PJM officials said last week they have acquired sufficient new black start capacity to replace coal-fired units that will retire over the next year due to environmental rules.
PJM’s black start capacity will decline to 8,070 MW (150 units) from 8,720 MW (195 units), PJM’s Dave Schweizer told the Market Implementation Committee Wednesday.
Schweizer said PJM will have adequate supplies despite the reduction because of a redefinition of “critical load” and a rule change allowing units in one zone to provide service to others.
The redefinition — which will include units with hot start times of four hours or less — will increase the number of critical load units to 600 from 475 while reducing the total capacity to 2,910 MW from 4,780 MW.
PJM’s black start costs for 2016-17 will total more than $72 million, a 1.8% increase over 2015-16, according to an analysis by the Independent Market Monitor. Some zones, such as Dominion (+39%) and DPL (+27%), will see large increases, while others, such as Commonwealth Edison (-30%), will see sharp drops.
The RTO completed a solicitation for new black start resources because the Environmental Protection Agency’s Mercury and Air Toxics rule (MATs), which takes effect next year, will result in the shuttering of dozens of coal-fired plants.
PJM will attempt to win stakeholder approval for limited changes to the compensation rules for black start units and for a plan for selecting “backstop” resources for regions that fail to secure service through competitive solicitations.
In February, stakeholders rejected two proposals that would have boosted payments to existing black start units by at least 40%. On July 31, the Markets and Reliability Committee will consider smaller compensation changes. (See PJM to Seek Smaller Black Start Changes.)
PJM officials are considering boosting the RTO’s installed reserve margin (IRM) for winter as a result of its experience in January, when it narrowly avoided shedding load amid frigid temperatures and high outage rates.
PJM’s Tom Falin told the Planning Committee last week that a winter IRM is among the responses officials are considering based on a loss-of-load analysis that highlighted the winter risks.
PJM’s current IRM requirement is based on its summer peak demand and the assumption that generator-forced outages occur randomly at a constant rate under all load and temperature conditions.
In early January, however, PJM saw outage rates three times the assumed 7.35%, with many generators unable to start or obtain fuel due to the cold.
As a result, PJM recently conducted a loss-of-load analysis for the winters of 2014/15 and beyond to determine the risk of the RTO having insufficient resources to meet load.
The analysis found that on a 90/10 peak day next winter (90th percentile of winter loads), there is a “virtual certainty” of load shedding if 18% of generation is lost to weather outages and maintenance in addition to the year-round 7.35% outage rate, Falin said.
The situation could be more dire in 2015/16 as a result of retirements resulting from the Environmental Protection Agency’s Mercury and Air Toxics rule. The analysis finds a 90% chance of load sheds on a 90/10 winter peak day with only 12.5% in additional outages.
Falin said the results indicate that only 7.4% of PJM’s generation can be “at risk” of winter-related outages to remain in compliance with the “one day in 10 years” loss-of-load expectation on which PJM’s IRM is based.
As a result, he said, PJM is considering proposing either a winter IRM or ensuring that no more than 7.4% of the resources clearing in the capacity market are at risk of cold-related outages.
James Wilson, a consultant to state consumer advocates, said the analysis was conservative and misleading because, among other assumptions, it ignored energy efficiency and assumed no demand response available in the winter.
Falin said the assumption was justified, noting only 43 MW of annual DR cleared for the upcoming winter.
Wilson noted that the threshold identified by PJM was based on preventing any non-zero increase in LOLE, which might lead to costly policies to limit at risk units. He suggested a threshold be applied, as PJM has done in other contexts.
Members OK Load Model for IRM
In related news, the Planning Committee last week approved a PJM staff recommendation to use an eight-year load model (2004-2011) for this year’s reserve requirement study.
Planners chose the model from among 36 candidates ranging in length from seven to 14 years. They said it did well in two coincident peak analyses and was a more recent time period than the other alternatives.
The load model will be used in resetting Installed Reserve Margins for 2015/16, 2016/17 and 2017/18, as well as establishing the initial IRM for 2018/19.
Load and supply factions deadlocked Thursday, as members rejected three proposed changes to the Minimum Offer Pricing Rule. The score was nil-nil-nil for proposals by PJM, PSEG and a joint plan backed by Maryland regulators and consumer advocates.
At issue was the MOPR unit-specific review process, which sets a floor price for capacity resources that do not qualify for the self-supply or competitive entry exemptions.
PJM and the Independent Market Monitor had proposed changes they said would standardize some parameters and reduce the subjectivity in the review. Market Monitor Joe Bowring said “it’s difficult to tease out” questionable developer cost assumptions in the 30 days the Monitor has to conduct the MOPR review.
The PJM-IMM proposal would have required use of nominal levelized values, a 20-year asset life and a residual value of zero. It would also bar inclusion of sunk costs. Although it received wide support in a poll by the Capacity Senior Task Force, it received only a 44% endorsement support in sector-weighted voting at the Markets and Reliability Committee Thursday.
Inconsistent with FERC Order
Walter Hall of the Maryland Public Service Commission said the proposal was “inconsistent” with a Federal Energy Regulatory Commission order requiring PJM to maintain the unit-specific review and would increase prices as much as 30%.
By assuming that any new generation came from merchant generators with B-rated debt, it prevented generation developers from offering prices that reflected capital cost advantages, Hall said. PJM and the IMM also chose a nominal levelized costing formula that inflates costs and has been rejected by PJM’s consultant, The Brattle Group, Hall said.
The proposal would have also barred inclusion of revenues from power purchase agreements outside of PJM and required developers to recover the costs of turbines and other equipment that typically operates for 40 years in only 20 years, with an assumption of no residual value at the end of that period. By contrast, ISO New England rules recover costs over 35 years and allow for residual value, Hall said.
Pamela Quinlan of Rockland Electric also criticized the 20-year recovery without residual value, saying it was “overly conservative.” Quinlan said, however, that her company supported the PJM-IMM proposal.
An alternative by PSEG Energy Resources & Trade also fell short at 41%. PSEG’s Ken Carretta said it would have used the best available evidence of the developer’s costs, while the PJM-IMM proposal would provide developers incentives to understate costs.
Hall said the PSEG proposal included most of the features that Maryland found objectionable in the PJM-IMM proposal.
Generation Owners and Transmission Owners generally supported the PJM and PSEG proposals, which won only 45% support from Other Suppliers and no votes from End Use Customers and Electric Distributors.
Suppliers Turn the Tables
After the PJM-IMM and PSEG proposals failed, suppliers turned the tables to reject a proposal by the Maryland PSC and the Maryland Office of People’s Counsel. It won only 35% support. (Package B in the MOPR Unit Specific Review Matrix.)
It won unanimous support from the EUC sector but less than 40% from the ED and OS sectors and virtually no support from Generation and Transmission Owners.
Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS) said the Maryland proposal would retain much of the current rules. “We are open to … establishing a neutral process” for better defining some parameters in the review, he said.
PSEG’s John Citrolo said the proposal would allow the exercise of buyer-side market power, which the MOPR is designed to prevent.
“Long-term contracting can lower costs and shouldn’t be considered a subsidy,” Hall responded.
With no proposals receiving two-thirds support, the issue will be returned to the CSTF. “Send it back to the committee and see if they can wrestle a consensus,” said PJM Executive Vice President for Operations Mike Kormos, the MRC chair.
The Midcontinent ISO has agreed to withdraw a unilateral petition to amend the MISO-PJM joint operating agreement (JOA) after PJM officials protested.
Stu Bresler, PJM vice president of market operations, told the Markets and Reliability Committee Thursday that PJM and MISO will make a joint filing with the Federal Energy Regulatory Commission to replace MISO’s June 11 filing in docket ER14-2159.
The filing was intended to ensure that MISO is reimbursed for transmission charges it may incur in providing emergency energy to PJM. It was prompted by the ISO’s dispute with the Southwest Power Pool (SPP) over the use of SPP’s transmission system to deliver power between MISO’s Midwest and South regions.
MISO Footprint (Source: MISO)
MISO’s filing asked for permission to pass through to PJM additional costs it would incur if MISO exceeds the 1,000-MW contract path limit between the Midwest and South regions to supply emergency energy to PJM.
PJM had informed MISO that it did not believe the filing was necessary because the existing JOA language is broad enough to cover the SPP charges. “However, it is MISO’s customers that are at risk, not PJM’s customers, if that interpretation proves incorrect in a future dispute,” the ISO said in its filing. “Rather than mitigate that risk by simply refusing to supply emergency energy, MISO prefers to eliminate any doubt that such charges can be recovered if an emergency does arise.”
On Jan. 28, SPP proposed a 200% penalty rate for transfers of real-time energy in each direction between the MISO Midwest and South regions that exceed the 1,000-MW limit of the physical tie between Ameren and Entergy Arkansas (ER14-1174).
The commission approved the rate on March 28 subject to refund and directed SPP and MISO to engage in settlement talks. Settlement Judge Carmen Citron reported last week that talks were progressing and should continue.
Bresler told the MRC that MISO’s original filing was overly broad. The joint filing “will be much more specific than what was originally proposed,” he said.
HERSHEY, Pa. — PJM and state officials pledged last week to develop a regional plan to minimize the cost of complying with the Environmental Protection Agency’s proposed carbon emission rule. But lawmakers in coal-dependent Kentucky and West Virginia may be more interested in fighting the regulation than in joining in.
Jon McKinney, WV PSC Commissioner eyeing EPA’s Joe Goffman
“For [a regional solution] to actually happen, it goes way beyond the public service commissions. It has to get [approved by] the governors and the legislators,” West Virginia Public Service Commissioner Jon McKinney told the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) annual education conference. “I’m handcuffed in my ability to do that. It has to start someplace else.”
Kentucky Public Service Commissioner Jim Gardner said his state “is of two minds” on how it should respond to the proposed rule, which calls for an 18% cut in the state’s carbon emissions by 2030.
While the state’s energy and environment secretary drafted a white paper outlining how the state might respond, the legislature rejected the proposal and enacted a law that prevents the state from complying with all but the first of four “building blocks” the EPA used in calculating state targets, Gardner said. Building block No. 1 is efficiency improvements at existing coal-fired generators.
Joe Goffman, EPA associate assistant administrator, told the gathering that the agency encourages regional compliance, saying that it “tried to make the state boundaries as permeable as possible.”
He said the EPA may consider additional building blocks if they are proposed by states. These are the “early days in our decision making,” he said.
RGGI
Commissioner Kelly Speakes-Backman, MD PSC
Maryland Public Service Commissioner Kelly Speakes-Backman said she was pleased that the EPA mentioned the nine-state Regional Greenhouse Gas Initiative (RGGI) as a potential vehicle for compliance. Maryland and Delaware are the only PJM states currently participating; New Jersey withdrew in 2011.
“We’ve been there. We’ve done that. We’ve been doing it for five years,” Speakes-Backman said. “It just makes perfect sense to me to comply with an environmental rule that affects power plants aligning with the regional nature of our grid … I just can’t see how we do this otherwise.”
PJM: Ready to Help
Mike Kormos, PJM’s executive vice president for operations, told regulators that the RTO can incorporate state implementation plans into its economic dispatch engine.
Mike Kormos, PJM Executive Vice President of Operations
“There’s many ways you can do it that are maybe something short of a full-blown environmental dispatch,” Kormos said. “There’s ways to price that … that’s a conversation that we’ll have to have with the states.
“We would love to help you model what you are thinking — what the impacts might be, what those unintended consequences may be — and try and get that all out in the open and hopefully bring the best plan for consumers,” he said.
But West Virginia, which the EPA says should cut its carbon emissions by 20% by 2030, may not be ready to embrace a regional approach, McKinney said.
“There may be a middle-American response to this that’s different from the coastal-American response,” he said. “We have legislators and governors who have taken, in some cases, a very opposed case to EPA.”
McKinney suggested some of the opposition is a reaction to what he called the “misleading way” the agency is selling the proposal.
He said the agency underestimated the likely impact on electric rates and coal-state jobs and overestimated the health benefits of the rule by counting the same benefits under multiple EPA programs.
Partial Agreement
Gardner asked Kormos whether Kentucky could swap its state target for participation in a regional compliance plan if not all states agreed.
Kormos said that while PJM would prefer all member states agree to participate in a regional plan, the RTO could work with only a “core set of states.”
“It will obviously work best if … all the states [are] in and are cooperative. I think then we will be able to use all the tools of all the states because I think the states will have different competitive advantages to be able take advantage of different building blocks.”
Kormos cautioned that state implementation plans (SIPs) will affect each other under PJM’s economic dispatch. “While you may have thought your high-carbon units were not going to be dispatched based on whatever you’ve done, if your neighbor has just flat-out retired his [units], ultimately we’re going to end up running yours to supply his load. And that may in fact end up in some cases undoing what you thought [you had accomplished.]”
Kormos said PJM has not drafted any rule changes to respond to the carbon rule “because there’s a lack of understanding on our part on how the states want to respond.”
“Let’s start the conversation early. We’re not bashful about making changes. We’ll make the changes we need to make to keep the system reliable.”
Dallas Winslow, chair of the Delaware Public Service Commission, said his state is eager for the conversation. “We now need to communicate amongst ourselves and also with our governors’ offices and then we need to collaborate over the next 10 months … and see how it is we can help each other,” he said. “I think this probably will slide by us. Two years from now we’ll look back and say, `Wow, we worked together and we were successful.’”
Base Year Question
While many regulators seemed accepting of the carbon rule, others called for changes.
Some states have called for changing EPA’s proposed 2012 baseline year to 2005 so that they get credit for emission reductions over the past decade.
Pennsylvania Public Utility Commission Chair Robert Powelson said a 2012 baseline means the state wouldn’t get to count the impact of its renewable portfolio standard and nuclear uprate projects made between 2005 and 2012. He said Pennsylvania has invested $1 billion in energy efficiency and retired 5,000 MW of coal-fired generation.
PJM CEO Terry Boston noted that 2012 had lower emissions than 2013, when rising natural gas prices caused a rebound in coal-fired generation.
But the EPA’s Goffman said that the agency must be forward-looking because its regulations require limits set based on the “best system of emission reduction adequately demonstrated” (BSER).
“The threshold question we’re really asking is ‘What is the next thing that a source can do to further reduce their emissions,’” Goffman said.
“All we did, in a way, was look at each state’s existing [generation] fleet and look at technologies that have been exhaustively demonstrated as a way of achieving reductions and applying those reductions to each state’s existing fleet.”
Robert Powelson, chair of the Pennsylvania Public Utility Commission
The agency had to set the targets “in a way that doesn’t have a perverse effect of having emission reductions that have already occurred offset emission reductions in the future,” he said.
Speakes-Backman said the EPA’s plan was fair, even if it does require Maryland to reduce emissions by 37% — more than either West Virginia or Kentucky. (See Carbon Rule Falls Unevenly on PJM States.)
“If they had taken 2005 as a baseline instead of 2012 they could have just made our goal not 37% but 75%,” she said.
Powelson said that the EPA needs to demonstrate its flexibility by “fast-tracking” the process of approving natural gas pipelines that states need to continue the transition from coal to gas-fired generation.
“Phil, I’m not letting you off the hook,” Powelson said, turning to Federal Energy Regulatory Commissioner Philip Moeller. “You guys need to move quicker [on pipeline approvals] as well.”
PJM will join in calls asking the D.C. Circuit Court of Appeals to reconsider its May 23 ruling sharply limiting federal jurisdiction over demand response.
PJM General Counsel Vince Duane told the Markets and Reliability Committee last week that the RTO will join the Federal Energy Regulatory Commission in seeking to reinstate FERC Order 745, which required PJM and other RTOs to pay demand response resources market-clearing prices.
Duane said PJM’s filing, which he said will be akin to an amicus brief, will express the RTO’s support for maintaining federal jurisdiction of DR under the Federal Power Act. Duane said the RTO was acting out of practical concerns — the need for DR this summer — despite the fact that it opposes Order 745’s equal-compensation mandate.
Duane acknowledged that the court grants less than 1% of the rehearing requests it receives. But given the implications of the ruling, he said, “There’s a sense that this has got a much better chance than average.”
“It allows us to preserve our options,” he said. With an appeal pending, “we can continue to rely this summer on demand resources. We don’t have any practical alternative to replacing these resources in short order.”
Order 745 required PJM and other RTOs to pay DR participating in the day-ahead and real-time energy markets locational marginal prices identical to those for generation. The order only applied when DR was capable of balancing supply and demand and lowered the market-clearing price.
FERC said it had authority for the order under sections 205 and 206 of the Federal Power Act because reducing retail consumption through DR can aid reliability and lower wholesale prices. The commission made a distinction between “price-responsive” DR, which it acknowledged was a retail product subject to state regulation, and DR response to incentive payments, which it called “wholesale demand response.”
The court’s majority disagreed, saying “a reduction in consumption cannot be a ‘wholesale sale,’” and thus does not come under federal jurisdiction. The commission “went far beyond removing barriers to demand response resources,” as Congress had ordered in the Energy Policy Act of 2005, the judges ruled.
“This is a big, sweeping decision with national implications,” Duane said.
The ruling was a subject of discussion at the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) annual education conference.
New York Public Service Commission Chair Audrey Zibelman, PJM’s former chief operating officer, said the court “got it wrong.”
“The states have the ability to delegate to the federal government through the RTOs if we want to,” Zibelman said. “I think that’s what [Order] 745 said. If we wanted to do demand response through the RTOs we can do it. If we want to do it ourselves we can do it.”
Uncertainty over the grid’s vulnerability to sabotage could lead to wasteful and excessive spending, a new Congressional Research Service report warns.
“There is widespread agreement among state and federal government officials, utilities and manufacturers that HV [high voltage] transformers in the United States are vulnerable to terrorist attack, and that such an attack potentially could have catastrophic consequences. But the most serious, multi-transformer attacks would require acquiring operational information and a certain level of sophistication on the part of potential attackers,” concludes the June 17 report Physical Security of the U.S. Power Grid: High-Voltage Transformer Substations.
“Consequently, despite the technical arguments, without more specific information about potential targets and attacker capabilities, the true vulnerability of the grid to a multi-HV transformer attack remains an open question. Incomplete or ambiguous threat information may lead to inconsistency in physical security among HV transformer owners, inefficient spending of limited security resources at facilities that may not really be under threat or deployment of security measures against the wrong threat.”
Enticing Target for Sabotage
Officials have known for decades that the grid presents an enticing target for terrorists.
The Congressional Office of Technology Assessment (OTA) reported in 1990 that “in most cases, the nearly simultaneous destruction of two or three transmission substations would cause a serious blackout of a region or utility, although of short duration where there is an approximate balance of load and supply. … The destruction of more than three transmission substations would cause long-term blackouts in many areas of the country.”
The report cited the example of an unnamed city served by eight transmission substations along a 250-mile line through five states. “A knowledgeable saboteur would be needed to identify and find the eight transmission substations. A highly organized attack would also be required. However, the damage would be enormous, blacking out a four-state region, with severe degradation of both reliability and economy for months.” (See related story, Physical Security Cure: More Transmission?)
The CRS report quotes from a sabotage manual associated with white supremacist groups and recounts the Irish Republican Army’s plans to attack six substations in the United Kingdom in 1997. The attack, which was prevented, reportedly could have caused widespread power outages in London and southeast England for months.
Metcalf’s Significance
The issue caught Congress’ attention early this year as a result of a campaign by former Federal Energy Regulatory Commission Chair Jon Wellinghoff.
Wellinghoff cited a 2013 FERC analysis to identify critical high-voltage substations. The “Electrically Significant Locations (ESLs)” analysis reportedly concluded that a coordinated attack that knocks out nine critical substations could cause an extended blackout in the continental U.S.
Wellinghoff also cited the April 2013 rifle attack on Pacific Gas & Electric Co.’s Metcalf substation, which he called a “dry run” for a larger attack on multiple substations. The FBI has declined to characterize the attack as a terrorist incident. (See Substation Saboteurs ‘No Amateurs’.)
“Because the perpetrators have not been identified, it is impossible to know [their motives], but the ambiguity has significant implications for HV substation security going forward,” the CRS report says.
Utilities’ Responses to Date
Before this year’s heightened concern over sabotage, grid owners’ physical security initiatives focused primarily on preventing vandalism and theft of copper wire — incidents that are common and whose costs are well-understood.
Investing in security against terrorist attacks is more problematic, as the Electric Power Research Institute noted in a 2006 report: “Security measures, in themselves, are cost items, with no direct monetary return. The benefits are in the avoided costs of potential attacks whose probability is generally not known. This makes cost-justification very difficult.”
The CRS report cites four utilities — PG&E, Dominion, Bonneville Power Administration and the Tennessee Valley Authority — that have recently announced plans to significantly increase spending on physical security.
At a conference of state regulators last week, Bill Gausman, Pepco’s senior vice president of asset management, described steps his company is taking. At its Burches Hills substation in suburban Maryland, for example, Pepco is adding more surveillance cameras. It is also enclosing some open-air transformers.
“Differences in the interpretation or application of threat information … may be a reason why some large utilities have announced major new substation security initiatives while others have not,” the CRS report said.
Recommendations for Congress
The report recommends Congress focus its attention on “identifying critical transformers, confidentiality of critical transformer information, adequacy of HV transformer protection, quality of federal threat information and recovery from HV transformer attacks.”
The report also raises concerns about the proposed physical security standards that the North American Electric Reliability Corp. submitted to FERC May 23, noting that it allows transmission owners to identify any critical transformers in their territories. (See Grid Security Rules Win NERC Stakeholder OK Despite Criticism.)
Although the owners’ identification will be subject to independent validation, “the standard’s reliance on company-by-company assessments may still allow for important differences in analytic methodology or assumptions and thus inconsistent conclusions about transformer criticality. Furthermore, company-specific studies may not align with a ‘top down’ assessment of asset criticality like that performed by FERC in its Electrically Significant Location (ESL) analysis.”
“Properly identifying which HV transformer substations are critical is a key issue. Otherwise, the electricity sector risks the possibility of hardening too many substations, hardening the wrong substations, or both. Either outcome could increase ultimate costs to electricity consumers without commensurate security benefits and could potentially divert limited security resources from other important grid priorities (e.g., cybersecurity).”
Generation owners last week helped kill a joint proposal from PJM and the Independent Market Monitor to reduce payments to frequently mitigated units (FMUs).
The PJM-IMM proposal, which earned nearly 70% approval in a vote of the Markets and Reliability Committee in May, won support of only a 65.6% sector-weighted vote of the Members Committee, falling just short of the two-thirds consensus. (See PJM-IMM Limits on FMU Adders Prevail.)
While End Use Customers and Electric Distributors voted unanimously in favor, the proposal won only 23% of Generation Owners and about half of Transmission Owners and Other Suppliers.
The PJM-IMM plan won the MRC vote in May after three packages favored by suppliers failed to earn enough support for approval.
Market Monitor Joe Bowring has said the adders are no longer needed because of PJM’s capacity market.
The PJM-IMM proposal would have left the calculations for FMU adder payments unchanged but limit them to units whose net revenues are not covering their avoidable cost rate (ACR). Had the proposal been in effect in 2013, it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire.
Mike Kormos, PJM executive vice president for operations
HERSHEY, Pa. — Planners seeking to protect the grid against physical threats should consider transmission alternatives as well as security measures, Mike Kormos, PJM executive vice president for operations, told a conference of state regulators last week.
“You can only harden a substation so much. If someone wants to attack a substation, they will,” Kormos said during a panel discussion at the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) annual education conference here. “That leads us to the resilience piece. Maybe the best way to make a substation less critical is to build more transmission. A substation is critical basically because we’re pushing too much power through it.”
Kormos said most of PJM avoided the cascading 2003 blackout largely because it had “headroom” — excess capacity — in its system. “It wasn’t operations [that saved PJM]. It happened too fast. It was good planning.”
Kormos said PJM will start ranking its substations by criticality to target needed spending. PJM has begun discussing with state regulators and the Federal Energy Regulatory Commission how it can balance confidentiality concerns with the need for cost oversight and the transparency of the Regional Transmission Expansion Plan (RTEP).
Kormos said PJM will publicly share its criteria for determining criticality “so people are comfortable we’re not simply gold plating the system for the sake of … returns.” The challenge, he said, is creating a process that allows state regulators to validate the need for security spending while “not going so far as putting out a map and putting a big ‘X’ and saying, ‘Plant the bomb here.’”
Transformers’ Vulnerability
Transformers are a tempting target because they are expensive and time-consuming to replace, requiring a lead time of five to 12 months from U.S. manufacturers and six to 16 months from foreign suppliers, according to a newly released congressional report.
Substations containing transformers are easy to identify and generally unguarded, unlike other critical facilities such as generating stations or control rooms.
At a cost of $2 million (230 kV) to $7.5 million (765 kV) — excluding transportation and installation — maintaining a large inventory of spare high-voltage transformers “is prohibitively costly,” the Congressional Research Service report noted. (See related story, Report: Uncertainty over Sabotage Threat Could Lead to Wasteful Spending.)
In 2006, the Edison Electric Institute (EEI) began a Spare Transformer Equipment Program (STEP) to enable the grid to restore operations quickly following a terrorist attack. The program requires participating utilities to maintain a specific number of transformers up to 500 kV to be made available to other utilities in an emergency.
Although the number of spares that grid operators keep on hand is closely guarded, a 2007 news report cited in the congressional study said that PJM maintained 29 spares for 188 transformers on its system rated at 500 kV.
PJM may be better off than some regions, having standardized 500-to-230-kV transformers several years ago, according to Kormos. There are two standard designs, one for the Dominion zone another for the rest of the RTO.
PJM may have to refund millions in transmission costs to Midwest utilities following a federal appellate court ruling last week, but the RTO’s current cost allocation method for regional transmission projects shouldn’t be in jeopardy, PJM officials said yesterday.
The Seventh Circuit Court of Appeals ruled Wednesday that the Federal Energy Regulatory Commission had failed in its second try to demonstrate that the “postage-stamp” cost allocation method formerly used for high-voltage transmission lines in PJM’s eastern region is fair to the RTO’s Midwestern utilities.
In a 2-1 ruling, the court remanded the case to FERC for the second time, ordering it once again to justify why utilities in the Midwest should be billed under the same “socialized” method as utilities in the east for the construction of 500-kV lines that are exclusively in Mid-Atlantic states.
New Hybrid Cost Allocation Formula
The postage-stamp method in dispute was supplanted last year with an Order 1000-compliant hybrid formula that allocates only half of the cost of regional projects using the postage-stamp socialization. For reliability projects, the remainder of the allocation is determined by a solution-based distribution factor (DFAX) analysis. Changes in load energy payments determines the balance for economic projects.
PJM General Counsel Vince Duane said the RTO is waiting to see how FERC responds to the remand before determining the RTO’s next step. “It’s unclear whether FERC will throw the towel in or attempt to justify” the postage-stamp allocation, Duane said.
If FERC concedes, PJM will likely have to rebill its transmission customers for payments received until 2013, when the hybrid formula took effect. PJM Chief Financial Officer Suzanne Daugherty yesterday asked PJM’s billing department to calculate how much money is at stake.
The case originally involved plans for 18 new projects. Currently at issue are 15 projects: 11 completed, one under construction and three more under study, according to the court.
Among the projects affected are the TrAIL, Susquehanna-Roseland and Carson-Suffolk lines, as well as cancellation costs for the MAPP and PATH lines, according to PJM. The total cost of the affected projects is $2.7 billion, but PJM would have collected only a fraction of that through 2013 because the allocations are collected over the projects’ useful lives.
Rebilling Method in Question
One question yet to be answered is what allocation formula would be used in any rebilling. Dayton Power & Light Co., which was assessed $66 million under the postage-stamp formula, would see its allocation drop to $1 million under a 100% DFAX formula, the company’s attorneys stated in a reply brief earlier this year.
Regardless of how the rebilling issue is settled, Duane said he was confident that the current hybrid formula will survive.
“I think this current method is more defensible. It seems to be more in line with what the court is looking for,” he said.
In addition to reducing the socialized portion of the allocation by half, the new method expands the definition of “regional” projects to include not just lines of 500 kV and above but also double 345-kV circuits, which are more prevalent in western PJM, Duane said.
“We’re not back to square one” on cost allocation, he said.
Order 494
The appellate court case stems from an April 19, 2007 FERC ruling (Order 494) that replaced PJM’s former “license-plate” method with the postage-stamp method, which bills all utilities in proportion to their sales.
The court ruled that FERC had again failed to show how a western utility would benefit as much as an eastern utility from new transmission facilities in the east. The court called FERC’s argument that it was too difficult to quantify the benefits western utilities would receive “a feeble defense.”
“We conclude, with regret given the age of this case, that the commission failed to comply with our order remanding the case to it,” Judge Richard A. Posner wrote for the majority. “It must try again. If it continues to argue that a cost-benefit analysis of the new transmission facilities is infeasible, it must explain why that is so and what the alternatives are.”
The court said that it was unlikely that much electricity will be transmitted from the eastern to the western utilities via the new transmission lines because the west is a net exporter.
Illinois’ Complaint
The Illinois Commerce Commission, which filed the complaint on behalf of Commonwealth Edison, did not dispute that the construction of high-voltage transmission lines in the east would provide some benefit to western utilities. For example, ComEd would be able to reduce its reserves, as the increased transmission capacity in the east would reduce the likelihood of outages there.
“So some of the benefits of the new high-voltage transmission facilities will indeed ‘radiate’ to the western utilities, as the commission said, but ‘some’ is not a number and does not enable even a ballpark estimate of the benefits of the new transmission lines to the western utilities,” Posner wrote. The ability to obtain and deliver electricity and reducing reserve capacity “are not equivalent benefits, though treated by the commission as equivalent. The only explanation for why it did that is that, having failed to conduct a cost-benefit analysis, it had no basis for treating the benefits as other than equivalent.”
Instead of the postage-stamp approach, the ICC argued that the western utilities’ contribution to the costs should be based solely on a DFAX analysis. FERC argued that this approach was an underestimate and the court agreed, calling it “the opposite extreme.”
In his dissent, Judge Richard D. Cudahy called a mathematical solution to the cost-allocation problem a “complete illusion. Despite the frequency with which cost-benefit analysis is used, it does not resolve the difficulty of accurately or meaningfully measuring the costs and benefits involved with these grid strengthening projects. Cost allocation, particularly at these extraordinarily high voltages, is far from a precise science, and there are no mathematical solutions to determining benefits region by region or subregion by subregion.”
The majority acknowledged “that the benefits of the new facilities to the western utilities may prove unquantifiable because they depend on the likelihood and magnitude of outages and other contingencies, and that likelihood and that magnitude may for all we know baffle the best analysts.”
“If the commission after careful consideration concludes that the benefits can’t be quantified even roughly, it can do something like use the western utilities’ estimate of the benefits as a starting point, adjust the estimate to account for the uncertainty in benefit allocation and pronounce the resulting estimate of benefits adequate for regulatory purposes,” Posner wrote. “If best is unattainable, second best will have to do, lest this case drag on forever.”
PJM officials said last week they have acquired sufficient new black start capacity to replace coal-fired units that will retire over the next year due to environmental rules.
