CARMEL, Ind. — Facing an increased number of outages from an aging fleet of baseload generators across the footprint, MISO officials are examining how they can capture the risk of planned and maintenance outages occurring during peak load.
Ryan Westphal, MISO resource adequacy coordinator, said an investigation by the RTO’s Loss of Load Expectation Working Group suggests a need to account for intentional outages, but stakeholders have not yet reached consensus on how to proceed.
“Every year [since 2012], we saw some number of both planned and maintenance outages that happen on peak,” Westphal said during a Nov. 8 Resource Adequacy Subcommittee meeting.
Westphal said MISO has looked into incorporating a combined average volume of planned and maintenance outages into its loss-of-load-expectation (LOLE) calculation, which would bump up the RTO’s predicted 17.1% planning reserve margin by about 0.4% in the 2018/19 planning year. The increase would lead to an additional 600 MW being cleared in this year’s capacity auction, MISO estimated.
MISO currently does not model any planned and maintenance outages at peak load, assuming such outages are optimized and not occurring during peak demand, but the RTO may want to revise its LOLE study to include the probability that some outages will occur during the peak, Westphal said.
“It leads us to think that all the risk isn’t being captured in our planning reserve margin today,” he said. Over the last several years, MISO has carried a sufficient reserve margin to cover outages that occur on peak, he added.
During July 2016, MISO experienced about 3.4 GW of planned outages and 1.8 GW of maintenance outages. The following month saw planned and forced outages of 2.4 GW and 4.2 GW, respectively. While those outages combined were nowhere near the volume of forced outages in the summer (12 GW in July, 10 GW in August), they helped nudge total outages above 16 GW during both months, a benchmark that was surpassed only once before in August 2015.
MISO outages during peak summer demand | MISO
Duke Energy’s Brian Garnett asked how a maintenance outage occurs that’s not already planned or forced.
MISO defines maintenance outages as less severe mechanical issues that don’t result in an immediate outage trip but must be scheduled for repairs, Westphal said.
Indianapolis Power and Light’s Ted Leffler asked if the new calculation will be applied universally across the footprint or target individual units.
“I would caution that not every generation unit that has planned outages has load,” Leffler said.
Westphal said MISO would discuss the proposal again next month, and asked stakeholders to send written feedback before the Thanksgiving holiday.
CARMEL, Ind. — MISO is defending its methods for validating utility load forecasts after Dynegy last month charged that Ameren Illinois miscalculated its summer peak load forecast.
Michael Robinson, MISO principal adviser of market design, said the RTO’s Tariff obligates it to draw a random sample of load-serving entity demand forecasts to “assess credibility” of the forecasts. For the LSEs selected for the sample, MISO performs an ex post review of their previous year’s forecast and works with them to reconcile differences between their forecasts and those produced by Purdue University’s State Utility Forecasting Group.
“Ameren was a draw in the random sample last year,” Robinson confirmed at a Nov. 8 Resource Adequacy Subcommittee meeting. “We did have to come back and ask them for additional documentation. Some of their documents were a bit sketchy, I guess, but they gave us everything we needed.”
Last month, Dynegy called on MISO to develop a new process for verifying load forecasts produced by LSEs, claiming Ameren’s forecasts led to under-procurement in the capacity auction for Zone 4. (See Dynegy: MISO LSE Load Forecasts Require Tune-up.)
MISO said it found no evidence of systemic bias in forecasts. Robinson said Zone 4 was slightly hotter than normal at coincident peak this summer and all local resource zones were within two standard errors of their forecast values.
“The way we design this is the LSEs are the experts in the sense that they know when customers are building. They certainly have more information than we do,” Robinson said. “We don’t forecast ourselves on the zonal level for the coincident peak. We don’t have that kind of information.”
FERC Chairman Neil Chatterjee said last week he will seek an interim “lifeboat” to ensure the survival of struggling coal and nuclear plants while the commission ponders long-term rule changes.
He laid out his plans in remarks at an industry conference and in an interview Thursday on Bloomberg television.
Chatterjee has said the commission will take action by Dec. 11 on Energy Secretary Rick Perry’s call for “full recovery” of coal and nuclear plants’ costs in RTOs with energy and capacity markets, including PJM, ISO-NE and NYISO. More than 700 comments were filed in response to the Department of Energy’s Notice of Proposed Rulemaking (RM18-1). (See NOPR Backers, Foes Seek Last Word at Comment Deadline.)
In a meeting with reporters last month, Chatterjee said FERC’s options include initiating its own rulemaking, convening a technical conference or issuing a final rule based on DOE’s NOPR.
Now, facing legal and political obstacles to winning approval of a final rule, Chatterjee said he is seeking a short-term plan to rescue as many plants as possible while the commission does additional fact-finding.
“What I don’t want to have is plants shut down while we’re doing this longer-term analysis, so we need an interim step to keep them afloat,” Chatterjee told the S&P Global Platts Energy Podium in D.C. “I don’t know that we can get everybody in the lifeboat,” he added.
“My approach is going to be one of no regrets,” he said in the Bloomberg interview. “The worst-case scenario would be we do the long-term analysis, we figure out we actually did need these plants, but they’re gone. They’re offline and we can’t get them back.”
He said his plan will not alter RTO dispatch practices or distort markets.
Jones | FirstEnergy
Chatterjee also disclosed he had met with FirstEnergy CEO Chuck Jones “to really kick the tires on what they proposed [in their comments on the DOE NOPR] and challenge them on some of what they had put forward.” FERC’s ex parte rules, which bar commissioners from private discussions with parties in “case-specific, contested proceedings,” do not apply to rulemakings, according to a 2010 presentation by FERC Associate General Counsel Lawrence R. Greenfield (18 CFR 385.2201(a), (b), (c)(1)(ii)).
FirstEnergy proposed that the commission require RTOs and ISOs adopt a pro forma Resiliency Support Resource (RSR) tariff agreeing to make monthly payments to “fuel-secure, resilient generators.” The payments would be “equal to its full costs of operation and service” and a “and a fair return on equity,” minus its revenues for capacity, energy and ancillary services.
Chatterjee, a native of coal state Kentucky and a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), has made no secret of his desire to aid coal generators. Commissioners Robert Powelson, a Republican, and Cheryl LaFleur, a Democrat, have reacted more warily to the Perry proposal, expressing concern it could damage wholesale markets.
Republican Kevin McIntyre and Democrat Richard Glick, who were confirmed to FERC by the Senate on Nov. 2, are awaiting their swearing-in and have not commented publicly on the proposal. Chatterjee told Bloomberg that he had not discussed the NOPR or his interim proposal with McIntyre, who will replace him as chairman.
“Kevin is somebody with a lot of expertise. He’s a smart, thoughtful guy. … And I hope that he will ultimately be persuaded to follow the course that I’ve laid out,” Chatterjee said.
Perry’s Sept. 28 proposal requested that FERC issue a final rule within 60 days. But even if Chatterjee won the two additional votes he needs to approve a final rule in December, it could be vulnerable to court challenges on the grounds that it was rushed through without sufficient notice to the public and proper evaluation by the commission.
FERC last week opened a fresh settlement proceeding to determine the fairness of DTE Electric’s decreased revenue requirement for reactive power services, an issue already under scrutiny by the agency (ER17-2465).
DTE in April asked the commission to approve an $11 million annual revenue requirement for reactive supply in the ITC transmission pricing zone, down 14% from the current $13 million requirement (ER17-1414). The Detroit-based utility submitted the revised request in September to account for an additional $118,000 decrease stemming from the Nov. 14 retirement of St. Clair Unit 4, an aging coal-fired generator. The first request had been under settlement proceedings for four months by the time of the second filing (EL17-71).
St. Clair Power Plant | Inland Mariners
The company cited seven retirements, increased investments in generation units that provide reactive service, and the replacement of its total revenue requirement with unit-specific revenue requirements as reasons behind the rate decrease.
FERC said preliminary analysis shows that DTE’s rate schedule may still be unreasonable even with the $118,000 decrease, and consolidated the newly opened settlement proceeding with the existing one under a new docket, EL18-23.
“Because DTE Electric is proposing a rate reduction, but a further rate decrease may be appropriate, we will institute a Section 206 proceeding,” FERC wrote.
FERC last week approved SPP’s proposal to change the way it prices regulation and operating reserves but said the RTO should respond to complaints that it overuses out-of-market procedures to avoid scarcity pricing.
The ruling, effective May 11, 2017, finalized a tentative approval granted by FERC staff in August before the commission regained its quorum (ER17-1092).
The changes were in response to FERC’s June 2016 ruling (Order 825) requiring RTOs and ISOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period. (See FERC Issues 1st RTO Price Formation Reforms.)
SPP previously set a single administrative scarcity price for each reserve product regardless of the severity of a shortage. Under the new rules, the RTO will use segmented demand curves with higher degrees of scarcity resulting in higher prices. It is also renaming its operating reserve demand curve as the contingency reserve demand curve.
In approving the changes, the commission rejected a complaint from Golden Spread Electric Cooperative that the regulation demand curves should begin with a steeper slope to incentivize units to provide regulation earlier.
“We find that SPP has supported the structure of the proposed contingency reserve demand curve, which is based on NERC requirements for SPP to carry reserves to protect against loss of the largest online resource in its footprint and based on the contingency reserve the [Reserve Sharing Group] procures to protect against the loss of half of the second largest online resource in the SPP footprint,” FERC said.
However, it directed SPP to add to its Tariff definitions and other details of the new rules, which the RTO had planned to include in its Marketplace Protocols. “The commission has found that provisions that are used to calculate a rate should be included in the Tariff because they significantly affect rates, terms and conditions of service,” the order said.
The commission also rejected Golden Spread’s complaint that SPP has prevented the implementation of shortage pricing by overusing out-of-market actions such as reliability unit commitments and manual commitments.
Golden Spread Electric Cooperative complained that SPP’s shortage pricing rules are insufficient, depressing prices for plants that can respond quickly to scarcity conditions. Its Antelope Station, near Abernathy, Texas, can reach its full 168-MW output in five minutes. | GSEC
Although the commission said Golden Spread’s call for market design changes regarding such actions was outside the scope of the proceeding, it said the cooperative had “raised an important issue that SPP should consider exploring through its stakeholder process.”
“We understand that there may not be sufficient data available to stakeholders to facilitate these discussions, as the commission noted in its Notice of Proposed Rulemaking in Docket No. RM17-2,” the commission said, referring to its January 2017 proposal to reduce uplift, allocate it more accurately and increase transparency. (See FERC Seeks More Transparency, Cost Causation on Uplift.)
“While further commission action in Docket No. RM17-2 may result in additional transparency, we encourage SPP to work with its stakeholders and provide them with the data necessary to aid in any discussions about this issue.”
CAMP HILL, Pa. — Pennsylvania, which was among the first states in the U.S. to abandon cost-of-service electric regulation, now finds itself at ground zero of a debate that could largely reverse the process. So last week’s 7th Annual Pennsylvania Energy Management Conference couldn’t have been more timely.
FERC Chief of Staff Anthony Pugliese, who grew up just a few miles from here, praised the Department of Energy’s Notice of Proposed Rulemaking to support struggling coal and nuclear generators, while promising it would not destroy PJM’s competitive market.
And PJM Independent Market Monitor Joe Bowring, who shared a panel with Barron and NRG’s Abe Silverman, continued his attack on the RTO’s proposed alternative. (See related story, NOPR Reply Comments Bring More Criticism of PJM Proposal.)
Stranded Costs
Pamela C. Polacek, an attorney with McNees Wallace & Nurick, one of the conference’s sponsors, joined in the criticism. Her firm has long represented industrial customers and was central to Pennsylvania’s move — following California and Massachusetts — to customer choice in 1996.
Pennsylvania consumers paid $12.3 billion in stranded costs to Exelon’s PECO Energy and other nuclear plant owners between 1996 and 2010 as part of the bargain to unbundle generation from distribution. Polacek said subsidies for all of Pennsylvania’s nuclear plants could cost $1.2 billion per year — raising the annual electric bill for a small industrial user (12 million kWh/year) by more than $100,000, and that for a steel mill (330 million kWh/year) by $2.8 million.
“We can’t afford this in Pennsylvania,” she said. “We rank 48th in manufacturing job creation. … We can’t continue to pile costs onto our industrials. Right now, our average industrial electric rate is about the middle [of the states]. But remember, we did this [retail choice] back in 1996 to get competitive advantage, not just to be in the middle.”
Polacek said Three Mile Island Unit 1, the only planned nuclear retirement in Pennsylvania, doesn’t deserve a rescue.
“As Joe has said, other Pennsylvania nuclear plants continue to clear the [capacity] auction. For the most part, they are not at risk of retirement.”
Investment
She acknowledged that as a single-reactor plant (following the partial meltdown of Unit 2 in 1979) TMI does not have the labor economies of scale of multi-unit plants. But she said saving TMI’s 750 workers would cost jobs in manufacturing because of higher electric rates.
“Three Mile Island didn’t really take the opportunities to do upgrades that other Pennsylvania-based plants did. So those plants were looking at investing in their infrastructure to expand their capacity, to be more efficient. And Three Mile Island didn’t do that.”
Barron disputed Polacek’s claim of underinvestment. “I can tell you we continue to invest very heavily in Three Mile Island, having replaced the steam generator … and [made] other investments,” she said.
She cited a Brattle Group study that predicted early retirement of the state’s nine nuclear generators would increase prices by $788 million per year, a 5% increase.
Resilience
The two also sparred over nuclear power’s value to the grid’s resilience.
“Looking at the idea of having onsite fuel supply as being something that is going to help us if all four gas pipelines serving the Northeast go down, I have to ask: Well if the terrorists do that, what’s going to stop them from also targeting the nuclear plants, which would seem to be a pretty attractive, World Trade Tower-type targets?” Polacek said.
Barron said nuclear plants’ defenses against terrorists are second to none. “We are so heavily regulated by a number of regulators, including the [Nuclear Regulatory Commission], on this specific point, on the amount of security we have to have in our plants and the ways that we need to protect them,” she said. “There are more people who [are carrying] guns than people who are operating the plant. … We do not have anywhere near that kind of protection on the natural gas supply system.”
That is beside the point, responded Bowring, saying the vulnerabilities of gas pipelines also apply to electric transmission. “It doesn’t matter what the fuel type is if the transmission grid is not there,” he said. “So, you have to be careful how far you extend this argument.”
NRG’s Silverman said that he agreed with the DOE on the need for price-formation reforms. But he said zero-emission credits for nuclear plants are not a good solution. ZEC prices in New York and Illinois will produce half as much carbon-free electricity as equivalent spending on renewables, he said.
“It completely ignores the energy market response. Completely ignores the power of competition to find cheaper solutions and drive down the price,” he said.
“We have these price-formation initiatives at FERC that have now been pending, in some cases, for four or five years. They need to be acted on. I mean come on guys, yes or no.”
And he said the issue is broader than price formation. The challenge, he said, is creating incentives for what NRG calls the “four-product future,” which envisions renewables providing most energy, supported by storage, controllable demand and fast-ramping gas. NRG says it will reduce the carbon emissions from its generation 50% by 2030 and 90% by 2050.
“A [gas-fired] power plant built today is already going to be lasting until 2050 and [will] be emitting too much carbon” to address climate change, Silverman said. “So, we end up with this long-term stranded cost environment where today’s gas plants are tomorrow’s coal plants.”
PJM’s proposed alternative to the Department of Energy’s proposed coal and nuclear price supports came under fire last week, as market monitors, regulators and other RTOs joined PJM Independent Market Monitor Joe Bowring in opposition.
PJM was harshly critical of the DOE Notice of Proposed Rulemaking, which would provide cost-of-service payments for coal and nuclear plants with at least 90 days of on-site fuel supply (RM18-1). Coal and nuclear generation is responsible for more than 50% of PJM’s winter fuel mix, more than any other region in the U.S., excluding VACAR South.
Instead, the RTO called on FERC to order it and other RTOs to file price formation rule changes within 180 days. It has proposed that inflexible generators be allowed to set LMPs. CEO Andy Ott says that by increasing energy prices and creating a steeper supply curve, the change would reduce uplift and increase incentives for following dispatch instructions. (See Critics Slam PJM’s NOPR Alternative as ‘Windfall’.)
At a conference in Camp Hill, Pa., on Wednesday, Bowring rejected Ott’s premise. “Clearly the supply curve is not too flat in PJM,” Bowring said. “PJM has been ensuring the reliability of the grid for the last almost 90 years and it continues to do so. The grid is reliable and resilient, although resilience remains to be defined.”
In reply comments last week, Bowring faulted the proposal on both substance and process, saying the RTO’s 180-day timeline “would unnecessarily truncate the PJM stakeholder process.”
Pennsylvania Public Utility Commission Vice Chairman Andrew Place was also critical, saying PJM’s “fast-track proposal for consideration of reforms to marginal cost and shortage pricing are inconsistent with its comments which document the sufficiency of PJM’s reliability.”
“Appropriate and cost-effective reliability and resiliency requirements can be developed through market-based mechanisms, rather than discriminatory, cost-based mechanisms,” Place said.
Robert Howatt, executive director of the Delaware Public Service Commission, joined with environmentalists, industrial customers and others in also opposing the PJM plan. “PJM’s request for a near-term directive to file a proposal it has not fully revealed to its stakeholders, and which has not received the appropriate (let alone any) vetting, inappropriately subverts the stakeholder process,” the group said.
ISO-NE, NYISO Seek Distance from PJM
Both ISO-NE and NYISO sought to distance themselves from PJM’s proposal.
“The region has already invested significant work in implementing major market improvements, including energy market offer-flexibility enhancements, sub-hourly settlements and Pay-for-Performance,” ISO-NE said.
NYISO said it “takes no position on PJM’s proposed reforms at this time other than to emphasize that they are not applicable to New York. Similarly, the NYISO takes no position on the question of whether the commission should initiate Section 206 proceedings in PJM, other than to note that doing so in PJM does not mean it needs to be done in New York. … Consequently, if the commission decides to initiate a Section 206 proceeding to consider PJM’s reforms, it should be a PJM-specific proceeding.”
Other Monitors Also Critical
The CAISO Department of Market Monitoring and Potomac Economics, which monitors MISO, ISO-NE, NYISO and ERCOT, also expressed opposition.
CAISO’s DMM did not submit initial comments on the DOE NOPR because it does not include CAISO, which lacks a centralized capacity market. But it said it was concerned PJM’s proposal could apply to CAISO because it would make changes to spot markets. “If applied to CAISO, the pricing proposed by PJM would undermine CAISO’s spot markets,” the department said. “PJM’s proposal is actually an administrative pricing rule that moves away from efficient spot market pricing.”
Potomac Economics said PJM’s proposal “will be highly inefficient and destructive to existing energy markets in the Eastern Interconnection.”
P3 Group Supports PJM Plan
PJM wasn’t completely lacking for allies. The PJM Power Providers Group (P3) said it “supports the framework that PJM [has] presented to resolve the shortcomings.”
But coal interests said it is too little, too late. FirstEnergy said PJM’s proposal is “nothing more than an argument for delay and will not lead to a remedy for current unlawful rates any time soon.”
“While PJM has not yet determined how much customers will have to pay under this construct and how much power plants would be paid, it almost certainly is not enough help to assure that power plants with resilience benefits through on-site fuel will remain in the market,” said the American Coalition for Clean Coal Electricity and the National Mining Association in a joint filing.
The NERC Board of Trustees posted a notice saying it “is aware of the personal incident involving” Cauley and naming General Counsel Charles Berardesco as interim CEO. Cauley is on a leave of absence “until further notice,” the board said, adding that it is “taking steps to ensure the work of NERC continues seamlessly.”
Reached by phone before the statement was posted, NERC Board Chairman Roy Thilly declined to say whether he had spoken to Cauley but said he had been released from jail.
“I don’t want to discuss any further what our process is,” he said. “Obviously the board is aware, and we need to proceed very deliberately and expeditiously to determine what the facts are.”
Asked whether NERC was aware of any prior history of domestic abuse, Thilly said, “Not to my knowledge.”
A FERC spokeswoman said the agency had no comment.
Familiar Face
Cauley, who has led NERC as CEO for nearly eight years, is a familiar face in D.C., often testifying before Congress and FERC.
He holds a bachelor’s in math and electrical engineering from the U.S. Military Academy, a master’s in nuclear engineering from the University of Maryland and an MBA from Loyola University.
He served as the program manager for grid operations and planning at the Electric Power Research Institute and served five years as an officer in the U.S. Army Corps of Engineers before joining NERC in 1996.
As vice president and director of standards, he helped prepare NERC’s application to become the FERC-certified Electric Reliability Organization after the 2005 Energy Policy Act gave the commission the power to enact mandatory reliability standards.
He left NERC in March 2007 to become CEO of SERC Reliability Corp., returning as CEO in January 2010.
He earned $757,481 in salary and $80,985 in other compensation in 2015 according to NERC’s IRS form 990. NERC, which employs about 230, has a 2018 budget of almost $73 million.
Berardesco
Berardesco, who goes by “Charlie,” joined NERC as general counsel in July 2012 after more than nine years at Constellation Energy, where he served as senior vice president, general counsel, corporate secretary and chief compliance officer.
Before Constellation, Berardesco practiced law and served in executive positions at Fusara, a consortium of AIG, Kemper and Prudential, and HCIA, a health-care information company.
Berardesco | Duke University Chapel
He has a bachelor’s in political science from Duke University and a law degree from George Washington University, where he was managing editor of The George Washington Law Review and now serves on the dean’s board of advisors.
According to his NERC biography, his other nonprofit endeavors include serving as chair of Duke University Chapel’s advisory board; board chair of the Gay Men’s Chorus of Washington, and a member of the Business Council of the Human Rights Campaign.
Among his awards and recognition: named one of the top 10 “GC’s to Watch” by The Corporate Board magazine; named a Leader in the Law by The Daily Record; and winner of the Out and Proud Corporate Counsel award by the National LGBT Bar Association.
Increased labor costs from the expanding Western Energy Imbalance Market (EIM) helped push up CAISO’s 2018 revenue requirement by $1.9 million to $197.2 million, but growing EIM revenues will offset some of the costs, the ISO said Tuesday.
CAISO is taking comments on its proposed 2018 budget, which calls for $217.4 million in total outlays, up 1.4% from this year. The spending package includes 14 new full-time positions, along with raises, promotions and benefit increases. Offsetting the costs are a projected $3.4 million increase in revenues, including a projected $2.6 million growth in EIM proceeds.
“That is almost entirely being driven by EIM,” CAISO Chief Financial Officer Ryan Seghesio said of the new employee positions during a Nov. 7 conference call. “We see some needs to add some headcount, particularly in the technology space, to help the EIM market. The good news there is that it gets offset from some EIM revenue.” The proposal would bring the ISO’s total number of budgeted employees to 614, according to his presentation.
The operations and maintenance budget, which refers to costs of ongoing operations, grew by about 3% to $178.5 million, including the 14 new positions. Debt service — principal and interest payments — remains flat at about $16.9 million. Collection of capital was lowered by $2 million to $22 million to help absorb some of the operations and maintenance increase, he said. Transmission volume is expected to increase slightly to 241 TWh.
Proposed 2018 CAISO budget, by resource | CAISO
Capital and project requirements are budgeted at $18 million. CAISO listed dozens of proposed projects for 2018, divided into market and operational excellence; technology improvements; customer service; and grid evolution readiness and regional innovation opportunities.
EIM administrative charges are projected to grow by 56%, or $2.6 million, to about $7.4 million, because of increased participation. Fees for forecasting intermittent renewables are also projected to grow by 52%, or $1.1 million, to about $3.2 million because of new resources coming online.
But the costs of conducting studies of large interconnection projects are projected to decrease by $700,000, or 37%, to $1.2 million, CAISO said. The ISO recovers its revenue through the grid management charges paid by market participants.
CAISO in the budget proposal also discussed its goals, including aggregating distributed energy and clean resources, citing 21,000 MW of renewables that are connected to the grid.
“The ISO is closely coordinating and collaborating with generators, utilities, transmission owners, energy regulators and diverse stakeholder groups, developing a grid and market structure that encourages distributed energy resources,” CAISO said. “Following a tariff filing and regulatory approval (which is expected in early 2018), entrepreneurs and utilities will be allowed to bundle, or aggregate, DERs such as energy storage, so that any extra energy can participate in the ISO wholesale market just like a utility-scale generator.”
Comments on the budget proposal are due on Nov. 14, with a vote by the Board of Governors set for Dec. 13-14.
While not even a year has passed since MISO implemented its new interconnection queue process, one market participant is already urging stakeholder groups to consider a two-stage queue instead of the RTO’s selected three-stage design.
EDF Renewable Energy argues that the “flawed” three-stage process is worsening the interconnection backlog, and that MISO has the means to implement a two-stage queue. During a Nov. 7 conference call, the company asked the RTO’s Steering Committee to assign the appropriate stakeholder committee a discussion on shortening the queue process for vetted projects and developing an earlier assessment of milestone payments.
“MISO’s published data shows a serious backlog in its queue,” EDF’s Omar Martino wrote in comments to the RTO. “It needs a streamlined process so that projects that demonstrate they are ready to proceed toward an interconnection agreement can actually achieve that.”
Steering Committee members determined they need more information on the EDF proposal before they can assign the issue to a stakeholder committee. They asked the company to return in January with a fuller explanation.
Bruce Grabow, an attorney with Locke Lord representing EDF, said that while MISO’s three-stage process is a “good” model, it doesn’t require enough front-end milestone fees to discourage “speculative megawatts.” He said charging milestone payments before the definitive planning phase (DPP) of the queue could discourage uncertain projects from entering.
In an effort to reduce restudies that caused backlogs in the old queue process, MISO’s new queue design divided the DPP — the final stage of the queue — into three phases in which system impact studies are performed three separate times in lieu of restudies. At the time, MISO estimated that interconnection customers would spend 460 days in all three stages combined, instead of the previous average 589 days in the DPP.
“Shore up a bit more the site control from the beginning,” Grabow urged, noting that 60 to 70% of MISO’s queue entrants now enter the queue without securing site control, electing to instead pay a $100,000 fee as part of the new queue rules.
“We’ve opened the floodgates, so to speak,” he said.
MISO views a queue overhaul so soon after the January approval of the new design as “premature,” MISO Stakeholder Relations Specialist Justin Stewart said. “FERC approved the process in January, and we’d like to see a full cycle through.”
Grabow said he was only asking to begin a discussion in the Planning Advisory Committee.
MISO External Affairs Director Vikram Godbole said stakeholders debated the merits of a two-phase queue process in 2015 and ultimately decided against it. He asked stakeholders to allow time for the new queue design to work before proposing modifications.
“I’m personally wary of making changes before we see how the changes we’ve just made roll through the process,” said PAC Chair Cynthia Crane.
Similar Requests Denied in FERC Order
EDF’s request for a faster queue comes on the heels of a Nov. 3 FERC order that denied a rehearing of several aspects of the new queue process.
That order stemmed from a filing by a group of generation developers who complained that MISO’s new process had failed to actually streamline the queue because it does not update system data as quickly as promised and charges only $100,000 upfront when a project developer has not yet secured site control (ER17-156).
The generation developers also questioned FERC allowing MISO to conduct restudies after a generation interconnection agreement has been signed, and also contended that a developer that withdraws its projects within six months of signing such an agreement should have to pay to mitigate the cost shifts stemming from the cancellation.
The commission rebuffed most of the developers’ arguments, saying the group failed to provide evidence or reasoning to support its proposal, and that MISO’s role was to “minimize but not necessarily eliminate restudies.”
But FERC did agree with the developers’ concerns about projects withdrawing from the queue after executing interconnection agreements, which prompts the need for restudies and increases interconnection costs. The commission directed MISO to include data on the number of such withdrawals — and the number of resulting restudies and their cost impacts — in its semiannual reports on the queue process.
FERC denied a request for a special “fast track” study process for developers who can demonstrate “site control, evidence of power sales opportunity and security in the amount of 20% of all identified network upgrades,” but it advised MISO to alleviate delays for those developers anxious about missing production tax credit deadlines.
The developers claimed that MISO’s queue transition timeline is already behind schedule, with interconnection agreements for the MISO West region February 2017 transition group delayed until June 2019, “a full five months beyond the planned January 2019 completion date.”
MISO argued that adding a faster study timeline option would throw its interconnection process “into disarray.”
“Although such delays suggest that MISO’s queue reforms may not be working as well as intended, we do not find that these delays rise to the level of the ‘extraordinary circumstances’ the commission has required to reopen the record … and to disturb the finality of the DPP framework accepted in the Jan. 3 order,” the commission said. “We strongly encourage MISO to consider measures that could be adopted to address the delays.”
