PJM’s scheduling rules aren’t flexible enough to meet the needs of wind and other variable energy resources, the Federal Energy Regulatory Commission ruled last week.
The commission said PJM’s rules failed to meet the requirements of Order 764, which requires transmission providers to offer scheduling at 15-minute intervals. FERC ordered PJM to submit a new compliance filing within 30 days.
Prior to Order 764, the pro forma Open Access Transmission Tariff — developed for generation that could be scheduled with relative precision — included no option for adjusting transmission schedules within the hour.
As a result, variable energy resources could not avoid generator imbalance charges when they knew their generation was likely to change within the hour. Generator imbalance charges pay for energy the transmission provider must purchase when a generator’s output falls short of the amount scheduled.
The revised pro forma OATT requires that transmission providers allow scheduling changes be made within 20 minutes “or a reasonable time that is generally accepted in the region … before the start of the next scheduling interval.” The commission said it wanted to allow generators to adjust their schedules in 15-minute intervals.
PJM proposed amending the firm and non-firm point-to-point transmission service provisions of its Tariff to allow 15-minute schedules. But the commission said it was not compliant with Order 764 because the proposed Tariff required that the changes be made 20 minutes “before the next clock hour,” rather than before each 15-minute interval.
(As a practical matter, PJM said it does not assess imbalance penalties on any generators, because virtually no market participants use point-to-point transmission to serve load.)
Interchange Transactions
FERC also took issue with PJM’s practice of requiring that interchange transactions have a minimum duration of 45 minutes, which the commission said “is inconsistent with Order No. 764 because it does not allow a generator to schedule for less than three consecutive 15-minute intervals.”
PJM said it implemented the 45-minute rule on interchange transactions in 2008 to prevent “market abuses.”
In 2007, MISO and its Independent Market Monitor determined that nearly 60% of intra-hour schedules between MISO and PJM occurred in the final 15 minutes of the hour. PJM said the trading was the result of “market participants’ ability to see price differences between the two RTO markets for the first third of the hour and thereby predict with relative certainty the direction of the price separation between the two RTOs when the hourly integrated prices were calculated.”
PJM said this resulted in interchange spikes of up to 1,000 MW — increasing uplift charges because of the need to call on combustion turbines to balance the generation swings.
“A return to a 15-minute duration rule would cause an increase in imbalance charges [and balancing operating reserve] costs because it is entirely reasonable to expect that market participants would return to the [prior] practices,” PJM said.
Last year, the commission rejected MISO’s proposal to retain an existing requirement that schedules starting at the 30- and 45-minute marks of the hour be made by the beginning of the hour, which MISO said was intended to prevent the problems identified in 2007.
The commission last week granted MISO an extension until June 30, 2015 to fully implement Order 764.
Data Requirements
Order 764 also requires variable resources to provide meteorological and forced outage data to help transmission providers more accurately forecast generation. The commission accepted PJM’s addition of these requirements to its Tariff.
Calpine Corp. is selling six power plants in the Southeast and Midwest to LS Power for $1.57 billion in cash as part of a plan to focus on its electricity sales businesses in the Mid-Atlantic, Texas and California. The plants — representing a combined 3,498 MW — are in Alabama, Oklahoma, Louisiana, Florida and South Carolina.
Calpine spokesman Brett Kerr said the company planned to sell the six power plants for some time. It wanted to sell additional plants in Alabama, Arkansas and Florida but wasn’t able to get the price it needed for those assets. The LS Power deal is expected to close in the second quarter, and Calpine said it plans to use proceeds to pay down debt, buy back shares and possibly buy new generation.
The company operates 77 natural gas-fired power plants across the U.S., including 24 in California, 20 in Mid-Atlantic states and 14 in Texas. Calpine also has geothermal power plants in California.
PSEG’s Izzo Frustrated Over Opposition to “Energy Strong”
Ralph Izzo (Source: PSEG)
A frustrated Public Service Enterprise Group chief executive Ralph Izzo last week renewed his call for the state to approve a multibillion-dollar infrastructure-hardening project the company proposed shortly after Hurricane Sandy. In comments following PSEG’s annual shareholder meeting in Newark, Izzo questioned how the project’s opponents could maintain what he believes are two competing objections: that it costs too much and that it won’t help enough customers.
“The only way to reconcile those two is by saying, OK, we’re not proposing to spend the money in an optimal way,” Izzo said in an interview. “In which case, I say, we’re an open book. Tell us a better way to do it. And the reality is, there isn’t a better way to do it.”
Izzo said part of the planned 10-year, $3.9 billion “Energy Strong” project calls for strengthening facilities that were damaged by Sandy and Tropical Storm Irene. Newark-based Public Service Electric & Gas — PSEG’s largest subsidiary — filed Energy Strong with the state Board of Public Utilities in February 2013, four months after Sandy. While the utility maintains the project would improve reliability and help prevent the kind of massive power outages Irene and Sandy caused, opponents have pushed back against its price tag. The state Division of Rate Counsel, AARP New Jersey and a coalition of large energy users have also questioned the project’s stated effectiveness and the utility’s insistence on receiving approval for the money before starting construction.
As Stock Slides, Exelon’s Crane Gets 70% Raise in 2013
Christopher Crane (Source: Exelon)
Even as the company’s stock slid nearly 8% last year, Exelon Corp. CEO Christopher Crane was rewarded with a 70% raise, making more than $17 million in 2013. Crane’s total compensation in cash, stock and benefits topped out at $17.2 million, up from $10.2 million the year before. Crane’s compensation moved to a new performance-pay system that ties rewards over a three-year period rather than year-by-year. The company also eliminated stock options and moved its stock-based compensation to restricted shares and performance shares.
Exelon said it raised Crane’s pay to make it comparable to the median for peer CEOs. Before 2013, his pay was targeted at 20% less than the median. Exelon has suffered from falling wholesale power prices as its nuclear plants have grown less profitable. Increases at its regulated utilities — particularly ComEd, which is collecting annual delivery rate hikes per a state law authorizing $2.6 billion in local grid upgrades — have partially offset the declines at the power plants. But the 8% stock slide last year followed a 31% drop in 2012.
Duke Shareholders Urged To Oust Board Members Over Ash
Two of Duke Energy’s major institutional investors are urging fellow shareholders to vote out four directors at the May 1 shareholders meeting over the company’s ongoing coal ash problems. The California Public Employees’ Retirement System (CalPERS) and the New York City Pension Funds wrote shareholders last week, asking that they not reelect four board members responsible for environmental safety and health compliance.
Ash Spill (Source: Duke Energy)
The letter cites the Feb. 2 ash spill into the Dan River, saying Duke had “forewarning of the public risk” from environmental groups that had intended to sue Duke over ash contamination. None of the committee members named — Alex Bernhardt, James Hyler, James Rhodes and Carlos Saladrigas — has coal industry or other relevant experience, CalPERS and New York City comptroller Scott Stringer wrote. “In light of the serious failures of oversight, scale of impact on the company’s risk profile and the poor response to shareowner enquiry thus far, we urge our fellow investors to hold the relevant board members accountable.”
Duke said last week it has spent $15 million so far cleaning up the spill but said the costs would not be “material” to the company. Duke CEO Lynn Good has said Duke will pay for cleaning up the 70-mile trail of ash in the Dan River, but that it will ask the North Carolina regulators to approve ratepayer funding of costs associated with closing 33 ash basins at Duke sites across the state.
Duke had no immediate comment on the stakeholders’ action. CalPERS owned $140 million in Duke stock in 2013. The New York City funds have $62 billion in U.S. stocks, although it’s unclear how much of that is Duke stock.
PPL Generation, Trading Sale Rumors Fuel Stock Rise
PPL Corp. stock is trading near the top of its 52-week range amid continued speculation that the company may spin off its generation and energy marketing business. PPL shares closed Friday at $33.14, close to its 52-week high of $33.55. The rise came after the International Strategy and Investment Group raised its target price for PPL, citing the strength of its regulated utilities and the potential benefit if it spun off its generation. The report also cited the potential upside for PPL if it merged its power plants with another company’s.
A trade publication earlier this year published a report saying PPL hired Morgan Stanley and Citibank to conduct an internal review of PPL Energy Supply, the business arm that includes PPL’s generation and energy trading and marketing businesses. That report pointed at Dynegy as a possible buyer. PPL declined comment on any sale or spinoff rumors.
Dominion Virginia Power will conduct an earthquake risk assessment for its North Anna nuclear generating station but doesn’t expect the study to point to any significant modifications. The plant’s two 980-MW reactors were knocked offline by a 5.8-magnitude earthquake that shook central Virginia in August 2011. Although the temblor caused no significant damage, the station remained out of service for three months while the company and the Nuclear Regulatory Commission conducted a thorough safety check.
“These plants have so much design margin on the seismic side, I have no concerns about this whatsoever,” said David A. Heacock, president and chief nuclear officer of the parent company’s Dominion Nuclear operating group, said last week. “We verified our plant can withstand a stronger earthquake” than it was designed for.
In 2012, the U.S. Department of Energy, the Electric Power Research Institute and the NRC updated the seismic model for the central and eastern U.S., reflecting a greater seismic hazard at some nuclear plants than previously thought. Forty-seven plants will have to conduct additional studies to determine whether their designs protect them from earthquake hazards. Once the assessments are complete, the NRC will decide if plants require upgrades.
A judge allowed a competitor of a Delaware fuel cell company to challenge a state-sanctioned surcharge added on the bills of Delmarva Power customers last Thursday. U.S. District Court Magistrate Christopher Burke decided that FuelCell Energy, of Connecticut, can go forward with its suit against Delaware Gov. Jack Markell and the state Public Service Commission, saying it violated the Constitutional prohibition against state interference with interstate commerce.
The subsidy was created and approved by the commission in 2011 in a successful attempt to get Bloom Energy to move its fuel cell operation from California’s Silicon Valley to Delaware. The subsidy is funded by a surcharge on Delmarva’s residential customers averaging $4 to $6 a month. Burke wrote in his ruling that the tariffs help Bloom, but not FuelCell, and put FuelCell at a competitive disadvantage. There was no public solicitation for bids from out-of-state fuel cell companies.
ComEd Asking For Rate Hike; Says Improvements Paying Off
Commonwealth Edison Co. is asking for a rate hike, marking the fourth time since 2011 that the company has gone to regulators for permission to boost rates for modernization programs. The company said this increase request would add about $3 to the average electric bill. ComEd says improvements already undertaken have prevented 500,000 power outages, saving consumers about $82 million.
“These improvements, if done right, should pay for themselves in the long run, but the key moving forward is to hold ComEd accountable,” said Jim Chilsen, a spokesman for consumer advocacy group Citizens Utility Board in Chicago.
South Side Petcoke Storage Spurs Residents’ Outrage
(Source: MidWest Energy News)
Southeast Chicago residents vowed to take their fight to the streets over the increasing piles of petroleum coke being stored in their neighborhood. Saying they’ve been let down by elected officials who last year promised to crack down on companies storing the fuel, residents are planning an April 26 march and a boycott of BP, the source of the “petcoke” being stored along the Calumet River.
An expected City Council vote on an ordinance that would have limited petcoke storage morphed into a tamer proposed ordinance that allows more petcoke storage. Opponents are concerned the new ordinance would be the first step in the eventual approval of a contentious proposal for a synthetic gas plant in the area.
The gas plant plan was tabled last year after Gov. Pat Quinn vetoed legislation that would have committed Chicagoans to pay a fixed rate for synthetic gas from the plant for 30 years, even if market natural gas prices were much lower.
Ameren Brags on Upgrades; Critics Remain Unconvinced
Ameren Illinois’ pride in its transmission and distribution upgrades and resultant reliability improvements are being met with a jaded eye by some customers. The company said the $625 million spent on upgrades have shown a 20% improvement in reliability and savings worth $57 million a year since 2012 for residential and small business owners. Ameren Illinois was forced to make the investments, which included smart meter installations and energy-efficiency programs, under the Illinois Energy Infrastructure Modernization Act of 2011.
“This is a long-term process, but we have been able to deliver results to customers while keeping their rates reasonable,” said Ron Pate, senior vice president of operations for the utility.
Critics hope Ameren’s calculations are right but think the company may be jumping the gun. “We haven’t seen the evidence yet, and we think it’s too early to tell,” said David Kolata, executive director of the Citizens Utility Board public watchdog group. “It’s really going to be in the next six months that we’ll really start to get a read on it.”
East Kentucky Power Cooperative plans to shut down all four units at the 196-MW William C. Dale coal-fired power plant in Clark County over the next year, but the company said the two largest units will be held ready for restart if needed. East Kentucky decided that retrofitting the units so they meet 2015 pollution limits would be too expensive. The company said it has often been cheaper to operate other plants or purchase power from the market, particularly since East Kentucky’s 2013 integration into PJM.
“Dale Station was East Kentucky Power Cooperative’s first power plant,” Tony Campbell, the co-op’s president and CEO, said in a statement. “This plant has been a reliable workhorse, generating the electricity that powered many thousands of Kentucky homes and businesses over the past 60 years.”
East Kentucky also owns and operates the 341-MW Cooper baseload coal plant in Pulaski County and the 1,279-MW Spurlock baseload coal plant in Mason County. The co-op has installed pollution controls on both plants and intends to continue operating them.
The Public Service Commission is giving utility customers a gift after a brutal winter: a two-month extension to the period when certain utility companies can cut off service to non-paying customers. The new deadline is May 31, instead of March 31, and applies to Baltimore Gas & Electric Co., Potomac Electric Power Co. and Delmarva Power Co.
The utilities themselves had proposed the extension during a meeting with the commission. The commission is calling for all Maryland utilities to adopt the extension and wants utilities to move faster in switching customers with smart meters to competing retail suppliers when asked.
Southern Maryland Electric Cooperative signed a 20-year power purchase agreement last week with the developers of a proposed 10-MW solar facility in Charles County. Under the PPA with Juwi Solar Inc., SMECO will purchase all energy, capacity and renewable energy credits from the Rockfish Solar farm. If approved by the Public Service Commission, the $40 million project is scheduled to be completed by the end of the year.
SMECO has a 5.5-MW solar farm in Hughesville and purchases energy from two wind projects in Pennsylvania.
Attorney General Roy Cooper is returning to the state Supreme Court to try to block Duke Energy’s recent rate increase. Cooper argues that the state Utilities Commission failed to weigh the rate hike’s economic impact on Duke’s electricity customers.
The Utilities Commission originally approved Duke’s 7.2% rate increase in 2012 and upheld its decision in 2013. The state Supreme Court agreed with Cooper the first time around, setting up the current challenge. Now Cooper says the Supreme Court needs to send a clearer message to get the point across.
“The commission’s position is deeply unfair to consumers,” according to the attorney general’s legal challenge, which was filed Thursday.
Duke said the commission did everything correctly. “We believe the commission’s order satisfies all of the requirements set out by the N.C. Supreme Court and that the commission properly weighed the evidence,” the company said in a statement.
Thomas W. Johnson was sworn in last week as the new chair of the Public Utilities Commission, bringing with him experience in finance and budget issues from 22 years in the Ohio House. Johnson takes the helm of the 330-person agency for a five-year term.
(Source: PUCO)
Gov. John R. Kasich swore in Johnson Wednesday, after expressing misgivings over the state’s move to retail choice.
“The ideological effort to deregulate, I’m not so sure it’s the smartest thing we’ve done in the state of Ohio,” Kasich said, speaking to the audience in the PUCO chamber before the swearing-in. “But we are where we are, and we can’t go backwards now. So it’s onward in a deregulated environment, and we’ve got to figure it out.”
Poll Shows Ohio Voters Back Renewables, Efficiency
Ohio residents overwhelmingly favor using renewable power to replace coal-fired generators and want utilities to help customers increase energy efficiency, according to a poll commissioned by a green energy advocacy group. The telephone survey of Ohio voters found that 72% favor renewable energy over traditional power plants and 86% favor mandated utility energy efficiency programs. Two-thirds of those polled said they would back legislative candidates who promote renewable power over those who continue to support coal and nuclear power plants.
The poll was commissioned by Ohio Advanced Energy Economy, which opposes a Republican-backed bill that would freeze energy-efficiency efforts at the current level pending a study.
AEP Consolidating TX Ops To New Building in New Albany
American Electric Power plans to build offices in New Albany for its division that manages the interstate flow of electricity, bringing together about 500 workers who are now based at several central Ohio locations.
AEP Transmission Executive Vice President Lisa Barton said the company expects “significant cultural, operational and efficiency benefits” from having all transmission operations employees in one spot. The new headquarters will be completed in about two years.
PPL Electric Utilities wants to update its price to compare for default electricity customers twice a year, rather than quarterly, according to a proposal filed with the Public Utility Commission. PPL said twice-yearly prices “will provide customers more certainty around shopping and provide retail suppliers with more time and flexibility in creating pricing programs to encourage customers to shop.”
The price to compare is the price customers pay for generation and transmission if they don’t choose a competitive electricity supplier. PPL’s plan would cover the period from June 1, 2015 to May 31, 2017. The PUC is expected to rule on the request in early 2015.
Appalachian Power will ask the State Corporation Commission to let it increase the monthly residential customer charge from $8.35 to $16, but offset that by decreasing the base rate for each kilowatt-hour used. The SCC has set a Sept. 16 hearing date in Richmond to review the electric provider’s rates.
The SCC will review Appalachian Power’s generation, transmission and distribution rates, with any changes approved to take effect early next year. Appalachian Power also is seeking to establish two residential energy-efficiency programs. Appalachian Power serves about 500,000 customers in Virginia.
Stakeholders will attempt to develop more accurate measurement and verification of residential demand response under a problem statement approved by the Market Implementation Committee last week.
PJM currently measures load reductions for much of its residential DR based on data that was compiled more than a decade ago in Maryland and New Jersey.
PJM’s Shira Horowitz said the data is no longer representative because of the growth of PJM’s footprint, changes in DR programs and increases in the energy efficiency of air conditioners and other appliances.
The old data were collected based on legacy “direct load control” (DLC) programs. Residential demand response now includes use of smart meters and programmable thermostats.
Some stakeholders questioned why PJM wants the review to include firm service level (FSL) and guaranteed load drop (GLD) programs in addition to DLC.
“I’m not seeing any concerns with the other two verifications,” said one stakeholder. “I’m struggling with why we want to expand this past DLC programs.”
Pete Langbein, of PJM, said the RTO wants to take a holistic approach to the issue.
“Residential [DR] is unique. We’re not dealing with a few thousand customers, we’re looking at millions,” he said. “From PJM’s standpoint, we don’t think we should limit this to DLC.”
Residential demand response supplies about 1,000 MW of capacity in PJM.
Among the many questions about the pending EPA carbon rules on existing generation are how state implementation rules will mesh with regional compliance approaches and what role RTOs such as PJM will play.
Paul Sotkiewicz, chief economist, PJM
PJM stands ready to help, Paul Sotkiewicz, PJM’s chief economist, told a Bipartisan Policy Center forum last week.
The economies of scale that RTOs have brought to unit dispatch, planning and other grid functions can also help reduce the costs of complying with the greenhouse gas rules, Sotkiewicz said.
“We can reflect the cost of environmental retrofits. It makes sense to piggyback on the existing infrastructure,” he said.
While it will be up to state officials to decide what the RTO role is and whether they want to participate, states that go it alone, he said, “are leaving money on the table.”
Two visions for how RTOs might take part were sketched out earlier this year. In January, PJM and other RTOs asked the EPA to allow states to meet the greenhouse gas rules through regional caps and to include a “safety valve” to maintain reliability.
ISO/RTO Council
The ISO/RTO Council (IRC) said that it usually doesn’t take policy positions on EPA regulations, but that it wanted to ensure EPA officials “recognize the relationship between proposed environmental rules, electric system reliability and economically efficient dispatch.”
The council’s seven-page proposal asks the EPA to allow states to adopt State Implementation Plans (SIPs) based on “a regional measurement mechanism for determining compliance.” The group also said the EPA’s regulations should include a process to mitigate reliability impacts of the regulations.
MISO Role Envisioned
In February, The Brattle Group and Great River Energy, a cooperative in MISO, proposed that RTOs build the carbon emission limits into their markets instead of making individual generators or states meet them.
Jeanne Fox, commissioner, New Jersey Board of Public Utilities
For the states that joined MISO or other regional operators, “It doesn’t seem like much of a stretch to add carbon management to that plate,” said Jon Brekke, vice president of Great River.
The proposal would have RTOs and ISOs translate EPA emission reduction limits into targets for their regional power markets. The reductions would be met by applying an RTO- or ISO-administered carbon price to generation and refunding the revenues to load serving entities based on consumption levels.
“This not a social cost of carbon … this is an economic signal,” said Brekke, who added that it would avoid stigma as a “tax” because the funds would go to LSEs rather than government.
Asked after the forum whether MISO was willing to take on the market-clearing role envisioned in the plan, Brekke responded: “We know that MISO is willing to facilitate a discussion that’s state-led.”
The idea of a regional solution is “getting traction,” he added. “Whether it’s our approach or another is secondary.”
RGGI Redux?
A top Delaware official, meanwhile, pitched the nine-state Regional Greenhouse Gas Initiative (RGGI) as a “plug-and-play” solution that other jurisdictions could adopt.
Collin O’Mara, secretary, Delaware Department of Natural Resources and Environmental Control
Carbon emissions in RGGI states have dropped by nearly 52% since 2005, thanks to energy efficiency and fuel switching — as well as the lackluster economy.
Current emission levels are 45% below RGGI’s 2013 cap, said Collin O’Mara, secretary of the Delaware Department of Natural Resources and Environmental Control. Participating in addition to Delaware are Connecticut, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont.
Money collected through RGGI is reinvested in energy efficiency and renewable energy giving every expenditure a multiplier effect twice or triple the investment he said. (New Jersey Gov. Chris Christie, however, used some of the revenues to balance his budget before pulling the state out of the program in 2011.)
Rather than calling it cap and trade, however, O’Mara suggested a less politically combustible name: “budget and invest.”
New Jersey’s Democratic-controlled legislature has tried on several occasions to pass legislation reversing Christie’s decision, but it has been defeated by vetoes. “I don’t see [rejoining RGGI] happening in the near future,” said New Jersey Board of Public Utilities Commissioner Jeanne Fox.
Seams
The PJM-MISO seam has vexed both regions for years, but when it comes to GHG compliance it could be a boon, Sotkiewicz said.
State implementation plans for the four states split between PJM and MISO — Michigan, Illinois, Indiana and Kentucky — could manage emission allowances across RTO borders, he said.
“Rather than seams being a problem it actually creates fungibility between different regional compliance programs,” Sotkiewicz said. “Rather than being a barrier, per se, it almost becomes an opportunity.”
PJM is planning a system-wide drill Sept. 23 to simulate simultaneous physical attacks on critical substations, cyber attacks and the loss of supervisory control and data acquisition (SCADA).
The drill will assess PJM’s and transmission operators’ readiness to respond to nation-state sponsored attacks.
It will incorporate lessons learned from the North American Electric Reliability Corp.’s GridEx II, an exercise that drew participation from 200 organizations, including PJM, in November. Some participants complained that the GridEx “injects” were introduced too rapidly and that communications between participants didn’t use real-world methods. (See Grid Exercise `Like a Disaster Movie.’)
“GridEx was a good exercise, but sometimes they used communication paths that were not traditional,” said LeRoy Bunyon, PJM manager of business continuity planning. He said the PJM drill will feature communication “not between planner and planner, but operator to real operator.”
According to a presentation to the Operating Committee last week, the drill will test the communication channels between PJM and transmission owners and their ability to respond to attacks by implementing emergency procedures.
Bunyon said PJM will participate using its Dispatcher Training Simulator and asked transmission owners to consider simulator use, as well, instead of using the drill as a tabletop exercise. He asked transmission owners to designate planners to help develop drill materials and conduct training.
Fuel procurement and environmental limitations are the top obstacles to increasing the flexibility of PJM’s generating fleet, according to survey results released last week.
About 83% of generator operators responding to the survey said they are operating to the limits of their plants’ flexibility. Of the remaining 17%, most cited fuel and emissions limits, with insufficient compensation “a distant third,” PJM said.
The survey was developed in response to what Adam Keech, manager of wholesale market operations, said was a decline in generation flexibility over the last decade.
PJM’s Eric Hsia told the Market Implementation Committee last week 20% of those who said their units were being offered as flexibly as possible reported their flexibility has decreased over time. Among the reasons cited were compensation rules that discourage investment in aging plants, lack of fuel, emission limits and “additional risk of tripping.”
PJM’s next step will be one-on-one meetings with companies to get more details. Hsia said some of the fuel issues are already being addressed by the Gas-Electric Senior Task Force.
Bethlehem SPS (Source: Calpine and PJM Interconnection LLC)
Calpine announced a special protection scheme that will allow the outage of the Blooming Grove-Bushkill 230-kV line July 1 to accommodate construction of the Susquehanna-Roseland 500-kV line. According to a presentation to the Operating Committee Tuesday, the SPS also takes into account the expected retirement of the Portland coal units, scheduled for June 1.
The SPS calls for the trip of Unit 8 at Calpine’s Bethlehem station to relieve potential congestion from the loss of either of the two Steel City-Quarryville 230-kV lines. The SPS is expected to end in summer 2015 with the completion of the Susquehanna Roseland 500-kV line.
New Line Designations at Breinigsville
Breinigsville line designations (Source: PPL and PJM Interconnection LLC)
PPL announced new line designations coming out of its new Breinigsville substation. PPL plans to reuse the 5044 designation, currently used for the 500-kV Wescovsville-Alburtis line, for the Wescosville-Breinigsville 500-kV line. It would then christen the Breinigsville-Alburtis 500-kV line as 5058.
The new Breinigsville substation is designed to protect against excess voltage drop on 138-kV lines between Wescosville and Seigfried, excess transformer load at the Wescosville substation, and maximum allowable load drop if the Wescosville-Trexlertown #1 and #2 lines are lost.
The project is expected to be completed in May 2015.
The Federal Energy Regulatory Commission last week rejected Consolidated Edison Co.’s attempt to avoid paying for a major transmission upgrade in northern New Jersey but suggested it might order PJM to recalculate the company’s bill.
FERC’s ruling (ER14-972) approved PJM’s cost allocation for 111 baseline reliability upgrades included in the RTO’s Regional Transmission Expansion Plan (RTEP), including 17 eligible for regional cost allocation under Order 1000.
Only one of the projects, a $1.2 billion project upgrade to address thermal overloads and short circuit problems in the PSEG transmission zone outside New York City, was challenged. (See PJM: Con Ed Protest over PSEG Upgrade Groundless.)
PSEG Short Circuit Solution (Source: PJM Interconnection, LLC)
The project will convert Public Service Electric and Gas Co.’s Bergen-to-Linden 138 and 230 kV transmission line to 345 kV and add a second 345 kV transmission line between those points.
PJM’s cost allocation assigned $629 million of the cost to Con Edison under the Con Ed-PSEG “wheel,” in which PSEG takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City.
Also challenging the cost allocation for the project is Linden VFT LLC, which owns a 315-MW merchant transmission facility that interconnects both PJM and NYISO. Linden said its RTEP bill would increase by $2.5 million annually as a result of the project.
FERC rejected Con Ed’s contention that it was not liable for the project because the reworked transmission grid would change its delivery point from that specified in its contract with PJM.
But the commission said it wanted more information on how PJM performed the distribution factor (DFAX) analysis that determined Con Ed’s share of the cost.
Con Ed says it was unfairly assessed almost 83% of the $762.6 million assigned through DFAX for its 1,000 MW wheel while PSEG was assessed only 7%, despite load of 11,000 MW. Con Ed said the cost distribution for the project is “grossly disproportionate to the relative loads” of the two companies.
“We cannot determine from this record whether the issues raised by Con Edison are generic issues related to the implementation of Solution-Based DFAX or are specific assumptions relating to this project,” the commission wrote.
Thus it ordered PJM to submit a compliance filing within 30 days “explaining and justifying the specific assumptions relating to the PSE&G Upgrade.”
Rules covering how PJM reallocates load when a load serving entity defaults can’t be found in the RTO’s manuals because, well, it doesn’t happen much.
But the collapse of two retail marketers after a spike in wholesale power prices during January’s arctic cold showed that load reallocation rules are needed, PJM officials told the Market Implementation Committee last week.
While there are mechanisms for collecting from other PJM members the $2 million in unpaid bills the two retailers left behind, what happens to the load the two companies had been serving is not clearly laid out in PJM’s rules.
Michelle Souder, of PJM’s member relations department, said PJM will add a new Section 3.2.4 to Manual 33: Administrative Services for the PJM Interconnection Agreement that covers this eventuality.
The new rules specify that PJM will notify the electric distribution companies delivering power to the retailer’s customer of the need to reallocate the load “as soon as such default is evident to PJM” and no later than the day the LSE is declared in default.
PJM will notify the EDCs by 10 a.m. the day after declaring an LSE in default whether the LSE has provided the funds to return to good standing. EDCs will not be required to reverse the load reallocation even if the LSE cures the default.
The manual language will be shared with the MRC later this month and presented to both groups for endorsement in May.
Bid Volume Limits
PJM is also considering a rule change that the RTO said would likely have reduced the size of the retailers’ January defaults.
PJM’s Hal Loomis outlined a proposal to prevent LSEs from entering day-ahead demand bids that are more than 20% and more than 10 MWs above their peak load forecast for the day.
“This would provide a way to keep inappropriately high demand bids from clearing,” including those resulting from data entry errors, said Loomis.
Had the proposal been in effect Jan. 7, at least 4% of demand bids would have been rejected, PJM said.
PJM will gauge the Credit Subcommittee’s interest in developing such a limit based on results of survey that closes today.
