PJM plans $30 million in capital spending next year, a $2 million reduction from 2013, under a preliminary budget that will be presented to the Board of Managers for approval.
PJM’s Jim Snow told the Operating and Planning committees last week that the proposed budget allocates $18 million for current applications and systems reliability (e.g., eDART, eSuite). Included will be updates to legacy systems not updated in the AC2 project. Also included is a $1.5 million project requested (and partially funded by) the Federal Energy Regulatory Commission that will allow PJM to rerun Day Ahead market results with modified inputs.
Seeking growth as its stock languishes due to low wholesale power prices, Exelon Corp. is on the hunt for another acquisition. Analysts disagree on whether it will look to add another regulated utility or seek opportunities in the merchant sector.
The company’s chief strategy officer told the Barclay’s 2013 CEO Energy-Power Conference last week that prices in PJM’s May capacity auction “were lower than anyone expected and continue to be disappointing to us.” But he said the company continues to see “a disconnect between forward prices and what prices will be when coal plants retire.”
Baltimore Gas and Electric (BGE) will use Opower’s new “Behavioral Demand Response” platform in its upcoming smart meter rollout.
Opower’s system takes individual and neighborhood energy-usage data and turn it into personalized reports delivered via text messages, email and phone. Opower said it believes the new system can dramatically increase residential demand response.
Commonwealth Edison, which has lost 800,000 retail customers to alternative suppliers, is hoping to win some of them back now that it has negotiated new supply deals.
The company lost business to rivals charging six cents per kWh, a three-cent savings from ComEd rates. The company says it has reduced the gap to half a cent per kWh due to the expiration of old electricity agreements.
Dominion Resources won federal approval to export liquefied natural gas to Japan and India from its Cove Point terminal in Maryland. Dominion needed Energy Department approval because neither country has a free-trade agreement with the U.S.
The company plans to spend up to $3.8 billion to upgrade the terminal.
PPL Corp. began shutting down Unit 2 of its Susquehanna nuclear power plant early Saturday after vibration monitoring equipment indicated that two turbine blades may have developed small cracks. Unit 1 will continue generating electricity during repairs.
PPL Corp. said it will pay $1,000 for information leading to the arrest and conviction of anyone caught stealing copper wire and other materials from its substations. Police say they’ve seen an “epidemic” of copper thefts as the price of copper has risen to $3 a pound.
Members Wednesday approved streamlining the demand response registration process.
Reason for Change: Current rules require Curtailment Service Providers to submit customer names to both the Electric Distribution Company and Load Serving Entity. The EDC and LSE have 10 days to approve or deny the registration. If either rejects the application — for example because they were mistakenly associated with the customer — the process has to begin from the start.
The change was motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.
Impact: The Market Implementation Committee approved two proposals:
Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.
An alternative (2b) to remove the LSE from economic registrations, was dropped at the request of Exelon, which had originally proposed it.
The proposals were approved with no objections and five abstentions from Pepco Holdings Inc.
John Brodbeck, of PHI, said his company is concerned that the changes don’t address the fact that DR transactions settle up to 90 days later than Real Time transactions — a lag that impacts balancing operating reserve charges.
The Consumer Advocates of the PJM States (CAPS) has named longtime Pennsylvania government official Dan Griffiths as its first director.
Griffiths, who was chosen from among 20 candidates, will represent CAPS in PJM stakeholder meetings and coordinate communications and strategy. Incorporated last year, CAPS includes consumer advocates for the District of Columbia and 13 states served by PJM.
“I think Dan’s going to be just the right guy,” said Stefanie Brand, president of CAPS and director of the New Jersey Division of Rate Counsel. “He has extensive experience at PJM and a good background on the issues facing the consumer advocate offices. We really want to increase our participation in the stakeholder process and I know Dan will hit the ground running.”
Pennsylvania Experience
Griffiths worked for 18 years at the Pennsylvania Public Utility Commission, serving as manager of planning and research in the Bureau of Consumer Services and as energy assistant to then-Commissioner David W. Rolka.
From 1997 to 2000, he worked as vice president for corporate development at New Energy Ventures (now Constellation New Energy), the director of operations at the Energy Cooperative Association of Pennsylvania, and as a consultant for Customized Energy Solutions.
He moved in 2000 to the Pennsylvania Office of Consumer Advocate as a senior analyst, where he represented consumers before PJM and the Federal Energy Regulatory Commission.
In 2007, he left the consumer advocate’s office to become deputy secretary in the Office of Energy and Technology Deployment at the Pennsylvania Department of Environmental Protection.
After retiring from his state post in 2010, he worked as a consultant for Sustainable Futures Communications, LLC and represented demand response provider Comverge at PJM.
CAPS’ Priorities
Griffiths and Brand said CAPS’ priorities include the PJM capacity market and transmission planning.
“There are tens of millions of people whose electricity costs are largely determined in [PJM], so it’s very important for them to have someone representing them,” Griffiths said in an interview.
CAPS’ bylaws requires that any position taken by the organization be based on a unanimous vote of the board of directors. Because some member states have competitive retail markets while others remain cost-of-service regimes Griffiths said it may be rare for the group to achieve the unanimity required to make filings at FERC.
At PJM meetings, Griffiths will cast proxy votes for individual states if requested.
The Operating Committee Tuesday postponed a vote on proposals to increase penalties for under-performing synchronized reserve providers.
The committee voted 70-0 to delay the vote until five days after PJM provides members with performance data for their own Tier 2 synchronized reserve resources. PJM’s Stan Williams said PJM should provide the requested data within 10 days.
The representative for Dayton Power & Light Co. initially proposed the vote be delayed until the October OC meeting.
Williams said that an October vote would jeopardize PJM’s hopes of enacting tougher penalties by the end of 2013 — and thereby avoid a mention of the issue for the third year in a row in Monitoring Analytics’ State of the Market report.
Williams’ comment angered Brad Weghorst, of PPL. “Are we going to rush a proposal through just so we can make the State of the Market report?” he asked. “I don’t give a crap” about meeting the report deadline.
The Dayton representative, however, agreed to Williams’ request to amend his motion by calling for a special OC meeting five days after the data is provided.
PJM and the Market Monitor proposed increasing the penalties, saying the current penalty structure is insufficient to ensure compliance.
The current penalty is to take away revenue for the hour when the resource did not perform and also require the resource to provide Tier 2 reserves without compensation when needed for three days. If a resource fails to perform in one hour it doesn’t affect its credit for performing in another hour during the same day.
Because Tier 2 SR calls have declined to about once every 10 days from one in every three days, the three-day penalty has lost its bite. A PJM analysis found that between 2009 and 2012 generators provided only 64% of the megawatts they were assigned while demand response resources provided 53% of assignments.
Second Penalty Option
The second alternative was proposed by Dave Pratzon, of GT Power Group, who represents generation owners. Pratzon said the proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.
PJM shouldn’t switch from a “penalty that’s likely too low to catch people’s attention to a penalty that’s too high,” Pratzon said.
Pratzon said one of the causes of the current performance is that many resource owners may not realize they’re being penalized because the penalties aren’t itemized in their PJM bills.
“I believe there’s a shared interest in improving performance,” Pratzon said. “Are there any bad actors in my generation fleet? If there are, I want to get with the station operators … and improve their performance.”
Another member agreed that PJM’s proposal was overly harsh but said Pratzon’s might be too lenient. He suggested a 25% “adder” to Pratzon’s penalty.
Members Wednesday gave preliminary approval to a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.
The Market Implementation Committee approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based. The Markets and Reliability Committee will vote on the measure in a sector-weighted vote as soon as Sept. 26.
The amendment was proposed by a representative of J.P. Morgan Ventures Energy Corp. [Editor’s Note: RTO Insider is prevented from quoting from this representative without his permission due to the Code of Conduct.]
The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.
Reducing Uneconomic Flows
The new product is intended to improve price convergence between PJM and NYISO by reducing uneconomic power flows. Traders would be able to submit “price differential” bids that would clear when the price difference between New York and PJM exceed a threshold set by the bidder. (See PJM, NYISO Tout New Option to Improve Power Scheduling.) This option would be in addition to two current options: hourly evaluations of traditional wheel-through transactions and intra-hour evaluations of traditional LMP bids and offers.
J.P. Morgan’s amendment commits PJM to provide members with the results of its IT SCED forecasts — previously used only by PJM operations — beginning December 15.
Although PJM will file required tariff changes with FERC in the interim, CTS could not be implemented until the MRC votes to approve the use of the algorithm — a vote that would not occur before the July 2014 meeting. “If [members] are uncomfortable with the forecast we could not move forward with CTS until we have an improved” forecast, endorsed by MRC, explained PJM’s Stan Williams. [See table, CTS Implementation Timeline]
A Natural Death
The vote came after a lengthy discussion.
One member asked whether PJM would make public the forecasting model. “We’re trying to understand how to IT SCED comes up with these prices,” he said.
Adam Keech, PJM director of wholesale market operations, said PJM could not disclose the algorithm, which was developed by Alstom Holdings, because of intellectual property concerns.
Another member noted that CTS trades are voluntary and will supplement – not replace – current scheduling options. “If people don’t have confidence in it this dies a natural death because nobody uses it.”
MIC chair Adrien Foley rejected several members’ suggestions that the proposal was being rushed, noting that the committee had been discussing it since July and held a special meeting on the topic Sept. 10.
During the lunch break, PJM officials negotiated with J.P. Morgan on changes to the proposal. (See redlines in the proposal.) After lunch, Foley announced that the RTO and the sponsor had reached a deal.
Notice of Changes
In addition to allowing members to validate the IT SCED forecasts before CTS takes effect, the agreement requires PJM to provide 90 minutes’ notice before making changes to IT SCED that “would have any effect on” forecasts.
Keech balked at J.P. Morgan’s original proposal, which would have required 30 days’ prior notice. Keech said it could prevent operators from making timely changes needed to ensure smooth operations. “You’re handcuffing our ability to fix things that may have nothing to do with this issue,” Keech said. “…If I see a problem, I need to act today.”
The agreement also requires PJM to consider “appropriate” balancing operating reserve charges for CTS transactions in the Energy Market Uplift Senior Task Force (EMUSTF), and to assess transmission service charges on CTS trades “in a manner that is consistent with the transmission service charges for all cross-border transactions.”
Vote Tally
The proposal was approved by acclimation with 43 abstentions and 17 votes in opposition. Edison Mission Marketing and Trading was among those voting no. Those abstaining included FirstEnergy, NRG Energy, Old Dominion Electric Cooperative, DC Energy, Noble Americas, the PJM Public Power Coalition and the PJM Industrial Customer Coalition.
PJM has added more granularity for the Mid-Atlantic area in its load forecasting file. The Mid-Atlantic area is now represented with zonal forecasts for PSE&G (e.g. PSE&G/MIDATL), PECO, PPL, UGI, BG&E, JCP&L, METED, PENELEC, PEPCO, AE, DP&L, and RECO.
The zonal forecasts are apportioned based on the zonal percentage of Mid-Atlantic load in that hour on a similar day (temperature and load) or the prior day’s loads.
The Operating Committee last week endorsed revised charters for the System Information and Dispatcher Training subcommittees.
System Information Subcommitee
Reason for change: Introduction of synchrophasor technology systems to PJM.
Impact: Adds language to core competencies: “SIS members should be knowledgeable in both Information Technology and the generation, transmission and economic operation of the electric power grid. The member should be a leader in either the operations or markets area of their company.”
SIS members are appointed by their Operating Committee member.
Dispatcher Training Subcommittee
Reason for change: The charter was never updated after the subcommittee was upgraded from a task force.
Impact: Removes outdated references; notes that subcommittee reports to Operating Committee.
PJM cut loads in Indiana, Michigan, Ohio and Pennsylvania Tuesday as 90-degree temperatures pushed loads to the highest ever for September, stressing the grid at a time when much generation and transmission was offline due to planned outages.
Load peaked at 144,370 MW Tuesday and would have been higher Wednesday but for demand response. PJM said it tapped almost 6,000 demand response resources Wednesday –- an all time record, equivalent to five nuclear plants –- limiting the day’s demand to 142,071 MW.
Last year, September loads never exceeded 130,000 MW.
Tuesday’s peak load was almost 3% above the RTO’s 140,500 MW forecast. “We under-forecast by quite a bit,” Adam Keech, director of wholesale market operations, told the Market Implementation Committee in a briefing Wednesday.
The large change in temperatures from Monday to Tuesday made load forecasting more difficult, officials explained yesterday. “We look closely at the patterns of the previous day’s temperatures and load when forecasting for a day, and, when they greatly differ, it’s much more difficult to estimate the day’s load,” said PJM spokesman Ray Dotter.
In response to a question from the Michigan Public Service Commission at the MIC meeting, PJM officials acknowledged they had ordered Indiana Michigan Power to shed load. But they provided members no specifics and did not mention that the RTO had cut loads in four states.
That disclosure came when PJM issued a press release later Wednesday, in which it said that the “unusual, extreme heat combined with local equipment problems to create emergency conditions in Indiana, Michigan, Ohio and Pennsylvania. “
The RTO said it was forced to cut load in those areas “to avoid the possibility of an uncontrolled blackout over a larger area that would have affected many more people.”
“We sincerely regret that conditions on the grid yesterday required us to call for emergency reductions in consumer demand,” the release quoted PJM CEO Terry Boston.
The initial statement provided no details on the location, size or duration of the cuts. PJM told RTO Insider Thursday the cuts totaled about 150 MW and ranged from one to eight hours: the Erie South substation, in Penelec, was off for about 6 hours; the Tod substation, in FirstEnergy’s ATSI zone, about 1.5 hours; the Summit substation, in AEP’s Indiana Michigan Power, 1 hour and I&M’s Pigeon River substation, about 8 hours.
According to local media reports, Indiana Michigan Power (I&M) reported more than 3,300 customers in Northwest Fort Wayne lost power at 7:15 p.m. Tuesday, with power was restored by 8:30 p.m.
I&M also cut power to about 1,072 customers in White Pigeon, Michigan, beginning about 1 p.m. Tuesday. All customers were returned to service by 9 p.m.
Wednesday, PJM called on emergency demand response but did not issue any additional load shed orders.
PJM issued a hot weather alert in the west beginning Monday. On Tuesday, it deployed emergency demand response in ATSI from 15:50 to 21:30. Keech said DR set marginal prices at $1,800/MWh “for the better part of peak.”
PJM also had an unusually long spin event — about one hour — because of difficulty maintaining its Area Control Error (ACE). “We under-forecast load… we had to make it up somewhere,” Keech explained.
The Northeast Power Coordinating Council (NPCC) responded to a call for shared reserves with 800 MW.
Exelon’s 3,586 MW Braidwood 1 nuclear plant in Braceville, IL was one of four PJM-area nuclear plants offline for maintenance during the unexpected September heat spike. (Source: NRC)
Keech said the Cleveland interface was a major challenge with multiple transmission lines tripping.
Wednesday brought a maximum generation alert for the entire RTO, with PJM activating emergency DR in both the AEP and ATSI zones. Keech noted that forecasts called for thunderstorms that had the potential of quickly dampening load.
“If the storms come in during the peak we potentially get stuck holding the bag for emergency DR,“ Keech said.
Officials did not provide members any details about the amount of transmission and generation out of service for maintenance. However, the Nuclear Regulatory Commission reported that four nuclear plants in or near PJM – Exelon’s Peach Bottom 3 and Braidwood 1; Dominion’s North Anna 1, Detroit Edison’s Fermi 2 — were out of service today.
The Energy Information Administration last week highlighted PJM’s response to the retirement of coal-fired generation in the ATSI zone in northern Ohio.
FirstEnergy’s retirement of 1,400 MW of generation in 2012, and planned closure of an additional 885 MW in 2015, will reduce generating capacity in the ATSI zone by 21%. But PJM was able to compensate with transmission, EIA noted in its Today in Energy feature, because of its 29% reserve margin.
“In a highly populated area that requires significant backup power in reserve, it may be more cost-effective to upgrade the transmission system” than build new generation, EIA said.
(Source: Energy Information Administration)
In May, the PJM Board of Managers approved more than two dozen transmission projects in ATSI to address the retirements, at a projected cost of about $1 billion. Replacing FE’s coal generation with 2,285 MW of new advanced combined cycle units would have cost almost $2.3 billion, according to EIA’s estimated overnight capital cost of $1,003/kw.
Capacity prices in the ATSI region, which cleared at about $350/MW-day in the 2015-16 auction conducted last year, fell to less than $100/MW-day in the 2016-17 auction, conducted after approval of the transmission upgrades.
The projects include the new Toronto-Harmon 345 kV line ($218 million) and the Mansfield-Northfield 345 kV line ($184.5 million).
