PJM’s recommended Installed Reserve Margin (IRM) will increase slightly because of the increasing alignment of the RTO’s peak demand with demand outside of the region, according to a preliminary analysis presented to the Planning Committee Thursday.
The analysis recommends an IRM of 16.2% for delivery year 2014/15 (up from 15.9% in the 2012 analysis) and margins of 15.7% for delivery years 2015 through 2017.
(Source: PJM Interconnection, LLC)
The IRM is increasing despite a small reduction in the average Effective Equivalent Demand Forced Outage Rate (EEFORd).
PJM’s Tom Falin told members the reason for the increased IRM was an increase in the “World Peak” — the world’s share of its annual peak coincident with the PJM annual peak — to 96.4% from 95.4% last year. “We’re seeing a little less help coming in from the other regions,” Falin explained.
The study results will re-set IRM for the 2014/15 through 2016/17 delivery years and establish the initial IRM for 2017/18.
The IRM must be finalized by February 1 prior to its use in next year’s capacity auction.
PJM will seek to set a limit on capacity imports before next year’s Base Reliability Auction under a problem statement approved Thursday by the Planning Committee. The problem statement, proposed by PJM, was approved without objections or abstentions.
PJM officials said they are concerned that some of the external resources that cleared in May’s base capacity auction might not be deliverable.
Growing Imports
In the last five base capacity auctions, cleared imports have grown from about 3,000 MW to more than 7,400 MW. PJM officials were especially concerned because most of the cleared imports in this year’s auction came from MISO and other points west, with very little from the north or south. (See Capacity Auction: New Generation, Imports Up, Prices, DR down)
To clear in the auction, external generators currently need nothing more than a request for firm transmission service in the transmission queue, a very low hurdle, say PJM officials.
PJM hopes to win member approval on limits in time to use them in the May 2014 auction. That will require winning FERC approval for changes to PJM’s Reliability Assurance Agreement (RAA) — which governs procedures for maintaining system reliability — before PJM posts its planning parameters on Feb. 1. The RAA changes would have to be filed with FERC by the end of November.
Aggressive Schedule
“It is a very aggressive schedule,” PJM’s Mark Sims acknowledged. Because of the tight timeline, Sims said members should provide feedback on PJM’s Key Analytical Assumptions before the next Planning Committee meeting Oct. 10. Comments can be submitted to RTEP@PJM.com
The assumptions include consideration of monitored facilities, simulated contingencies, existing commitments (long term firm transmission agreements), distribution factors (DFAX) and outage transfer distribution factors (OTDF).
Conflicting Interests
Restricting imports could benefit PJM generators who have been dismayed by falling capacity prices. But it could be challenged by MISO officials, who have complained to FERC that PJM’s modeling of cross border transmission deliverability is unfairly limiting its generation from competing in PJM’s capacity market. (See FERC Likely to Increase Pressure on PJM-MISO Joint Market Talks)
The Planning Committee will consider both an overall capacity import limit and path-specific limits. In addition to potentially reducing export participation in the capacity auction, the limits would be inputs in planning analyses.
A Toronto entrepreneur announced plans last week to build a 1,000 MW merchant transmission line to deliver power from Ontario to PJM.
(Source: Lake Erie Power Corp.)
The “Lake Erie CleanPower Connector” would run under Lake Erie for about 60 miles from Nanticoke, Ontario to Erie County, Pennsylvania.
The HVDC project is expected to cost $1 billion and create 300 jobs over three years of construction. A PJM feasibility study indicated the project would also require about $410 million in upgrades to FirstEnergy’s 345 kV system.
Price Disparity
John Douglas, CEO of developer Lake Erie Power Corp., said the project is designed to capitalize on Ontario’s surplus power and avoid often-congested transmission lines into Michigan and New York.
In August, locational marginal prices at Nanticoke averaged less than $28/MWh (in U.S. dollars), about $6 below the average LMP for PJM’s Penelec zone.
(Source: PJM Interconnection, LLC and IESO)
The biggest price disparity was in hours ending 14-17, with a differential of more than $10/MWh. (See chart)
Douglas says the project also will help U.S. utilities meet their renewable energy portfolio goals. In 2012, the Independent Electricity System Operator of Ontario (IESO) generated 25% of its power from hydro and wind. Most of the balance was split among nuclear (56%), natural gas (14.6%) and coal (2.8%).
With connections to Manitoba, Quebec, New York, Michigan and Minnesota, Ontario currently can export up to 4,800 MW. In 2012, the province had net exports of almost 10 TWh.
Months of meetings
Lake Erie Power has been meeting for months with federal and state regulators and local politicians and fishermen to smooth the way for the project.
The company filed an application with the Federal Energy Regulatory Commission in July (docket #ER13-1979) requesting permission to charge negotiated rates for transmission service on the route. Although the proposal announced last week envisions two cables with 1,000 MW of capacity, the FERC application describes the project as “up to” four lines with a 2,000 MW capacity.
The company hopes to begin construction in 2015 with financing from Toronto-based JCM Capital, a private investment firm focusing on renewable energy projects.
The line will use two HVDC electric cables, each approximately six inches in diameter, a technology similar to that used in the Cross Sound project connecting Shoreham, Long Island and New Haven, Connecticut.
The company’s preferred route would reach shore in Girard Township, Erie County. The line would continue underground about seven miles south of the lake along an abandoned railroad right of way to a $200 million AC converter station adjacent to Penelec’s Erie West substation.
Previous Projects
Douglas has developed wind, hydro and transmission projects over more than a decade following a career in corporate finance and investment banking.
He sold wind farm developer Ventus Energy Inc. to GDF Suez S.A. for $200 million in 2007. He sold another proposed HVDC project — a 1,000 MW line from Montreal to New York City under the Hudson River — to the Blackstone Group LLP in 2010. That project is seeking regulatory approval.
The Operating Committee and Market Implementation Committee endorsed changes to Manuals 12 and 27 to implement new rules regarding black start generators, as approved by FERC in docket ER13-1911. The changes include section 7 of Manual 27: Open Access Transmission Tariff Accounting, and section 4.6 of Manual 12: Balancing Operations. See MIC, OC Review Black Start Manual Changes.
The Operating Committee also endorsed changes to Manuals 1, 3, 10 and 13:
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.
