Impacts: Updates contact information; definitions; adds model validation and benchmark tests in response to FERC audit finding 13.
Manual 13: Emergency Procedures
Reason for Changes: 2014 Day Ahead Scheduling Reserve Requirement; Updates to terms, procedures.
Impact: Sets Load Forecast Error and Forced Outage Rate effective Jan. 1. References to interruptible load for reliability (ILR), no longer a valid term, are removed. Revised order of emergency procedures so that curtailment of non-essential plant and building load is curtailed as step 6, prior to issuing a manual load dump warning (step 7) and voltage reduction (step 8).
Impact: Changes section 6.3 to increase penalties for resources that fail to provide assigned amounts of Tier 2 Synchronized Reserve. Changes section 5.2.6 to clarify the requirements that must be satisfied in order for wind resources to be eligible to receive Lost Opportunity Cost (LOC) credits.
PJM will likely approve only one of 17 congestion relief transmission proposals submitted in September, saying most failed to provide sufficient benefits or targeted problems that were already addressed.
Five of the projects were rejected because the congestion developers targeted had been addressed by other transmission projects or generation, PJM told the Transmission Expansion Advisory Committee in a briefing last week. Another nine projects failed to clear the 1.25 benefit-to-cost ratio.
(Source: PJM Interconnection, LLC)
Only three projects passed the cost-effectiveness screen. Because they all address congestion on the Hunterstown 230/115 kV transformer only one project — FirstEnergy’s proposed $8 million upgrade in the MetEd zone — is likely to be approved. Two proposals by Northeast Transmission Development (LS Power) were more expensive and had lower benefit-to-cost ratios, even under sensitivity analyses assuming a $1/mmBtu increase in natural gas prices and a 2% increase in load.
Wasted Time
It was a disappointing beginning for those who had hoped the Federal Energy Regulatory Commission’s Order 1000 would unleash competition in transmission development. Six developers and utilities submitted proposals ranging from $200,000 to $64 million, many of them targeting congestion in AP South and the Cleveland interface.
“A tremendous amount of time was spent on [these proposals] with no result,” said one stakeholder.
“PJM needs to educate stakeholders about how we calculate these values,” PJM’s Tim Horger told the Transmission Expansion Advisory Committee last week, citing one of the “lessons learned” from PJM’s first competitive window for “market efficiency” projects. “They’re not getting the same results we’re getting.”
“I’ll take the fault in that,” he added. After PJM conducts its training next year, he said, developers are “not going to spend a month developing a proposal that’s getting thrown out.”
Evaluating the proposals also consumed substantial PJM staff and computing time. Each proposal took 30 to 40 hours of computing time to evaluate, according to Vice President of Planning Steve Herling.
Cleveland Congestion Clears
PJM told the TEAC in June that the Cleveland Interface – the location of three proposed projects – was projected to have $15.5 million in annual congestion costs in 2017, growing to $38.3 million by 2023.
But Horger told the TEAC that the updated Regional Transmission Expansion Plan (RTEP) model showed “there’s no more congestion … or minimal congestion” in the area. “The model is constantly changing” due to new generation and transmission reliability projects, Horger explained.
Jung Suh, of Noble Americas Energy Solutions, noted that a $62 million FirstEnergy project rejected by PJM included a static VAR compensator. “Maybe you’re missing out on an opportunity to reduce reactive costs,” he said.
“That’s certainly something we could look at,” responded PJM’s Paul McGlynn, general manager for system planning.
Auction Revenue Rights
Dominion Virginia Power’s $24.6 million proposal to address constraints at AP South was rejected because it reduced Auction Revenue Rights (ARRs) more than it did Locational Marginal Prices – thus resulting in negative benefit-cost ratios.
“There was no information provided along with the models regarding ARRs,” said another stakeholder.
Horger said PJM had provided developers only information on ARRs from previous years because the Tariff requires a six-month lag before release. He said the values “don’t change much from year to year.”
“I agree it’s surprising to see negative values,” he added.
Moving Target
Herling said he hoped the next round of proposals would fare better. But he and Horger said developers will still face the risk of having proposals rejected because of the dynamics of the grid.
PJM will begin a new two-year planning cycle in January. Planners will conduct analyses through the spring and summer and release results in October, in time to open the next market efficiency window between November 2014 and February 2015. At the same time, however, PJM will be proposing upgrades to address reliability problems identified in their analyses.
PJM will consider relaxing rules for up-to congestion transactions under a problem statement approved last week.
Noha Sidhom, of Inertia Power LP, requested the inquiry, saying that the $50 bid cap and restrictions on the nodes that are eligible are inhibiting use of UTCs as a hedge.
The Market Implementation Committee approved the request over the objections of the Market Monitor’s Howard Haas, who said expansion of the UTC product would be “premature” and should not be considered until UTCs are subject to the FTR forfeiture rule and pay uplift charges.
Issues with UTC Rules
A UTC combines a day-ahead offer to sell energy at a source with a bid to buy the same quantity at a sink. The transaction is only executed if the difference between the Locational Marginal Prices at the source and sink are under a threshold set by the bidder. Current market rules limit such bids to differentials of $50 or less.
The proposed rules also limit such transactions to nodes historically available for interchange transactions, excluding those load buses below 69 kV and buses for generators below 100 MW.
Sidhom said traders are not able to place “price sensitive” bids due to the bid cap and are substituting paths because their preferred paths are unavailable. The bid limit can prevent prevailing flow transactions from clearing on peak days while allowing counterflow bids, causing a risk of a “biased market,” Sidhom said.
The limitations can result in excessive bidding on some paths and prevent asset owning stakeholders from using UTCs to hedge, she said.
Monitor Opposition
Haas said there was no evidence that current rules are impeding the use of UTCs. UTCs represent one-third of injections and withdrawals in the day-ahead market and are on the margin 70% to 90% of the time. UTCs have “a dramatic and influential effect on this market,” he said.
Haas cited an analysis by the Monitor that simulated market results with and without UTC bids for a five-day sample in May. The analysis found that UTCs affect unit commitment and dispatch in the day-ahead market, increase the number of day-ahead binding constraints and contribute to negative balancing congestion. (See Bowring: UTCs Boost FTR Shortfalls.)
In its 2012 State of the Market report, the Monitor called for eliminating UTC transactions or making them responsible for day-ahead and balancing operating reserve charges.
PJM officials disagreed with the recommendation. Instead, PJM requested “a broad discussion of operating reserve costs and allocation methods.”
Sidhom said she did not oppose addressing the Monitor’s concerns. “We’re fine with the FTR forfeiture rule being applied to UTCs. In fact we voted for it,” she said. “I think it’s more a debate between PJM and the [Monitor] that has to be resolved.”
Dave Pratzon, who represents generators, said PJM and the Monitor need to reach agreement on a way to measure the impact of UTCs. He urged inclusion of the measurement issue along with Sidhom’s concerns. “Let’s try and take care of this issue once and for all,” he said.
The Members Committee last week gave final approval to rules allowing more generation owners to obtain PJMNet communication links and an initiative to clarify rules on withdrawing from PJM membership.
The members approved a problem statement and issue charge to eliminate conflicts in the Operating Agreement regarding the timelines for withdrawing from membership. The goal is to clarify the steps required to resolve outstanding obligations of the withdrawing member. The work is expected to be completed in about three months.
The Market Implementation Committee last week approved the sunset of the Financial Transmission Rights Task Force, which was created to investigate the causes of modeling differences between the FTR, day-ahead and real-time markets and identify solutions. The task force’s work resulted in Tariff and manual changes that took effect beginning with the August FTR auction. (See MIC OKs Options to Reduce FTR Shortfalls.)
It took three tries Dec. 9 before the Members Committee reached consensus on Tariff changes that will allow PJM operators more flexibility in dispatching demand response.
Under the new rules, resources will be dispatchable in 30 minutes beginning delivery year 2015/16 — down from a current two-hour default — unless they can demonstrate physical reasons for a longer dispatch.
The PJM proposal, backed strongly by transmission owners, failed with a sector-weighted vote of 55%, below the two-thirds threshold. A second proposal, which included an amendment to increase the maximum dispatch time to 120 minutes for state-authorized “mass market” DR programs, gained more support among electric distributors but still fell short at 57%.
The third vote cleared with 70% support despite erosion among transmission owners. It included the first amendment and a second one allowing industrial loads — part of the end-use customer sector — an exemption from the 30-minute requirement if needed to avoid damage to “product or feedstock.” (See Members OK DR Dispatch Rules after Late Amendments.)
Members agreed last week to develop rules for demand response providers requesting maintenance outages. Under the problem statement approved by the Market Implementation Committee, members will develop amendments to Manual 18 regarding eligibility for maintenance outages. The issue charge, which will be brought before the committee next month for approval, would assign the tasks to the Demand Response Subcommittee.
American Electric Power directors elected Nicholas Akins to chair the board effective Jan. 1, adding that role to his titles of president and CEO. Akins, 53, succeeded Michael Morris in those roles in 2011. Morris is to step down from his position as non-executive chairman before Jan. 1
Commonwealth Edison’s smart grid program created about 2,900 full-time equivalent jobs by the end of the third quarter, the utility reported. The total includes more than 900 direct jobs at ComEd and its contractors and an estimated 1,900 indirect positions created.
The grid modernization program started in January 2012 and the company began installing smart meters in September this year, aiming for 60,000 this year and more than 800,000 through 2015.
Pepco Energy Services won a deal to implement a 23-year energy savings performance contract at the U.S. Army Natick (Mass.) Soldier Systems Center. It will allow the center to exceed the Army’s 30% energy reduction goal by 2015.
Electric Light & Power magazine named PPL Corp. its North American utility of the year, PPL’s second such honor since 2008. It’s “unheard of” for a company to win again in such a short time, Editor in Chief Teresa Hansen said, explaining that after trying harder to find other winners the magazine could not deny the choice. “We quickly realized the winner could be no other utility than PPL this year,” she said. “It was that clear.”
Award criteria included customer satisfaction, financial health and storm preparedness, among other metrics. “After Hurricane Sandy, PPL became the model for how to handle big storms and the people affected,” Hansen said, crediting CEO William H. Spence.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next week’s newsletter for a full report.
3. PJM Manuals (9:15-9:30)
Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA)
Impacts: Defines times when interconnection request information will be exchanged and studied; Reinforces JOA requirements to impose the applicable study criteria; Describes Transmission Service Request studies to be performed.
Impact: Changes section 6.3 to increase penalties for resources that fail to provide assigned amounts of Tier 2 Synchronized Reserve. Changes section 5.2.6 to clarify the requirements that must be satisfied in order for wind resources to be eligible to receive Lost Opportunity Cost (LOC) credits.
4. ENERGY MARKET UPLIFT TASK FORCE (EMUSTF) (9:30-9:40)
Members will be asked to approve revisions to the Energy Market Uplift Senior Task Force charter. The MRC created EMUSTF May 30 to develop ways to minimize energy market up-lift charges and methodologies for allocating make-whole payments (See MRC Approvals 5/30/13.)
The proposed changes would incorporate into the charter the scope originally assigned to an MIC subgroup on Day-Ahead Reliability and Reactive Cost Allocation (DARRCA). The DARRCA group met nine times from December 2012 through October 2013 and was creating solution packages when it decided to combine the issues of the group into EMUSTF.
The volume and magnitude of changes PJM is attempting to impose on demand response raise the question of whether the high-flying sector is still a growth business or one in retreat.
Comverge Inc. sees the industry as under an assault that threatens its growth. “The Commission should not allow PJM to use [shortcomings of the capacity auction] as an excuse to impose anticompetitive measures that will very likely arrest any growth in demand resource participation in its capacity market,” the company told the Federal Energy Regulatory Commission in a Dec. 3 filing.
PJM officials insist they are acting only to ensure reliability, fairness and operational flexibility. Generators echo PJM’s concerns, though their own rivalry with DR cannot be denied: With demand flat, DR market share gains come at generators’ expense.
Whatever the motivations, there’s no doubt that if PJM prevails in its plans, demand response will undergo a dizzying number of changes:
The volume of limited DR clearing in the annual capacity auction could be reduced by as much as two-thirds.
Many resources will be required to dispatch in 30 minutes, down from the current two-hour default.
Curtailment Service Providers will be required to provide more detail to support planned resources (and planned resources could be banned altogether, if some generators get their way).
Emergency energy prices would be cut by as much as 39%.
DR received a boost from Congress in the 2005 Energy Policy Act, which barred “unnecessary barriers” to DR participation in energy, capacity and ancillary service markets. The Federal Energy Regulatory Commission’s Order 745 allowed DR payment of full locational marginal prices beginning in April 2012.
But with its growth raising questions about market saturation, and with low gas prices pinching generator margins, DR has found itself increasingly on the defensive.
Both DR offers and cleared MWs declined in ISO New England and PJM’s capacity auctions this year. DR participation also has declined in NYISO.
Demand resources offered declined 27% (and cleared DR dropped 16%) in PJM’s 2013 base capacity auction versus 2012. The Market Monitor said the decline was the result of low prices, while Comverge blamed it on the “chilling effect” of PJM’s new rules requiring more documentation of planned resources.
Demand response’s participation in ISO New England’s forward capacity market declined this year for the first time ever, with cleared offers dropping 24% from 2012.
UBS Investment Research attributed the reduction to the imposition of ‘must offer’ rules similar to those for generators. Former EnerNOC executive Jim Bride also cites the must-offer rules, along with other changes approved by FERC in January (ER12-1627) — what he called “onerous” data requirements and the elimination of the capacity price floor in 2017.
“Many of the players from several years ago have left the market or substantially pulled back,” Bride, now president of Cambridge-based consulting firm Energy Tariff Experts LLC, wrote. “EnerNOC recently significantly reduced its position in the ISO-NE FCM as the market had become unprofitable for all but the largest customers or those with advanced automation.”
DR had shown steady growth in NYISO until recently. “However, changes in market rules to enhance estimates of providers’ ability to deliver demand response during peak conditions have led to a decline in program participation in recent years,” the ISO said in its annual report. “The increased use of demand response resources may also test the ability — and willingness — of some program participants to sustain their commitments.”
The ISO deployed DR on a record six days during the summer of 2012.
Growth Areas
To be sure, DR is not going away. “Regulators are hard pressed to look past this source of cheap demand reduction,” notes UBS.
And there are growth opportunities in other regions, including California, Texas and non-RTO markets. In September, ERCOT changed its rules to allow DR participation in its real-time market. EnerNOC, which has operations in Australia, Canada, the United Kingdom and New Zealand, says the international market will be three times the size of the U.S.
But in more mature markets, DR’s growth, if not over, surely has slowed.
In a report last month, UBS said the PJM changes approved and pending “could continue to pressure DR’s market share, as proposed reforms to both aspects of the market would ratchet up participation requirements.”
Bride sees similar challenges in New England. “I’m pretty sure that DR will thrive again in ISO-NE, but for the average commercial or industrial customer, DR will be on hiatus for a couple of years until these issues get worked out,” he said.
Long-term Outlook
UBS says more independent power producers and utilities could enter the DR industry, which could “limit further pressure on DR participation from a regulatory perspective.” NRG Energy acquired Energy Curtailment Specialists in August. Exelon’s Constellation unit owns a demand response business (formerly CPower).
Much will depend on FERC’s stance on the proposed changes. DR lost a strong supporter with the departure of FERC chairman Jon Wellinghoff and his replacement has not been named.
An early indication could come in the commission’s ruling, due by March 2, on PJM’s increased documentation requirements.
Market leader EnerNOC — influenced perhaps by the fact that it is publicly traded and doesn’t want to voice doubts that could hurt the stock — has taken a less alarmist tack than Comverge in response to the PJM proposals.
“New rules are happening all the time in these competitive wholesale markets. DR is under more and more scrutiny,” EnerNOC CEO Timothy Healy told the Credit Suisse analyst conference earlier this month. “Some days we have some good news on that front — Texas was exactly what we were looking for — then a couple weeks later: PJM.”
“This is a very cost effective resource. It’s a flexible resource,” he continued. “Public utility commissions love demand response. This too will fade and we’ll see that demand response continues its steady march in these markets.”
