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.”
HERSHEY, Pa. — As PJM’s chief operating officer, Audrey Zibelman helped design PJM’s Reliability Pricing Model. Now the chair of the New York Public Service Commission, Zibelman says she has a “different prism” for viewing capacity markets.
Audrey Zibelman, NY PSC
“Centralized procurement may not be good for everything we want to do as states,” she told the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) annual education conference last week.
Zibelman criticized rules that restrict states’ ability to contract for capacity, such as buyer-side mitigation constructs that she said force ratepayers to pay twice for the same resource.
“That’s frankly absurd. That’s saying the rules of the market are form over substance,” Zibelman said. “We need to sit with [the Federal Energy Regulatory Commission] as partners and say ‘We have a whole issue about how procurement’s going to happen, particularly post-111(d) [the Environmental Protection Agency’s proposed rule to cut carbon emissions].’
“It’s a complex issue and there isn’t a single solution but it’s got to start with a good conversation between us and FERC.”
Officials from Maryland and New Jersey, who have been frustrated by court rulings in their attempts to contract for generating capacity, also called for changes.
Dianne Solomon, NJ BPU
Dianne Solomon, chair of the New Jersey Board of Public Utilities, vowed, “We’re going to continue to flex our state’s rights.” The BPU has filed for rehearing of an appellate court ruling that invalidated contracts it ordered utilities to sign with a natural gas-fired generator. (See Rebuffed by Courts, CPV Seeks FERC End-Around.)
Maryland Commissioner Lawrence Brenner said he has also seen the capacity issue from two vantage points, having helped negotiate a settlement over PJM’s RPM while an administrative law judge for FERC (ER05-1410).
“The capacity market tried to adjust for bilateral contracts and self-supply but there was a balance sought so as not to sink the basic capacity market,” Brenner said. “And it turned out that some of those balancing mechanisms were a little too creaky to work.”
FERC Commissioner Philip Moeller suggested state rule changes could relieve some of the pressure on the capacity markets, which were designed to ensure sufficient supply for peak loads and provide the so-called “missing money” needed to supplement energy and ancillary services revenues.
“I’d like to see my colleagues at the state level consider real-time pricing,” Moeller said. During high load periods, he said, “you can’t expect people to act altruistically for more than a couple of days.”
Robert Powers, chief operating officer of American Electric Power, called Moeller’s real-time pricing suggestion “interesting.” But he asked “how much tolerance is there to send these [price] signals?”
Pennsylvania Public Utility Commission Chair Robert Powelson said that he supports the capacity market, which he said sends appropriate market signals.
But he said his state is concerned about the lack of stability in market rules. Consumer advocates and demand response providers have also grown weary of the rule changes. (See Consumer Advocates to PJM: No More Changes, Please.)
“Mike Kormos, Terry Boston and Andy Ott — very bright guys — but I think in my state we’ve reached a bit of a fatigue level with: What’s the next iteration of the BRA [base residual auction]?” Powelson said. “What’s going to happen next?”
Members narrowed the scope of a task force created to improve funding of financial transmission rights (FTR) Thursday, agreeing to eliminate consideration of balancing congestion.
The Markets and Reliability Committee approved the narrowed scope after first rejecting a proposed charter for the FTR/ARR Senior Task Force.
The MRC approved the charter on a second vote, which called for removing from the charter and issue charge a reference to “enhancing the mechanism by which balancing congestion is allocated.”
The MRC had approved the task force on first reading May 29 after PJM officials said they wanted to fast-track the issue in order to have a solution in place before next year’s FTR auction. (See New Task Force to Target FTR Underfunding.)
PJM said it had suggested an altered allocation of balancing congestion as a potential transition mechanism for any rule changes.
At the task force’s first meeting, however, Market Monitor Joe Bowring objected to the inclusion of the balancing congestion issue. Bowring told the MRC Thursday that the task force’s work would be “bogged down” by including the issue, which has been the subject of litigation and has eluded previous stakeholder attempts at consensus. Bowring said members could craft a transition without it.
Others, including Susan Bruce of the PJM Industrial Customer Coalition agreed, calling Bowring’s observation “a cautionary tale on approving things on first read.”
Pamela Quinlan of Rockland Electric said she agreed with Bruce’s concern over approving matters on first read. “People walked away with different understandings of what this group is actually going to work on,” she said.
Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), said that including balancing congestion in the charter suggested the task force had already decided on a solution.
ARRs ‘Sacred Cow’
Steve Lieberman of Old Dominion Electric Cooperative, however, opposed the narrowed scope. “We agreed to the problem statement with the understanding that it would be a broad discussion,” he said.
“We’re very sensitive to focusing only on ARRs [auction revenue rights]” as a solution to the underfunding, Lieberman said, calling ARRs the “sacred cow” for load-serving entities.
PJM Executive Vice President for Markets Andy Ott said the task force would be hamstrung with the narrowed scope. “I don’t know how you talk about an expanding set of causes” without considering balancing congestion, he said.
Jason Barker of Exelon agreed, noting that PJM told the task force meeting June 25 that balancing congestion represented almost $420 million in revenue inadequacy for 2013/14, nearly two-thirds of the total. “We’re interested in discussing all of revenue inadequacy, not one-third of it,” he said.
Bowring had proposed eight changes that he said would improve funding adequacy to 91% from the current 72%. “Either do ARRs only or consider everything,” Bowring said, calling PJM’s original scope a “half-measure.”
In his 2013 State of the Market report, the Monitor rejected suggestions that load subsidize payments to FTR holders by ignoring balancing congestion when calculating total congestion dollars available to fund FTRs.
“This approach would ignore the fact that loads must pay both day-ahead and balancing congestion,” the Monitor said. “To eliminate balancing congestion from the FTR revenue calculation would require load to pay twice for congestion. Load would have to continue paying for the physical transmission system as a hedge against congestion and pay for balancing congestion in order to increase the payout to holders of FTRs who are not loads.”
Growing Shortfall
PJM told the task force Wednesday that the shortfall could be narrowed by allowing proration of Stage 1A allocations. PJM said it would improve FTR funding by removing infeasibilities and improve confidence in FTR values with a “minimal impact” on ARR revenues.
A second alternative proposed by PJM would remove Stage 1 historical resources when they physically retire. PJM said transmission system rights are not necessary for generators that do not exist.
PJM says more than 15% of Stage 1 historical generation (25,544 MW) has retired or submitted deactivation notices since the ARR allocation process was designed.
Below is a summary of issues discussed and voted on at the Markets and Reliability and Members committees on Thursday June 26.
MEASURES REJECTED
RPM Supply Curve Change Rejected
The Markets and Reliability and Members committees rejected a proposal to create more informative supply curves from capacity auctions. The proposal won only 40% support after Market Monitor Joe Bowring warned that “We continue to think this is an extremely bad idea.”
Stakeholders had approved a problem statement by Exelon on the issue without opposition last June. But support for the change eroded after Bowring signaled his opposition, saying it could reveal sensitive data about price-quantity offers and cause collusion among generators. Load representatives opposing the change cited Bowring’s concerns and news reports indicating Exelon had helped boost clearing prices in the May auction by offering 4,255 MW of nuclear capacity at the maximum price allowed. (See Load Balks at Supply Curve Fix in Response to Auction Strategies.)
The proposal won support of three-quarters of Transmission and Generation owners but less than half of Other Suppliers and virtually none of End Use Customers and Electric Distributors.
Cost Development Subcommittee to ‘Hibernate’
PJM withdrew a proposal to sunset the Cost Development Subcommittee after members and the Market Monitor predicted the panel would be needed in the future.
The subcommittee was created to develop standard procedures for calculating the costs of products or services provided to PJM when those products or services are required to be provided at a cost-based rate. It has been dormant since October.
“It strikes us as inevitable” that the committee will be needed again, Exelon’s Jason Barker said.
Dominion’s Louis Slade said it might take as long as two months to reestablish the committee, which is comprised of technical experts, if it were disbanded.
Market Monitor Joe Bowring said the committee may be needed soon to consider the costs of batteries used in energy storage. “There will soon enough be additional work” for the committee, Bowring said.
The subcommittee will remain standing but will hold no meetings until it receives another assignment.
Members Balk at ‘Deferring’ Issues
Leaders of the Members Committee backed off from a proposal that it “defer” action on four initiatives after receiving push-back from members last week.
Vice Chair Jim Jablonski outlined a proposal to delay further action on four initiatives so that members could concentrate their efforts on several other items that have early fall deadlines for completion. MC Secretary Dave Anders said further meetings on the deferred items would be delayed until about October.
But when members raised objections to delaying two of the four issues, Anders and Jablonski said they would reconsider the proposal.
MEASURES APPROVED
The Markets and Reliability and Members Committees approved the following by acclamation Thursday following little discussion or debate:
Markets and Reliability Committee
PJM Manuals
Members endorsed revisions to Manual 01: Control Center and Data Exchange Requirements and Manual 14D: Generator Operational Requirements that incorporate requirements for installation of SynchroPhasor Measurement Units (PMU) at new generation interconnections. Related Tariff changes were approved by members last June and approved by the Federal Energy Regulatory Commission in February. The requirements apply to interconnection customers entering the new services queue on or after Oct. 1, 2012 with facilities with a maximum output of 100 MW or greater. (See Members Approve PMU Requirement.)
Members endorsed changes to Manual 01: Control Center and Data Exchange Requirements and Manual 14D: Generator Operational Requirements governing rules for members wishing to purchase access to the PJMNet data feed. (See Final OK for Membership Inquiry, PJMNet.)
Designated Entity and Interconnection Coordination Agreements
The MRC and MC approved the Designated Entity Agreement (DEA) and Interconnection Coordination Agreement (ICA) developed by the Regional Planning Process Task Force (RPPTF).
The documents define the obligations of companies designated to build and operate transmission projects awarded under the competitive rules of FERC Order 1000. They include project scope, planning criteria, development schedules, project milestones and terms and conditions.
FERC ordered PJM to file the DEA for commission approval by July 14. (See: 147 FERC ¶61,128).
Coordinated Transaction Schedule
The MRC gave PJM final approval to implement the Coordinated Transaction Schedule (CTS) product for trading between PJM and the New York ISO.
Last week’s vote endorsed the accuracy of the PJM scheduling tool that will be used to optimize the cross-border transactions. PJM officials told members in March that the Intermediate Term Security Constrained Economic Dispatch (IT SCED) tool is accurate within $5/MWh more than two-thirds of the time. (See PJM Price Forecasts: Close Enough for Power Trading?)
CTS, which is intended to reduce uneconomic power flows between the two regions, is scheduled to be implemented as soon as November.
Transmission Owner Data Feed
Members approved a revised issue charge for the Transmission Owner Data Feed Task Force to include consideration of generator real-time reactive capability data. Members approved creation of the task force in April to consider an easier method for transmission owners to access real-time generator data, an effort intended to improve situational awareness and emergency response.
During initial task force discussions, stakeholders shared concerns about TOs having access to generator-characteristic data in addition to real-time telemetry. Exelon responded that generator real-time reactive capability data is necessary for accurate state estimator and contingency analyses. (See Members to Consider Easier Sharing of Real-Time Generator Data.)
