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.
New York transmission owners will be eligible for full cost recovery when regulated backstop solution reliability projects are canceled, FERC said last week, clarifying a 2017 order (ER17-2327-001).
The TOs asked for clarification or rehearing of the commission’s Oct. 17, 2017, order approving revisions to NYISO Rate Schedule 10, which were intended to expand its applicability for all regulated projects resulting from the ISO’s reliability, economic or public policy-driven transmission planning processes.
| NYSEG
The TOs said they were concerned about the 2017 order’s reference to Order 679, which implemented incentives ordered by Congress under Section 219 of the Federal Power Act and allows a public utility receiving a reliability incentive to recover only up to 50% of prudently incurred costs in abandoned projects.
The commission’s July 25 order clarified that Order 679 did not affect the TOs’ previously established right to 100% recovery on a reliability project if the ISO cancels it as unnecessary or if the project cannot be completed because of the failure to obtain necessary permits.
The commission approved the 100% recovery as part of the ISO’s Reliability Agreement in 2004. “This occurred before the promulgation of FPA Section 219 and the commission’s regulations issued in Order No. 679 implementing Section 219,” the commission said. “New York transmission owners’ right to cost recovery was thus not approved as an incentive under Section 219, nor could it have been.”
The order directed the ISO to remove the abandoned plant recovery provisions to avoid any ambiguity in the Tariff.
VALLEY FORGE, Pa. — Seeing no hope to resolve a nearly two-year standoff on supplemental projects for replacing end-of-life transmission infrastructure, PJM stakeholders are seeking a new tack after voting last week to sunset the Transmission Replacement Process Senior Task Force (TRPSTF).
PJM’s Fran Barrett, task force administrator, provided a report on the group’s recent activity. Factions in the task force have been at odds, and RTO staff attempted to put it on hiatus at its most recent meeting. (See PJM Seeks to Suspend Task Force in ‘Unprecedented’ Move.)
Following the review, American Municipal Power’s Ed Tatum motioned to sunset the TRPSTF because “it doesn’t seem fruitful to continue on.” Old Dominion Electric Cooperative’s Adrien Ford seconded it, but Dominion Energy Marketing’s Jim Davis suggested that any action on disbanding the task force should wait until the D.C. Circuit Court of Appeals rules on ODEC’s request to overturn FERC’s policy of allocating all costs from Form 715 projects to the zone of the transmission owner whose criteria triggered the upgrades. (See FERC OKs Cost Allocation of PJM Transmission Projects.)
LS Power’s Sharon Segner called that case “potentially a gamechanger,” along with a CAISO complaint pending at FERC.
“Those two are the external factors that change the debate here. … My view is that [the TRPSTF] hasn’t been a particularly productive task force,” she said.
PJM and its TOs submitted compliance filings in March in response to a commission ruling that TOs weren’t properly complying with their obligations under Order 890 to provide stakeholders with adequate information on supplemental projects — transmission expansions or enhancements not required for compliance with reliability, operational performance or economic criteria.
Tatum said approval and implementation of the compliance filings will go on with or without the task force, so putting it on hiatus would remove any chance for all stakeholders to be involved in determining “the meat of what would actually be in those meetings” required by FERC’s order.
Barrett said the task force has been tasked with navigating “a strange intersection between the stakeholder process and a [FERC] directive that’s before the TOs and PJM,” but “we are at the end, and we were gearing up for a vote.”
He confirmed, following an inquiry from Tatum, that no one has voiced an opinion to him either way on whether to continue the task force. Tatum acknowledged it “has been the most unusual stakeholder process I’ve ever been involved in.”
GT Power Group’s Dave Pratzon called the task force “duplicative” and “not a great idea.” He endorsed sunsetting it in favor of developing a way to address the issues on a comprehensive scale.
“We appreciate it and that it has been moving at a good clip and it certainly has slowed down,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS). “Where it goes from here is a question, but it certainly has been useful.”
The motion was endorsed by stakeholders.
Tatum then offered a proposal that would define what information must be presented at each of the meetings required by FERC. AMP’s proposal would attempt to fully use each end-of-life project to address any reliability violations and seeks to define the dispute resolution process for challenging project proposals.
The proposal reflects many of AMP’s proposals in the task force but “softened” some of them so that it “erred on the side of what we think the TOs would say,” Tatum explained.
Pratzon called Tatum’s proposal “totally inappropriate” because it hadn’t been vetted through a lower committee. Several TO representatives agreed. However, load interests continue to be interested in addressing the concerns raised in the task force.
“The issues remain. I don’t feel like we’re to the finish line. Certainly, my members care deeply about these issues,” said Susan Bruce, representing the PJM Industrial Customer Coalition.
PJM staff questioned several of Tatum’s contentions that the proposal wouldn’t adversely impact the delicate timing of the Regional Transmission Expansion Plan process, among them that projects in dispute resolution would not hang in limbo. Tatum agreed to continuing to work with staff and acknowledged that staff do not agree with AMP’s belief that it would work without a hitch.
FERC last week approved a $115,000 civil penalty against Entergy for failing to promptly inform ISO-NE of the inability of its Rhode Island gas-fired generator to meet its capacity obligations because of pipeline restrictions.
The commission’s July 25 order accepted an agreement between Entergy and the Office of Enforcement assessing the civil penalty and requiring reimbursement of $47,084, plus interest over the 2013 incident (IN18-5).
Entergy’s Rhode Island State Energy Center (RISE), a two-unit combined cycle natural gas plant, was paid $1,459,610 a month for 575 MW of capacity during delivery year 2013/14. (The company sold RISE to the Carlyle Group in 2015 for $490 million.)
Rhode Island State Energy Center | Entergy
Enforcement’s investigation found that, despite becoming aware at approximately 9:30 p.m. on Dec. 26, 2013, that it would be unlikely to meet its capacity commitment for the next day because of pipeline problems, Entergy waited until the following morning to contact the RTO about the issue.
RISE had a contract for firm transportation service with Tennessee Gas Pipeline for up to 45,000 Dth/day, which allowed it to bank in its “operational balancing account” (OBA) gas unneeded on a given day for future use.
On the morning of Dec. 26, Entergy offered RISE into ISO-NE’s day-ahead market. RISE received a commitment for 9,900 MWh. Entergy planned to use about 36,540 Dth from its OBA to meet the capacity obligation, which it determined would require 71,540 Dth of gas to produce.
On Dec. 18, however, TGP had issued a “Critical” notice to shippers saying it anticipated potential disruptions in service and that customers should “match physical flow with scheduled volumes.” On Dec. 26, Tennessee issued another notice, warning of restrictions on gas delivery downstream of its compressor station in Agawam, Mass., including RISE.
Despite low gas delivery pressures, Entergy began operating RISE at 2:45 a.m. on Dec. 27. “RISE not only took gas volumes it had scheduled from Tennessee but attempted to pull additional gas volumes from the pipeline,” according to Enforcement’s settlement agreement with the company.
RISE was able to meet its offer and ramp rate for about an hour, but when pipeline pressures continued to drop, Entergy contacted ISO-NE at 5:31 a.m. to advise that the plant could not meet its obligation. With ISO-NE’s approval, RISE operated at a reduced level of 310 MW for the remainder of the operating day, while the RTO dispatched other generators to fill the gap.
Enforcement concluded Entergy’s violations were the result of a “failure to exercise sufficient diligence” to ensure that RISE was able to meet its dispatch obligations but that it did not intend to violate the RTO’s market rules.
FERC said its penalty also reflected Entergy’s cooperation in the investigation and the steps it has taken to prevent repeat violations.
Environmentalists and industrial gas consumers last week challenged a Department of Energy-funded study that concludes U.S. economic growth would be boosted by unlimited LNG exports — even if they double current natural gas prices.
More than a dozen comments were filed by the July 27 deadline in response to the June 7 study, performed by NERA Economic Consulting for the department’s Office of Fossil Energy. DOE said it plans to consider the study in responding to 25 pending applications for LNG exports to countries lacking free-trade agreements with the U.S.
Although there is a consensus that exporting too much domestic natural gas could expose U.S. consumers, industrial users and electric generators to much higher world prices, there is no agreement on what that tipping point is, or how soon the U.S. could get there. (See No Agreement on Tipping Point for LNG Exports.)
The NERA study — the fifth DOE has commissioned since 2012 examining the economics of LNG exports — suggests that policymakers should not worry about any price increases, finding “consistently positive relationships between LNG exports and measures of economic performance” such as gross domestic product and U.S. living standards.
The Natural Gas Act requires DOE to determine whether natural gas exports to countries without FTAs with the U.S. are in the “public interest.” Exports to countries with FTAs do not require such reviews.
The Industrial Energy Consumers of America (IECA) said the DOE study “confirms that excessive volumes of LNG exports to non-free-trade agreement countries is not in the public interest under the Natural Gas Act.”
The group, which represents 3,700 U.S. manufacturing facilities, said it is not opposed to LNG exports. “We are against excessive LNG exports which would result in U.S. prices being dictated by global demand like crude oil is today.”
IECA said the Supreme Court has defined “public interest” under the NGA as requiring “plentiful supplies … at reasonable prices.”
U.S. Henry Hub Prices Across the More Likely Range of U.S. LNG Exports in 2040 | NERA Economic Consulting
“The study’s most likely scenario assumes that LNG exports up to 30.7 Bcfd could increase prices 117% above today’s Henry Hub prices by 2040 and 44% above the [Energy Information Administration’s Annual Energy Outlook] 2018 price (which assumes only 14.5 Bcfd of LNG exports),” IECA said. “Such price hikes plainly threaten the plentiful supply of natural gas at reasonable prices for domestic consumers.”
Other Comments
The American Petroleum Institute said it agrees with the study’s conclusion of a “consistently positive relationship” between LNG exports and U.S. economic performance. “The study thereby confirms what multiple past studies have concluded, which is that U.S. LNG exports are a clear net benefit to the economy and are therefore in the public interest,” wrote Todd Snitchler, API’s director of market development.
The US LNG Association said the study should allow DOE “to grant approvals to all U.S. LNG export applications to non-FTA countries without the need for any further macroeconomic studies” for at least four years.
Environmental groups criticized the study for ignoring the costs of climate change and the growth of renewable energy.
“The study should be adjusted to give much greater emphasis to low demand scenarios that align with the Paris Climate Agreement,” said a coalition of more than 60 groups in the U.S., Canada and Europe, including Food & Water Watch, 350.org and the Center for Biological Diversity. “Even if minimal progress in international climate policy making was a robust assumption, the study fails to assess the real-world trends occurring with renewable energy and the threat they pose to gas demand. The study does not attempt to either account for substantial progress in renewable energy installations and cost reductions made in recent years or assess projections of substantial progress to come.” (See How Long a Bridge for Natural Gas?)
54 Scenarios
The DOE examined 54 scenarios based on four major sources of uncertainty affecting U.S. LNG exports: natural gas supply conditions in the U.S.; natural gas demand in the U.S.; and gas supply and demand in the rest of the world. None of the scenarios limited LNG export volumes.
It found a 68% probability that LNG exports will be between 9 and 30.7 Bcfd in 2040. DOE has approved 21.4 Bcfd of LNG exports to non-FTA countries. The DOE study said there is a 12% probability that exports will reach that level by 2030 and a 63% chance of hitting that level by 2040.
About 80% of the increase in LNG exports would be satisfied by increased U.S. natural gas production, “with positive effects on labor income, output and profits in the natural gas production sector,” the study said.
“The higher world prices that bring forth those supplies improve U.S. terms of trade, so that there is a wealth transfer to the U.S. from the rest of the world equal to the increase in prices received for LNG exports times the quantity exported. The transfers from natural gas related activity to the U.S. economy improve the average consumer’s ability to demand more goods and services leading to higher economic activity,” NERA said.
“These two factors more than make up for the dampening economic effects that are observed in these scenarios, including slightly slower output growth of some natural gas-intensive industries, costs of substituting other fuels for a small fraction of natural gas use in power generation, and infinitesimal reductions in natural gas use by households and other industries.
“Even the most extreme scenarios of high LNG exports that are outside the more likely probability range, which exhibit a combined probability of less than 3%, show higher overall economic performance in terms of GDP, household income and consumer welfare than lower export levels associated with the same domestic supply scenarios,” the study said. “It is also important to note that our analysis also shows that the chemicals subsectors that rely heavily on natural gas for energy and as a feedstock continue to exhibit robust growth even at higher LNG export levels and is only insignificantly slower than cases with lower LNG export levels.”
GDP Increases with Rising Levels of LNG Exports within the More Likely Range of Scenarios in 2040 | NERA Economic Consulting
But IECA President Paul Cicio said the study “lacks credibility due to … the inability of the economic models to determine whether the oil and gas industry is consuming U.S. or imported goods to produce, transport and build LNG terminals, thereby overinflating economic growth and job projections due to LNG exports.”
IECA said the study’s conclusions conflict with that of a 2012 NERA study that acknowledged the difficulty of forecasting natural gas prices and that the new study uses proprietary NERA models that cannot be replicated by third parties.
Trump Administration Promoting Exports
The Trump administration has praised LNG exports as evidence of the nation’s “energy dominance.”
Dominion Energy’s Cove Point LNG terminal is the second operating export facility in the U.S. | Dominion Energy
Last Thursday, Energy Secretary Rick Perry appeared at a ribbon cutting for Dominion Energy’s Cove Point LNG export facility in Maryland, the second in the U.S. Perry noted that the U.S. is exporting natural gas to 30 nations and last year became a net gas exporter for the first time in 60 years.
Also last week, DOE finalized rules to eliminate public interest reviews for “small-scale” LNG exports to non-FTA countries. The rules, effective Aug. 24, apply to applications to export no more than 51.75 Bcf/year.
FERC last week granted AEP Energy Partners’ request to transmit power between ERCOT and Mexico over existing DC tie connections, easing concerns that the Texas grid operator might find itself subject to the federal agency’s jurisdiction (TX18-1).
The American Electric Power subsidiary made the request on behalf of Sharyland Utilities, AEP Texas and Electric Transmission Texas. The DC tie operators asked the commission to allow them to provide transmission service over the ties and to confirm that the ties’ use would not subject ERCOT or any of its market participants to FERC jurisdiction.
Texas officials have expressed unease that a pair of transmission projects along the U.S.-Mexico border could place ERCOT’s freedom from federal jurisdiction in jeopardy.
The ISO’s transmission grid is located solely within the state and not synchronously interconnected with the rest of the U.S. Under the Federal Power Act, FERC has no jurisdiction over transmission lines that cross international boundaries if they don’t also cross U.S. state lines. ERCOT has several synchronous (AC) and asynchronous (DC) ties with Mexico, but energy does not flow between Texas and other states through Mexico’s national grid.
| Mexico Ministry of Energy
Public Utility Commission Chair DeAnn Walker has said the federal agency could exert its jurisdiction over ERCOT through the U.S. Constitution’s Commerce Clause “if the commingling of power between ERCOT and the rest of the United States occurs.” (See Regulators Fear Cross-Border Tx Risks ERCOT’s FERC Exemption.)
Sharyland sister company Nogales Transmission has applied for a presidential permit to build an HVDC interconnection between Arizona and Mexico (OE PP-420). Nogales last year asked the Department of Energy to delay processing its permit until it can obtain “the necessary FERC disclaimer” of jurisdiction.
Further west, Mexico is considering a major project that would link the state of Baja California, which is part of the Western Electricity Coordinating Council, with the rest of the country’s grid and with California.
ERCOT said it was pleased with the FERC order. “[It] alleviates any current or future jurisdictional concerns resulting from new interconnection projects with Mexico and other neighboring states,” spokesperson Leslie Sopko told RTO Insider.
AEP asserted that if FERC granted the parties’ request, the DC ties would become facilities for the transmission and wholesale sales of electric energy in interstate commerce “solely by reason of” a commission order.
“The continuing operation of the ties in compliance with the requested Section 211 order would not cause the tie operators to become ‘public utilities’” as defined by the FPA, the utilities said.
Commission Eases 2006 Requirements on Westar Energy
The commission on July 27 granted Westar Energy’s request to remove mitigation measures and reporting requirements imposed in connection with its 2006 acquisition of a ONEOK Energy Services gas plant (EC06-48).
Westar asked FERC to remove the measures and quarterly and annual reporting requirements, saying that changes in the SPP market since the 2006 acquisition made the decade-old requirements no longer necessary. SPP went live in 2014 with its Integrated Marketplace, which included day-ahead, real-time and financial transmission rights markets, and a consolidated balancing authority that replaced 16 legacy BAs.
In approving Westar’s acquisition of ONEOK’s 300-MW Spring Creek facility and a 75-MW power purchase agreement from the Oklahoma Municipal Power Authority (OMPA), the commission ordered the utility to increase transfer capabilities into its BA to reduce its 42% share of the market.
Westar requested a clarification of the order, committing to not use 225 MW of network integration transmission service during the winter period. The commission granted the request, but OMPA in 2007 requested a rehearing. FERC asserted Westar had asked SPP to move Spring Creek from the Oklahoma Gas & Electric BA to Westar’s, undermining the mitigation alternative. FERC agreed, directing that Westar continue to model the facility in OG&E’s BA.
Westar filed its request in 2016, arguing that SPP’s consolidated BA meant its market share should be measured using the RTO’s entire capacity, rather than that of the utility’s former BA area. It also pointed out that the OMPA contract had expired in 2015.
SWEPCO ROE with East Texas Co-ops Reduced
FERC on July 26 approved a settlement agreement between Southwestern Electric Power Co. and two East Texas cooperatives, East Texas Electric (ETEC) and Northeast Texas Electric (ER18-1560).
The settlement reduces SWEPCO’s return on equity with ETEC from 11.1% to 10.1%, effective Sept. 1, 2017. It also revises the utility’s formula rate templates that govern its power supply agreements with the two co-ops.
VALLEY FORGE, Pa. — PJM’s effort to include variable operations and maintenance (VOM) costs in energy market cost-based offers appears to be on its way to FERC following a long-awaited vote to revise the current rules at last week’s meeting of the Markets and Reliability and Members committees.
Stakeholders rejected five proposals, including one of them twice, after which PJM’s Stu Bresler indicated the RTO might recommend its Board of Managers approve changes anyway. He said his starting point for the recommendation would be PJM’s proposal, which was twice rejected in its original form and also in a revised alternative motion.
Stakeholders said they would keep a close watch on what recommendation staff develop, and Brian Wilkie with Rockland Electric Co. (RECO) called Bresler’s plan “disappointing.”
The initial proposal was sponsored by American Electric Power and would allow use of default U.S. Energy Information Administration calculations for the amount of VOM costs allowed in offers. The proposal was rejected with a sector-weighted vote of 2.28 in favor and 2.72 opposed. Such sector-weighted votes have a threshold of 3.35 to be endorsed.
AEP’s Brock Ondayko had been promoting the proposal as preferable to a proposal from RECO because it used data that were independently developed and published.
“What we have proposed, and what was accepted earlier, is this concept of using data from an independent provider that has no agenda or opinion of PJM’s markets,” Ondayko said. “The point is there’s actual data. … Nothing is hidden from public view. … There’s no data with the potential defaults in the other package.”
PJM’s proposal remained unchanged from past discussions as the only one that would allow units to include fixed costs in their energy offers if they failed to clear in the year’s capacity auction. It was also rejected with 2.86 in favor and 2.14 opposed.
The Independent Market Monitor’s proposal would limit costs allowed in energy offers to “short-run marginal costs,” which would be defined. The proposal was rejected with 1.83 in favor and 3.17 opposed.
“This is about the prevention of market power,” Monitor Joe Bowring had said prior to the vote, noting that PJM’s manuals don’t clearly define several related components.
RECO’s proposal was meant to strike a compromise between generator-friendly and load-friendly proposals to ensure that stakeholders wouldn’t be stuck with the status quo if coalitions stood their ground and those proposals failed to win endorsement, Wilkie said. It would allow generators to recover VOM costs up to limits that would be posted into Manual 15. Almost all unit types would be capped at $3.50/MWh for the costs. Sub- and super-critical coal and biomass would be capped at $4/MWh; nuclear at $3/MWh; and wind, solar and hydro at $0/MWh.
“I agree. They’re not based on data,” Wilkie said in response to Ondayko’s comments. “They’re a compromise between the data the IMM thinks is reasonable and the data EIA thinks is reasonable.”
He said his customers would benefit most from the Monitor’s numbers, but he was particularly concerned with the appearance that generators were simply trying to increase revenues by moving the costs to the energy market as opposed to the capacity market, where they’re currently allowable.
“If it’s just and reasonable for these costs to be in the unit’s capacity offer, then it’s hard to understand how it can instead be just and reasonable for them to be in the energy offer. It can be one or the other, but toggling those costs back and forth based on where generators think there’s going to be the most money doesn’t seem like a sound market design principle,” Wilkie said.
Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS), agreed with that perception.
“I would call that market shopping. … That’s a concern,” he said.
However, Exelon’s Jason Barker said many asset owners agreed RECO’s proposal “parrots” the Monitor’s proposal.
The proposal had a similar voting result with 1.97 in favor and 3.03 opposed.
Stakeholders next voted on an alternative proposed by Adrien Ford with Old Dominion Electric Cooperative. Ford had offered a friendly amendment to the PJM proposal to remove the language that allowed units to include fixed costs in their energy offers if they failed to clear in that year’s capacity auction so that the package aligned with the other three.
Staff wanted to “get a read” on favorability for the package that was originally endorsed at the Market Implementation Committee meeting, so they did not consider it friendly. Because it was the motion endorsed by the lower committee, a stakeholder had to object to the motion being friendly, so Citigroup Energy’s Barry Trayers did so.
Ford then offered it as an alternative motion, but it too was rejected, receiving 2.65 in favor and 2.35 opposed.
American Municipal Power’s Steve Lieberman motioned for a revote of the original PJM proposal, which was seconded by Trayers, but that was also rejected, receiving 2.93 in favor and 2.07 opposed.
Following the vote, Bresler informed stakeholders that PJM may not be satisfied with retaining the status quo and might consider making its own recommendation to the Board of Managers. He said he would “start” with PJM’s proposal as the basis for the recommendation.
Susan Bruce, representing the PJM Industrial Customer Coalition, promised “robust oversight” of staff’s development of the potential recommendation.
Wilkie called Bresler’s announcement “disappointing.”
Asked to opine on PJM’s rules for such situations, CEO Andy Ott said he felt the board being informed of stakeholders’ voting record on the issue would provide enough evidence of their preferences so that the board would be properly informed before considering staff’s recommendation.
At the Members Committee meeting that followed the MRC, stakeholders voted to adopt the MRC votes so that the board would be informed.
