The D.C. Circuit Court of Appeals on Tuesday denied a petition by NextEra Energy and other industry players to review FERC orders allowing ISO-NE to exempt a limited volume of state-sponsored renewable resources from its capacity market’s minimum offer price rule.
A three-judge panel concluded that the commission “engaged in reasoned decision-making to find that the renewable exemption to the minimum offer price rule results in a just and reasonable rate” and that “FERC did not abuse its discretion by denying the petitioners’ request for a hearing” (17-1110).
ISO-NE revised its Tariff in 2014 to allow up to 200 MW of qualifying new entrant renewable capacity to be exempt from the MOPR, beginning with the ninth Forward Capacity Auction covering the 2018/19 commitment period. The Tariff change included a carry-over rule allowing any unused portion of the 200 MW to carry forward for two additional auctions, up to a total of 600 MW.
Citing “changing market conditions,” ISO-NE phased out its MOPR exemption in March 2018 while the case was under review.
6 MW Solar Farm in Salisbury, MA | LandVest
Generators argued that the renewable exemption was unjust and unreasonable because it would undermine competitive entry and result in significant price suppression, an argument the commission rejected.
The court sided with FERC. “We defer to the commission’s determination that the renewable exemption effectuates the market’s primary purpose by sending the correct demand signals to new entrants and by protecting consumers from excessive rates.”
Petitioners also argued that the commission’s approval of the MOPR exemption conflicted with a previous decision to reject a categorical exemption to the rule, which was upheld by the D.C. Circuit.
But the court noted that in this case, the commission considered the price suppression associated with the uneconomic entry of a small quantity of renewable resources, rather than a categorical exemption, and in doing so “has performed an updated balancing of competing interests in the New England market.”
The court also found that the commission explained how ISO-NE’s sloped demand curve mitigates the price suppression and why its view on the renewables exemption had evolved.
The commission is not required to show that a previous rate was unjust and unreasonable in order to demonstrate that the revised rate is just and reasonable, the court said.
FERC has considered several MOPR exemptions in other markets, accepting some and rejecting others.
“This type of balancing requires an expert understanding of the market, which is well within the commission’s realm of expertise. We see no reason to disturb the commission’s balancing just because it came out in favor of the renewable exemption despite the potential for price suppression,” the court said.
The petitioners also argued that the commission did not rationally link the magnitude of the exemption to any particular prediction of load growth or retirement. However, FERC explained that the 200-MW exemption was based on the best estimate of expected retirements and load growth, which was “estimated at 189 MW annually, plus an adjustment for the reserve margin required to meet the installed capacity requirement.”
They further contended that FERC inappropriately raised its retirement rationale on remand, that uneconomic entry would continue after retirements are complete and that its experts found price suppression would occur even with retirements.
“But the commission is not required to protect against all price suppression … [and] acted reasonably in concluding that retirements would help mitigate any price suppression,” the court said.
“Accordingly, we defer to the commission’s conclusion that the renewable energy exemption had only a limited potential for price suppression because of the implementation of the sloped demand curve, the prediction of a flatter supply curve, and predicted load growth and retirements.”
By Michael Kuser, Rory D. Sweeney, Amanda Durish Cook and Rich Heidorn Jr.
WASHINGTON — FERC Commissioner Cheryl LaFleur, who has been attending the commission’s annual reliability technical conference since her appointment in 2014, always opens the meeting by citing something special about each year’s gathering.
At Tuesday’s conference, LaFleur noted it has been 50 years since NERC was formed following the 1965 Northeast blackout. “I was practicing piano when the lights went out in Boston,” she recalled.
Issues cited in past years — including cybersecurity and improving NERC’s efficiency — were joined in this year’s hearing by concerns over inverter-based resources, the wind-down of Peak Reliability and the impact of gas shortages on resilience. Commissioner Neil Chatterjee chaired the session for Chairman Kevin McIntyre, who was unable to attend. Chatterjee was joined by LaFleur and Commissioners Robert Powelson and Richard Glick (AD18-11).
It was the FERC debut for new NERC CEO Jim Robb, who joined the organization four months ago from the Western Electricity Coordinating Council. Robb said his initial focus has been implementing the risk-based philosophy that NERC and the Regional Entities (REs) established over the last several years “and really embedding that in all the activities we undertake.”
A second priority, he said, is “consistent implementation” of NERC’s programs across the regions. “It’s clearly a challenge. It’s clearly an issue that industry wants to see us get better at.” He vowed to focus on the big issues and “try not to be distracted by the trivial.”
Time for a Gas Standard?
Robb also described his organization’s work on fuel assurance, the subject of a NERC technical conference in early July. Robb said it is time to shift from recognizing the challenges caused by the increasing reliance on natural gas and identify actions that can “synch” the operating practices of the gas and electric industries to make them “compatible and harmonious.”
“We’re not close-minded to the possibility of a suite of standards, if indeed they’re required. I think at this point in time we haven’t made that leap that we think we need to go to the step of creating a fuel-specific standard — that we can address this through some of the existing processes that we have,” Robb said. “But it’s clear that industry wants more guidance around what they should be studying and what sort of corrective actions they should be contemplating.”
That was exactly the ask of Peter Brandien, ISO-NE’s vice president of system operations. “It would be helpful for us if there was some sort of guideline or something agreed upon by the industry on how to look at energy security and what are the attributes or the pass/fail criteria you should be looking at,” he said.
Glick asked witnesses whether there are sufficient cybersecurity rules for gas pipelines. In June, Glick and Chatterjee penned a joint op-ed calling for mandatory reliability standards for natural gas pipelines like those FERC and NERC enforce on the grid. They noted that Transportation Security Administration has only a half-dozen employees overseeing pipeline security and relies on voluntary cybersecurity standards.
Berkshire Hathaway Energy CEO William Fehrman, who testified for the Edison Electric Institute (EEI), said NERC’s Critical Infrastructure Protection (CIP) standards “were very effective in developing a culture of security” in the industry.
“I do think that similar approaches should be made on gas pipelines. Whether or not there needs to be a standard I think is debatable, but I certainly believe that a similar focus on security and a culture of defensive postures on gas pipelines is appropriate.”
He added, “When we look through our assessments of pipelines, I would say that the vast majority of operators are already well beyond what would be a similar CIP standard. But, nonetheless, there is a good opportunity for further discussion on that matter.”
“I don’t have nearly as much visibility into the mechanics of how the pipeline systems actually operate,” said Robb.
“I’m not in a position to say whether or not the TSA … approach is adequate or not.”
Testifying later, independent consultant Alison Silverstein pointed out that no one from the gas industry was invited to appear on any of the four panels.
Silverstein also challenged the focus on fuel security, saying fuel shortages account for only a tiny portion of outage events. “We have a grid that some of the pieces on it are 70, 100 years old,” Silverstein said. “Today we’re built for ‘Ozzie and Harriet’ weather, and we’re facing ‘Mad Max’ in terms of the magnitude of threats from extreme weather.”
She also urged a focus on reliability measures with proven benefits, “like tree-trimming, the gift that keeps on giving, every season.”
When to Press
LaFleur asked when FERC should press NERC and the industry on new standards, citing a “conservatism” built into NERC’s industry voting mechanism. “Part of our job is to be annoying and push when there’s something” that needs to be addressed, she said citing FERC’s directives on physical security and geomagnetic disturbances.
“That’s a great question,” Robb responded. “I wish I had a crisp answer to it, but I don’t. … I think there’s a little bit of ‘you’ll know it when you see it’ embedded in here.”
Tim Gallagher, CEO of RE ReliabilityFirst, said the answer depends on the pervasiveness and imminence of the threat. “Standards are not in my mind the ideal way to respond to emerging or potential threats. Sometimes the threat or the risk can be addressed quite well outside of the standards process,” he said.
Gallagher cited NERC’s response to the widespread generation failures during the 2014 polar vortex. Afterward, NERC made site visits to willing generators and suggested corrective measures.
“If we had gone down the standards path in that case,” he said, “we would not have been prepared for the next winter. Taking this more aggressive, non-standards approach, we were able to elevate performance — along with working with our RTOs and improvements they made — and the voluntary cooperation of the industry to have much better performance.”
Steven Naumann, Exelon’s vice president of transmission and NERC policy, said the time-consuming standards process is especially ill-suited for responding to cyber threats. “The threat is going to change. We’re dealing with intelligent adversaries … so if we close one door they’re going to look for another.”
RC Function in West
LaFleur asked what FERC should be concerned about regarding Peak Reliability’s plan to cede its role as the Western Interconnection’s reliability coordinator to CAISO and perhaps others.
“The thing to remember about the Western Interconnection is it really works as one integrated machine,” said Robb, noting that radially connected Alberta is an exception. “Having a unified reliability coordinator overseeing that system was very beneficial. One of the issues we deal with in the West is that a problem in the Northwest can manifest itself in New Mexico very, very quickly. So, I think the most important thing, as we shift to a multi-reliability coordinator system in the West, is that the seams agreements and operating protocols between them really recreate that wide area view for the entire interconnection. The most important thing that can happen right now is for the TOPs [transmission operators] and BAs [balancing authorities] in the West to declare where they are going to go so that we know where the seams are.”
Glick asked how CAISO was going to address concerns he’s heard from some entities in the West that CAISO’s role in operating the markets and being the RC could lead to conflicts of interest — an issue that dogged SPP in the past.
“RC services are driven by compliance standards. They’re operational and engineering in nature,” responded Eric Schmitt, CAISO’s vice president of operations. He said CAISO asked potential customers to help it create the framework for the new function.
“We think it honors independence and separation between our … BA reliability function and markets and RC services. Organizationally and process-wise, we’re creating the kind of separation that the customers would like to see. Yes, there’s more discussion to be had around that as we go forward, but we think that was a good start.”
Standardizing Inverter Configurations
Schmitt also called for standardization of the configuration of inverters on renewable generation, citing the ISO’s problem with utility-scale solar tripping offline. (See Solar Inverter Problem Leads CAISO to Boost Reserves.)
“Nobody ever told the inverter owners how to program them,” said Robb. “The good news is industry has been very responsive. I think we’ve solved the problems that we know of. We may find others.”
Robb said NERC expects to begin work in August on two Standard Authorization Requests (SARs) on inverters.
Don’t Attempt to Control the Future
Panelists in the conference’s third session looked to the future and urged the commission not to attempt to control what it looks like.
“I think the way we’ve been thinking about essential reliability services is right on point,” said John Moura, NERC’s director of reliability assessment and system analysis. He cited several examples of recent grid-level issues, such as frequency response, that have been addressed with interaction between NERC and FERC.
Quanta Technology President Damir Novosel, who appeared on behalf of the IEEE Power & Energy Society, said the key is “knowing what we want to accomplish through [performance] standards, then [having] the market that will value what [we] want to accomplish.”
Speaking for the Large Public Power Council, ElectriCities of North Carolina CEO Roy Jones urged the commission to ensure that any resource that can provide the necessary services has access to the market to do so. He called for driving the standardization of storage resources further upstream to manufacturers, where “it’s more efficient to work on it there once so that everything coming down the assembly line has that standard.”
Wabash Valley Power Association CEO Jay Bartlett, who appeared on behalf of the National Rural Electric Cooperative Association, said regulators should first determine the right information to know about new equipment on the system so “that we can effectively model it and ensure that we don’t spend good money after bad, trying to cover parameters that we can’t model with reserves.”
Nicholas Miller, a principal at HickoryLedge, called for standards and market signals that are “outcome-based, not enabling-based,” because “there’s a lot more knobs that can be turned with inverted-based resources than with synchronous machines.”
Peter Gregg, CEO of Ontario’s Independent Electricity System Operator, said managing data is essential for the future.
“If we think about how our systems are becoming more complex, they are only going to become more complex,” he said. “I think our challenge is, how do we better leverage the data that we’re creating … how to actually access, interpret, analyze and use that data.”
Information Sharing
On the final panel, which focused on cybersecurity, NERC Senior Director Bill Lawrence discussed NERC’s plan to expand its Cybersecurity Risk Information Sharing Program (CRISP) to improve information sharing.
“Right now, CRISP covers well over 75% of the meters in the United States. … We have a very good sample set of what’s going in and out of IT networks,” Lawrence said.
But information sharing methods are still limited, he said.
“Whenever we start talking about … automated information sharing, I like to throw ‘HV’ in front of that ― human verified. Right now, we don’t have the trust on any information shared to be able to apply directly to production systems without awareness of the consequences it might have. So, we don’t have machine-to-machine yet,” said Lawrence, adding that the Department of Energy National Laboratories and federal research and development programs are working on trust models “to separate the wheat from the chaff.”
DOE’s Carol Hawk said the National Laboratories are also looking into “containerizing” power system applications so that each is isolated with a decreased chance of being compromised.
Hawk said cybersecurity staff could use the operational nature of the industry itself to protect against attacks. “Here’s an example: Each component in [a] system is designed to perform a very specific, limited function. We have developed technology that will allow the system to deny by default any unexpected cyber activity. … If it’s not expected, don’t allow it,” she explained. Hawk said with the system effectively locked down by only allowing its intended function, it “shrinks the cyberattack surface.” She added that protective relays could use modeling to analyze within four milliseconds whether a command sent by an adversary would destabilize the grid.
“So I see a bright future … because we can use characteristics of that operational environment to protect itself, to automate a response that makes sense,” Hawk said.
Trinity Cyber President Marie O’Neill “Neill” Sciarrone said addressing cybersecurity issues has changed little from her time at the Department of Commerce’s Critical Infrastructure Assurance Office in the early 2000s.
“We were coming out of Y2K and addressing the Code Red [virus], and you realize we’re talking about the same thing today we were talking about in 2000, and that’s sad. And that’s basically where we are,” Sciarrone said. She urged the sharing of more “actionable information.”
“You can share … IP addresses for someone to block, but you’re not giving the context of why or how the threat is evolving or how the threats to their IT systems are making their way to their [operation technology] systems,” she said, adding that it’s “absurd” to prepare for an unnamed adversary.
“When it comes down to it, we all need to admit adversaries have more motivation, more funding, more resources than any of us, and we need to bind together and be very transparent and open about what we’re seeing, how we’re acting, how we’re solving problems, and be as willing as they are to adopt modern technology and to be flexible and to move if we’re going to combat that. Otherwise, we’re fighting with both arms behind our back,” Microsoft’s Matt Rathbun said.
NERC CIP Standards
LaFleur asked whether the NERC CIP standards are sufficient or excessive.
“We hear the standards were just a baseline ― any self-respecting company has gone well beyond that. In other parts, we hear that we are way too restrictive and should be cut back. … [Edison Electric Institute] said we should have a moratorium on standards; there are too many,” she said.
Lincoln Electric System’s Paul Crist said utilities must balance compliance with emerging security threats. He said situations can arise where software vendors become compromised, but removing their software would lead to noncompliance. Crist admitted CIP standards “are probably a struggle for all” and said his company tries to balance the risk of violating compliance with having sufficient incident response capabilities. He noted that some vendors deliberately refuse to offer CIP compliance.
Rathbun said CIP guidance is not clear enough to issue any guarantees an entity will pass an audit.
“I have 78 certifications. CIP is not one of them,” he said.
Dragos’ Ben Miller said the industry’s understanding of threats is limited: “We have anecdotes. We don’t have large data sets. So I think it’s hard from a standards process … to chase the threat.”
After Hawk suggested asset owners may not be able to afford to cover the costs of sophisticated cybersecurity programs, LaFleur said she’s never spoken to a transmission owner who doesn’t have the opportunity to recover cybersecurity costs in rates.
Hawk said the issue of cost may emerge with research and development programs for new technologies.
“If a company is wanting to do something on their system, buy a new package to make it more secure, and they are not able to fund that, we would like to know about that,” LaFleur said. “There are so many things we can’t control, that are not within FERC’s authority. Utility rates are one of the things we actually do.”
SCANA stockholders on Tuesday overwhelmingly approved the company’s sale to Dominion Energy, moving the deal one step closer to completion.
South Carolina Electric & Gas would become part of Dominion under a deal approved by SCANA shareholders Tuesday. | SCANA
In a vote taken at a special meeting, shareholders voted 72% in favor of the sale, more than the two-thirds required for approval.
The sale now has only three more major hurdles to clear: authorizations by South Carolina and North Carolina regulators as well as the Nuclear Regulatory Commission.
FERC and the Georgia Public Service Commission have already approved the deal, and the Federal Trade Commission has indicated it won’t try to block it on antitrust grounds.
SCANA shareholders also voted against paying severance packages to SCANA executives if they are let go after the sale is completed, but that vote is non-binding. SCANA has set aside $110 million in severance for its executives, attorneys for the South Carolina legislature said Monday.
If approved, the deal would be a stock-for-stock transaction with Dominion paying two-thirds of a share of its stock for each SCANA share it acquires. At Dominion’s Tuesday closing price of $71.71, the company would be paying $6.83 billion for SCANA.
SCANA became an acquisition target due to its failed attempt to expand the V.C. Summer Nuclear Station in Fairfield County. S.C. It and Santee Cooper, a utility owned by the state of South Carolina, gave up on the expansion last summer after spending $9 billion on it over a decade.
A failed attempt to expand the V.C. Summer Nuclear Station led SCANA into Dominion’s arms. | SCANA
If the deal were to go through, it would give Dominion 6.5 million regulated electric customer accounts, 31.4 GW of generation capacity and 93,600 miles of electric transmission and distribution lines.
The deal is controversial, in large part because customers of SCANA’s South Carolina Electric & Gas subsidiary have already been charged more than $2 billion for the failed expansion and continue to pay about $27 a month for it.
South Carolina passed a bill that would roll back most of the payment, but SCANA is challenging its constitutionality.
MISO’s proposal to put time limits on its alternative dispute resolution process with RTO members is still missing key details, FERC said Monday.
In a deficiency letter issued July 30, the commission asked MISO for multiple specifics on its plan to set limits on the amount of time MISO members have to initiate alternative dispute resolution measures with the RTO over market settlements (ER18-1648).
MISO’s alternative dispute resolution process is used in place of a lawsuit or FERC complaint when parties seek to negotiate contractual disputes over settlements. The RTO’s current Tariff doesn’t contain provisions that “categorically bar settlement disputes raised after a long time,” according to MISO.
MISO has proposed giving members a limit of 90 days to request either an informal or formal alternative dispute resolution and 120 days for MISO and members to resolve settlement disputes. MISO itself would have two years from the operating day in question to make resettlement corrections. Resettlement outside of the two-year cutoff would require MISO and the participant to seek a Tariff waiver with FERC.
MISO’s May Tariff filing provided for a two-year limit for adjustment of “any billing, invoice or settlement statement with respect to any transmission service under the Tariff” and “any settlement statement with respect to any market activity or other service under the Tariff” involving “a system or software error of the transmission provider.”
But FERC has asked MISO to define the terms “system error” and “software error.” It has also ordered MISO to define the meaning of “readily discoverable, one-time MISO errors” and asked if the RTO foresees any short-term errors that are not “readily discoverable.”
The commission is also requiring MISO to clear up when the 90-day timeframe begins and if an “extended delay in the resolution of a settlement dispute or [an alternative dispute resolution] dispute by MISO” could possibly limit the resettlement of incorrect billings under the two-year limit.
FERC also inquired about a hypothetical situation raised by MidAmerican Energy in its comments on the proposal , which said that MISO could violate its two-year correction deadline if a months-long error is discovered and the resettlement period needs to extend to before the operating day or invoice date in question. FERC asked if MISO planned to file an amendment to allow for resettlement for more than two years for such a scenario.
FERC also questioned language in the proposal saying MISO “may make an appropriate adjustment” in “cases involving a system or software error of the transmission provider.”
“The word ‘may’ suggests that MISO is under no obligation to make the ‘appropriate adjustment’ even if a system or software error results in a Tariff customer paying an incorrect amount. Please explain why it is appropriate for MISO to have this discretion,” FERC said.
Lastly, the commission ordered MISO to clarify whether the alternative dispute resolution will apply to both market settlement disputes and transmission service disputes. FERC said certain sections of the proposal indicated it would apply only to market settlement disputes.
MISO lengthened the cutoff periods from the original proposal after stakeholders earlier this year expressed concerns they would need longer than 30 days to research and raise settlement disputes and longer than one year to make settlement corrections. (See MISO Considering Time Limits on Dispute Resolution.) MISO did not propose to place a dollar limit on resettlements. The RTO was aiming to have the deadlines imposed in July.
VALLEY FORGE, Pa. — PJM stakeholders at last week’s meeting of the Markets and Reliability and Members committees unanimously endorsed proposed revisions for aggregating seasonal resources.
PJM’s Andrea Yeaton presented the revisions, which would allow for dispatching resources individually based on their seasonal ability but account for them cumulatively for the purposes of Capacity Performance. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: July 11, 2018.)
Independent Market Monitor Joe Bowring reiterated a request that the rules be amended to explicitly state that PJM has the authority and ability to call on resources without calling all resources in a zone and does not have to schedule the dispatch a day ahead.
“I think it’s less than clear” in the current language, Bowring said.
Default Details
PJM’s Suzanne Daugherty announced that the RTO submitted a request to FERC for waiver of rules requiring staff to liquidate “the large [financial transmission rights] portfolio of a recently defaulted PJM member.” The waiver would “reduce [PJM’s] liquidation of GreenHat’s portfolio to only the portion of the FTR portfolio that is about to become effective for the next calendar month, for each monthly auction for the period from the FTR auction conducted in July until the FTR auction conducted in October” (ER18-2068).
Staff had planned to liquidate the FTR positions in a way that minimizes the resulting burden on all other market participants, who will end up covering the remaining defaulted amount. (See “Credit and Default,” PJM MRC/MC Briefs: June 21, 2018.)
However, PJM said in its filing that it “has encountered adverse pricing effects of attempting to maximize the liquidation of this portfolio irrespective of price,” specifically in the most recent auction that closed on July 27.
“For periods with less liquidity … this large portfolio in combination with PJM’s obligation to offer a price designed to maximize the likelihood of liquidation, irrespective of a price floor, would essentially cause the prices to significantly diverge from the expected day-ahead price outcomes,” PJM said. “An unbounded liquidation of a large FTR portfolio for periods with less liquidity can and will cause a market disruption event and result in distorted market outcomes that may be unjust and unreasonable.”
The waiver “will provide PJM with time to further communicate with stakeholders regarding the concerns of the current Tariff-imposed liquidation process given the significant default allocations that will be incurred under the current liquidation process and to discuss any alternative liquidation process the PJM members may prefer be applied after the FTR auction conducted in October.”
Fuel Security
Because the MRC and MC ran late, a special MRC meeting scheduled to follow the meetings was postponed. A meeting of the now-sunset Transmission Replacement Process Senior Task Force was scheduled for July 31, so staff moved the fuel security session to that time slot. Staff plan to announce they have almost completed the base case for studying the impacts on the system from several fuel-security related contingencies, such as extreme cold weather or gas pipeline interruptions.
Manual Revisions Approved
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 14A: New Services Requests Study Process and Manual 14G: Generation Interconnection Requests. PJM sought to split out part of Manual 14A into a new Manual 14G to better organize interconnection information. (See “Interconnection Procedure Split,” PJM PC/TEAC Briefs: June 7, 2018.)
Revisions to the Reliability Assurance Agreement and Manual 18 associated with changes developed by the Demand Response Subcommittee to address issues identified with atypically low customer load during the winter peak load (WPL) calculation period. The Market Implementation Committee endorsed the changes in June. The proposal would use measurement and verification processes that already exist for a similar process and minimize administrative adjustments. It would define “low usage” days as less than 35% of the five-day WPL average and allow the exclusion of up to two such days from the WPL calculation. The measure was also endorsed at the MC via the consent agenda. (See “Now is the Winter of Our Discontent (with DR Rules),” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)
Tariff revisions to implement a 10-cent/MWh minimum monthly credit requirement for FTR bids submitted in auctions and cleared positions held in FTR portfolios. Staff announced they will move the effective date up from October to Sept. 3. The measure was also endorsed at the MC via the consent agenda. (See “Credit Requirements,” PJM Market Implementation Committee Briefs: July 11, 2018.)
Problem statement and issue charge setting black start fuel requirements, which include pushing the anticipated start date for the stakeholder group back a month to December. Staff also added “critical non-fuel consumables” to the list of requirements to develop and minimum tank suction level to compensation-related issues to hash out. The measure was unanimously endorsed, but several stakeholders voiced concerns with adding another issue to the agenda when many have already expressed concerns about overscheduling. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: July 10, 2018.)
A D.C. Circuit Court of Appeals panel on Friday declined to review FERC’s approval of plans to expand capacity on the Algonquin Gas Transmission natural gas pipeline.
The court also dismissed a petition from a group of elected Boston officials for lack of standing.
Circuit Judge Sri Srinivasan filed the opinion (Case No. 16-1081) for the three-member panel July 27, denying petitions from the Town of Dedham, Mass., Riverkeeper, and a coalition of other environmental groups that said the commission should have evaluated three separate Algonquin expansion projects in a single environmental impact statement.
The court noted that FERC approved the Algonquin Incremental Market (AIM) project in March 2015, that Algonquin submitted the application for the Atlantic Bridge project in October 2015 and that the company has yet to file its application for the Access Northeast project.
| Algonquin Gas Transmission
“The projects thus were not under simultaneous consideration by the agency,” and thus not improperly segmented, the court said. It also found FERC reasonably concluded that the projects were not interdependent, as they each had separate timelines for approval and commencing service.
The petitioners also contended that the commission failed to consider sufficiently the cumulative environmental impacts of the three projects. But the court said FERC took into account the AIM project’s EIS when evaluating Atlantic Bridge’s, and that Access Northeast is too early in development.
“The adequacy of an environmental impact statement is judged by reference to the information available to the agency at the time of review, such that the agency is expected to consider only those future impacts that are reasonably foreseeable,” the court said.
Indian Point Proximity
The $972 million AIM project includes about 5 miles of new pipeline, the West Roxbury Lateral, which would run adjacent to a quarry outside Boston, and larger-diameter replacement pipeline next to the Indian Point nuclear plant on the Hudson River in New York.
The petitioners questioned FERC’s reliance on testimony from the Nuclear Regulatory Commission and Indian Point owner Entergy that AIM — which will lay pipeline 2,370 feet from the plant’s security barrier — posed no increased threat to the nuclear plant.
| Algonquin Gas Transmission
“We disagree,” the court said, ruling that FERC had “permissibly decided to credit the NRC’s expert conclusions, and to accept that NRC’s ‘extensive formal responses’ had adequately addressed the opposing experts’ concerns.”
The court also said it lacked jurisdiction to consider petitioners’ contention that the third-party contractor preparing the project’s EIS, Natural Resource Group, had a conflict of interest, as they had not raised the issue with FERC.
Not Really Boston
Although the commission did not initially contest the Boston delegation’s standing, Algonquin raised the issue as an intervenor in the case, which led the court to address the issue. The delegation consisted of nine elected representatives from Boston, including the mayor, a congressman and two state legislators.
The delegation’s claim of injury for standing purposes rested on the West Roxbury Lateral’s allegedly adverse safety, health and environmental effects on the city. The delegation staked its standing primarily on the mayor’s participation in the petition, claiming that effectively made the city a party.
“We are unpersuaded by the delegation’s theory,” the court said. “While the city of Boston could in theory bring an action, the mayor does not act as the city when he files a lawsuit in his own name.
“The city code specifies the process by which a lawsuit is initiated on behalf of the city of Boston. … That process did not take place here.”
ERCOT stakeholders and staff last week discussed several alternatives to market price investigation announcements, following a July 20 market notice that raised anxiety levels during the height of the recent Texas heatwave.
The grid operator sent the market notice following discovery of inaccurate definitions of two double-circuit contingencies in its market systems. According to the notice, staff had begun “an investigation of market prices.”
The market’s shadow price at the time was $20/MWh, when it should have been around $24/MWh.
Reliant Energy’s Bill Barnes | Admin Monitor
“It happened at a very heightened time in the market. There was high anxiety when this was noticed,” Reliant Energy’s Bill Barnes said during the July 26 Technical Advisory Committee meeting. “I appreciate the market notice … but we were surprised to see how small the change in price was. Why the fire drill?”
Staff explained there is no threshold for issuing a market notice on price investigations and that they were only following protocols.
“There’s a tradeoff of me sending something out as soon as we’re investigating,” said Kenan Ogelman, ERCOT’s vice president of commercial operations. “If I try to understand what’s going on, there could be some delay.”
Citigroup Energy’s Eric Goff suggested staff could have sent an initial notice that a contingency had been found but that it wasn’t related to the market’s operating reserve demand curve.
July’s ERCOT TAC meeting. | Admin Monitor
“[The notice] just said a price correction without the details,” Goff said. “That caused some uncertainty as we moved into high-priced periods.”
ERCOT sent the notice following the discovery of an error in the definition of two double-circuit contingencies east of Dallas. Only one of the contingencies was part of a binding transmission constraint that lasted only four hours.
The issue affected the July 18 real-time operating day and the July 20 day-ahead operating day.
| ERCOT
Corrected day-ahead prices were published on July 23. Staff will have to ask the Board of Directors for approval to resettle the real-time prices during its Aug. 7 meeting.
| ERCOT
Staff said ERCOT is making “procedural changes” to ensure the error doesn’t happen again.
“I think there is a better answer out there,” Ogelman said. “We appreciate the conversation. We want to eliminate [that problem].”
TAC Endorses Long-Delayed Governing Amendments
The TAC unanimously endorsed proposed amendments to ERCOT’s articles of incorporation and bylaws, ending a monthslong series of delayed votes and redline exchanges.
“We’ve ended up with a very, very good work product,” said ERCOT Assistant General Counsel Vickie Leady.
The amendments include identifying the Public Utility Regulatory Act as the source for the board’s mandatory composition, and using Public Utility Commission rules to govern the distribution of assets and winding up provisions in the event ERCOT is decertified as an independent organization.
The amendments will be presented to the Human Resources and Governance Committee on Aug. 6, and then to the board Aug. 7. Staff plans to use an email vote to seek approval from its nearly 300 corporate members, and then file the amendments for the PUC’s approval in mid-September.
The ISO hopes to have the amendments in place by January.
Staff have created a website to store the different versions of the proposed changes. The amendments are the first updates since 2000.
New Leadership Confirmed to ROS
The committee confirmed new leadership for its Reliability and Operations Subcommittee.
Golden Spread Electric Cooperative’s Tom Burke will become chairman, replacing Oncor’s Alan Bern after he stepped down from the role in June. Tenaska’s Boon Staples will replace Burke as vice chair.
Committee Endorses 17 Revision Requests, Changes
The committee unanimously approved new language in a remanded Nodal Protocol revision request (NPRR) incorporating an intraday or same-day weighted average fuel price into the mitigated offer cap.
The TAC unanimously cleared NPRR847 in May, but the Board of Directors sent it back in June over concerns that the calculation of blended fuels was “vague and confusing.” (See “Board Approves 8 Change Requests,” ERCOT Board of Directors Briefs: June 12, 2018.)
Staff told stakeholders the original language did not define the calculation correctly, using the total fuel volume twice.
The NPRR is meant to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.
The committee also unanimously approved 16 other changes, clearing a backlog produced by the cancellation of its June meeting: seven NPRRs, a revision to the Nodal Operating Guide (NOGRR), two changes to the Planning Guide (PGRRs), three revisions to the Retail Market Guide (RMGRRs), an update to the Resource Registration Glossary (RRGRR), a system change request (SCR) and a change to the Verifiable Cost Manual (VCMRR).
NPRR856: Clarifies that for day-ahead make-whole settlement purposes, the “offline but available for SCED deployment” status is considered an online status and will be considered an offline status after system implementation.
NPRR862: Incorporates a number of revisions addressing recent changes made by the PUC’s rulemaking related to reliability-must-run service (Project No. 46369).
NPRR866: Addresses two objectives related to mapping registered distributed generation and load resources to transmission loads in the network operations model by codifying the existing process for mapping a load resource or an aggregate load resource to its appropriate load point in the model; and by outlining how to map a registered DG facility to its appropriate load point in the model.
NPRR873: Outlines expectations for posting information pertaining to intra-hour wind power and load forecasts on the Market Information Systems public area. The NPRR also proposes two new definitions and acronyms for the intra-hour wind power and intra-hour load forecasts (IHWPF and IHLF, respectively).
NPRR874: Changes the net allocation to load settlement stability report by breaking out the load-allocated congestion revenue rights monthly revenue zonal amount from the other load-allocated charges, and by providing dollars per megawatt-hour by congestion management zone.
NPRR875: Adds clarifying language to sync the protocols with NPRR864, which modifies the reliability unit commitment engine to scale down commitment costs of fast-start resources with less than one-hour starts.
NPRR877: Allows for the use of actual metered interval data for initial settlement of an operating day for electric service identifiers that currently require BUSIDRRQ load profiles.
PGRR061: Includes locations for registered DG facilities in the annual load data request process.
PGRR062: Proposes new processes, communication and document sharing and storage requirements to be included in the new generation interconnection or change request application.
RMGRR152: Changes the cancellation method from the MarkeTrak cancel-with-approval process to the 814_08 cancel-request Electronic Data Interchange transaction.
RMGRR153: Removes references to Sharyland Utilities, which no longer operates as a distribution service provider in the retail market, and updates American Electric Power contact information.
RMGRR154: Removes references to the Lite Up Texas discount, which ended in August 2016.
RRGRR017: Supports NPRR866 by providing a process for mapping registered DG facilities to their appropriate load points in the network operations model.
SCR796: Modifies the Market Management System’s validation rules for bids and offers to exclude resource nodes within a private-use network site as valid settlement points for day-ahead market energy-only offers and bids, and for point-to-point obligation bids.
VCMRR022: Directs ERCOT to contract a coal index price with a fuel vendor and includes a methodology for calculating the quarterly fuel adder for coal-fired and lignite-fired resources based on that index.
NextEra Energy Resources last week announced that it will close the 615-MW Duane Arnold Energy Center, Iowa’s only nuclear power plant, five years earlier than expected as a result of a buyout agreement with Alliant Energy.
Florida-based NextEra said that Alliant, the plant’s largest customer, will pay $110 million to NextEra in September 2020 to cover the last five years of their power purchase agreement. Alliant will instead buy 340 MW of power from four wind farms that NextEra plans spend $250 million to repower, part of a $650 million package of investments in Iowa renewables.
The deal is contingent upon Alliant getting approval from the Iowa Utilities Board to recover the buyout payment from ratepayers. Alliant said the deal will save its customers nearly $300 million over 21 years beginning in 2021.
NextEra plans to close the Duane Arnold Energy Center in 2020. | NextEra
“Partially replacing energy from Duane Arnold with NextEra’s additional wind investments in Iowa will bring significant economic benefits to our customers,” Alliant CEO Patricia Kempling said in a statement.
NextEra said it expects to gradually reduce staff at the plant, which employs 500 now, over the next seven years as it decommissions it. It also said it is evaluating redevelopment opportunities for the plant site, including new solar energy, battery storage or natural gas facilities.
Duane Arnold is one of numerous nuclear power plants experiencing economic difficulties because of cheap natural gas and falling renewable generation costs. Bloomberg New Energy Finance Analyst Nicholas Steckler said in May that 24 of the 66 nuclear plants operating in the U.S. were either scheduled to close or wouldn’t make money through 2021.
FERC last week granted GridLiance West incentive rate treatments for upgrades to a Nevada transmission line that connects to the CAISO grid, but it also ordered that the project’s overall 10.6% return on equity be subject to settlement judge procedures (ER18-1693).
The commission approved full recovery of GridLiance’s “prudently incurred” costs for its investment in upgrading the 14-mile, 230-kV Bob-Mead line if the project is abandoned for reasons outside the company’s control, as well as a 100% full “construction work in progress” incentive. FERC also granted the company a 50-basis-point “transco” adder made available to independent transmission developers.
GridLiance last year acquired Valley Electric Association’s 230-kV network in a deal valued at about $200 million, providing the company with 164 miles of transmission between CAISO and the interior West. (See GridLiance Gets OK to Acquire Valley Electric Tx Assets.)
The Six Cities group of Southern California public utilities protested inclusion of the adder, contending GridLiance had requested it just four months after reaching a settlement allowing for an overall 10.1% overall ROE, which included a 50-basis-point RTO participation adder.
Six Cities argued there was “overlapping justification” for the company’s prior request for a regulatory asset incentive (coupled with the RTO adder) and its current request for the transco adder because the latter “is designed to recognize the business model-related benefits provided by independent transmission companies,” similar to the rationale for the regulatory asset incentive already granted to GridLiance, the commission noted in its order.
But the commission rebuffed that contention, saying the functions of the transco adder and the regulatory asset incentive differ, and that it was “not persuaded that they rely upon overlapping justifications.”
“As an independent transco, GridLiance West satisfies the requirements for the transco adder. In contrast, the commission granted GridLiance West the regulatory asset incentive based upon a determination that GridLiance West had demonstrated that its request for that incentive satisfied the nexus test established in Order No. 679,” the commission said.
FERC also rejected as beyond the scope of the proceeding Six Cities’ request that GridLiance be ordered to disclose all authorized incentive adders in future transmission development proposals to CAISO because the adders could have a “material impact” on transmission projects in the ISO.
But while the commission favored GridLiance’s request for the adders, it also said its preliminary analysis indicated the overall 10.6% ROE for the Bob-Mead project might be too generous.
“Based on the record in this proceeding, the commission does not have a basis for determining whether GridLiance West’s overall ROE, inclusive of the transco adder granted above, falls within the zone of reasonableness,” FERC said in ordering settlement procedures.
MISO issued two maximum generation alerts and conservative operations declarations because of severe weather in June and a heatwave in July.
Both months were hotter than normal, and MISO recommended suspending transmission and generation maintenance in the North and Central portions of its Midwest region on July 5, when temperatures and loads were both above forecasts. The RTO said its system was stable throughout the event.
MISO spokesperson Mark Brown said staff coordinated closely with members and neighboring system operators during the event to manage generation and transmission resources. “MISO and our members train regularly and intensively to manage the power system in all types of conditions,” Brown told RTO Insider, adding that the alerts are meant to provide “situational awareness” to members.
The RTO also declared a hot weather alert for MISO South July 20-23 when the average temperature was 99 degrees Fahrenheit.
MISO Senior Director of Systemwide Operations Rob Benbow also said the system performed well during June despite above-normal temperatures and severe weather in the South region.
“We did see some hot weather alerts in the Central and North regions … at the middle to the end of the month, and we also experienced a transmission system emergency due to a forced outage in the South region in the early part of June, and that was followed by conservative ops and a max gen alert on the following day until that facility was returned to service,” Benbow said during a July 24 Informational Forum.
The day after severe weather on June 3, MISO declared a transmission system emergency in South with a maximum generation alert and conservative operations instructions. Benbow said the event caused real-time price spikes.
MISO’s June load peaked at 121 GW on June 29, up about 10 GW from last June’s peak. Average load was just under 77 GW, up 7 GW from a year earlier. Average real-time energy prices were $31.74/MWh, up 13%, which MISO attributed to localized congestion and higher demand.
MISO Reviewing Hartburg-Sabine Proposals
MISO has received multiple proposals for its second competitively bid transmission project, but it will not reveal the number of companies behind the proposals for at least another month — if at all.
The second request for proposals for the Hartburg-Sabine 500-kV junction project closed July 20, part of MISO’s 2017 Transmission Expansion Plan. The project will be in service by 2023 and is meant to alleviate system congestion in eastern Texas. The RTO opened the submittal window in early February.
However, MISO only identifies the number of proposals and their submitters once they’ve been judged and accepted as complete during an initial review expected to wrap up in early September, CEO John Bear said. The RTO will then post a list of finalists advancing to the evaluation process. Incomplete proposals are not revealed.
“MISO is pleased with the robust number of responses to the request for proposals,” Aubrey Johnson, executive director of competitive transmission, said in a statement. “This shows broad interest from qualified transmission developers and underscores the confidence in our competitive selection process. We look forward to moving to the next phase of the selection process to identify the best proposal for this important project.”
MISO plans to announce its selected developer for the project by Dec. 31. Bear said the project is expected to cost $129 million and have a benefit-to-cost ratio of 1.35:1. He added that it is the RTO’s first competitive project to include a substation.
