Although MISO’s new queue design has just been implemented, RTO officials are continuing to look for improvement.
“We are not done. Queue reform is a journey, not a destination,” MISO Vice President of System Planning and Seams Coordination Jennifer Curran told the System Planning Committee of the Board of Directors on Feb. 21. FERC approved the changes in January. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)
Curran said that while MISO has already addressed multiple requirements that could arise from FERC’s December Notice of Proposed Rulemaking (RM17-8) requiring changes to pro forma large generator interconnection rules, the NOPR could require additional work on cost caps and eliminating barriers to storage’s participation.
In 2008, the RTO found that if it didn’t change its queue process, it would take a “clearly unacceptable” hundreds of years to process all of the project requests then in the queue, Curran said. Since then, MISO has moved from a “first-come, first-served” approach to a “first-ready, first-served” approach. She said historically 15% of queue entrants’ requested megawatts make it to commercial operation.
MISO’s new rules are designed to reduce restudies, allowing it in some instances to keep milestone payments from withdrawn projects to fund transmission upgrades on which other queue projects relied.
“Queue reform is, and has been, an on-going process. We will continue working with stakeholders to ensure we have the most efficient and effective rules in place to interconnect resources of all types,” Curran said.
Curran said the MISO queue remains dominated by wind projects, although there is also a “non-negligible” number of solar requests. She said the number of projects in the queue will face uncertainty in 2020 as wind production tax credits expire and planned wind projects could drop.
Wind has long had the highest project drop-out rates because several developers often enter the queue to serve a single load area, Curran said.
She also said MISO’s future HVDC lines must enter the interconnection queue under its “other” category because merchant lines can behave like new generation with their ability to inject energy.
Aside from 72 MW of storage planned for MISO Central, there is not a lot of storage on the horizon, she said. Storage also is a part of the RTO’s “other” queue categorization.
Duff-Coleman in Monitoring Phase
MISO has moved into the monitoring phase of Republic Transmission’s Duff-Coleman project construction in southern Indiana and Kentucky, Priti Patel, regional executive for MISO North and executive director of the RTO’s Competitive Transmission Administration, told stakeholders.
The RTO will receive quarterly project reports from Republic Transmission that will detail any construction delays or cost overruns, Patel said. Before Order 1000, she said, MISO received “vary basic” project reporting on market efficiency and multi-value projects.
Project reporting “is a very critical tool for MISO, to hold developers responsible. … Mainly, we will monitor and make visible the developer’s activities on the project so the developer eventually delivers what they have promised,” Patel said.
MTEP 16’s Huntley-Wilmarth upgrade — though not competitively bid because of Minnesota’s right-of-first-refusal statute — will also be subject to the more intensive reporting as a market efficiency project, Patel said. (See MTEP 16 Proposes 394 Projects at $2.8 Billion.)
Although MISO has no jurisdiction over the two projects, she continued, stakeholders can use its progress reports to raise any concerns to state or federal regulators.
Director Phyllis Currie asked if MISO encountered anything unexpected in last year’s competitive bid process.
MISO was impressed that all 11 developers provided “much more” information than required of them in the request for proposals, Patel replied.
MISO General Counsel Andre Porter halted the board’s question on whether any developers left disgruntled with the process. “That’s best left for closed session,” he said.
In a related matter, Patel said that MISO will complete its qualification of transmission developers by March 7.
NiSource is holding firm to its plan to retire half of its coal generation by 2023 while increasing infrastructure spending from already record levels, the company told Wall Street analysts Wednesday.
The company’s Northern Indiana Public Service Co. will close its 480-MW Bailly coal-fired plant near Chesterton, Ind., by mid-2018 and plans to shutter Units 17 and 18 (a combined 722 MW) at the 1,780-MW R.M. Schahfer plant near Wheatfield, Ind., by the end of 2023. (See NIPSCO Considers Closing 4 Coal Units in 7 Years.)
Bailly Generating Station | NIPSCO
NiSource spokesman Nick Meyer confirmed that MISO in mid-December approved the Bailly coal plant retirement for May 31, 2018. Meyer said both retirements are primarily the result of “low market gas prices and an aging coal fleet.”
The retirements are part NIPSCO’s biannual integrated resource plan submitted to the Indiana Utility Regulatory Commission on Nov. 1. The plan is still awaiting commission approval.
During an earnings call, NiSource CEO Joseph Hamrock said the company’s IRP does not call for any new generation through 2019. A longer-term proposal to replace the capacity will come in the next IRP in 2018, the company said.
In 2015, about 70% of NIPSCO’s approximately 3,800-MW generation fleet was coal-fired. Natural gas generation comprises roughly 20% of NIPSCO capacity, the lion’s share at the 535-MW Sugar Creek Energy plant near Terre Haute, Ind.
While NiSource’s coal capacity will shrink, it expects its infrastructure spending to balloon. Hamrock said NiSource invested a record $1.5 billion in gas and electric utility infrastructure in 2016, including replacement of 406 miles of gas pipeline, 60 miles of underground cable and more than 1,200 electric poles.
Hamrock also reaffirmed the IRP’s proposal to upgrade its remaining coal fleet, with the utility asking regulators for approval to invest $400 million in environmental upgrades at the two remaining Schahfer units and its 580-MW Michigan City coal plant.
Graycor Industrial Constructors completed a Wet Flue Gas Desulfurization system at NIPSCO’s R.M. Schahfer Generating Station located in Wheatfield, Ind., in 2014. | Graycor
Hamrock highlighted the company’s gas base rate case settlement approvals in Kentucky, Maryland, Pennsylvania and Virginia, as well Indiana regulators’ approvals of a seven-year $824 million gas modernization plan and a settlement granting NIPSCO a $72.5 million annual electric rate increase.
Altogether, NiSource plans $20 billion in long-term gas infrastructure investments and $10 billion in long-term electric infrastructure spending. Hamrock said NiSource now expects to invest between $1.6 billion and $1.7 billion in infrastructure in 2017, up from a prior estimate of $1.5 billion.
“We’re committed to further reducing our greenhouse gas emissions through these continued gas modernization investments and planned coal-fired plant retirements as we diversify our electric generation portfolio,” Hamrock said. In early 2016, he noted, NiSource signed on for EPA’s Methane Challenge Program, committing to reduce methane emissions by 300 Mcf over five years.
NiSource reported 2016 income of $328.1 million ($1.02/share) from continuing operations, compared to 2015’s $198.6 million ($0.63/share). Fourth-quarter earnings from continuing operations were $88.8 million ($0.28/share) versus $64.4 million ($0.20/share).
2016 was the first fiscal year for NiSource as an exclusively regulated utility, following its separation from Columbia Pipeline Group in mid-2015.
Hamrock said NiSource added 33,000 new customers in 2016, the best growth in a decade. NiSource serves roughly 500,000 electric customers in northern Indiana and 3.5 million natural gas customers in seven states.
CAISO market participants continue to seek more details about an “expedited” ISO proposal to procure black start resources.
During a Feb. 21 call to discuss the plan, stakeholders pressed ISO staff to provide more specific information on the expected technical requirements for black start units, how the procurement process would play out and the contract terms for selected resources.
The ISO developed the proposal after identifying a need for additional black start resources in the transmission-constrained San Francisco Bay Area, which falls within Pacific Gas and Electric’s service territory. (See CAISO Kicks off Initiative to Procure Black Start Resources.)
CAISO’s black start procurement initiative was prompted by the need to acquire more system restoration resources to serve the constrained San Francisco area. | SF Travel
CAISO’s draft plan envisions significant collaboration between the ISO and an affected transmission owner to develop the specifications describing the requirements and selection criteria for the black start resource in the procurement process. The ISO would approve or reject the TO’s recommended resources. (See CAISO Proposes TO-focused Black Start Procurement.)
Ellen Wolfe, president of Resero Consulting, sought to know more about the history of black start procurement in California, questioning why CAISO was developing a new process.
“Historically, [TOs] have developed the restoration plans — is that correct?” Wolfe asked.
Neil Millar, CAISO executive director of infrastructure development, confirmed that utilities previously were solely responsible for devising black start plans. With the creation of CAISO, system restoration took on a collaborative approach in which the ISO “accumulates, reviews and can modify” plans if it identifies shortcomings.
“So it’s a layered approach, with the [TOs] taking a first cut and then the ISO looking at the aggregate of the various restoration plans and reviewing to make sure that there are adequate black start resources available,” Millar said, noting that the requirement for developing plans is now a “shared responsibility.”
Millar added that the ISO’s tariff allows for the acquisition of additional black start resources if needed.
“That’s the direction we see needing to move, but the question is how do we go about doing that and where should those costs actually fall?” he said.
Wolfe turned her focus to the proposed collaborative procurement process itself, asking whether the affected TO would get just the technical information from a resource bidding as black start capable, or cost information as well.
“We’re expecting that [the TO] would get all that information” from the bids, said Scott Vaughan, CAISO lead grid assets engineer. “Then they would provide a recommendation to the ISO and we would look at the analysis and either agree or not.”
Wolfe asked if the TO would effectively be acting as the “agent” for all the load-serving entities within its territory “in terms of making prudent financial choices as well.”
“The one point that we want to be clear on is that the ISO is ultimately procuring the additional service under our Tariff, so while we’re looking for the heavy participation of the [participating] TO to sort out which is the best resource, we ultimately have to wear our procurement decision,” Millar said.
Paul Nelson, electricity market design manager at Southern California Edison, sought more specifics on the potential length of the contracts and wondered whether entering multiyear arrangements with generators marked a “new area” for the ISO.
“Is this something you’ve done in the past?” Nelson asked.
CAISO currently has multiyear contracts for black start capability with TOs and generators, but they offer no compensation, explained Andrew Ulmer, the director of federal regulatory affairs at the ISO.
“So it’s a little different, because we’re talking about contracts with non-zero price terms now and figuring out a way to address that fact and allocate costs,” Ulmer said. “But [there is] no real difference in the structure of the contracts we have today.”
Ulmer added that the ISO is specifically seeking stakeholder feedback on the terms of the contracts.
Brian Theaker, director of market affairs at NRG Energy, asked if CAISO expected to publish a list of resources capable of meeting the black start requirements in the San Francisco area before conducting the solicitation.
“I think our expectation was that we would be able to define geographically the area that would help us meet the requirement, and that the generators themselves would be able to decide whether or not they were in or out,” Millar said.
Theaker raised the potential for a conflict of interest in the procurement.
“Is it possible that PG&E — in addition to being an entity that would review the offers into the solicitation process — would also be a party that would be participating in the solicitation process?” he asked.
Millar said it could happen, but it was unlikely because any black start-capable resource already owned by the utility is probably already included in the system restoration plan. “I think we’ll take your point that there needs to be some check and balance on a potential conflict there,” Millar added.
Alan Wecker, market design analyst at PG&E, said his company is “thinking through” the conflict-of-interest issue to ensure that it develops “walled-off procedures similar to how we run our [requests for offers] — such as the storage RFO — where we have our utility side participating as a bidder.”
CAISO is leaning toward a cost-of-service approach for compensating generators rather than providing a capacity-type payment sufficient to support the operation of an otherwise unprofitable resource. Under the current proposal, contracts — in which the ISO would be the counterparty — would run either five or 10 years with a clause requiring one year’s notice for termination.
On the issue of cost allocation, Wolfe asked if ISO staff had considered collecting the costs through CAISO’s transmission access charge. The ISO has proposed having individual TOs recover the expense from its customers through its reliability services rate schedule.
Ulmer said staff had considered the TAC alternative, and that the Tariff would allow the ISO to “peanut butter” the cost across all scheduling coordinators.
“But if we wanted to step back and make a more geographic, precise allocation of these costs, would that mechanism meet that requirement? We don’t think it would,” Ulmer said.
The ISO is seeking comments on the black start procurement proposal by Feb. 28 and plans to issue a draft final proposal by March 14. ISO management expects to submit a final plan to the Board of Governors approval in May.
AUSTIN, Texas — NextEra Energy has taken its bid to acquire Texas utility Oncor before the Public Utility Commission of Texas, the same body that last year effectively sank a previous attempt to buy the same company.
If the first day of hearings Feb. 21 was any indication, NextEra’s $18.7 billion attempt to gain 100% ownership of Oncor is no slam dunk.
PUC commissioners peppered Oncor CEO Bob Shapard with questions about whether his regulated Texas utility would really be able to be managed by a Florida company with a reputation as an aggressive competitor.
“A broad concern in the pink building,” Commissioner Ken Anderson said, referring to the nearby state Capitol, “as well as with the stakeholders, is that they’re not known as being wallflowers. Even early on in this process, they have gently reminded us that [our approach] wasn’t the right approach.”
NextEra is “trying to show they’re listening,” he said. “They’re trying to convince you they’re listening to other parties.” Shapard pointed out that, through its Florida Power & Light subsidiary, NextEra is the largest investor, employer and taxpayer in Florida, a position it’s vigorously protected.
“When they first came in [to Texas], they thought this market was like Florida, but it’s not,” Shapard said. “I think [NextEra CEO] Jim [Robo] will trust us to handle business in Texas.”
Robo is scheduled to personally make his case as a witness before the PUC on Thursday.
The two companies need the commissioners’ approval to proceed with the acquisition. NextEra has attempted to appease the PUC through numerous commitments to maintain Oncor’s independence, including placing Texas residents and independent directors on the utility’s board. (See NextEra Energy Talks Up its Oncor Acquisition.)
Shapard would chair the board, with General Counsel E. Allen Nye Jr. succeeding him as CEO. Nye is the son of former TXU CEO Erle Nye, who retired from the company before a 2007 leveraged buyout by private-equity groups that eventually led to the Chapter 11 bankruptcy of Oncor’s parent corporation.
“Aren’t you a little worried about being hometowned by a Florida company?” Chairman Donna Nelson asked Shapard.
“Jim will insist this company is run pretty well,” Shapard said. “Will he drive Allen crazy? I don’t know, but the operation of the company is not the issue.”
There was little disagreement with commissioners over Oncor’s performance and value, despite the bankruptcy of its parent company, Energy Future Holdings. That was generally attributed to stringent ring-fence measures placed upon the utility after the leveraged buyout, which insulated Oncor from its unregulated generation and retail energy affiliates and the eventual financial difficulties of its owner.
PUC staffer Stephen Mack said there was no disputing that the ring fence around Oncor has served its purpose and the risks to the company are lower than if it had been exposed to the “EFH family.”
Oncor has “maintained a strong credit rating, and it cares deeply about maintaining that credit rating,” Mack said.
NextEra and Oncor are now saying the ring fence is still strong enough. Intervenors, led by PUC staff, the Texas Office of Public Utility Counsel, Texas Industrial Energy Consumers (TIEC) and the Steering Committee of Cities Served by Oncor, are pushing for even more robust protection.
Attorney Geoffrey Gay, representing cities served by Oncor, noted that when Hunt Consolidated withdrew its offer for Oncor last year, the utility was still able to reach out to 18 other entities to gauge their interest. (See With Oncor Back on the Market, Multiple Suitors Line Up.)
“That tells me the industry in general recognizes Oncor is a gem,” Gay said. “It’s worth a lot, and its ownership will be beneficial to whoever acquires it.”
NextEra says it needs to maintain control over Oncor’s board by having the ability to appoint, remove or replace the utility’s directors.
That might seem a small price to pay for having NextEra lend its A- credit rating and a market cap of $59.24 billion to help Oncor eliminate the overhang of $11 billion to $12 billion in debt left by EFH — but the Texas entities don’t seem to see it the same way.
“The TIEC members represent billions of dollars captive to Oncor that could be harmed if this doesn’t turn out well,” said the TIEC’s legal counsel, Phillip Oldham. “Our group requires us to kick the tires, look under the hood and see how much stress this situation can endure.”
The TIEC has submitted testimony from Charles Griffey, a consultant and former regulatory executive with Houston-based Reliant Energy. Griffey offered a number of recommendations that he said would improve Oncor’s position, including a requirement that all the board members be Texas residents.
“We ask you to take a hard look at that issue in particular,” Oldham said. “Our desire is to ensure Oncor is protected and continues to do the job it’s been doing, even if there are problems with the parent.”
Oldham also said NextEra is not really “extinguishing” Oncor’s debt, a position with which Anderson agreed.
“That’s not really correct,” Anderson told Oncor’s panel of witnesses. “It’s being refinanced. Whatever the amount and however you describe it, what they’re really doing is spreading the peanut butter over a bigger piece of bread.”
During the second day of hearings, Mark Hickson, NextEra’s executive vice president of corporate development, strategy and integration, said that the company has $12.2 billion in funding for the transaction — $9.8 billion for an 80% interest in Oncor and $2.4 billion for a 20% interest in various holding companies.
He agreed that the full debt would not transfer to NextEra, saying the company would assume only $6.5 billion, in line with its 60/40 debt-to-equity ratio.
“We have said we are going to finance this transaction in a way that allows us to maintain our strong credit rating,” Hickson said. “We are laser focused, as we always have been as a company, in maintaining our credit metrics, which means maintaining our target metrics.”
Hickson said NextEra works closely with Moody’s Investors Service, Standard & Poor’s and Fitch Ratings, and has separate targets with each of the three. He spent much of Wednesday downplaying the company’s communications with the agencies.
The PUC’s approval would end EFH’s nearly three years in bankruptcy. What’s left of TXU has already spun off its Texas competitive businesses, power generator Luminant and retailer TXU Energy as standalone companies.
On Feb. 17, a U.S. bankruptcy judge in Delaware accepted EFH’s plan to exit bankruptcy after the company said it had resolved a final lingering dispute after its noteholders reached an agreement to modify what they were owed.
The settlements were with two creditor groups, who were offered 95% or 87.5% of their make-whole claim premiums, in addition to full principal and interest. The groups had been seeking about $800 million.
The PUC’s hearings on the acquisition are scheduled through the end of the week but will likely end Thursday.
After reporting a loss of $6.2 billion ($14.49/share) for 2016, FirstEnergy’s CEO said the company plans to seek subsidies for its Davis-Besse and Perry nuclear plants in Ohio to make them attractive to buyers and allow the company to exit competitive generation in 2018.
Perry Nuclear Plant | Wainstead
“I can’t speak for prospective new owners of these four nuclear units, but I can tell you this: Running nuclear reactors isn’t something that just anybody can do. And there is a significant amount of capital risk associated with that business,” CEO Charles E. Jones said in response to analysts’ questions during an earnings call Wednesday. “I’m not sure people are going to be willing to take on the risk of even the next refueling outage, which is very expensive, so I don’t think there’s any guarantee — absent some other support for these units — that they’re going to keep running far into the future.”
The “support” would be zero-emissions credits, which have been approved for nuclear power plants in Illinois and New York but face challenges in federal court.
FirstEnergy’s multibillion-dollar loss for 2016, which came on revenue of $14.6 billion, includes asset impairment and plant exit costs related to its decision to leave competitive generation by mid-2018. The company reported earnings of $578 million ($1.37/share) in 2015 on revenue of $15 billion.
For the fourth quarter, FirstEnergy posted a loss of $5.8 billion ($13.44/share) on revenue of $3.4 billion versus a loss of $226 million ($0.53/share) on revenue of $3.5 billion a year earlier. Higher corporate operating expenses and increased retirement costs factored into the loss, but it was partially offset by reductions in the valuation of pension and post-employment benefits.
The company’s adjusted earnings were $2.63/share for 2016 compared to $2.71/share for 2015 and 38 cents/share for the fourth quarter compared to 58 cents/share a year ago.
Jones said the company’s generation fleet will go into bankruptcy without a buyer, and a buyer is unlikely without more financial certainty for the nuclear assets.
“These assets are now valued at somewhere around $1.5 billion and that includes the nuclear fuel that they own. The debt is significantly higher than that. … It’s highly unlikely that we’ll get the book value to a place that’s greater than the debt. … Absent something to raise the value of these units and make them attractive to a buyer, there’s only one way for us to exit this business,” he said. “I’ve been up front with the legislators that I have met with, personally, to tell them, ‘Don’t do this [approve ZECs] for FirstEnergy because it’s unlikely we’re going to be the long-term owner-operators of these assets.’”
PJM has remained agnostic about state actions but active in figuring out ways to address them.
“Our position is not whether a state should or shouldn’t do whatever it is they want to do, but [what] we have to think about is how do we make sure the market remains competitive. … We need to protect the integrity of the regional market price,” PJM CEO Andy Ott said in an interview with The Plain Dealer, Cleveland’s major daily newspaper. “We have to figure out a way to harmonize what is happening in wholesale markets and what is happening at the state level.”
Last month, RTO stakeholders approved the creation of the Capacity Construct/Public Policy Senior Task Force to consider how to ensure that PJM’s markets don’t run afoul of state initiatives. Its first meeting is on March 6. (See PJM to Review Impact of State Public Policies on RPM.)
He also noted that the company has restructured its finances in preparation for a potential return to cost-of-service regulation in Ohio.
“We successfully restructured our credit facilities to provide the necessary financial flexibility to become a fully regulated company,” he said.
On the regulated utility side, distribution deliveries increased 4% in the fourth quarter. Weather-related usage resulted in an 8% increase in residential sales compared to the prior-year period, while commercial sales increased 3% because of a combination of weather and stronger demand. Heating degree days in the fourth quarter were 8.9% below normal but 26.3% higher than the same period of 2015. Deliveries to industrial customers increased nearly 2%, primarily because of higher usage in the shale gas and steel sectors.
The regulated transmission business increased because of a higher rate base associated with its Energizing the Future infrastructure program. Earnings were flat year over year, reflecting an increase in rate base offset by a lower return on equity at its electric transmission subsidiary, American Transmission Systems Inc., as part of its comprehensive formula rate settlement.
In its competitive generation business, its commodity margin was down compared to 2015 from lower capacity revenues and contract sales volume, though it was partially offset by higher wholesale sales and lower capacity and fuel expenses.
PJM stakeholders have lingering questions about the RTO’s plan to implement a fuel-cost policy review process — despite a three-hour discussion intended to help sort out the issue.
Those questions focused on how the review will unfold in light of an ongoing debate between PJM and its Independent Market Monitor about who has the final word on policy approval.
Responses from PJM and the Monitor only added to the confusion.
The issue provoked tension between the two during PJM’s submission of a compliance filing with FERC on hourly generation offers. While that filing was supposed to focus on improving flexibility for such offers, PJM also initiated a petition under Section 206 of the Federal Power Act to implement changes to its policy-approval rules and penalties.
During that proceeding, Monitor Joe Bowring argued that the RTO was attempting to usurp his authority to review fuel-cost policies. PJM requires generation units that use fuels with volatile prices to explain their methodology for purchasing fuel so the RTO and Monitor can confirm it was secured through a competitive process.
PJM argued that approval of the policies was wholly under its authority, and FERC accepted the RTO’s proposal earlier this month, including its delineation of review responsibilities. (See FERC Seeks More Details on PJM Fuel-Cost Policy Proposal.)
The debate extended into a Feb. 21 special session of the Market Implementation Committee, where PJM was emphatic that generators can’t hold separate discussions with the Monitor on such policies.
“PJM needs to be involved in those discussions,” said Jeff Schmitt, manager of market analysis. “There is only one process.”
Bowring responded that his role remains separate from that of PJM.
“Just to be clear: We have our own separate standard of review that we’ve had for some time,” he said. “If we ultimately disagree with PJM’s decision, we’ll make that clear [to PJM]. Our role remains our role.”
“You review for market power, but what you do not do is approve the fuel-cost policy,” PJM attorney Steve Shparber responded.
Shparber said that generators must follow PJM’s policy on the matter — not a Monitor “shadow” policy.
“There’s only one fuel-cost policy, and that’s approved by PJM,” he said.
Bowring countered that he wasn’t suggesting that there is a “parallel process.”
“We understand the process, but it’s not definitive about market power,” Bowring said.
The Monitor added that FERC’s ruling isn’t going to change how his team reviews policies, and that he didn’t think the ruling was intended to have that effect.
That exchange occurred near the middle of the meeting, but it colored many subsequent questions from stakeholders, who asked what shape the process would take and how generators would be notified about whether their policies need approval.
“In the last 18 months, we’ve been in touch with every single owner in PJM, so no one should be oblivious,” Bowring said.
Schmitt clarified that generators currently only require a policy that covers any fuel type the unit might use, but PJM plans to enhance that in the future.
“Ideally, we’d like to have a one-for-one where every unit has its own policy [for each fuel type], but we’re not there yet,” he said.
Bowring has repeatedly called for policies to be systematic, algorithmic and verifiable, but PJM has hesitated to require algorithmic accounting. That didn’t sit well with stakeholders.
“I guess my concern is you’re asking us to be comfortable with a standard that is: They comply with a document that the public cannot see,” said Gregory Carmean, the executive director of the Organization of PJM States Inc.
Catherine Mooney, who works for Bowring’s firm Monitoring Analytics, suggested developing sample-approved language that’s verifiable but not algorithmic, but Schmitt declined to commit to that.
Schmitt said PJM’s long-term plan is to get all policy information into a database rather than an approved document. Until then, RTO staff stressed that stakeholders need to follow the guidelines in the manuals.
During the meeting, PJM also displayed a slide that compared maintenance costs for units that run — which can recover for variable operations and maintenance (VOM) — versus units that don’t run, which recover avoidable cost rates. Dave Pratzon of GT Power Group questioned PJM’s grouping of combustion turbine hot gas path inspections under VOM when 2015 rule changes excluded major overhauls and inspections of CTs and combined cycle units in VOM.
Natural gas plants in PJM’s energy market, such as Duke Energy’s 620-MW Buck Combined Cycle Station in Rowan County, N.C., would be subject to the RTO’s rules on fuel-cost policies. Photo Source: Duke Energy
Schmitt said revisions to the CT and CC rules might be necessary but will likely need to be handled with a problem statement after the fuel-cost policy issue is resolved to figure out the best way to “unwind” them, given the complexities of three-year forward-looking energy auctions.
WASHINGTON — Scott Pruitt had his coming out at the EPA last week, promising to root for the Washington Nationals, obey the rule of law and “be a good listener.”
Pruitt
The new administrator took no questions following the 11-minute noontime speech Feb. 21.
Pruitt received an EPA lapel pin, an EPA baseball cap and a polite, partial standing ovation, as he was introduced as a father, husband, former state senator and a businessman — the former co-owner of the Texas Rangers’ AAA farm club in Oklahoma City. Because the Rangers are in the American League, Pruitt joked, he would feel no divided loyalties becoming a Nationals fan.
His low-key speech did not mention any of the more than a dozen lawsuits he filed against the agency, including the one now pending against the Clean Power Plan, nor the executive orders President Trump is reportedly readying that would undo the CPP and one expected Tuesday requiring a review of the 2015 Waters of the United States rule. There was no hint of the 25% budget cut President Trump is reportedly proposing for the agency.
But without mentioning any specific targets, Pruitt gently lectured the approximately 75 EPA employees in the Rachel Carson Green Room that “process matters,” saying the job of the regulator is “to give certainty to those that they regulate.” He also criticized the use of consent decrees that he said bypass the Administrative Procedures Act, calling it “regulation through litigation.”
Jefferson, Madison and Hamilton
Pruitt’s address came the day before Oklahoma officials released thousands of emails illustrating a cozy relationship between the former state attorney general and energy companies.
Pruitt opened the speech by telling a story from Joseph Ellis’ book “Founding Brothers” about how Thomas Jefferson, James Madison and Alexander Hamilton reached a deal over a bill authorizing the federal government to assume the states’ debts. Pruitt recounted how Madison and Jefferson agreed over dinner to Hamilton’s plan — in return for a promise to move the capital from New York to the banks of the Potomac.
Pruitt said the anecdote was meant to harken days when compromise was possible, contrasting it with the “very toxic environment” he said dominated the country now. “I seek to be a good listener,” he promised. “You can’t lead unless you listen.”
He also quoted from Daniel Hannan’s “Inventing Freedom,” to highlight the principle that “process matters.”
“Regulations ought to make things regular. Regulators exist to give certainty to those that they regulate. Those that we regulate ought to know what’s expected of them so that they can plan and allocate resources to comply. That’s really the job of the regulator,” he said.
‘Informed Decisions’
Pruitt said following the proper processes “sends a message that we take seriously our role of taking comment and offering response and making informed decisions.” In oral arguments over Pruitt’s challenge of the CPP in September, EPA had defended its outreach, saying it received 4.3 million comments and held more than 600 meetings with stakeholders during the rulemaking. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
The new administrator also said rulemaking “needs to be tethered to the statute.”
“The only authority that any agency has in the executive branch is the authority given to them by Congress. Sometimes those authorities are broadly stated, giving much discretion to agencies … but other times Congress has been very prescriptive … we need to respect that.”
Pruitt also said the agency should see itself as a “partner” with state regulators “and not adversaries.”
He closed the speech by quoting Sierra Club founder John Muir’s observation that man “needs beauty as well as bread,” insisting that one can be “both pro-energy and jobs and pro-environment.”
In his confirmation hearing in January, Pruitt had defended letters he sent to EPA and other federal officials — on state government stationary and signed by him — that had been authored by oil and gas companies, saying he was representing the state’s interest because the industry is responsible for one-quarter of the state’s budget.
Sierra Club Executive Director Michael Brune did not appreciate the shout out to his organization’s founder. “John Muir is rolling over in his grave at the notion of someone as toxic to the environment as Scott Pruitt taking over the EPA,” he said in a statement.
Confronting the Bureaucracy
Pruitt’s plans for the agency are certain to be met with skepticism, if not hostility, by many in the EPA bureaucracy.
John O’Grady, an EPA environmental scientist who leads the union that represents 9,000 EPA employees, toldThe Guardian that Pruitt’s remarks came across “very professionally and conciliatory. He didn’t come out heavy handed.”
“Mr. Pruitt isn’t a proponent of addressing climate change or of a strong EPA, so it won’t surprise me when they start to whittle away at what we do as an agency,” O’Grady added. “I’m wondering when the hammer is going to fall.”
Before Pruitt’s confirmation, dozens of EPA employees took part in a lunch hour rally outside the agency’s Chicago regional headquarters opposing his appointment. More than 400 former EPA officials signed a letter to Congress also seeking to block him.
But the new administrator is doing his best to wrest control of the agency. Immediately following his confirmation, EPA issued a press release quoting elected officials and industry leaders celebrating him and criticizing the agency’s “harsh regulatory overreach,” “runaway bureaucracy” and “toxic regulatory environment.” Rep. Jim Bridenstine (R-Okla.) was quoted calling EPA “one of the most vilified agencies in the ‘swamp’ of over-reaching government.”
The EPA workforce would be far smaller, if Trump has his way. The president will reportedly call for a 24% cut in EPA’s budget, part of broad cuts in domestic spending intended to fund increases in defense outlays.
EPA’s budget would be cut by $2 billion to $6.1 billion, according to news reports, with staff cut to 12,000 workers from 15,000.
The cuts would be far deeper than Congress has proposed, reducing EPA’s budget to its lowest level since the early 1990s and its staffing to the lowest since the 1980s. The House Appropriations Committee in 2015 called for reducing the agency’s funding by only $718 million.
Trump officials have said they will not slash the 40% of the agency’s budget that is sent to state, tribal and local governments as environmental grants. That means the cuts would fall more heavily on programs protecting air and water.
“We have real doubts that can be done without substantially weakening the ability of EPA to respond to environmental problems and to carry out its core functions that are all established in law,” John Coequyt, global climate policy director for the Sierra Club, told Bloomberg.
Emails Released
The day after Pruitt’s speech, the Oklahoma attorney general’s office released more than 6,000 pages of his email correspondence in response to an open records lawsuit by the watchdog group Center for Media and Democracy.
The emails show Pruitt taking talking points from energy companies, including American Electric Power and Oklahoma Gas & Electric, for letters complaining to federal environmental officials over rules on ozone, fracking and greenhouse gas emissions from oil and gas production.
Among the emails were some obtained previously by The New York Times, which reported in 2014 that Pruitt had sent letters to EPA, above his signature on state letterhead, that had been drafted by Devon Energy, an Oklahoma oil and gas producer.
The emails were “basically a big, long bear hug between Pruitt and oil and gas companies,” said Ken Cook, president of the Environmental Working Group, a nonprofit group that claims a mission of protecting human health and the environment.
The release of the emails also called into question Pruitt’s assertion in his confirmation hearing that he had never used private email for state business. KOKH, the Fox affiliate in Oklahoma City, reported that the attorney general’s office confirmed Pruitt had used a private account for some official correspondence.
Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitor, summed up her 2016 market year-in-review as simply as she could at the Board of Directors meeting Feb. 14. “Cheap, windy and all RUCed up,” she said to laughter.
Market prices dropped to an all-time low of $24.62/MWh for load-weighted average real-time energy and $2.45/MMBtu for natural gas, down from $26.77 and $2.57, respectively. While prices were low, a 30% increase in wind energy production led to an increase in its curtailments, and reliability unit commitments almost quadrupled, from 70 “unit days” to 269.
Garza said almost a third of those RUC events are under review as potential enforcement actions primarily from generators failing to comply with ERCOT dispatch instructions or not accurately reflecting the resource’s status.
“We see evidence of uncertainty and confusion about what you’re supposed to do when you receive a RUC instruction,” she said. “Thirty percent of RUC events in 2016 had something wrong with them. That’s too much. We either have a problem with the rules or people’s understanding of the rules.”
“When ERCOT issues a RUC instruction, there are ways for that generator to express a preference to opt-out. ‘Yes, I will come online, but I’m forgoing any make-whole payments that might come my way’ in exchange for, ‘I get to keep all the revenue,’” she said. “Because of that mechanism, I believe the increase in RUC activity that we’re seeing is a … result of generators trying to get some assistance in making that commitment decision.”
Garza pointed out that the ERCOT market is a self-commitment market, without rules or obligations to commit in real time besides financial incentives.
“Just because you have a day-ahead award does not mean you are required to start your unit in real time. That’s very different than other markets,” she said. “That difference leads to a commitment decision that is de-centralized. Every generator is making their own decisions. ‘Does it make sense for me to start today or tomorrow evening?’
“ERCOT is in the tenuous position of sometimes trying to figure out [whether] that action will actually happen, and when do they have to step in and ensure the adequacy of the grid, which they do through RUC instructions.”
Much of that problem is expected to be resolved by a rule change approved by the board and the TAC last year and scheduled to be implemented in late June. NPR744 enables qualified scheduling entities that submit bids and offers on behalf of resource entities or load-serving entities to opt out of RUC settlement by telemetering a resource’s status during the first interval it is online and available.
When unaffiliated Director Peter Cramton suggested the problem was a procedural issue that would be corrected by the protocol change, Garza said, “That’s my hope.”
“There are myriads of individual-type situations that could continue to be problematic,” she said. “We’re working with the ERCOT 744 team to understand how it’s being implemented. I hesitate to say it will all go away, but I will continue to raise awareness of this issue.”
The 269 unit days (a unit committed for as little as an hour counts as a day) resulted in only $1.2 million in make-whole payments, which are paid for by entities that were short generation. Another $1.4 million was clawed back from generators with offers in the day-ahead market and distributed to all load, the difference being market energy prices don’t cover start-up or minimum energy costs.
Half of the payments from day-ahead offers are clawed back from generators that opt out of RUC dispatch orders. Garza said generators RUCed for a thermal constraint are often motivated to opt out because their real-time energy prices will likely exceed their operating costs. But those RUCed for a local voltage issue, which would not cause a price spike, would generally obey the RUC order to qualify for make-whole payments, she explained. The bulk of RUC activity took place in the Houston area and South Texas, two regions where infrastructure projects have recently been energized or are under construction.
Garza also said zonal price differences indicated that wind energy once trapped behind constraints is now serving load. The West zone’s increased oil and gas production activity and congestion around Houston instead of the West led to lower prices in the West, reversing recent trends.
ERCOT Releases 2016 State of the Grid Report
ERCOT has released its 2016 State of the Grid report, titled “Inside the Promise.”
The promise, the ISO said, “is to coordinate the operation of the grid and market that serve electric consumers. In 2016, ERCOT implemented new tools to help manage more renewables and upgraded aging equipment for increased functionality. ERCOT also worked closely with stakeholders to update criteria used to determine the need for new transmission projects and improvements.”
The report highlights the ISO’s demand and energy usage records set last year, new milestones for wind generation, the doubling of installed solar capacity and new lows for average wholesale market prices.
Magness Foresees Growth in Utility-scale Solar
CEO Bill Magness began his regular report to the board and members by asking, “What could be more romantic than an ERCOT board meeting on Valentine’s Day?”
Magness said the Long-Term System Assessment shows continued load growth for the ERCOT market, with every scenario indicating significant increases in utility scale solar resources that could accelerate the need for additional transmission infrastructure in West Texas. He said the falling costs of solar and its potential to replace older generation may shift the “summer resource adequacy challenge” from the traditional 4-5 p.m. window to the 8 p.m. hour.
“A lot of the best solar resources are not congruent with the best wind resources,” Magness said. “Net peak resource adequacy issues are something we have to keep an eye on. We’ll have to work on ramping issues, just like we did for wind.”
Staff and the Regional Planning Group endorsed six major transmission projects in West Texas last year, and others are under review.
The Port of Brownsville near the Mexico border, where several LNG facilities have been proposed, could be “the big wild card,” Magness said. That will require additional generation in the fast-growing Lower Rio Grande Valley or additional transmission, he said.
“We’re going to have continued challenges to meet that load,” he said.
ERCOT’s preliminary net revenues for 2016 show a $13.4 million favorable balance, Magness said. The system administration fees were up $2 million, thanks to a stronger Texas economy. Personnel costs and purchases of computer hardware and other equipment were a combined $6.2 million under budget.
However, milder weather at the start of 2017 has left ERCOT “a little behind,” Magness said. Administrative fees are already $1.4 million under budget.
According to the CEO’s operational report, ERCOT has 254 active generation-interconnection requests totaling 59,896 MW, including 26,732 MW of wind generation, as of Dec. 31. The ISO had 17,604 MW of wind capacity in commercial operation at year-end.
Another Above-Normal Texas Summer Seen
ERCOT Senior Meteorologist Chris Coleman predicted another hotter-than-normal summer in Texas this year, saying it will follow recent patterns.
“Eight or nine of the past summers have been hotter than normal,” he said. “That’s just been the trend. It would really be going out on a limb to forecast a mild summer for Texas this year.”
Using the latest information from the National Oceanic and Atmospheric Administration, Coleman said 2016 was Texas’ third warmest year on record, dating back to 1895. He said this winter has been the sixth-warmest on record, with Austin recording 17 days of 80-degree temperatures or warmer.
Still, frigid temperatures early in the year helped ERCOT set a new winter peak of 59,650 MW on Jan. 6, breaking the previous record of 49,263 MW, set in January 2016.
Coleman said there is increasing potential for a warmer-than-normal spring that will likely produce a spring load peak in May. He will issue his final spring forecast and preliminary summer forecast March 1 as part of ERCOT’s Seasonal Assessment of Resource Adequacy, but he said there’s “no reason to deviate from a warmer-than-normal spring” prediction.
He also projected a wet spring. Texas recorded its two wettest years on record, with almost 74 inches of rain, in 2015 and 2016. The rainfall ended the state’s drought and any possibility of long-term droughts into the next decade, Coleman said.
Technology Refresh on Schedule, Budget
CIO Jerry Dreyer told the board that ERCOT’s four-year effort to update its software and hardware technology — some of it dating back to the last decade — is on schedule and “on budget, or slightly below.”
The $48 million DC4 program, the ISO’s fourth data center refresh, is aimed at replacing technology at the end of its life and support, including networks, telecommunications, servers and storage. It was approved as part of ERCOT’s administrative fee request in 2015.
“Most equipment we’re running today is from the 2010 era,” Dreyer said. “You take on a lot of risk when you’re running outdated equipment. You take on compliance risk and security risk.”
Dreyer said he had no major risks and issues to report. He said 38% of the new technology has been deployed and 40% of the budget was spent through 2016. Some new technology has completed testing and is already being migrated.
Dreyer pointed out that his IT group supports three data centers, 4 million GB of stored data, more than 400 distinct applications and 1,400 servers. He said that at the same time the DC4 program is replacing 400 systems, ERCOT will also be making architectural improvements.
The project will conclude in 2019.
“The intention is to reduce the impact of an outage across multiple lines of business,” Dreyer said. “IT does not run the grid … but reliable technology is key. In order to ensure reliability at the top, we need to keep the underpinnings working as well.”
Board Approves 5 Revision Requests
The board unanimously approved four nodal protocol revision requests (NPRRs) and one Planning Guide revision request (PGRR) previously approved by the TAC. (See Revision Requests, Shadow-Price Cap Change Endorsed, ERCOT Technical Advisory Committee Briefs.)
NPRR794: Moves reporting requirements for unregistered distributed generation from the Commercial Operations Market Guide to the protocols.
NPRR800: Incorporates futures prices in calculations of collateral requirements.
NPRR805: Clarifies the criteria under which congestion revenue right (CRR) account holders can submit multi-month offers for long-term auctions. The months must be consecutive, within the period covered by the auction and during months when the account holder has ownership of the CRR.
NPRR806: Clarifies that municipalities and cooperatives not participating in ERCOT’s competitive market (non-opt-in entities, or NOIEs) have the option of accepting a refund or capacity for their pre-assigned CRR-eligible resources. The NOIEs cannot select one option for some months of the year and the other option for the remaining months.
PGRR053: Modifies the conditions proposed generating resources must meet to be included in steady state working group base cases, requiring only the data provided for full interconnection studies.
TAC Cancels February Meeting
With a “limited number” of voting items on the agenda, the TAC has canceled its Thursday meeting. The committee will resume its regular schedule March 23 before the board’s next scheduled meeting in April.
TAC Chair Adrianne Brandt told committee members to expect an email vote on a revision to the Commercial Operations Market Guide (COPMGRR044), which aligns with NPRR794.
The RTO’s two most recent studies of wind and other variable resources analyzed wind-penetration levels as high as 60% and found that the RTO has the potential to serve 75% of its load with wind, Operations Vice President Bruce Rew told SPP’s Variable Generation Integration Workshop on Wednesday.
But why stop there? Asked how high a penetration level SPP could handle, Casey Cathey, SPP’s manager of operations analysis and support, replied with a smile: “As high as you want.”
That’s a big change, Cathey said, recalling “we were freaking out about 20% in 2009.”
SPP set the record for wind penetration at 4:30 a.m. Feb. 12, topping out at 52.1%, with several hours also registering above 48.5%. (See related story, SPP First RTO to 50% Wind Energy Penetration Level.) The RTO has set seven wind peaks in the last 14 months, the latest coming Feb. 9 when the footprint produced 13,342 MW of wind energy.
“We’ve been studying [wind] at higher load levels than SPP’s minimum [load] at times,” Rew said. “With nukes and hydro, we could have a majority of our load being served by [non-thermal generation] using the existing system we have now.”
32 GW of Wind?
SPP currently has 87,635 MW of generating capacity, with gas (42%) and coal (31%) providing the great bulk of it. Wind accounts for 18% of the capacity (16,124 MW of nameplate generation), with hydro (4%) and nuclear (3%) trailing. An additional 32 GW of wind capacity is in the interconnection queue, along with more than 4 GW of solar.
Cathey said a “good” wind-capacity factor is around 30%, but SPP’s newest wind projects have factors of more than 50%.
“Maybe not all that 32 [GW] will be installed, but we know we’ll have more than 16” GW, he said.
Staff last week shared the results of its latest variable generation study, which looked at requirements to reliably operate at higher wind-penetration levels. Using 45% and 60% scenarios, staff analyzed transient stability, frequency response, seasonal voltage stability, seasonal load-pocket stability and five-minute ramping.
The study assumed 27,419 MW of wind generation would be in service by the end of 2019.
“I don’t that that we will hit 27 [GW] in three years, but when you see a number like this, I think there’s going to be a lot of wind coming in,” SPP’s Jason Tanner said.
“We discovered we needed additional data,” Cathey said, citing the longitude and latitude of every wind farm in the footprint as an example. “We really need a good, robust plan for handling this stuff.”
The transient stability study showed the system could handle 45% and 60% wind penetration for simulated events. But it found the SPP damping ratio criteria of 0.8% — a measure of how quickly oscillations in a system decay after a disturbance — to be very low, and out of line with the 3 to 5% used by much of the industry.
Frequency response was found to be fully compliant with NERC criteria and indicated that new and existing renewable resources can be reliably integrated at higher penetration levels. However, three of the four cases used in the voltage-stability analysis found limitations. A 2021 case at the 60% level was successful in the planning models without operation outages.
Staff determined further analysis is needed in the ramping five-year outlook to focus on the risk of forecast errors.
Recommendations
Based on the study’s results, SPP staff recommended:
Using an online voltage stability analysis tool to manage voltage fluctuations;
Having the Transmission Working Group define the requirements for a voltage stability analysis of low-load scenarios;
Asking the TWG to consider increasing the existing damping ratio (0.8%) in SPP’s voltage disturbance performance requirements;
Installing transient stability contingency screening and other tools measuring signal changes over time for next-day operational analysis;
Quantifying the risk of load and renewable forecast deviations;
Having the TWG assess the cause and impact of modes of inter-area oscillation for machines identified by the SPP study; and
Using the report’s findings as parameters for future phasor measurement unit siting.
Staff will present the study’s findings and recommendations to SPP’s Board of Directors and Markets and Operations Policy Committee in April.
“We are reliable, we are secure,” Golden Spread Electric Cooperative’s Mike Wise said. “That’s a great distinction to talk about.”
But when is too much wind too much? The Export Pricing Task Force found that SPP’s neighbors share the same problems in working with massive amounts of wind.
“There are things that can be changed in different areas, but there’s not a silver bullet,” Sam Loudenslager, the task force’s staff secretary, told attendees. “We’re not alone in this. There’s a lot of wind around us, and we’re all going to be competing to manage it.”
So far, the task force has focused primarily on educating members and other stakeholders, Loudenslager said. He said the group is planning to provide market and Tariff changes for consideration to the Strategic Planning Committee in April or May.
Staff described several market mechanisms it is pondering to deal with the issue, including adopting coordinated transaction scheduling (CTS), which reduces uneconomic flows across RTO borders by allowing traders to submit “price differential” bids that would clear when the price difference between the regions exceeds a threshold set by the bidder.
NYISO has been using CTS with PJM since November 2014 and began it with ISO-NE in December. PJM and MISO plan to launch CTS later this year. (See “MISO-PJM Coordinated Transaction Scheduling Delayed,” MISO Market Subcommittee Briefs.)
Staff is also evaluating RTO-to-RTO energy transfers similar to the CTS and market-to-market processes, multiday economic commitments, and ramp products, among others, as possible solutions.
WASHINGTON — A record 1,600 people attended the National Association of Regulatory Utility Commissioners’ winter meetings last week, where speculation about the Trump administration’s energy policies was Topic A. Here’s some of what we heard.
Infrastructure Bill Must Wait its Turn, House Transportation Chief Says
Rep. Bill Shuster (R-Pa.), chairman of the House Transportation and Infrastructure Committee, told NARUC’s General Session on Tuesday that he’s excited by the Trump administration’s call for expanded infrastructure spending but that a proposal won’t come until after Congress replaces the Affordable Care Act and develops a plan for overhauling corporate taxes.
“You’re not going to see the infrastructure package in the next month or two,” Shuster said.
“The order of things will be replacing Obamacare. … Tax reform will go next, and within that we have to figure out how to pay for infrastructure. It’s not all going to be federal dollars.
“One of our goals on the Republican side is to lower tax rates for corporations so they can keep more of their own money. So when it comes to pipelines and electric grid and broadband, let those corporations keep more of their money and then let’s get the regulatory barriers out of their way so that they can go build.”
Increasing the debt, he added, “is not an option in this Congress.”
Shuster said public-private partnerships can contribute but that the concept is “not the silver bullet … that some folks claim it is,” feasible only in instances in which private businesses can earn a return on their investments.
Although the D.C. Circuit Court of Appeals is expected to rule soon on legal challenges to EPA’s Clean Power Plan, the ruling won’t be the last word, meaning RTOs and state policymakers will be facing uncertainty for the foreseeable future.
“If its upheld, then I think we’ll be looking to the new administration to make any proposals for change that they make and put them through the regulatory process,” acting FERC Chairman Cheryl LaFleur said. “It seems they’re going to make a change, but I am not privy to what it is.”
Arkansas Public Service Commissioner Ted Thomas noted that under the plan, the tougher emission targets — and increased costs — would hit in the second half of the next decade.
“The election didn’t change all that much about carbon risk,” he said. “If you’re saying, ‘OK, new administration, I don’t have to worry about carbon anymore,’ you might be making a mistake.
“Of course the elections are decided on issues non-energy related. We’re kind of like the flea that rides on the dog. The dog goes in the mud; we go in the mud with it. And if the next three years are like the last three weeks, we might be wishing we had the Clean Power Plan. There is real risk of federal policy that we deal with. We do that all the time. We’re state policymakers and federal policy takers.”
Crane Presses Case for Nukes, Calls for Unifying Environmental and Energy Policies
Exelon CEO Chris Crane agreed with NARUC President Robert Powelson, who said he had never seen a “more dynamic phase” in the electric industry.
“It’s a huge, huge issue to know where public policy is going to drive us,” Crane said during a panel discussion with leaders from the water, natural gas and telecommunications industries moderated by Powelson. “One of the more reliable baseload generating assets in the country, the nuclear assets, [face] significant challenges with current market design.”
Last year, officials in Illinois and New York approved controversial rescue plans for Exelon’s nuclear plants in their states. The zero-emission credit programs, which are being challenged in court and before FERC, recognized nuclear’s carbon-free production and the plants’ jobs and tax payments. (See IPPs File Challenge to Illinois Nuclear Subsidies.)
“This country for too long has separated an environmental policy from an energy policy, and [conflict between federal and state policies] has made it very difficult for markets to be formed efficiently and made it very difficult for predictability of investments going forward,” he said. “The leadership at the federal level [should] either come up with a common policy or get out of the way. Have the states be allowed to work with the RTOs and design the markets of state desires. The states we serve want affordable, reliable [energy], but they also want clean power. And how … you build a market signal around that to adequately compensate all the generators in the stack is very important.” (See related story, LaFleur Plans Tech Conference on State Generator Supports.)
He remained focused on the nuclear fleet, calling them “solid baseload units” and noted that they do not experience the issues that caused outages for 22% of PJM’s generation capacity during 2014’s extreme cold snap known as the polar vortex. Exelon’s nuclear units last year had a 95% capacity factor, he said.
“Renewables are an important part of the stack and they should continue to be part of the stack, but we need to look at defining outcomes. If the outcome is a higher-reliability, diverse fuel stack, then how do you create a market design that compensates for that?” he said. “It’s whatever the outcome is versus pitting technologies against technologies.”
He pointed to NOx, SOx and mercury emissions standards as successful governmental regulation. “It said, ‘here, fix your stack and clean up the air.’ The market took care of the rest. Some plants didn’t make it, some plants were built, some plants were modified,” he said. “Hopefully, with some clarity coming from this administration, some clarity coming from FERC, the states and the RTOs can do what they need to design a reliable, affordable and — where they want it — a clean stack.”
