FERC on Friday granted ISO-NE another six months to file a long-term fuel security mechanism, the second extension since its original order last July (EL18-182). The new deadline is April 15, 2020.
ISO-NE in January filed a motion requesting an extension of the original July 1 deadline, which the commission granted, extending the deadline to Oct. 15. On July 31, the New England States Committee on Electricity filed a motion requesting an additional six months to allow ISO-NE and the region to work through issues related to the RTO’s proposed mechanism.
Several commenters, including Energy New England, the Environmental Defense Fund and National Grid, supported the motion, while ISO-NE, the New England Power Pool, Repsol Energy North America and Verso Corp. told the commission they took no position on the request.
The New England Power Generators Association opposed the request, insisting the commission issue an order on the proposal by Sept. 26, “before key deadlines lapse for the next scheduled Forward Capacity Auction, FCA 14.”
“Sept. 26 is a key date because it is the final day before the start of the submission window to finalize static delist bids in FCA 14,” NEPGA said. “By that date, generation resources must decide whether to delist or not. Basic market fundamentals — such as whether fuel security resources will be required to offer at zero or submit cost-based offers — must be established by that date.”
In the alternative, NEPGA said, FERC should at least issue an order by Jan. 31, 2020, just days before FCA 14 is scheduled to start. “In no event should an order be delayed beyond Jan. 31, 2020,” it said.
ERCOT CEO Bill Magness briefed the Texas Public Utility Commission last week on his organization’s response to the intense August heat, when the grid operator met record demand peaks and saw several price spikes.
ERCOT called two energy emergency alerts (EEAs) last month, its first in five years. Staff had warned before the summer began that EEAs were likely, given the system’s tight 8.6% reserve margin, but it did not have to resort to more drastic measures such as rotating outages. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)
“I feel a little like the air traffic controller telling you how great the air show was,” Magness told the PUC during his presentation Thursday. “As you know, [ERCOT doesn’t] fly the planes. I wasn’t out there on a Saturday when it was 105 degrees [Fahrenheit] fixing a tube leak so the plant could run. The entire industry worked very hard under difficult conditions, and that’s how we were able to keep the power on effectively for the state during a very rough period.”
ERCOT CEO Bill Magness briefs the Texas PUC on meeting August demand.
Commissioner Arthur D’Andrea offered thanks and kudos to Magness and the staff, saying, “We asked you to run a grid with very tight reserve margins. You stepped up and have given us reliability and probably the most efficient grid in the world. You’ve saved Texans a lot of money.”
Demand soared in August following the coolest June-July period since 2007. ERCOT set a new all-time peak of 74.7 GW on Aug. 12, smashing the record set in July 2018 by more than 1 GW. In all, the system topped the 2018 record seven times that week.
The Texas grid operator recorded its second-highest demand peak on Aug. 26 at 74.6 GW, along with two other top 10 marks.
Ironically, the EEAs were declared on two of the three days following the record peak, when temperatures and load were lower, but wind production dropped and thermal generation outages increased. Prices briefly hit the $9,000/MWh maximum during both energy alerts.
As he has before, Magness explained that ERCOT sees a trough in wind production during the early afternoon hours, when West Texas winds die down and before the coastal winds pick up.
“We have a fairly consistent pattern established in the summer where the West Texas and the coastal wind support the system at various times of the day,” he said. “As we have an increasing amount of intermittent resources on the system, there’s a divergence between the peak load of the day and when the reserves are lowest.”
Magness said forced outages were to be expected, considering the stress placed on generating units.
“When you’ve been running units through August with that kind of heat,” he said, “running units can become limping units, and limping units can become stopping units, if you don’t let them take a break and fix mechanical problems that come from running them so hard.
“The forced outages are not out of the ordinary, but when combined with a loss of wind generation and continued high load, that’s what took us into the EEAs,” Magness said.
| ERCOT
ERCOT filed detailed reports on the Aug. 13 and Aug. 15 EEAs in a reopened docket (27706). The commission also opened a docket to review the grid operator’s summer performance (49852).
The PUC has tentatively scheduled an Oct. 11 workshop for a final and more in-depth debrief on ERCOT’s summer performance. The grid operator and its Independent Market Monitor are among those who will deliver presentations.
Commission Chair DeAnn Walker, who requested Magness’ presentation, said she and Magness will both be attending NERC’s quarterly meeting in November. “NERC is concerned about the reliability of our grid, and Bill and I are going to go tell them we’ve got it,” she said.
ETEC OK to Transfer 35 MW into ERCOT
The commission approved East Texas Electric Cooperative’s (ETEC) request to move 35 MW of load and related facilities into ERCOT from SPP (47898).
ETEC, which provides wholesale service to eight smaller cooperatives straddling the ERCOT, SPP and MISO footprints, said the transfer will reduce energy costs and better balance its load among the three grid operators. The co-op will have 185 MW in ERCOT, 965 in SPP and 450 in MISO when the load transfer is completed during the last three months of 2020.
To transfer the load, ETEC will disconnect three substations from SPP and connect them into ERCOT through interconnections on a 138-kV line transmission line. The co-op and Oncor are responsible for building the interconnections.
PUC Rejects T&D Waiver Request
The PUC denied a petition by Oncor, CenterPoint Energy and Texas-New Mexico Power for a waiver of the commission’s quarterly retail market performance-measure reports, as required of ERCOT, retail providers, and transmission and distribution entities (49301).
The companies said it was “impractical and unduly burdensome” to comply with the rule and its reporting form because of changes over time in the applicable tariff and the market. Walker disagreed with their assertion, saying a rulemaking would be a more appropriate proceeding to change the rule.
“CenterPoint and others have been filing these in May and August, so it can’t be burdensome and impractical,” she said. “This is not the way to fix a rule or a form.”
Hearing Scheduled for El Paso Purchase
The PUC is working to schedule a hearing on an investment fund’s proposed acquisition of El Paso Electric (49849).
Commission staff are trying to schedule a hearing in November. A prehearing conference Thursday will set a procedural schedule and address pending motions.
EPE and J.P. Morgan Investment Management’s Infrastructure Investments Fund announced the $4.3 billion deal June 1. The sale must be approved by EPE shareholders, the city of El Paso, and Texas, New Mexico and federal regulatory agencies.
The parties filed a merger application with the PUC on Aug. 13, starting the 180-day clock to rule on the application. Texas Industrial Energy Consumers, El Paso and the Texas Office of Public Utility Counsel have intervened.
Commission Approves Rate Recovery, $328K in Fees
In other business, the commission approved Southwestern Public Service’s request to recover $2.16 million in rate-case expenses (47588).
The commission also approved six settlement agreements, totaling $328,500 in administrative penalties.
Electric wholesaler Twin Eagle Resource Management agreed to pay $180,000 for capacity shortfalls, inaccurate telemetry and failure to send notifications to all required parties (49784).
Retail provider American PowerNet Management was fined $10,000 for a history of failing to timely file annual reports (49408).
Spark Energy, another retailer, was assessed $90,000 over improper enrollment, bills and disconnection notices (49684).
Three qualified scheduling entities were fined for violating the use of the emergency response service (ERS) demand response tool. Power Generation Services was fined $8,500 for failing to maintain the required ERS load (49281), the city of Garland was hit with a $25,000 fine for not maintaining the required portfolio-level ERS availability factor (49698), and Links EP was docked $15,000 for not maintaining the required ERS load and availability factor (49731).
RENSSELAER, N.Y. — NYISO energy prices fell sharply in the second quarter, but congestion costs surged during the period despite lower gas price spreads and load levels, according to the Market Monitoring Unit.
Energy prices fell by 9 to 36% in the second quarter compared to the same period last year, while average load dipped to the lowest second-quarter level since 2008, Pallas LeeVanSchaick, of MMU Potomac Economics, told the ISO’s Installed Capacity/Market Issues Working Group on Thursday in presenting its quarterly report on the markets.
Falling locational-based marginal prices and lower capacity costs in most areas accounted for the overall price decline. Average all-in prices fell in all areas and ranged from $20/MWh in the North Zone to $55/MWh in New York City.
While capacity prices were up 4% in the city, they fell by 14 to 56% in other areas of the state because of lower peak load forecasts, uprates and new generation coming online. The report also showed that energy costs fell by 11 to 34% in most regions because of lower natural gas prices, which dropped 17 to 29% from the previous year in Eastern New York.
The Monitor’s 2018 State of the Market Report, presented by LeeVanSchaick in May, showed that rising natural gas costs and increased load levels drove up NYISO electricity prices by 23 to 36% last year, with peak load up 7% — “quite a large increase,” he said. (See “State of the Market: Peak Load Up 7%,” NYISO Business Issues Committee Briefs: May 13, 2019.)
Second quarter electric and natural gas prices in NYISO and neighboring regions | Potomac Economics
DA Congestion Revenues Rise 37%
Day-ahead congestion revenues rose 37% from the second quarter of 2018, the Monitor reported.
The West Zone marked the largest increase in congestion costs because of the combined effects of modeling 115-kV constraints in the market software; more costly transmission outages; the return to operation of the South Ripley-Dunkirk 230-kV line on the PJM-NYISO seam, which has increased the impact of loop flows; and an increase in imports stemming from low Ontario spot prices.
“West Zone constraints were hard to manage despite recent modeling enhancements,” LeeVanSchaick said. “The most significant factor leading to BMS [Business Management System] limit reductions was the cap on clockwise changes.”
The BMS and Energy Management System (EMS) encompass the critical core reliability functions on the grid. When physical (EMS) flows exceed flows considered by the scheduling models (BMS flows) by a significant margin, the ISO reduces scheduling limits to ensure flows remain at acceptable levels.
The cap on clockwise changes in circulation was previously set at 75 MW per real-time dispatch (RTD) interval, which prevented dispatch from reducing flows sufficiently after sudden changes in loop flow. NYISO increased the cap to 125 MW in June and 200 MW in July.
Frequency (top) and value (bottom) of day-ahead and real-time congestion along major transmission paths by quarter | Potomac Economics
NYISO increased the constraint reliability margin (CRM) on the Niagara-Packard 230-kV lines and the Niagara-Robinson Road 230-kV line from 20 MW to 40 MW in June and to 60 MW in late July to assist in managing the constraints.
Noting the change to the Niagara-Packard and Niagara-Robinson Road CRMs and cap on loop flow changes, Chris Wentlent, representing the Municipal Electric Utilities Association of New York State, asked, “Are those going to remain in place going forward?”
“They’re not temporary, but the CRMs and the cap on circulation changes can always be modified,” LeeVanSchaick said. “The increased cap on circulation changes recognizes that the dispatch model needs to redispatch generation when circulation changes by a large amount.”
Moving East and South
“NYISO is looking whether to relocate the proxy bus for Ontario to reflect that those imports tend to increase unscheduled power flows in the clockwise direction around Lake Erie,” LeeVanSchaick said.
Another issue has to do with the Saint Lawrence phase angle regulator (PAR), which can be used to reduce congestion in the West Zone by diverting a portion of Ontario imports to northern New York, but the PAR is generally less flexible than assumed by RTD.
In August, the ISO reduced the optimization range used by RTD to be more consistent with the anticipated operation of the PAR, which “tightened up some of the modeling assumptions to better reflect how it’s actually going to be operated,” LeeVanSchaick said.
Asked by Wentlent when the St. Lawrence PAR might be evaluated, LeeVanSchaick said he was not sure, “because those are complicated issues. Hopefully we can answer by the next quarterly report.”
Asked how the transmission build-up in the western part of the state would affect constraints, LeeVanSchaick said, “You might see more Ontario imports, which would hit hidden downstream bottlenecks, like perhaps Central East, but it’s not something that we’ve looked at carefully.”
Central East congestion increased primarily because of increased exports to New England from eastern New York, which were up approximately 400 MW, and more transmission outages leading to reduced transfer capability in April and May.
“Modeling these 115-kV constraints allows the market to reflect the congestion appropriately,” he said. “In the Hudson Valley-Dunwoodie category, we saw significant constraints, which is due to some new combined cycle natural gas generation in the Hudson Valley, and not as much energy being wheeled from the Hudson Valley through New Jersey to New York City.”
When the Indian Point nuclear plant retires in 2021, it will shift the location of congestion to another area south of the UPNY-SENY interface, LeeVanSchaick said.
New York City
NYISO’s efforts to manage constraints “have greatly reduced out-of-merit actions, especially in the West Zone,” LeeVanSchaick said.
However, most reliability commitments occur in New York City because additional generation is needed to satisfy operating reserve requirements that have not been reflected in the NYISO market, he said. On June 26, the ISO began to model city-wide requirements in the day-ahead and real-time markets.
Supplemental commitments for reliability in NYC by reason and location in New York City, where most reliability commitments occur | Potomac Economics
Couch White attorney Kevin Lang, representing the city, questioned the extent to which market-based approaches would reduce the need to dispatch particular units in specific locations for reliability purposes.
“That’s a legitimate concern,” LeeVanSchaick said. “If you have higher energy and ancillary services prices, there’s going to be an decrease in uplift. … Generators should be able to earn more of what they need through providing those energy and ancillary services products.”
The ISO’s “granular operating reserves” project would define a set of locations so that the market is procuring what the system needs, he said.
“If we can shift investment toward areas where new resources provide real value in the day-ahead and real-time markets, it will be more efficient, even if the investment is driven by subsidies, and it will reduce the likelihood of needed [reliability-must-run] contracts,” LeeVanSchaick said. “Now is a particularly important time to have more efficient market signals.”
Ohio Attorney General Dave Yost last week approved a draft petition to repeal the state’s nuclear subsidy program, giving supporters just seven weeks to collect more than 265,000 signatures to get the referendum on the November 2020 ballot.
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts and sponsor of the petition, said the “quick resolution will help Ohio voters exercise their constitutional right to put controversial legislation up to a statewide vote.”
Yost rejected the first draft last month, citing disparities in its language compared with the Ohio Clean Air Act signed into law on July 23. (See Ohio Approves Nuke Subsidy.)
Davis-Besse nuclear power plant
The controversial law makes Ohio the third state in the PJM footprint to provide subsidies for its nuclear plants as cheap natural gas floods the wholesale power market and drives energy prices down to record low levels. (See Monitor: PJM Markets Remain ‘Under Attack’.) Supporters say keeping the reactors operating will reduce carbon emissions — a primary target of clean energy bills across the country — and provide around-the-clock reliability to support the intermittency of solar and wind power.
Pierce’s group argues the law amounts to a “corporate bailout” that wastes money on less efficient resources at the expense of continuing to expand Ohio’s renewable energy portfolio. And it has some powerful, if not unlikely, allies on its side: the natural gas industry, independent power producers, environmental activists and clean energy groups.
But not everyone agrees. Last month, Ohioans for Energy Security launched a $1 million television and radio ad campaign that links the petition to furthering the interests of the Chinese government, warning residents not to sign away the state’s jobs and energy security.
The Energy and Policy Institute, a renewable energy advocacy group, said Ohioans for Energy Security’s spokesperson, Carlo LoParo, has connections to FES and also fronts the Ohio Clean Energy Jobs Alliance, a known proponent of the subsidy program.
“These ads are designed to intimidate and threaten our petitioners who are exercising their constitutionally guaranteed right to place this ridiculous bailout on the ballot,” Pierce said. “This is the kind of garbage that will get someone hurt, and we will hold all parties associated with their campaign responsible for any harm that comes to our circulators.”
But Pierce is also tight-lipped about where his group’s money comes from, telling RTO Insider previously that he will disclose its financial supporters as required by Ohio campaign finance law.
“Until then, I can say that you will find that they are many of the same groups and individuals who testified against the bill in the legislative debate over the bill,” he said.
MISO is poised to recommend nearly $4 billion in spending in its 2019 Transmission Expansion Plan (MTEP), making it the second costliest such package in the RTO’s history.
The draft MTEP 19 was brought into focus over a final series of subregional planning meetings last week. The transmission projects in the bundle so far number 483 at a total cost of $3.95 billion, with MISO South’s 72 proposed projects accounting for $760 million. The priciest projects are clustered in southern Illinois, southern Michigan and southern Louisiana.
MISO will post a final draft on Sept. 16, a day before putting the plan before the System Planning Committee of the Board of Directors at its meeting in St. Paul, Minn.
MTEP 19 breakdown | MISO
Last month, MISO was positioned to recommend 529 new projects at $4.4 billion. Even with the loss of about four dozen projects, the latest MTEP is positioned to be second most expensive behind the 2011 package that contained the multi-value project portfolio. Last year, MTEP 18 rang in at $3.4 billion and 442 projects. (See MTEP 19 Revealing High Price Tag.)
During an East subregional planning meeting Wednesday, Thompson Adu, MISO senior manager of transmission expansion planning, advised stakeholders that the cost and project figures are still subject to change, but he said the numbers are “almost finalized.”
MTEP 19 contains new breakdowns in MISO’s “other project” category to capture the specific drivers of projects. This year’s $2.7 billion “other” category is now broken down into about $1.2 billion in reliability projects, $768 million in age- and condition-based projects, $644 million in load growth projects and $105 million worth of other local needs. Baseline reliability projects account for almost $1 billion in spending, while generator interconnection projects make up $245 million. MISO said the majority of MTEP 19 projects are expected to be in service within five years.
Director of Planning Jeff Webb said MISO had been mulling creating an MTEP project classification for age- and condition-based upgrades to avoid having so many projects simply labeled as “other.”
Webb said the number of MTEP projects falling into the “other” category is a “carried-over legacy” from when the RTO had to separate regional reliability projects from local reliability projects for cost allocation purposes.
“Every time we take the [project] bar charts to the board, it’s mostly ‘other.’ … We’re thinking of changing that. We’re tired of having to explain exactly what ‘other’ is over and over,” Webb said during a June planning meeting.
During an Aug. 23 West subregional planning meeting, stakeholders criticized MISO for modeling too few future wind resources in congestion relief planning. Multiple staff members pointed to the planned overhaul of futures in time for the 2021 transmission planning schedule. But some stakeholders said MISO was planning for less wind for 2030 than would be actually installed in 2020.
“I find myself wondering why we’re building futures with significant future generation and don’t include the likely associated interconnection upgrades,” WPPI Energy’s Steve Leovy said.
Some stakeholders at the meetings also said the MTEP timeline is challenging, only allowing for stakeholders to suggest alternative projects in June and July.
Historical MTEP spending with draft MTEP 19 data | MISO
1 Possible Project from MCPS
Stakeholders last week also learned that few proposals were able to demonstrate enough benefits to pass the first round of scrutiny in this year’s Market Congestion Planning Study (MCPS), designed to identify congestion-relieving projects.
Among the proposals, MISO will only take a deeper look at two possible solutions to resolve the congested Bosserman-Trail Creek 138-kV line in northern Indiana. Both projects are also under consideration as part of the MISO-PJM Coordinated System Plan, and the RTOs will make a recommendation at the Sept. 20 Interregional Planning Stakeholder Advisory Committee meeting if they plan to pursue one of the two.
MISO has until Sept. 23 to file another cost allocation plan with MISO Mulling Next Steps on Cost Allocation Overhaul.) MISO staff said they hope to have a revised interregional cost allocation structure in place before project approvals in December.
MISO planning staffer David Severson said no projects in the RTO’s North region or along the SPP seam met requirements in the MCPS. Project candidates to address congestion on the Helena-to-Scott County 345-kV line in southern Minnesota did not pass a robustness analysis, MISO said. The $32 million line was one of eight initially promising projects to come from the MCPS. (See “8-Project Draft from Congestion Study,” MISO Studying Projects to Cut North-South Tx Reliance.)
Last week’s planning meetings did not address the ongoing analysis into a possible project to ease traffic on the North-South transmission constraint. That effort is being conducted separately from the MCPS and will continue beyond the MTEP 19 approval deadline in December. MISO staff earlier this year said they weren’t bound to an MTEP 19 deadline to submit any project recommendations and could take more time to conduct thorough testing of candidates.
The electric grid cannot be protected against electromagnetic pulses (EMPs) without guaranteed cost recovery and more access to classified information, NERC’s Electromagnetic Pulses Task Force concluded in a draft Strategic Recommendations report released for comment Friday.
The task force, created in response to President Trump’s March executive order, said efforts to quantify the risks of EMPs and develop mitigation strategies have been hampered by limited access to classified data on attack scenarios and a dearth of research on the ability of grid components to withstand pulses. And the threat cannot be addressed, the task force said, without a public policy consensus.
The “threshold item that the ERO Enterprise should take the lead in addressing … is to determine the bulk power system expectations for an EMP event. Based on that information, the industry can make the necessary preparations for attempting to meet those expectations,” the task force said. “However, several policy matters, outside of the ERO Enterprise, will severely impact the electric sector’s ability to address an EMP event. Those policy matters include the lack of a cost-recovery mechanism and access to classified information regarding an EMP threat.”
The report makes 15 recommendations in four areas — research needs; vulnerability assessments; mitigation guidelines; and response and recovery — and suggests lead organizations for each, including NERC, the Department of Homeland Security and the Federal Emergency Management Agency.
It said the 13-member task force should be expanded and continue work in collaboration with NERC’s technical committees to develop vulnerability assessments, mitigation guidelines, and response and recovery plans.
Comments on the recommendations are due by Sept. 30.
NERC’s EMP Task Force is proposing 15 recommendations on research needs; vulnerability assessments; mitigation guidelines; and response and recovery. | NERC EMP Task Force
Performance Expectations, Cost Recovery
The task force’s first recommendation is that the ERO Enterprise work with FERC, DHS, the Department of Energy and the Electricity Subsector Coordinating Council (ESCC) “to establish performance expectations for all sectors of the BPS regarding an EMP event” including survivability; expectations of ride-through versus recovery; restoration time frames; and permissibility of operations in a reduced protection state.
“This performance expectation will serve as the basis for industry with regard to where future mitigation efforts and capital expenditures should be most focused,” it said.
The task force said those performance expectations cannot be set, however, without “clear consistent cost-recovery mechanisms (federal financial support) for planning, mitigation and recovery plans.”
Policymakers should “consider establishing federal cost-recovery mechanisms for the electric utility industry to proactively address the performance expectations established by NERC,” the task force said.
“Effective EMP mitigation will span all portions of the electric sector: generation, transmission and distribution. The EMP Task Force highlights the importance of this recommendation in light of the variety of cost-recovery methods that exist across industry today, ranging from open competitive markets, to formula transmission rates, to traditional cost-of-service regulation.”
It suggested DHS take the lead on cost-recovery mechanisms, with support from NERC, FERC, asset owners, DOE and the ISO/ RTO Council.
The report makes no mention of state regulators, who approve distribution cost recovery and — in states with traditional vertically integrated utilities — also control spending on generation through integrated resource plans.
Trump’s executive order directed the federal government to provide incentives to “encourage innovation that strengthens critical infrastructure against the effects of EMPs through the development and implementation of best practices, regulations and appropriate guidance.” But the order made no mention of a federal funding stream for overall mitigation efforts.
Task force member Thomas S. Popik, president of the Foundation for Resilient Societies, said Congress did not address the funding issue when it enacted the Energy Policy Act of 2005, which created the ERO and gave FERC the authority to approve mandatory reliability standards.
The new system “was at its core an unfunded mandate on electric utilities,” he said in an interview with ERO Insider. “What wasn’t fully appreciated at that time was there would be additional standards for high-impact, low-frequency events — for example, cyberattack or electromagnetic pulse, even physical security — and that the reliability standards for [these events] would be many times more expensive than the previous voluntary standards, which were concentrated on operational procedures but not expensive hardware mitigations.”
Need for Declassification
The task force also recommended the creation of educational materials to inform industry and the public about EMP impacts on electronic devices and BPS stability. It said the ERO should provide guidance to the electric industry on coordinating responses with interdependent utility sectors such as telecommunications, fuel supplies and water. And it said NERC, DHS and FEMA should work with DOE and the U.S. Geological Survey to develop real-time notification system for informing system and plant operators of EMP events.
But it said those efforts will be hamstrung without more access to classified research by DOE, the National Labs and the Defense Threat Reduction Agency and to additional unclassified data on E1, E2 and E3 EMP “environments” — a reference to the three EMP “hazard fields.”
Data currently available “have very limited usability to the industry mainly because there are many parameters that are not shared with a greater audience,” the task force said.
EMP environment (E1, E2, and E3) | Department of Defense
A Bigger Challenge than GMDs
The task force said it relied in part on DOE’s 2017 action plan on EMP resilience and the Electric Power Research Institute’s (EPRI) April report on high-altitude EMPs triggered by nuclear weapons. Last week, a group affiliated with Maxwell Air Force Base released a harsh critique of the EPRI study, saying it underestimated the risks and should not be used as the basis for policymaking. (See Critics: EPRI EMP Report Understates Risks.)
The NERC task force said that improving the grid’s resilience to EMPs will be more difficult than the effort to address geomagnetic disturbances (GMDs). “The scientific evidence and basis of analysis for EMP events is not as well advanced and is likely to require some time to mature sufficiently to be of practical use,” it said. “Research conducted so far indicates that the impacts of GMD events tend to remain confined to longer lines operating at transmission voltage levels and interfaced to large power apparatus (e.g., generators and transformers). In comparison, the disruptive influence of an EMP event seems likely to span across the full spectrum of power system assets, including the transmission system, the distribution system, the protections and controls hardware, and the command-and-control infrastructure relied upon to monitor and maintain the power system in a stable operating state. Finally, the impact of an EMP event may extend to customer loads, since it remains unclear to what extent even these loads may be disrupted.”
FERC on Wednesday halted GridLiance Heartland’s entry into the MISO markets by blocking its $11.7 million purchase of six transmission lines from a Vistra Energy subsidiary (EC19-42).
The commission said GridLiance and the subsidiary, Electric Energy Inc. (EEI), failed to prove the acquisition wouldn’t adversely affect MISO rates. The deal involved two 161-kV substations and six 161-kV transmission lines that cross the Ohio River and connect to the EEI-owned Joppa Power Plant in southern Illinois. Vistra owns an 80% interest in EEI, with Kentucky Utilities controlling the remaining 20%. The assets in question currently sit outside the MISO footprint.
The move would have marked GridLiance’s first foray into MISO, while increasing revenue requirement rates in the Ameren Illinois transmission pricing zone. GridLiance estimated it would incur $8.2 million a year to operate the lines, 8 to 10 miles in length, compared with EEI’s $4.6 million in costs. Once the transaction closed, GridLiance said it would transfer functional control of all six lines to MISO by 2022. The request was submitted to FERC late last year.
GridLiance and EEI claimed the increased rate requirement would be offset by the transaction’s benefits, including use of EEI’s existing interconnection with the Tennessee Valley Authority to ease the burden on MISO’s north-to-south constraint, elimination of some pancaked rates and the expansion of the RTO’s footprint by adding transmission that can import power from neighboring balancing authorities.
Paducah Gaseous Diffusion Plant | DOE
But the six lines, originally constructed for the sole purpose of powering the U.S. Energy Department’s now-defunct Paducah Gaseous Diffusion Plant uranium facility, aren’t exactly in high demand now, incumbent transmission owner Ameren argued. EEI reconfigured its transmission system to disconnect from the Paducah plant in 2017. Four of the lines connect with TVA, while the other two connect with the Louisville Gas & Electric/Kentucky Utilities balancing authority area.
Ameren challenged GridLiance and EEI’s beneficial claims, arguing that no entities — except those already affiliated with EEI — have ever requested service over the lines in the last 25 years. Ameren also contended that neither GridLiance nor EEI undertook analysis to determine the likelihood of new transmission customers and pointed out that MISO already has interconnections to the TVA and LG&E/KU areas.
FERC agreed with Ameren, calling the supposed benefits “non-quantifiable” and unable to counteract an “admitted” increase in rates.
The commission also pointed to a GridLiance witness statement that “regardless of whether GridLiance Heartland purchases the EEI transmission facilities, those facilities will be placed into MISO’s functional control” because Vistra was already in the process of transitioning “several” units at the Joppa station into the RTO.
“We conclude that the benefits from integration of the transmission assets into MISO would occur irrespective of the proposed transaction,” FERC said.
While FERC wouldn’t speak to other factors regarding the merger because of the rate impact issue, it said its rejection was without prejudice and it invited the parties to file a revised acquisition proposal.
PJM’s incumbent transmission owners must sign designated entity agreements (DEAs) just the same as the nonincumbent developers building projects in their zones, FERC said Tuesday in an order denying rehearing on the issue.
The commission held firm to its position, explained in its original July 2018 ruling, PJM’s proposal to exempt incumbent TOs from signing DEAs because it would give them an undue advantage over non-incumbents (ER18-1647). (See FERC Rejects PJM Exemption for Incumbent TOs.)
It also rejected arguments by PJM and incumbents that the two groups of TOs were not “similarly situated” because each face different service mandates and penalties for falling short of those mandates.
“‘To say that entities are similarly situated does not mean that there are no differences between them; rather, it means that there are no differences that are material to the inquiry at hand,’” FERC said, quoting language in a separate February 2018 ruling involving NYISO TOs (ER15-2059-002, ER13-102-008). “Likewise, the courts have explained that entities are similarly situated if they are in the same position with respect to the ends that the law seeks to promote or the abuses that it seeks to prevent, even if they are different in many other respects.”
Construction of Ameren’s Illinois Rivers transmission line | Plocher Construction
FERC said that in past rulings it has held new and existing generators to the same standards for reactive power compensation, and equally applied transmission curtailments among non-federal renewable resources and federal hydroelectric and thermal services “because they all take firm transmission service.”
PJM and incumbent TOs requested rehearing in August 2018. Under current rules, both incumbent and nonincumbent TOs sign DEAs, which terminate once construction is complete. Nonincumbent TOs — competitive developers whose project proposals are selected by PJM through the FERC Order 1000 process — must also execute a consolidated transmission owners agreement (CTOA) before the prior contract can expire.
Notably, the commission said, breaching a DEA proves far easier and more expensive for nonincumbent TOs, which are subject to meeting construction milestones that may be delayed for reasons beyond their control. However, incumbent TOs only risk breaking the terms of a CTOA by missing scheduled in-service dates. Unlike incumbents, nonincumbent TOs must also “obtain a letter of credit or other financial instrument equal to 3% of the incremental project cost in the event of a breach,” meaning this extra cost must factor in project submissions, making the incumbent TO’s proposal cheaper by default.
The incumbent TOs “fail to recognize that the penalties for such noncompliance are not comparable to the upfront costs associated with the security requirement in the Designated Entity Agreement,” FERC wrote. “The penalty provisions of the Consolidated Transmission Owners Agreement are implicated only in the event of breach or other specified noncompliance, while the security requirement of the Designated Entity Agreement, as discussed above, necessarily increases a nonincumbent transmission developer’s costs. Further, due to the potential number and frequency of breach events, [the incumbent TOs’] comparison is inapt.”
FERC did accept PJM’s proposed Tariff revision that sets the time period for a transmission developer to accept its designation as a designated entity for 60 days after receiving an executable DEA, effective July 16, 2018.
FERC on Wednesday dismissed a second request from Linden VFT to rehear its order denying reconsideration of cost allocations for several PJM cross-seams projects (ER18-614).
The commission said Linden just rehashed its original rehearing request. The company also can’t offer new arguments unless the order it’s protesting changed the outcome of the proceeding, it said.
“The commission has explained that the successive rehearing of an order on rehearing lies only when the order on rehearing modifies the original order’s result in a manner that gives rise to a wholly new objection,” FERC wrote. “If it were otherwise, the commission would be faced with countless successive requests for rehearing as parties raised argument after argument, in search of a winner.”
| MISO
In June, the commission reaffirmed a July 2018 order that directed PJM and its transmission owners to submit compliance filings regarding cost responsibility assignments for four targeted market efficiency projects (TMEPs) with MISO.
In that order, Linden and Hudson Transmission Partners, each of which operates merchant lines into New York City and had recently converted its firm transmission withdrawal rights to non-firm, were ordered to partially pay for TMEPs b2971, b2973, b2974 and b2975 after FERC said existing Tariff language indicated the congestion benefits accruing to the lines justified subsequent cost responsibility. (See FERC Rejects PJM TMEP Rehearing Requests.) PJM TOs then submitted a compliance filing clarifying that TMEP allocations would be assigned to merchant facilities in the future too.
The New York Power Authority joined with Hudson and Linden in opposing the order, arguing that the Tariff “limits all cost allocations … based on their actual firm transmission withdrawal rights.”
In its second rehearing request submitted in July, Linden alone argued that TMEPs are a subset of required transmission enhancements, which carry associated charges that are “not to exceed the firm transmission withdrawal rights specified in the applicable interconnection service agreement.”
Linden also said FERC gave it no notice that it would impose costs once the merchant TO dropped the rights and argued that assigning the company cost responsibility for TMEPs from which it does not benefit conflicts with the commission’s cost-causation principle.
Texas power industry stakeholders grilled a member of NERC’s Board of Trustees during the Texas Reliability Entity’s quarterly meetings Tuesday.
Rob Manning, in just his second year on NERC’s board, was a special guest during Texas RE’s Members Representative Committee (MRC) and Board of Directors meetings in Austin, Texas. When conversation during the MRC meeting turned to NERC’s proposed merger of three technical committees, stakeholders took advantage of the opportunity to ensure ERCOT has enough of a voice before the agency. (See NERC Board Hears Debate over Committee Reorg.)
“I think it’s important, because ERCOT is very small. [It] doesn’t have the voting strength they do in the East and West,” said DeAnn Walker, chair of the Texas Public Utility Commission and a Texas RE director. “I’ll make every effort to be louder about it, because I have that capability. Maybe the reason we don’t sound loud to NERC is because we don’t have the problems they do in the East and [Western Electricity Coordinating Council].”
MRC Chair Liz Jones, an attorney for Oncor, said the composition of a working group to create a new Reliability and Security Council is “inherently biased to the East.”
“It’s not an issue to be remedied at an ad hoc committee level,” she said. “It’s an issue to be resolved at the NERC board.”
“Does it have to be written down, or can we agree?” Manning asked.
“It may be the lawyer in me, but words don’t last very long when they’re only spoken,” Jones replied.
Texas RE CEO W. Lane Lanford (left) and Director Lori Cobos, chief executive of the Texas Office of Public Utility Counsel | Texas RE
Manning said NERC wouldn’t get anything accomplished if it opened the decision-making to “everybody,” but he promised to share Jones’ concerns with the NERC working group.
“Once we come up with a plan and a process, we’ll put it out there for discussion,” he said.
“Everyone thinks they need to help us,” Walker said. “If they want to help us, they can let us be a part of the makeup of it.”
ERCOT spokesperson Leslie Sopko told ERO Insider that the grid operator is represented on several NERC committees. CEO Bill Magness is one of three ISO/RTO members of NERC’s Member Representatives Committee.
“Should changes occur to the existing NERC committee structure, ERCOT Inc., as well as market participants and stakeholders, would like to ensure the ERCOT region continues to be well represented,” Sopko said.
During the afternoon’s board meeting, Chair Fred Day ribbed Manning in announcing his presence as a “special guest.”
“After the MRC meeting, he feels that much more special,” Day said.
“The ERO machine is just the right thing we need to maintain reliability in North America,” Manning said. “It works. It works because of folks like you, keeping the train on the track and working properly.”
Human Error Causes 50% of Misoperations
Curtis Crews, Texas RE’s director of compliance assessments, briefed the board on the July 13 power outage in New York City, saying, “I don’t want anyone in this room to think it couldn’t happen here.”
MRC Chair Liz Jones (left) and Texas RE Director Curt Brockmann. | Texas RE
Pointing to Consolidated Edison’s recent explanation that the outage was caused by a misoperation on the distribution side, Crews said it appears there might not have been a violation of NERC standards. “Misoperation is not necessarily a violation,” he said.
Crews said the three largest causes of NERC misoperations last year were incorrect settings and design errors, relay failures and malfunctions, and communication failures. NERC has reported the same top three causes going back to 2014.
“Things happen out there,” he said, noting human error is responsible for about half of misoperations. “That human out there wiring to the wrong sensor.”
BP’s Ashby to Join Board of Directors
The board’s Nominating Committee said it would nominate former BP America Executive Vice President Crystal Ashby to one of four independent director positions. Ashby, who was last responsible for the company’s government and public affairs, will replace John Coughlin when his term expires at the end of the year.
The committee will also re-nominate Delores Etter to her independent position, effective Jan. 1, 2020. Etter and Ashby’s elections will be held in September.
The directors also approved revisions to the MRC election procedures for the Cooperative, Load Serving and Marketing, and Transmission and Distribution sectors, mirroring changes made by the Generation sector earlier this year. The changes address situations where there is a single vacancy for a sector’s primary representative to the MRC and remove language requiring a quorum during each round of balloting.
Pat Wood to Highlight Annual Meeting
Former FERC Chairman Pat Wood III will be the guest speaker at Texas RE’s annual membership meeting, to be held Dec. 11 at the organization’s conference center.
Wood also chaired the Texas PUC for six years. He has his own energy infrastructure development company, Wood3 Resources, and serves on three corporate boards: Dynegy, SunPower and Quanta Services.
Texas RE Hosts Japanese Professional
Kenta Takahashi, an associate director in the Japanese Ministry of Economy, Trade and Industry’s Space Industry Office, joined Manning as a special guest during Tuesday’s meetings. Takahashi is part of the Global Government-to-Government Partnership, a professional exchange program administered by the U.S. State Department in cooperation with Meridian International Center.
