A forecasting error is prompting CAISO to procure a large volume of out-of-market resources for September under a special measure not invoked since the emergency shutdown of the San Onofre Nuclear Generating Station in 2012.
CAISO will solicit up to 1,434 MW of resources under its Capacity Procurement Mechanism, stakeholders learned during a call Thursday.
The procurement was prompted by the California Energy Commission’s July 10 publication of a revised load forecast showing the ISO’s balancing area will next month need 1,247 MW more in systemwide resource adequacy (RA) resources than originally projected, plus a 15% planning reserve margin.
Under CAISO’s Tariff, the ISO can invoke CPM in response to a “significant event,” defined as any “substantial event” or “combination of events” that “causes, or threatens to cause, a failure to meet reliability criteria absent the recurring use of a non-resource adequacy resource on a prospective basis.” A load forecasting error qualifies as such an event, Delphine Hou, the ISO’s manager of state regulatory affairs, said during the Aug. 2 call.
The CEC attributed the RA forecast error to its reliance on 2016 — rather than 2017 — energy demand data in its original 2018 monthly forecast. The forecast is provided to both CAISO and the California Public Utilities Commission for RA planning, which is managed by the commission.
| CEC
The error was discovered because of discrepancies between the CEC forecast and the monthly peak forecast CAISO produces for Western Electricity Coordinating Council planning, which the ISO used this year for its flexible capacity needs assessment. The revised CEC forecast aligns with CAISO’s projections, which had been benchmarked to 2017 load figures.
October a ‘Concern’
While this month’s CPM solicitation will focus only on procuring resources for September, Hou said the ISO will continue to evaluate the need to procure resources for October, which the revised forecast indicates has an even bigger RA need: 5,103 MW. Under CAISO rules, a CPM procurement has an initial term of 30 days, which can be extended by another 60 days if the “significant event” is likely to persist.
Pointing to the much larger October deficiency, NRG Energy Director of Market Affairs Brian Theaker asked, “Can you elaborate on what the ISO will be looking for and what conditions it will impose before making a decision as to whether to CPM for October?”
While October load will be lower, the ISO is “sensitive” to the possible continuation of Santa Ana winds during the month, fire concerns in Southern California and the impact of drought, she said. She also pointed out that some generators may begin entering maintenance outages during that month.
“So we want to at least see how September goes. … It is likely we will extend the significant event through October, but we wanted at minimum to get the word out for September,” Hou said.
“Why are we hearing about [the error] now? It seems like we would’ve had this information back in January,” said Nuo Tang, principal energy policy strategist at San Diego Gas & Electric.
Hou was diplomatic in her response.
“It took some time because we were having a lot of discussions with the CEC and the CPUC about how to think about the difference between the forecasts, and it was eventually recognized that because the original RA forecast seemed somewhat low for September. … Out of an abundance of caution, we really should sunshine this other forecast for CAISO to use under significant events,” she said.
| CAISO
“I think what you’re highlighting is that we don’t vet the system RA forecasts,” leaving CAISO stakeholders unable to compare the forecasts used for system RA and flexible capacity, Tang said. “Would that be a fair characterization?”
“Yes, that is fair, and in fact you pre-empted my very [next] line … which is [that] for future coordination, we’re definitely working very closely with the CEC and CPUC to review the RA forecast for next year,” Hou said.
Credit Where it is Due
Tang also asked why CAISO chose to invoke a CPM significant event instead of relying on exceptional dispatch, a shorter-term out-of-market procurement mechanism.
Hou said that CAISO officials were concerned that if they delayed procuring resources, generators without RA designations could end up selling to other buyers, including those outside the ISO, or go out on maintenance outages.
“What we landed on was that we would prefer to notify the market earlier to get more bids into the competitive solicitation process [in order] to have a deeper pool for the operators to be able to pull from, because this is a system issue. It’s not going to be as a restrictive as a local issue,” she said.
Eric Little, manager of wholesale and GHG market design at Southern California Edison, asked if the ISO would reduce the 1,434-MW procurement if any LSEs show above their minimum RA requirements for the month.
Hou said the ISO had not yet performed that analysis, but that it would credit the system for any LSE overages.
“And then once you do that, when you start to cost allocate, will there be any reduction in bills for those LSEs that showed over, so they’re only getting allocated for their portion of the additional CPM procurement performed by the ISO?” Little asked.
“It would credit against the total required amounts … but it would not be a credit against the cost allocation,” Hou said.
“So all other LSEs get the benefit that the one LSE showed long?” Little asked.
“Yes,” Hou replied.
Resources owners have until Aug. 25 to submit their offers to the ISO. Bidding is open to any RA eligible resources internal to the ISO balancing authority area. External, or “intertie,” resources are excluded from participation.
FERC has allowed MISO and PJM to implement the first of a two-phase fix to remedy the RTOs’ double-charging of congestion fees on pseudo-tied generation.
The commission on Tuesday approved amendments to the RTOs’ joint operating agreement addressing market-to-market (M2M) settlement and day-ahead coordination of pseudo-tie transactions (ER18-136-003, ER18-137-003).
Effective Aug. 1, the RTOs will calculate day-ahead LMPs “that reflect the real-time usage of the pseudo-tied resource,” FERC said. To model generator pseudo-tie impacts, the RTOs will calculate flowgate impacts based on amounts offered in the day-ahead market. The two will also modify settlement procedures to account for market flows and associated M2M congestion payments.
Until now, the RTOs have reflected the costs of relieving a binding flowgate in both their LMPs.
FERC agreed with the RTOs that the proposal “represent[s] an improvement over current practices” and will eliminate most of the overlapping congestion charges.
Separately, the commission also approved PJM’s Phase 2 revisions, which will modify its Tariff to provide for rebates for deviations from day-ahead commitments and remove the remaining overlapping congestion charges not addressed by Phase 1 (ER18-1730).
FERC required MISO to make periodic informational filings on the status of its Phase 2 efforts.
MISO and PJM worked throughout 2017 to remove the overlapping congestion charges soon after the first of several complaints about the issue were filed with FERC. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)
MISO reports 754 MW pseudo-tying into the footprint and about 2,142 MW pseudo-tying out.
Possible Interregional Projects
Meanwhile, the RTOs are working on two studies that could identify both small-scale and large-scale interregional transmission projects.
MISO and PJM are conducting a two-year coordinated system plan study to identify more expensive seams projects called interregional market efficiency projects (IMEPs) and a shorter-term study to identify smaller targeted market efficiency projects (TMEPs). (See MISO, PJM Plan 2 Studies for Seams Projects.)
The windows for submitting interregional project ideas opens Nov. 1 for PJM and Jan. 1 for MISO. Analysis on the project proposals will take place next year. MISO and PJM have yet to approve an IMEP.
At an Aug. 1 Interregional Planning Stakeholder Advisory Committee conference call, MISO and PJM staff said they would be ready to share this year’s TMEP study results during the October IPSAC. PJM interregional engineer Alex Worcester said the two are investigating 19 facilities — down from an original 61 — that have each amassed more than $1 million in congestion charges in 2016 and 2017 combined.
“Very soon here, we’ll be reaching out to the equipment owners of the 19 facilities flagged for further study to identify the limiting equipment and what the potential solutions might be,” Worcester said.
In September, MISO and PJM will begin testing the potential upgrades to see if they solve congestion.
The D.C. Circuit Court of Appeals on Tuesday upheld a 2016 FERC order that reallocated most costs for the Presque Isle system support resource agreements to consumers in Michigan’s Upper Peninsula.
The court denied in full petitions from a group of Michigan officials and load-serving entities, which included the state’s Public Service Commission and attorney general (15-1098). They argued that FERC’s reallocation of the SSR costs amounted to retroactive ratemaking. (See Michigan Groups Contest Presque Isle Cost Allocation.)
But the court said FERC was within its authority to order refunds to customers “who paid too much, funded by surcharges on customers who paid too little.”
“The reallocation at issue here does not constitute an impermissible retroactive rate increase,” the court said. “FERC reasonably determined that the prior rate methodology was unjust and unreasonable, and its reliance on certain evidence in reaching this conclusion was appropriate. Having … determined that a different methodology would comply with cost-causation principles, FERC had authority to order refunds and corresponding surcharges.”
The court added that while FERC is limited in power over the filed rate doctrine, its “remedial authority is otherwise expansive.”
The decision means Upper Peninsula ratepayers will bear nearly all SSR costs for the coal-fired plant. Under the original 2014 agreement, those costs were allocated across the American Transmission Co. zone on the Michigan-Wisconsin border, with Upper Peninsula ratepayers paying 8% and Wisconsin ratepayers responsible for the rest.
Following a complaint by Wisconsin’s Public Service Commission that the state was paying for most of the SSR but not receiving the majority of the benefits, FERC allowed MISO to shift 98% of the costs to LSEs in the sparsely populated Upper Peninsula. That change in part stemmed from NERC’s 2014 decision to separate the Upper Peninsula from Wisconsin into its own local balancing authority.
FERC at the time said it was unjust to allocate SSR costs on a pro rata basis to all LSEs in the ATC zone, despite historical practice. It said the costs must instead be allocated to LSEs that require the operation of the plant for reliability purposes. The Michigan LSEs and regulators countered that there was no new evidence or change in circumstances to justify changing ATC zone allocations.
The court was not persuaded by the Michigan argument. It pointed out that ATC was the only MISO zone subject to such a pricing zone methodology, with LSEs in other zones paying for reliability resources in proportion to their reliability needs: “For the rest of the MISO area, the Tariff provided only that reliability costs were allocated to the LSEs ‘which require the operation’ of reliability resources. In other words, SSR costs for all non-ATC service areas were allocated to the LSEs that actually benefited from the reliability resources.”
The court was also not swayed by the argument that FERC improperly relied on a preliminary MISO load-shed study in its reallocation decision.
“FERC’s recognition that more accurate data was necessary does not undermine its reliance on the preliminary study at the time of the complaint, or on the final data once the study was complete,” the court said. At any rate, the court said, the Michigan groups did not demonstrate that the old pro rata calculation was superior.
Cloverland Electric Cooperative, one of the Michigan petitioners affected by the surcharges, said through its attorney that it was disappointed with the decision.
“We … believe it expands FERC’s authority to assess retroactive surcharges beyond anything we have seen before. It also undermines the court’s rule about accepting post hoc rationalization of earlier FERC orders,” attorney Christine Ryan said in an email to RTO Insider.
The Western Energy Imbalance Market saw financial benefits soar to a record $71.2 million in the second quarter on surging exports of low-priced solar generation from California and the addition of new members Idaho Power and Powerex, according to a report from market operator CAISO.
CAISO earned the largest share of the EIM’s Q2 benefits on surging solar exports. | CAISO
Quarterly benefits were up more than 69% from the first quarter and 75% from the same period a year earlier. (See CAISO, PacifiCorp Gain Most EIM Q1 Benefits.) The EIM has yielded $401.7 million in gross benefits for its members since it began operation with PacifiCorp in November 2014, the ISO estimates.
The CAISO balancing area reaped $27.9 million in EIM benefits last quarter, with net exports exceeding 1.9 million MWh, nearly 10 times the volume of the next biggest exporters, NV Energy and Arizona Public Service.
“The second quarter of 2018 saw an uptick in energy moving out of California through the EIM, as the system experienced high levels of renewable production at a time in the season when temperatures are still cool and electric demand is moderate,” the ISO said in a statement.
PacifiCorp was the biggest beneficiary of CAISO’s renewable surpluses, importing nearly 1.1 million MWh of low-cost power over the quarter and earning $11.67 million in EIM benefits, the second-largest share among market members.
Trailing the two biggest earners were APS ($8.6 million), wind- and hydro-heavy Idaho Power ($7.8 million), NV Energy and Portland General Electric ($5.4 million each), Puget Sound Energy ($2.3 million) and Powerex ($2.3 million).
The report once again shows CAISO as a significant exporter of power during spring. The ISO said the EIM’s transfer capability allowed it to avoid curtailing 129,128 MWh of surplus renewable energy among its members during the quarter, up 93% from a year earlier. The avoided curtailments resulted in displacement of 55,267 metric tons of CO2 emissions and increased the volume of renewable energy credits, although the benefits calculation does not include the value of RECs, the ISO said.
The report also illustrated the extent to which certain EIM areas function as paths for wheel-through transfers, meaning the BA area is neither the source nor sink for large volumes of power. During the second quarter, the NV Energy and APS systems handled 828,282 MWh and 321,667 MWh of transfers between CAISO and the PacifiCorp-East (PACE) area, respectively, while the relatively small PacifiCorp-West system facilitated 386,788 MWh of north-south transfers among California, the Pacific Northwest and PACE. By comparison, just 127,205 MWh of energy were wheeled through CAISO over the period.
“As part of the EIM Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel-through volumes to assess whether, after the addition of new EIM entities, there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits,” the report notes.
A CAISO proposal to compensate EIM participants for wheel-through transfers last summer drew strong opposition from stakeholders concerned about the impact on the economic dispatch of generating resources. (See EIM Members Wary of Need for Wheeling Charge.)
The EIM’s gross benefits represent either cost savings for serving load or increased profits from merchant operations within the participating BAAs. The benefits calculation nets out inter-BAA transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.
Idaho Power and Powerex began transacting in the EIM on April 5, days after the beginning of the second quarter. Sacramento Municipal Utilities District is slated to join the market in April 2019, followed by the Los Angeles Department of Water and Power, Salt River Project and Seattle City Light in April 2020.
FirstEnergy has reached what CEO Charles Jones called a “big milestone” in its process of unwinding from FirstEnergy Solutions, the bankrupt merchant generator that was until recently a subsidiary.
FirstEnergy’s Akron, Ohio headquarters
The FES bankruptcy settlement is now “definitive, comprehensive” and includes FES, its subsidiaries, FirstEnergy Nuclear Operating Co. and a committee for unsecured creditors, Jones said Wednesday. It builds on agreements FirstEnergy announced in April while reporting its performance for the first quarter. (See FirstEnergy Announces Mixed Earnings, Plan for FES Bankruptcy.)
“This definitive, comprehensive settlement defines and quantifies all of FirstEnergy’s obligations with respect to FES and FENOC,” Jones said.
The Aug. 1 announcement came as part of FirstEnergy’s review of its second-quarter performance, which exceeded both revenue and earnings expectations. The company reported quarterly adjusted earnings of 62 cents/share, which beat expectations by 9 cents, and revenue of $2.7 billion, which was $130 million over projections. Revenue increased $100 million compared to the same quarter last year, while earnings were up 18 cents/share year over year.
The settlement credits FES for nine months of its shared services costs with FirstEnergy and entitles the former subsidiary to continue purchasing the services through June 2020. FirstEnergy also agreed to increase its cash payment and cover costs for some FES employee benefits, which represent $218.5 million in additional costs incurred by FirstEnergy. FES is expected to file the agreement by the end of August as part of its bankruptcy case and to receive approval in September.
While FirstEnergy no longer has any merchant generation assets, Jones maintained his strong advocacy for financial supports for nuclear and coal units, saying that “the market policies in our country have severe flaws” and that he will “continue to be a loud advocate” for changes. Shuttering large-scale plants “is not going to be a good thing for the 6 million customers that I look out for,” he said. Jones said he remains “hopeful” that the U.S. Department of Energy “will eventually step forward to do something to stabilize” those plants.
Entergy accelerated its march towards becoming a “pure play” utility Wednesday, announcing the sale of its Pilgrim and Palisades nuclear power facilities for their accelerated decommissioning.
Financial analysts congratulated Entergy executives on the news during the second-quarter earnings call, where the company announced adjusted earnings of $1.79/share, beating Zack’s consensus estimate of $1.26 by 42%.
Palisades Power Plant | Entergy
CEO Leo Denault said the plants’ sale “solidifies” Entergy’s plans to fully divest itself of three of the four nuclear plants in its Entergy Wholesale Commodities (EWC) business.
Entergy’s share price jumped Wednesday by almost $2 — from $81.03/share at the market’s open to a high of $82.99 — before falling back to close at $81.82.
“This gives us a lot of capital, both financially and operationally, to focus on the growth of the utility,” Denault said.
Earlier this year, Entergy reached an agreement with Vermont state officials to sell its Vermont Yankee plant to NorthStar Group Services, which will handle the decommissioning. The plant was shuttered in 2015. The company is waiting on regulatory approvals to sell the plant’s holding company.
The transaction includes the transfer of the plants’ operating licenses, spent fuel and nuclear decommissioning trusts, to Comprehensive Decommissioning International, a newly formed joint venture between Holtec International and SNC-Lavalin.
Entergy received a “nominal” cash consideration in the deal, which must clear the Nuclear Regulatory Commission and other regulators.
“You could afford it if you could demonstrate the ability to close a nuclear plant,” CFO Drew Marsh told analysts. “The main objective was to move the risk to a party capable of [decommissioning] and doing it much quicker than we can.”
Pilgrim Nuclear Power Station | Entergy
Pilgrim, located in Plymouth, Mass., is scheduled to end operations by June 2019, and Palisades, in Covert, Mich., is to close in early 2022. The two plants date back to the early 1970s. They generate almost 1.5 GW of power between them and employ 1,200 people.
Entergy’s Indian Point nuclear plant in New York will close by 2021, according to an agreement between the company and state officials. Denault said there was “nothing to read” into not including Indian Point in the deal.
The company reported earnings of $245 million ($1.34/share), excluding a one-time tax benefit of 31 cents/share for the settlement of a 2012-2013 IRS audit. That compared to $410 million and $2.27/share a year ago.
EWC reported a loss of $57 million in the quarter. Entergy affirmed its 2018 consolidated operational earnings guidance range of $6.25 to $6.85/share.
FERC on Tuesday rejected NorthWestern Energy’s attempt to limit its liability for service interruptions to an ExxonMobil oil refinery in Montana, saying the provision was discriminatory (ER18-1715).
The utility had attempted to include the limitation in an unexecuted network integration transmission service agreement for ExxonMobil’s Billings refinery, saying it was needed because of the facility’s size, its “sophisticated equipment” that is “particularly sensitive” to loss of power, and that its continuous 24/7 operation lacks a backup power source.
The liability provision stated that neither party would be liable for “consequential, special, indirect or incidental damages whether arising in tort or contract, including a breach or alleged breach” of the agreement.
In 2016, ExxonMobil sued NorthWestern in state court, seeking $92.4 million in damages and lost profits over two power outages at the refinery that the oil company said resulted from NorthWestern’s negligence. The case was settled in December 2017 but terms were not released.
Billings Refinery | ExxonMobil
NorthWestern said the service interruptions — a 96-minute outage in 2014 and a 53-minute outage in 2016 — were caused by faults on its 50-kV radial lines feeding the refinery. It said the outages were triggered by problems on the distribution system of the city of Billings’ sewer plant. ExxonMobil’s suit alleged the utility was negligent because protective relays on its 50-kV lines were not coordinated with the relay system at the sewer plant.
FERC agreed with ExxonMobil that the liability provision was unduly discriminatory because NorthWestern was not seeking to impose such limits on other transmission customers, including three other oil refineries it serves in Montana.
“A transmission provider seeking commission acceptance of a non-conforming agreement bears a high burden to justify and explain that the non-conforming aspects of the agreement are not merely ‘consistent with or superior to’ a pro forma agreement but are necessary,” FERC said.
The commission rejected NorthWestern’s argument that ExxonMobil expected perfect, uninterrupted service. “ExxonMobil’s lawsuit against NorthWestern was not based merely on service interruptions, but the allegation that NorthWestern had ‘negligently failed to exercise reasonable care in designing, constructing, installing, managing, maintaining, inspecting and operating its electrical facilities and equipment,’” the commission said.
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.
