The Markets and Reliability Committee Thursday approved two changes to the modeling of Financial Transmission Rights — an effort PJM hopes will reduce the risk of FTR funding shortfalls.
The changes make FTR modeling more consistent with that used in the energy markets and reduce or remove infeasibilities in the FTR model, allowing increased counterflow FTRs to clear.
The Financial Transmission Rights Task Force chose the two changes from more than 20 options.
Under the first change, PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.”
The second change will allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”
PJM’s Tim Horger said the RTO hadn’t quantified the impact of the changes, although an analysis for one constraint found more than a $15 million improvement in FTR adequacy.
Wind farms that fail to follow PJM’s electronic dispatch signals will no longer receive lost opportunity cost payments under a tariff amendment outlined to the Markets and Reliability Committee Thursday.
The MRC approved a problem statement that — in a departure from normal practice — was accompanied by the proposed tariff change. The tariff change will be brought to a vote at the next MRC meeting.
PJM proposed adding language to Section 3.2.3 of Tariff Schedule 1 to deny lost opportunity credits to pool-scheduled or self-scheduled wind generators that fail to follow PJM dispatchers’ electronic instructions to reduce output.
“We have (wind) operators not following the economic basepoints,” PJM’s Dave Souder told members. “They’re waiting for PJM to call them.”
Having to issue manual dispatch instructions delays generators’ responses, causing less efficient market operations and a potential risk to system reliability, PJM says.
PJM proposed the new language as a Tariff change in response to a May 29 Federal Energy Regulatory Commission order that rejected its earlier proposal to incorporate the new rules in the Operating Agreement. The commission said the OA language “failed to provide any detail or tariff language describing the specific circumstances under which compensation would be reduced or how the compensation would be reduced.”
Robert O’Connell, vice president of J.P. Morgan Ventures Energy Corp., said the rules were unfair because they were “developed behind closed doors” and would treat wind differently than other generation. O’Connell also objected to the inclusion of the tariff language in the problem statement. “Anything that comes with tariff language is a solution,” he said.
Mike Kormos, PJM senior vice president for operations, said PJM already had rules penalizing other forms of generation for not following dispatch instructions. “We’ve had this in the rules for eternity,” he said.
Market Monitor Joseph Bowring supported PJM’s proposed tariff change as “exactly right.
“This is a narrow problem that needs to be addressed,” he said.
O’Connell’s motion to return the problem statement to the Market Implementation Committee without the tariff proposal was ruled out of order by Kormos, the chairman of the MRC. Kormos said it would set a precedent to prevent a vote on a problem statement.
In a rare move, O’Connell appealed the parliamentary ruling to the members. His appeal received less than 15% support in a sector-weighted vote, far below the two-thirds needed to overturn the ruling.
The problem statement was approved with three abstentions and no objections.
If it’s the last Thursday of the month it’s meeting time for PJM’s two senior committees – and likely a vote on at least one problem statement directed at demand response resources.
At last week’s session, the Markets and Reliability Committee approved one problem statement and deferred a vote on a second that would change rules affecting DR. Meanwhile, the Members Committee approved a tariff change that increases DR providers’ documentation requirements.
The problem statement approved by MRC will explore changes to the way PJM calls on DR. The deferred issue would look at ways to ensure that DR and other resources offered into the capacity market show up in their delivery year.
“There’s been a freight train of changes for the DR market that have happened without evaluation of [the impact of] prior changes,” Dan Griffiths, of DR aggregator Comverge, said during a discussion on the first issue.
In a discussion on the second problem statement, Griffiths used a different metaphor, saying he was “disturbed by the sort of layer cake of similar issues that are being brought before us.” He cited the earlier problem statement as well as DR issues before the Capacity Senior Task Force. He urged PJM staff to review all pending inquiries affecting DR and seek a more coordinated approach.
DR as an Operational Capacity Resource
PJM told the MRC it wants to begin treating DR as “operational” capacity resource, subject to economic dispatch.
Andy Ott, PJM executive vice president for markets, said the change is needed because current rules treat DR as a “homogenous” block that cannot be tapped without declaring an emergency. “We simply can’t be declaring an emergency every time we need to access this capacity,” he said. “… What we want to do is get rid of the cliff and make it more gradual.”
The committee approved an amended version of the problem statement with four objections and 20 abstentions. The amendments were offered by Katie Guerry, representing curtailment service provider EnerNoc, who said the changes gives PJM the more flexible resources it desires “while preserving the flexibility that CSPs need.”
A motion by Bruce Campbell, of EnergyConnect, to add consideration of the impact on CSP’s operating costs was rejected. Campbell said he was “unconvinced” that the changes were needed for PJM operations rather than “an attack on DR.”
Potential outcomes of the inquiry include:
Changes to DR obligations to move from administrative procedures to economic dispatch.
Diversifying notification time requirements based on physical response capability, similar to current requirements for generators.
Allowing DR to operate with a dispatchable range.
Caps on the amount of Limited DR that can be cleared above the quantity specified in the reliability analysis. PJM says current rules allow Limited DR to fill all of the excess supply under the downward sloping demand curve, which hurts its effectiveness as an investment signal for long term resources.
Changes in the way DR is modeled in PJM planning studies.
Griffiths expressed concern that changes ordered now would be effectively retroactive because of CSPs sell their resources into the future. “We sold capacity based on how we believed the market would work. If we knew the rules were going to change we would have sold differently,” Griffith said.
However, he said the increased flexibility being considered “is actually good for us” because it provides more options for sales.
Physical Delivery of Capacity
DR providers had more luck slowing down the “freight train” when the MRC rejected a request by Jason Barker of Exelon to immediately vote on his problem statement to modify the design of the Reliability Pricing Model to ensure physical delivery of resources that clear the capacity auction. The issue will be brought to a vote at the next MRC meeting.
Barker said the current design lacks sufficient penalties for those who offer capacity resources but fail to produce them in the delivery year.
He said the problem statement was needed to address reliability concerns caused by the increase in non-firm, planned resources clearing in the past three base residual auctions — including uncontracted demand response, planned internal generation, and existing and planned external generation that lacks firm transmission service.
A failure of more than 16% of these “prospective” resources would leave PJM below its target reserve margin, Barker said.
He noted that more than a third of generation imports clearing in May’s 2016/17 BRA lacked a complete firm transmission path. He also cited a report from the Market Monitor that found more than one-quarter of DR purchased replacement capacity in incremental auctions for the 2012/13 Delivery Year.
Increasing Concern
Andy Ott, PJM executive vice president for markets, acknowledged that PJM has “not historically seen high non-delivery rates.” But due to the increasing amount of new entry and imports, he said, “there has been increasing concern that the physical nature of the RPM needs to be emphasized.”
Barker said current rules encourage marketers to purchase replacement capacity in the interim auctions to lock in profits.
The market monitor’s report concluded that the current penalties for failing to deliver — the seller’s weighted average resource clearing price for the resource plus the higher of 0.20 times the clearing price or $20 per MW‐day — are not enough of a disincentive.
Barker also said PJM should develop milestones to track the progress of prospective or planned resources.
Susan Bruce, an attorney representing industrial consumers, said she was concerned “we’re looking at the tail of the dog, not the whole dog,” noting that PJM’s load forecasts have been higher than reality. Barker said although PJM’s load forecast has been 5% or more too high, it doesn’t eliminate the issue.
Aaron Briedenbaugh, of EnerNoc, said he supported the inquiry because it will look at generation in addition to DR.
Members Committee Action
Later Thursday, the Members Committee endorsed tariff changes in response to FERC’s April order that the RTO seek commission approval for new rules requiring demand response providers to provide officer certifications and additional information on their customers.
FERC said the changes required amendments to the PJM tariff and not just its manuals. Tariff changes require commission approval while manual changes don’t.
The rules require curtailment service providers seeking to participate in capacity auctions to file “Sell Offer Plans,” including information about the provider’s customers. CSPs also must have a company officer sign a certification attesting to the company’s intent to physically deliver MWs.
You may have noticed the new name on the masthead at the top of this page.
We’ve made it official. Under threat of ruinous litigation by PJM, we have reluctantly agreed to change our name to RTO Insider. Over the next few months we’ll also be transitioning to a new web address, RTOInsider.com.
We’ll have more to say about this matter soon. The story will make you angry — and make you laugh. Right now, however, we’re still working out a settlement to get PJM’s foot off our throat.
What we can tell you now is that the name change won’t mean any difference in the depth or independence of our coverage: same intensive coverage, less contentious name.
We also want to emphasize the positives. Our readership and Web traffic continue to grow steadily. To improve response time, we will be moving our website to a faster, dedicated server. And we plan to roll out expanded coverage of the industry and the PJM region later this year.
So great things are ahead. R.I.P. PJM Insider. Long live RTO Insider.
We remain: Your eyes and ears at the PJM Interconnection.
The Members Committee Thursday endorsed Tariff revisions requiring new generators to pay for the installation and maintenance of phasor measurement units (PMUs). PJM will pay for the communication link with the PMUs, which provide data that helps PJM in real-time operations and system planning.
The Interconnection Service Agreement will be changed to require installation of PMUs at new interconnections for generators with nameplate ratings of 100MVA or larger. The changes were approved over the objections of generators, with a 71% sector-weighted vote.
Susan Bruce, an attorney who represents industrial energy users, won approval for a problem statement that could result in requirements that transmission owners make tariff filings disclosing their calculation of total hourly energy obligations, peak load contributions, and network service peak loads. The calculations are used to allocate energy, capacity, and transmission cost responsibility among load serving entities.
The problem statement alleges that many of PJM’s transmission owners have failed to file tariffs disclosing the methodology they use to make their calculations, in violation of the Federal Energy Regulatory Commission rules.
State Concerns
“A lot of these issues are state issues governed by our supplier tariff,” said John Brodbeck, of Pepco Holdings Inc. “We have a concern if this results in a PJM standard. That means we have to go back to four statehouses and change our supplier tariff.”
Bruce acknowledged “it’s a tricky issue” but said her intent was not to create a PJM standard.
The problem statement, which was assigned to MRC, was approved with two objections and one abstention. Members said the Transmission Owners Agreement-Administrative Committee is scheduled to discuss the issue at its next meeting July 8.
The Markets and Reliability Committee Thursday approved corrections to errors inserted in Schedule 1 of the PJM Operating Agreement and Attachment K of the Tariff in 2008 and 2009.
One correction will clarify how deviations occurring within one zone are associated with PJM’s Eastern or Western region for purposes of Operating Reserve charges.
The other will insert a cross reference to tie language concerning forgiveness of positive demand deviations to the shortage pricing “trigger.”
PJM will suspend its Day Ahead market if it loses Internet service under a contingency plan given approved Thursday.
PJM’s Tariff and Operating Agreement do not specify procedures for responding to an extraordinary event, such as an Internet failure, that disables the RTO’s eMKT application.
Under the tariff changes approved by the Markets and Reliability Committee, all market settlements would be done in real time in such circumstances.
The plan assumes that PJM’s internal processes are working but that eMKT and other Internet-based services are not functioning. Generator dispatch may be based on the most recent offers received by PJM before the loss of the web.
The deadlines established for clearing the day-ahead market do not apply if PJM is unable to obtain market participant bid/offer data due to extraordinary circumstances. All settlements, including Financial Transmission Right target allocations, will be based on real-time quantities and prices.
If the day-ahead market does not clear, the rebid period — typically from 4 to 6 PM — is cancelled. If day-ahead clearing is significantly delayed, PJM may establish a revised bidding period.
Extraordinary circumstances are defined as “a technical malfunction that limits, prohibits or otherwise interferes with the ability of the Office of the Interconnection to obtain Market Participant bid/offer data prior to 11:59 p.m. on the day before the affected Operating Day.”
The tariff changes were approved without objection. However, Marji Philips, RTO services director of Hess Corp., said stakeholders may need to consider additional protections to ensure load serving entities aren’t forced to pay for power that doesn’t flow under a blackout ruled a Force Majeure event.
With no load to supply, generation could buy back its commitment at no cost, Philips said, while the load might be forced to pay for the power it scheduled.
“If you schedule 5,000 MW day-ahead you could be wiped out,” she said. Phillips said she hopes to make a presentation on the issue at a future meeting of the Market Implementation Committee.
New Jersey regulators approved a $25.5 million annual increase in Atlantic City Electric Co.’s base distribution rates and recovery of $70 million costs for recovery following the June 2012 Derecho and Hurricane Sandy in October 2012.
Capital costs of $44.2 million were included in the rate base while deferred operation and maintenance expenses of $25.8 million will be amortized over three years.
The New Jersey Board of Public Utilities announced its approval of a settlement signed by the utility, the Division of Rate Counsel and intervenors including Wal-Mart Stores, Inc. on June 21.
The company’s $25.5 million base rate increase, which excludes sales and use tax, is based on a return on equity of 9.75%. The new rates will cost residential customers using 1,000 KWh per month $4.44, a 2.8% increase. The changes took effect July 1.
The company, a subsidiary of Pepco Holdings, Inc. (PHI), had sought a base rate hike of almost $70 million. Because of the lower increase, the company said it will reduce its capital expenditures by about $150 million through 2015, a cut of 30%.
The New Jersey legislature voted last week to urge state utility regulators to support development of an offshore transmission “backbone” to deliver wind power and relieve transmission congestion.
The Senate approved a resolution supporting the New Jersey Energy Link (SCR 159) 24-12 on Thursday, after an identical measure (ACR 197) passed the Assembly 58-18 on June 24.
The resolution asks the state Board of Public Utilities (BPU) to request that PJM include the project in its Regional Transmission Expansion Plan (RTEP) with an assumed capacity of 1,000 to 3,000 MW.
Map of Proposed New Jersey Energy Link (Source: Atlantic Wind Connection)
The measure outlines a four-stage process leading to commencement of construction in 2016 and urges BPU to sign a contract allowing the project developer, Atlantic Grid Development, LLC, to recover future development costs from ratepayers. The Federal Energy Regulatory Commission would be asked to modify a 2011 order so that ratepayers are not liable for any costs incurred before June 28 if the project is abandoned for reasons beyond the developers’ control.
The resolution also calls for a study by the New Jersey Economic Development Authority of the “economic activity, tax revenue growth, job creation [and] pollution reduction.”
The New Jersey Energy Link is the northernmost section of the Atlantic Wind Connection, which could transport wind from offshore turbines as far south as Virginia.
The developers say the project will create about 2,000 jobs, including 500 or more in the Delaware River port of Paulsboro, where they plan to build offshore converter platforms.
Atlantic Grid said four wind developers — Apex Wind Energy, EDF Renewable Energy, Fishermen’s Energy and OffshoreMW, LLC – have endorsed the project as the most efficient means to deliver the state’s offshore wind.
The developers say the undersea transmission also will help relieve transmission congestion when the wind isn’t blowing, allowing North Jersey to access cheaper power.
Atlantic Grid CEO Bob Mitchell has said approval of the legislation is “crucial” to getting the project built.
Stefanie Brand, director of the New Jersey Division of Rate Counsel, could not be reached for comment yesterday. She said previously that the line should not be considered until there is offshore generation for it to service, saying there are likely cheaper solutions to North Jersey’s transmission congestion. A BPU spokesman did not immediately reply to requests for comment yesterday.
New Jersey lawmakers approved legislation in 2010 committing the state to purchase 1,100 MW of offshore wind by 2020. But the only project proposed to date, a 25-MW pilot off Atlantic City, has been unable to win approval from state ratemakers to date.
