The mayor is ever an optimist and is hopeful that before the end of the year, we will have had a bill introduced, hearings and a vote from City Council on PGW [Philadelphia Gas Works] and the sale to UIL,” said Mark McDonald, Nutter’s press secretary. Council President Darrell L. Clarke announced abruptly on Oct. 27 that the city’s legislative body would not consider the proposal.
The mayor’s office released a document last week offering a point-by-point rebuttal of criticisms of the privatization. The deal expires by year’s end if not approved by council.
The Public Utility Commission will hold a hearing to discuss PGW’s future this week, and UIL CEO James P. Torgerson said his company will decide soon whether it will continue to pursue the deal, on which it has already spent $21.3 million. “We’re going to see how things go over the next few days, and then we’ll make some decisions on that,” he said during an analysts call.
The state Department of Environmental Protection has revised a rule it proposed in April to limit emissions from coal-fired power plants that was widely criticized by environmental groups and deemed “too lax” by federal environmental regulators.
The new proposed final rule requires the state’s more than two dozen coal-fired power plants to install and operate Reasonably Available Control Technology to reduce emissions of nitrogen oxides and volatile organic compounds.
Critics said DEP’s April proposal would have allowed many of the power plants to operate without turning those controls on and emit up to 40% more pollutants.
Gov. Earl Ray Tomblin picked state Sen. Brooks McCabe, who did not run for re-election this year, to one of three seats on the Public Service Commission.
McCabe, a Democrat, fills a vacancy on the three-member commission created when Ryan Palmer departed to join the Federal Communications Commission. McCabe must resign his Senate seat before joining the commission Nov. 15.
A veteran of the commercial and investment real estate industry, McCabe pursued economic growth and development for the state. He has served on the Senate Committees on Finance, Economic Development, Pensions, Banking and Insurance and Government Organization.
PSC Approves 83% Fixed Charge Increase for Wisconsin Public Service Customers
The Public Service Commission allowed Wisconsin Public Service to nearly double its fixed monthly customer fee, approving an approach that utilities are pursuing to get low-usage customers like those with solar panels to pay more of the costs of maintaining the distribution system.
The measure, approved by a 2-1 vote, will raise the fixed charge from $10.40 to $19 a month. The increase in the fixed charge is offset by a decrease in the energy charge, resulting in an overall hike of about 3%. Fixed charges go toward paying for a company’s fixed costs, such as poles, wires and substations.Consumer advocates and solar supporters criticized the PSC’s vote. “The decision takes the step that most helps utilities at the expense of customers,” said Kira Loehr, executive director of the Citizens Utility Board. “Increasing fixed charges hurts our most vulnerable low and fixed income households and frustrates residential and small business customers’ ability to lower their bills by using less energy.”
The commission has yet to rule on similar requests from other utilities. We Energies wants a 75% increase and Madison Gas & Electric is seeking an 82% jump.
The revised methodology (blue line) results in a reduction from the current forecast (green line).
PJM is testing a new load forecasting model to reverse a marked “degradation” in forecast accuracy.
The model being tested accounts for factors such as appliance saturation and energy efficiency that were previously not included, PJM’s Andrew Gledhill told the Planning Committee last week.
The new model’s “equipment indices” improved near-term forecast accuracy but caused an increase in instability because the forecasts of appliance saturation and efficiency change over time. The forecasts are made by Itron based on data from the Energy Information Administration. “The understanding of where we’ve been and where we’re going has had a tendency to change over time,” Gledhill said.
Officials said it was difficult to determine the model’s long-term forecast accuracy because of data limitations.
PJM is investigating incorporating the equipment indices into its peak-load model. One concern: Will accounting for these trends in the peak model result in an overlap with energy efficiency as a capacity market resource?
PJM previously considered shortening the estimation period but found that it created anomalies. The current forecast uses an estimation period of 1998 to the previous August. PJM found that while a three-year-ahead forecast resulted in a 0.6% reduction for the RTO, some zones increased by as much as 9% while others dropped 6% or more.
PSEG Seeks Injection Rights for PARs
The Planning Committee Tuesday approved PSEG Energy Resources & Trade’s problem statement to consider awarding firm withdrawal and injection rights to transmission projects employing phase angle regulators (PARs).
PJM awards withdrawal and injection rights to controllable AC and DC merchant transmission facilities using only variable frequency technology, which excludes PARs.
PSEG said PJM’s interpretation “creates an impediment to the development of a class of controllable merchant transmission projects that could efficiently address seams issues between PJM” and neighboring regions. Because PAR projects are not awarded rights, “it will be difficult if not impossible for PARs-based projects to be deemed deliverable” for sales of capacity or energy, PSEG said.
GMD Reliability Standard Struggling to Win Support
The North American Electric Reliability Corp. is struggling to win support for its reliability standard on geomagnetic disturbances, PJM’s Frank Koza told the PC last week. Two rounds of voting have failed to gain the two-thirds support needed to endorse the standard for review by the Federal Energy Regulatory Commission.
The most recent vote won support of only 58% of stakeholders, and a third vote will be taken this month, Koza said. “We need to turn about 25 votes around,” he said.
The standard requires reliability coordinators and some transmission operators to institute operational procedures to mitigate the effect of GMDs.
NERC is working on stage two of the standard, in which it must determine what severity GMD will constitute a “benchmark” GMD event. Covered entities will be required to assess the potential impact of such benchmark events on their equipment and systems. FERC required NERC to complete the standard by January. (See FERC OKs GMD, Training Standards; Proposes Modeling Rule Change.)
This is the space where we would have told you what happened at the PJM Board of Managers’ Enhanced Liaison Committee meeting Tuesday.
The subject of the meeting was PJM’s Capacity Performance proposal, by far the biggest, most expensive set of rule changes the RTO has considered in the nearly two years that RTO Insider has been providing stakeholder coverage.
While more than 300 stakeholders and state representatives attended the meeting or listened in by phone, the press and public were explicitly excluded under PJM rules that also bar attendees from sharing what they heard.
That is a disservice to our thousands of readers and to the 61 million people served by PJM, who will pay for whatever changes the board proposes and the Federal Energy Regulatory Commission approves.
We are happy that most PJM members have become accustomed to the presence of a reporter in their meetings over the last two years. Many have acknowledged the pains we have taken to ensure we quote members fairly and in context.
We hope that the members and the board will change the rules and extend this laudable transparency to future Liaison Committee meetings.
The Department of Energy says coal stockpiles at power plants around the country are lower than normal at this time of year, and that plant operators are scrambling to obtain deliveries for winter.
The Energy Information Administration said substantial draw-down during last winter, combined with challenges getting deliveries over rail routes congested with shipments of grain and petroleum products, is leaving some operators nervous about getting enough for this heating season.
“Issues with delivery by rail are making it more difficult to ship larger volumes of coal and rebuild stockpiles at coal-fired power plants,” the EIA said. At the end of August, 23% of coal plants had less than 30 days’ supply, compared to 13% last year.
LaFleur Says FERC will not be Part of EPA Rulemaking
Federal Energy Regulatory Chairman Cheryl LaFleur said her agency won’t be overly involved in discussions about the Environmental Protection Agency’s rules on emissions. “I don’t see a role for FERC in telling EPA what to write in the rule,” she said.
“We should have a reliability consideration of some kind in the Clean Power Plan,” she said. “Protecting reliability isn’t optional — the lights are going to stay on — so that that should somehow be built into the process seems to make sense.”
TVA Executive is Highest Paid Fed Employee, and Getting a Raise
The federal government’s highest paid employee just got a raise.
Tennessee Valley Authority increased the salary of its chief executive, Bill Johnson, from $950,000 to $995,000. His total compensation package, nearly $6 million last year, could increase to as much as $7 million next year.
Some critics decried the compensation, with a spokesman for Rep. John Duncan (R-Tenn.) calling it “ridiculous.” But TVA Board Chairman Joe Ritch defended Johnson’s pay package and said it is in line with compensation for comparable utility executives.
“We could go get someone for much less,” Ritch said. “But in my view, we are still underpaying our CEO.” The agency, with 12,000 employees, is heavily indebted, and Johnson, a former Duke Energy executive, is heading up a team that is aiming at cutting operating costs by $500 million by the end of next year.
NRC Increases Oversight at Exelon’s Peach Bottom Plant
The Nuclear Regulatory Commission issued Exelon’s Peach Bottom Atomic Power Station an “escalated enforcement action” after observing a security violation during an NRC inspection in May.
An inspection found a problem with an electronic security device at the dry cask storage facility, the NRC said. Exelon fixed the problem, the details of which were not disclosed. Exelon was not fined, but the commission “will be looking at doing a fairly extensive inspection … next year to look at their dry cask storage problem,” according to an NRC spokesman.
The violation is the latest NRC enforcement escalation taken against Exelon, the nation’s largest nuclear operator. The NRC ordered heightened inspections at Peach Bottom after security guards were caught sleeping in 2007. In June it cited security problems at Exelon’s Limerick Generating Station, and the agency issued a “white” finding against its Calvert Cliffs plant after an instrumentation malfunction was discovered in March.
Former NRC Chairman Selected for Duke Energy Board of Directors
Richard Meserve, the former chairman of the Nuclear Regulatory Commission, has been elected to Duke Energy’s board of directors.
He will become the 16th member of the Duke board, pending approval by the Federal Energy Regulatory Commission. He also sits on the board of directors at Pacific Gas & Electric. Meserve left the NRC in 1999 and became chairman of the Carnegie Institution for Science.
“Richard Meserve’s extensive experience in science and environmental issues makes him a strong addition to Duke Energy’s board,” Duke Chairman Ann Gray said.
Beginning in January, gas generators will be able to change their offers to reflect fluctuating fuel prices, under a proposal approved by the Operating Committee last week.
The proposal would allow generators to lock in their fuel prices three hours in advance of the operating hour.
The option would be available to resources that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time will be unable to change their cost schedules until released.
“It’s not a perfect solution,” PJM’s Chantal Hendrzak acknowledged during a briefing of the Market Implementation Committee Friday. “For right now, we think this would be better than what we have today, where we lock prices at 1800 [the day before] and there’s no way to change.”
Hendrzak said PJM’s security constrained economic dispatch (SCED) engine does not recognize an end to a price schedule. The three-hour “lockout” is necessary to give the engine time to produce the dispatch stack.
The changes are the result of work by the Gas Unit Commitment Coordination (GUCC) group within the Operating Committee.
The Operating Committee approved the new policy Thursday despite abstentions from Dayton Power and Light and PPL, and objections from Dominion Resources and American Electric Power. Dominion’s Louis Slade said that while his company agrees with the increased offer flexibility, he objected because PJM had not given members advance notice of the Manual 11 changes involved.
The OC will hold a conference call at 3 p.m. Nov. 12 to discuss the changes in advance of a Nov. 20 vote by the Markets and Reliability Committee.
PJM’s vendor is expected to deliver the required software changes in December. PJM is planning to put the changes into production in January. The new procedures will be explained during the winter-weather procedure changes webinar Nov. 24.
For a long-term solution, Hendrzak said PJM is considering the technology used by ISO-NE. Beginning in December, the ISO will allow generators to change pricing by hour in the day-ahead market and change real-time offers until 30 minutes before the operating hour. “We know we’re not done yet,” Hendrzak said.
The MIC also received a briefing from Market Monitor Joe Bowring on how generators should submit their fuel cost policies through Monitoring Analytics’ new member-information-reporting application (MIRA) tool.
The Monitor uses the fuel cost policies to review cost-based offers submitted by generation owners. The policy must specify the source of the generator’s fuel cost input. Allowable sources are:
The staff of the Federal Energy Regulatory Commission last week accused a Canadian independent power producer of misrepresenting the output of its three New England generators and its cost of fuel in schemes that the staff says netted the company millions in inflated payments.
FERC issued a Staff Notice of Alleged Violations (NAV) last week naming Calgary-based Maxim Power Corp., its CEO, John Bobenic, and Kyle Mitton, director of corporate development, as the targets of its investigation.
The NAV indicates that FERC enforcement staff has completed its investigation. Most FERC enforcement cases that become public are quickly settled. If Maxim declines to settle, the next step may be a commission vote on whether to issue an Order to Show Cause.
In May, Maxim disclosed to investors that FERC had accused the company of receiving unjust gains of $23 million. The company said it repaid about $3 million in 2010 through “the ISO-NE mitigation program.”
FERC staff alleges that Maxim collected “millions of dollars of inflated make-whole payments” from ISO-NE between 2012 and 2013 by gaming an ISO rule intended to mitigate the market power of generators needed for reliability. The notice did not elaborate on how this was allegedly done.
In a second alleged scheme in July and August 2010, Maxim submitted offers it said were based on high oil prices because it couldn’t procure enough natural gas. FERC says the company collected make-whole payments based on the oil price but actually burned cheaper natural gas and pocketed the difference. “In many cases Maxim had already purchased gas when it submitted day-ahead offers based on oil prices,” FERC said.
In the third allegation, FERC said that Maxim collected inflated capacity payments between 2010 and 2013 by using “extraordinary measures” to boost the output of its three New England plants during testing. It said that the “extraordinary measures” were used only during the tests, and that Maxim never intended to use those methods during normal operations.
FERC offered no details on what those measures were. There are several ways of temporarily boosting the output of gas-fired generating plants, including disconnecting emissions controls and using different fuel-air mixtures.
Maxim officials did not respond to requests for comment yesterday. In a news release last week, the company said it is cooperating with FERC’s inquiry and stressed that a NAV “is not a determination by FERC that any violation has occurred.”
“Maxim intends to vigorously defend itself before FERC or a federal district court and is confident it can demonstrate that the conduct set forth in the notice did not violate FERC’s anti-manipulation rule or any other rule.”
ISO-NE spokeswoman Marcia Blomberg told RTO Insider “we support FERC investigations by providing information to the commission, but we don’t discuss market enforcement activities publicly.”
Maxim operates three plants in the ISO-NE region: CDECCA, a 62-MW cogeneration plant in Hartford, Conn.; Pawtucket Power, a 63.5-MW cogeneration plant in Pawtucket, R.I.; and a 181-MW natural gas-fired plant in Pittsfield, Mass.
In total, the company owns and operates 39 power plants in Alberta, the U.S. and France, with a combined 777 MW of capacity. Its other U.S. plants are the Basin Creek natural gas-fired plant in Montana and a simple cycle 87-MW plant in Forked River, N.J.
The company, which trades on the Toronto Stock Exchange, reported $10.6 million in net income on $173.7 million in revenue for 2013.
CEO John R. Bobenic, an accountant, joined Maxim in October 2000 after stints at Peat, Marwick, Mitchell & Co. and TransAlta. He is a past vice chair of the Independent Power Producers Society of Alberta.
New York/New England Correspondent William Opalka contributed to this article.
Consumers Energy plans to replace some of its “Classic Seven” capacity with the purchase of this 540-MW natural gas-fired plant in Jackson, Mich.
The Federal Energy Regulatory Commission last week denied Consumers Energy’s request for a waiver from MISO’s must-offer requirement, three weeks after approving a similar request by Indianapolis Power and Light.
Both utilities complained that there was no clear mechanism within MISO’s Tariff that would permit them to buy replacement capacity to cover a six-week gap in 2016 between when they planned to retire older coal units under the Environmental Protection Agency’s Mercury and Air Toxics Standards and the end of MISO’s planning year on May 31.
Michigan-based Consumers Energy plans to retire its “Classic Seven” coal units — three at the J.R. Whiting generation station near Luna Pier; two at the B.C. Cobb Generating Plant in Muskegon; and two at Karn/Weadock, near Bay City — on April 15, 2016.
Consumers said purchasing replacement power for the entire 2015-16 planning year would cost $5.8 million to $84.8 million.
The Michigan Public Service Commission told FERC it should approve Consumers’ request to minimize costs to ratepayers. Alliant also filed in support.
MISO opposed Consumers’ waiver request, saying that it could cause the ISO’s North and Central regions to fall below the Planning Reserve Margin, increasing the risk of a loss-of-load event.
MISO said that Consumers’ request for a waiver reinforced its resource adequacy concerns for the six-week period at issue “because the request implicates an additional 940.7 MW during the time period in which Indianapolis Power requests waiver of approximately 216 MW.”
Calpine, NRG Energy and Dynegy told FERC that MISO’s Tariff exempts resources that are retiring in the middle of a planning year from the must-offer requirement. FERC did not say whether or not it agreed with the companies’ reading of the Tariff.
Instead, the commission ruled that unlike with IPL, Consumers Energy hadn’t adequately demonstrated that a waiver would not cause undesirable consequences.
“We find it significant that the Classic Seven comprise 940.7 MW of generation in Michigan, which represents approximately 14.5% of Consumers Energy’s total capacity,” FERC said.
Consumers had not identified whether the utilities in MISO Zone 7 have coordinated to provide generation outage schedules for April-May 2016.
In contrast, Indiana utilities did provide MISO with their generation outage schedules far in advance so that MISO could conduct a maintenance margin study for future years, FERC said. MISO’s analysis showed that MISO Zone 6, in which IPL is located, has a sufficient planning reserve margin even after accounting for scheduled outages.
FERC Chairman Cheryl LaFleur seemed to invite Consumers to refile to address the deficiency, noting in a concurring opinion that the order was made without prejudice.
Consumers spokesman Dan Bishop said yesterday that the company was studying the ruling and hadn’t decided whether to refile.
Consumers plans to replace lost generation from the Classic Seven retirement in part with a 540-MW gas generating unit it will acquire in Jackson, Mich. The company will also make wholesale purchases, Bishop said.
Commissioner Norman Bay dissented on the IPL waiver request, saying a one-time waiver “creates an unfortunate precedent that erodes MISO’s capacity construct, undermines the bilateral market for capacity and blurs, unnecessarily, a line that had once been bright.”
American Electric Power has three transmission proposals before the Public Utilities Commission of Ohio, including one project aimed at meeting demand from the shale oil and gas industry.
The 19-mile Biers Run-Circleville 138-kV line, which is slated for completion in 2017, would cost $97 million. The transmission portion would cost $22 million. It serves southern Columbus, Chillicothe and Circleville.
Another 138-kV project, the Biers Run-Hopetown-Delano line, will run for 12 miles across Ross County and cost an estimated $17 million.
The $5.2 million Sparrow 138-kV loop is proposed to support the expansion of a natural gas processing facility north of Cadiz. The facility’s operator, MarkWest Utica EMG, asked for the 2-mile line. As a result of an expedited request before PUCO, AEP is expected to complete construction in June.
NRG Building 360-MW Plant Near Houston; More to Come
NRG Energy says it will build a 360-MW natural gas-fired peaking plant near Bacliff, southeast of Houston, on the site of the former PH Robinson Power Plant.
The plant will contain six GE 7E fast-start combustion turbines relocated from an existing plant in New Albany, Miss. The turbines require no water for cooling, an important attribute in water-starved Texas. The project is scheduled for completion late next year.
NRG says it is also nearly ready to file for permits for two other natural gas-fired plants in the Houston area, both 850-MW combined-cycle plants. It didn’t provide further detail on those projects.
Babcock & Wilcox Spinning Off Generation, Nuclear Ops Companies
Babcock & Wilcox is spinning off its power generation unit into a separate company from its government and nuclear operations.
The power generation business, which will operate under the Babcock & Wilcox name, will provide fossil and renewable generation equipment for projects. The company’s government and nuclear operations business will become BWX Technologies. It will supply nuclear components and fuel to government facilities and provide technical, management and on-site services to both government and commercial facilities.
SoCal Edison Announces Largest Energy Storage Project in US
Southern California Edison is entering into agreements with five companies to procure 261 MW of energy storage, more than five times the minimum required by state regulators.
SCE has applied to the California Public Utilities Commission for approval to go ahead with the plan to meet a state mandate for energy storage, which requires investor-owned utilities to have a total of 1.325 GW of energy storage by 2020.
“The fact that SCE far exceeded the minimum amount of energy storage they were ordered to purchase after comparing multiple solutions head to head demonstrates that energy storage can be competitive with other preferred resources on both performance and value, and that it’s now an integral part of the utility planning tool kit in California,” said Janice Lin, executive director of the California Energy Storage Alliance.
SCE chose the five companies after reviewing more than 1,800 proposals: NRG will provide 0.5 MW; Ice Energy Holdings 25.6 MW; Advanced Microgrid Solutions 50 MW; Stem 85 MW; and AES Energy Storage 100 MW.
Three other California investor-owned utilities will announce their energy storage purchases by Dec. 1, expected to be another 200 MW.
Sunoco Planning $2.5B Pipeline to Quadruple Shale Gas Capacity
Sunoco Logistics, the company repurposing a fuel pipeline to carry Marcellus Shale natural gas liquids to its terminal in Marcus Hook, Pa., announced a $2.5 billion expansion project that would quadruple capacity by the end of 2016.
The Mariner East 2 project, which would follow the path of the original Mariner East pipeline from western Pennsylvania to the Delaware River, would transport propane, butane and ethane from the shale gas fields. The 16-inch pipeline is expected to carry 275,000 barrels of natural gas liquids per day to the Marcus Hook port, compared to the first pipeline’s daily capacity of 70,000 barrels.
The Philadelphia company is rebuilding its closed Marcus Hook oil refinery to store, process and ship gas liquids. The company said it is exploring the possibility of building a manufacturing facility in Marcus Hook to process propane into propylene for petrochemical customers.
Southern Maryland Electric Coop. Named Utility of Year by Solar Group
The Solar Electric Power Association has named Southern Maryland Electric Cooperative the Electric Cooperative Utility of the Year.
The co-op won the award for its commitment to using locally generated solar power to meet its renewable targets. SMECO developed a 5.5-MW solar project on a tobacco farm and is building a 10-MW solar plant. The output will go toward meeting the renewable mandates through 2018.
“SMECO leveraged one of the advantages offered by solar — as well as being true to its co-op mission to bring value to the community it serves — when it chose to build solar within the co-op service area rather than purchase renewable credits from a distant resource,” said Julia Hamm, president and CEO of SEPA. “The co-op also gained valuable hands-on experience with a new resource, inspiring a commitment to continue to expand its investment in solar.”
Fishermen’s Energy Plans to Go Back to NJ BPU in December
Fishermen’s Energy of Cape May, N.J., says it will return to the state Board of Public Utilities once again to seek approval for its proposed 25-MW offshore wind project three miles off Atlantic City.
The BPU previously rejected the $188 million as too costly for ratepayers. But the Obama administration awarded it a $47 million Department of Energy grant, and Fishermen’s CEO Paul Gallagher said his company will give the state agency another go.
“I’ve been living with this for four years and I can’t speculate as to what motivates the BPU,” he said.
Some believe that Gov. Chris Christie has soured on offshore wind and is now focused on appealing to conservative supporters outside New Jersey for a 2016 presidential run. Environment New Jersey Director Doug O’Malley said there is “nothing holding back New Jersey now other than Gov. Christie’s intransigence and, sadly, even though offshore wind has bipartisan support in the state, the governor has his eyes on a different prize right now.”
Westinghouse CEO Sees Bright Future for Nuclear in US
Westinghouse Electric CEO Danny Roderick says the company’s nuclear business is doing very well in the United Kingdom, China and other countries — international markets make up 60% of the company’s business. But he also foresees domestic growth from new U.S. nuclear facilities, where Westinghouse’s AP1000 reactors are already being used at sites under construction in Georgia and South Carolina. “We still see new plants are going to be built in Florida; we see new plants that are going to come up in the Carolinas,” Roderick told the Pittsburgh Tribune-Review. “Those are all progressing right now.”
In the last year, Westinghouse has taken heart from an announcement that Georgia intends on building more than the Vogtle project that is now under construction. Florida Power and NextEra Energy have announced they’re going to start work on the Turkey Point project in South Florida. Duke has continued discussion about building another unit in the Carolinas. And a proposal for a plant using an earthquake-hardened version of the AP1000 is being discussed in Utah.
“So what you’re seeing is, the regulated market actually does give a valuation to 24/7 power and recognizes the need for long-term investments of infrastructure like a nuclear power plant,” he said.
Alliant Energy announced it will expand its Riverside Energy Center in Beloit, Wis., by building a 650-MW combustion turbine combined-cycle plant. The company said it will file for approval with the Wisconsin Public Service Commission early next year and begin construction in 2016. The gas-fueled plant, which will cost between $725 million and $775 million, is expected to go into operation in early 2019.
“Having access to reliable, flexible, around-the-clock power that a combined-cycle energy center offers will be a direct benefit to our customers,” said John Larsen, president of Alliant’s utility WPL. “As part of our long-term planning, the Riverside Energy Center will also be evaluated for the integration of solar energy as we continue to expand our renewables portfolio.”
Insufficient natural gas pipeline capacity is the top concern in ISO-NE’s 2014 Regional System Plan, which was released last week.
“The lack of pipeline infrastructure has raised fuel adequacy for natural gas generators to the top of the list of pressing concerns for New England’s power system,” said ISO-NE CEO Gordon van Welie in a statement announcing the plan.
New England is projected to lose 4,600 MW of generation by June 2017, further stressing a regional power system that barely maintained reliability during last winter’s polar vortex. Of the 8,300 MW of new generation proposed through November, 4,500 MW is natural gas while most of the remainder (3,700 MW) is wind.
Natural gas is projected to rise from 43% of capacity in 2013 to 48% by 2017. Gas produced 45% of the ISO’s energy last year, typically setting the marginal price.
ICF International projects the region will face natural gas shortfalls during winters through 2020. The ISO says it may face gas shortages on 24 to 34 days per winter by 2019/2020 — even more during a severe winter such as 2013/2014.
In addition to highlighting challenges faced by the region, the plan’s 10-year look forward takes note of the region’s increased reliance on energy efficiency and demand response in a climate of relatively flat load growth.
Load Flat but Capacity Short
Including energy efficiency — currently 2,100 MW — the ISO forecasts no growth in total electricity usage, while predicting a 0.7% annual increase in summer peak demand over the 10-year planning horizon.
A year ago, the ISO was predicting a surplus of capacity. But that forecast was undermined by plant retirement announcements that preceded the eighth Forward Capacity Auction in February. The auction fell short of the targeted resource acquisition for the 2018/2019 commitment period, resulting in higher capacity prices than the seven previous auctions.
Chief among the retirements are the 619-MW Vermont Yankee nuclear plant that went offline this year and the 1,517-MW Brayton Point coal-fired generator in Massachusetts, slated to be mothballed in 2017.
Beginning with FCA #9, the ISO will implement a sloped demand curve similar to that used in PJM. The sloped curve is intended to reduce price volatility when the market moves between excesses and shortages. New resources also will be able to lock in clearing prices for seven years, an effort to reduce developers’ risks.
Winter Preparation
For the second year, the ISO will employ a Winter Reliability Program, which includes incentives for oil and dual-fuel generators to increase their oil inventories and for plants to become dual-fuel generators.
The Federal Energy Regulatory Commission approved most of the ISO’s long-term “Pay for Performance” plan, which will reward capacity resources that exceed their commitments and penalize those that fall short beginning in 2018.
One achievement noted in the report is the ISO’s investment in transmission infrastructure. Since 2002, when transmission bottlenecks were seen as the greatest threats to system reliability, 559 transmission projects totaling $6.6 billion have been completed, all but eliminating congestion.
For 2013, real-time system-wide congestion costs totaled only $175,000, and payments for “must-run” generators totaled $54.6 million — representing only 0.6% of the $8.82 billion wholesale electric energy market.
PJM will begin measuring the demand response performance of some residential customers through sampling of interval-meter data under a rule change approved by the Operating Committee Wednesday.
