PJM’s assessment for the 2013-14 winter months identified no reliability issues, officials told the Operating Committee last week.
The annual assessment concluded the RTO has sufficient installed capacity to meet reserve requirements at the forecasted winter peak (about 136,000 MW) and that off-cost generation redispatch and switching will be sufficient to prevent thermal and voltage violations.
The assessment included a 50/50 peak load study — which assumes weather at average peak-day conditions — and an analysis of reactive transfer limits.
Last month’s GridEX II security drill was a valuable test of PJM’s emergency response procedures but lacked in realism, according to a briefing to the Operating Committee last week.
PJM’s Don Wallin said the North American Electric Reliability Corp. tried to stress the capabilities of the 200 organizations that participated in the Nov. 13-14 drill by giving them multiple simultaneous “injects.”
The scenarios included:
Denial of service attacks against shared service websites such as OATI;
Malware – similar to that which hobbled Saudi Aramco in a 2012 attack – that that exfiltrated sensitive information and locked corporate desktops and laptops;
Physical attacks against transmission and generation; and
Snipers firing at first responders.
The exercise was meant to simulate nation-state sponsored attacks against the grid. But Wallin said those who took part thought the volume of simultaneous injects undercut the verisimilitude.
“We don’t want this to be a Bruce Willis movie,” he said. Because the injects were compressed in such a short time, “it really took away from the realism and turned it into a disaster movie.”
More than 200 organizations, including 35 PJM member companies took part. Among those involved from PJM were the dispatch training team, corporate incident response team, cyber security incident response team, physical security incident response team and crisis communications.
Also involved were the FBI, Department of Homeland Security and the Electricity Sector Information Sharing and Analysis Center (ES-ISAC).
In addition to recommending the staggering of “injects,” participants said the drill should have used real-world communications channels.
GridEx III will be conducted in 2015. PJM plans a joint exercise with transmission owners in 2014.
Some are in it for the money. Others say they are motivated by environmental reasons. “For my children … for their children and their grandchildren. For the future and the planet,” says one customer.
These are among the multi-ethnic group of customers, and their very cute kids, featured in testimonials for Pepco’s Energy Wise program.
Energy Wise is Pepco’s contribution to the EmPOWER Maryland initiative, created by the legislature with a goal of reducing energy consumption by 15% below 2007 levels by 2015.
The Maryland Public Service Commission’s Walter Hall and Pepco’s Gloria Godson worked doggedly to ensure PJM’s new rules on demand response would not ruin such “mass market” programs. As a result of their efforts, PJM’s new requirement for 30-minute dispatch exempts residential customers who cannot respond so quickly.
Results to Date
Three utilities and one cooperative run demand response programs under EmPOWER Maryland. In 2012, the utilities for the first time exceeded their annual savings forecasts, doing so by more than one-third. Still, they were only at 41% of their energy reduction and 51% of the demand reduction goals for 2015.
Much of the reductions to date have resulted from the lackluster economy, moderate temperatures and distributed generation. With direct load control programs beginning to reach saturation levels, officials said they will need contributions from combined heat and power and dynamic pricing to reach their goals.
The state, which spent $729 million on the program through 2012, approved an additional $95 million in funding last month. The funding comes largely from customer surcharges and capacity market revenues. The state expects to collect more than $57 million in capacity revenues for delivery year 2014/15 and $66.5 million for DY 2015/16.
Pepco’s Program
Pepco’s program includes three options for “cycling” air conditioners or heat pumps during PJM emergencies between June and October.
During an emergency, or “conservation period,” the air conditioner fan continues to circulate air but the compressor operations are reduced. Under the 50% option, the compressor operates half of the time it did in the hour prior to the conservation period, allowing temperatures to rise 1 to 3 degrees. It pays $40 a year.
There are also 75% cycling ($60/yr.) and 100% cycling ($80/yr.) options. The 100% option, which shuts down the compressor for the entire emergency, can result in temperatures rising up to 7 degrees and is not recommended for consumers with cardiac or respiratory conditions. Each program includes a one-time “installation credit” or signing bonus equal to the annual payment.
Pepco contributed about one-fifth of the state’s economic and emergency DR.
Baltimore Gas & Electric Co. runs the biggest program in Maryland, responsible for three-quarters of the state’s economic DR and 63% of emergency.
BGE’s Peak Rewards offers an air conditioning program similar to Pepco’s but with bigger savings ($50/$75/$100). BGE also offers a 100% hot water heater cycling program which pays $25 per year. It also conducted 63,000 home energy checkups in 2012.
Maryland represents nearly one–third of the 2,200 MWs enrolled in economic DR programs in PJM — more than any other state — but ranks behind Pennsylvania and Ohio in the emergency program with 15% of the 7,346 total. The top six states are responsible for more than 80% of the reductions in each of the programs.
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.
