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.”
PORTLAND, Ore. — For years after CAISO rolled out the Western Energy Imbalance Market in 2014, Avista took a wait-and-see approach to joining the effort to bring comprehensive real-time trading to the West.
Once the Northwest Power Pool scrapped its work on a competing regional market initiative in 2016, Avista “went into monitoring mode,” the utility’s director of power supply, Scott Kinney, told the EIM’s Regional Issues Forum at Bonneville Power Administration headquarters Tuesday.
“The needs and risks that were driving other utilities to join — we just didn’t see those same needs and risks ourselves,” Kinney said.
Hydroelectric resources currently comprise about 50% of Avista’s generation, while other renewables make up only 4%, providing the utility with ample flexibility to firm up its small wind portfolio. That meant it “didn’t have a driver from that perspective,” Kinney said.
“We had done some assessments around costs and benefits, and the economics at that time just weren’t compelling enough for us to join, so we continued to just engage,” he said.
That engagement included being “heavily involved” in the public meetings around the EIM and performing “outreach” to learn from the market’s existing participants. Avista also became a CAISO scheduling coordinator in 2016, allowing it to trade in that market.
But in late April, the Spokane, Wash.-based utility was finally compelled to commit to the EIM in response to a series of “drivers and risks” taking shape in the Pacific Northwest, Kinney said. (See Cold Forces NW to Dip More Deeply into EIM as Avista Joins.)
What changed?
“We started to see some market liquidity concerns in the summer of 2018. We had several days and several hours in those days where it was really difficult to find a counterparty in the near term,” Kinney said, adding it was the first time the utility experienced that problem.
“That had a lot to do with the current EIM participants having to meet their ramping and resource sufficiency tests, so they weren’t willing to do business with those nonparticipants during the stress times. That started to show as a possible risk for us,” he said.
Avista also faced the prospect of further isolation, with neighboring utility NorthWestern Energy last year agreeing to join the EIM, and BPA — by far the largest transmission provider in the Northwest — advancing toward a commitment. (See BPA Marches Toward EIM Membership.) Avista’s other neighboring balancing authorities, Idaho Power and PacifiCorp, already participate in the market.
“That meant that basically all of our neighboring utilities were going to be in the market, and so this liquidity risk really became a concern,” Kinney said.
Kinney also noted that Avista is anticipating a surge of new renewables coming into its BA area, with wind and solar comprising all of the nearly 1,100 MW of proposed generation in its interconnection queue — a “fair amount” of that being small projects falling under the Public Utility Regulatory Policies Act.
“We see that definitely there’s that risk for additional renewables integrating into our BA, and as others have seen who are participating in the market, there’s a lot of benefit to help balance those renewables and bring down that cost to integrate,” he said.
Avista has also signed a power purchase agreement to next year bring on 145 MW of capacity from the Rattlesnake Wind project in Central Washington and recently issued a PPA for additional renewables.
“Another thing for us is we did recently issue our own clean energy goals of being 100% clean by 2045 and being carbon neutral by 2027 … so that will probably drive some additional renewable integration into our system,” Kinney said.
Avista is also anticipating the future impact of state policies, including the likely expansion of cap-and-trade in the West. Kinney pointed to Washington’s recent passage of Senate Bill 5116, which bars the use of coal-fired generation by 2025 and requires the state’s utilities to be emissions-free by 2045. Coal currently accounts for 9% or Avista’s generation.
Cost of Joining vs. not Joining
But Avista’s decision to join the EIM may have been sealed by the economics.
“We’ve been monitoring how the market’s been operating and seeing there’s significantly more benefits being achieved by participants than what was anticipated through studies. We think the cost-benefit ratio is starting to change based on just the maturity of the market,” Kinney said.
And the utility foresaw increasing downsides to not participating.
“Not only the liquidity, but the higher dispatch costs for us if we aren’t a participant,” Kinney said, noting that Avista expects fewer market resources to be available for the utility to perform its own grid optimization.
“As more and more entities join the market, there’s less counterparties to do business with.”
Jennifer Gardner, a senior attorney with Western Resource Associates, asked whether Kinney could pinpoint either the liquidity or the renewable integration issue as a bigger factor in Avista’s decision to join the EIM.
“I think it’s probably that they’re equal. The liquidity risks and concerns that we started to see last summer happened at about the same time we saw significant upturn in interconnection requests in our transmission queue,” Kinney said. “I think since they both kind of happened together, it really made that decision for us probably easier, because we had several drivers.”
Avista estimates it will earn $3.5 million to $9.2 million in annual net benefits from participating in the EIM. It expects to incur about $21 million in start-up costs to join the market, with technology expenses — largely software — accounting for about half. Ongoing expenses are estimated at $3.5 million to $4 million annually, mostly for new staff. The utility will bring on 12 new full-time equivalent employees to manage its EIM efforts.
“The focus that we’ve got going on right now is change management. We’ve heard from those we’ve visited [that] that’s a big component of this project, so we’ve taken that advice seriously, and we’re really working on training and staffing,” Kinney said.
RIF Chair Therese Hampton, executive director of the Public Generating Pool, asked whether Avista is still exploring how its transmission assets will participate in the EIM, including the potential for “donating” transfer capacity to the market.
“We haven’t determined it yet. Still to come,” Kinney said.
Kinney said Avista hopes to secure FERC approval by next April to join the EIM. It is slated to commence participation in the market in April 2021.
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.
An electric industry-funded report on high-altitude electromagnetic pulses (HEMPs) underestimated the risks the grid faces and should not be used as the basis for mitigation, according to a critique released this week by a little-known group with ties to Maxwell Air Force Base.
In April, the Electric Power Research Institute (EPRI) released a study that concluded a HEMP caused by a nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers fear. (See EMP Task Force Looks at Black Start, Nukes.)
Example of the area affected by E1 EMP resulting from a high-altitude nuclear explosion | Electric Power Research Institute
A group calling itself the Electromagnetic Defense Task Force (EDTF) said almost 200 of its members — “military, government, academic and private industry experts in various areas of electromagnetic defense” — produced a critique of the EPRI report and concluded that relying on it would not address “remaining vulnerabilities impacting large power transformers, generating equipment, communication systems, data systems and microgrids designed for emergency backup power.”
“If U.S. government policymakers rely upon the methodology and conclusions of the EPRI report, effective high-altitude EMP protections will not be implemented, jeopardizing security of the U.S. electric grid and other interdependent infrastructures,” the group said in its 20-page report.
Randy Horton, EPRI’s EMP project manager and one of the authors of the April report, defended the work Wednesday. “EPRI stands behind our EMP research results and welcomes technical debates that are supported by science, facts and data,” he said in a statement. “Our conclusions were reached after three years of extensive laboratory testing and analysis of potential EMP impacts on the electric transmission system.”
Maps of the instantaneous geoelectric field magnitude of an E3 EMP at 20, 40 and 100 seconds | Electric Power Research Institute
An EPRI spokesman declined to elaborate or respond to specific criticisms, saying, “I think Randy’s quote lays out a good basis for further discussion.”
FERC declined to comment, and NERC and the Edison Electric Institute did not respond to requests for comment. Scott Backhaus, the Department of Homeland Security’s coordinator for EMP impacts on critical infrastructure, told ERO Insider on Thursday he is working on a response but that it is not complete.
EPRI’s report called for mitigation to protect the grid from the impacts of E-1 pulses — the first “hazard field” caused by an EMP, which lasts for about 2.5 nanoseconds. The second impact, an E2 EMP, lasts up to 10 milliseconds. The last hazard field, an E3, is marked by a very low frequency pulse that can last for hundreds of seconds. The event would be like a severe — albeit much shorter — geomagnetic disturbance (GMD) caused by solar flares.
EPRI acknowledged that its research was limited and did not include generation and distribution, saying it intended additional research on those subjects.
Scenario Choices
But the task force said EPRI also erred by not using realistic, worst-case scenarios in its analysis.
“Despite having access to defense-conservative Department of Defense threat scenarios, EPRI used alternative Department of Energy scenarios that assume adversaries would detonate nuclear weapons at nonoptimal altitudes, when the optimal altitudes are available in the open literature,” the report says.
The task force said a burst height of 75 km would produce the strongest E1 field strengths, but that EPRI used a height of 200 km, lowering the peak E1 field strength by almost two-thirds. Similarly, EPRI did not use the 150-km optimal burst height for peak E3 field strengths, choosing instead a height of 400 km.
The Electromagnetic Defense Task Force said EPRI did not use the 150-km optimal burst height for peak E3 EMP field strengths, choosing instead a height of 400 km. | Electromagnetic Defense Task Force, Metatech Corp.
“The methodology and findings of the EPRI report are not only markedly dissimilar from previous EMP studies, but in many cases entirely opposed to more than 60 years of prior DOD, government and contractor research and findings on EMP, system effects and hardening,” it said.
Russian and Chinese scientists have published research that calculated E1 impacts at least twice as great as those used in EPRI’s study, it said. “By avoiding the use of data from declassified Soviet EMP tests on the realistic E3 threat level, EPRI was able to minimize numerical estimates of damaged grid equipment, including hard-to-replace high-voltage transformers.”
“EPRI also assumed latitudes and longitudes for its detonation scenarios that are nonoptimal for producing maximum HEMP fields in the Northern Hemisphere,” EDTF said. EPRI assumed the detonation would be over the center of the U.S., not on the most populated portions of the country or the areas with most of the electric generation, the critique said.
Optimistic ‘in the Extreme’
The report says the digital protective relays (DPRs) on which EPRI focused its E1 research are more resilient than other grid elements such as substation communications and that EPRI suggested the relays would have a higher survival rate than previous peer-reviewed studies have found.
EPRI’s assessment of E1 HEMP impacts on voltage stability found that about 21,500 line terminals would be affected. Of the affected relays, EPRI assumed 1% of them would cause simultaneous tripping, which it said would cause the system to experience “perturbation” but “remain stable.”
“The EPRI report does not explain EPRI’s methodology of choosing just 1% of these relays, nor does it explain how EPRI can assume that the entire system will ‘remain stable’ when these relays are randomly tripped,” EDTF said.
Critics say a burst height of 75 km would produce the strongest E1 EMP field strengths, but that a study by EPRI used a height of 200 km, lowering the peak field strength by almost two-thirds. | Electromagnetic Defense Task Force, Metatech Corp.
EPRI did not assess how the failure of DPRs to prevent bus and transformer overloads or protect against over- and under-frequency and over- and under-voltage conditions would affect the grid, EDTF said.
EPRI also assumed that attackers would deploy only a single nuclear weapon in a HEMP attack, ignoring the risk of multiple HEMPS, according to EDTF.
“Protective relay damage and associated line terminal loss from realistic HEMP scenarios could be far greater, especially with a multiple-bomb EMP attack. Relay malfunction during a HEMP attack would likely cause other electric grid systems to fail, resulting in large-scale cascading blackouts and widespread equipment damage. Notably, E1 effects on protective relays are likely to interrupt substation self-protection processes needed to interrupt E3 current flow through transformers,” EDTF said.
“An initial HEMP attack could render a number of relays inoperable, causing grid debilitation due to the loss of transformer isolation, fault protection, and islanding capabilities. Thus, a follow-on HEMP attack on a grid with a portion of damaged or disrupted DPRs would likely cause increased and catastrophic equipment damage from flashovers, uninterrupted overloads, faults and cascading events resulting in a wider-scale and longer-duration blackout. Also, a second HEMP attack after damaged DPRs are replaced could eliminate the ability to recover due to depletion of DPR spare inventories.”
The EDTF noted that “large-scale grid blackouts have occurred in the past from single-point failures, such as the Northeast Blackout of 2003, which was caused by overgrown trees contacting electric transmission lines.”
The blackout affected more than 70,000 MW of load, leaving 50 million people without electricity. “In contrast, EPRI’s report concludes that a HEMP attack on the same Eastern Interconnection would cause limited regional voltage collapses and affect roughly 40% of the electrical load lost in the 2003 blackout. Experience with cascading collapse in the Eastern Interconnection shows EPRI’s finding to be optimistic in the extreme.”
Authors’ Identity Shielded
EDTF said its critique was the work of attendees of the group’s second “summit” in May under “Chatham House Rules,” in which they contributed without attribution. “The experts who contributed to this specific document range from uniformed military personnel, to civil servants throughout a range of government agencies and various national laboratories, to internationally renowned and published engineers.”
The critique was circulated by the Foundation for Resilient Societies and published on the website of Over the Horizon, which describes itself as “a digital journal that brings together disparate perspectives to advance the conversation on the emerging security environment.”
Thomas Popik, president of the Foundation for Resilient Societies | Harvard Business School
Resilient Societies President Thomas S. Popik, a former Air Force captain who attended the EDTF summit, said in an interview that the critique “has a firm scientific basis.”
The EDTF published the names of more than 100 organizations it said were represented at the summit, including DHS, FERC, the Joint Chiefs of Staff, NASA and several units of the Air Force. The only individual named in the critique is Air Force Maj. David Stuckenberg, who did not respond to requests for comment.
The Air Force also did not respond to questions about its relationship with the EDTF. The task force has a webpage on the Maxwell Air Force Base website, and its 2018 report is published on the website of the base’s Air University and included in the Homeland Security Digital Library. The 2018 report lists as authors Stuckenberg, former Navy Secretary and CIA Director R. James Woolsey Jr., and Air Force Col. Douglas DeMaio, who gave a presentation to the NERC EMP Task Force in July. (See Air Force: US Must Take ‘Higher Ground’ in Space.)
Popik said he wasn’t certain if Resilient Societies is part of the EDTF. “I know that we were invited to the meeting, so that would imply we’re part of the task force, but the actual conditions for membership in the task force are… I think it would be best if you ask that question of Maj. Stuckenberg.”
Incentives and Motives
EDTF said it “operates on the military’s premise of planning for the reasonable upper-bound scenarios and validating results through real-world testing.” EDTF said EPRI’s report might dissuade transmission owners and operators from mitigating EMP risks or planning for post-HEMP grid restoration. “Some EDTF personnel working on HEMP-mitigation efforts alongside electric industry partners have lost both momentum and the interest of their industry partners,” it said.
Popik praised NERC for including him as the only non-industry member of its EMP Task Force. “That’s been an open and transparent process, which is coming to a solid proposal for a process to address the executive order,” he said. “It really is very important to distinguish the work of the EMP Task Force at NERC from the efforts of the Department of Homeland Security and EPRI and [the] Department of Energy in regard to this study of EMP effects.”
He cited DHS’ Backhaus, who told the NERC task force in June that they should “use physics and engineering to constrain our analysis” and avoid overestimating the risk. “EMP is one of many threats, so we need to develop our best estimate of risk from EMPs and GMDs to place them in context of the other risks that the bulk system faces,” Backhaus said. (See EMP Task Force Takes ‘First Bite of the Elephant’.)
Popik said utilities “without a ready means for cost recovery [and] faced with the potential of a very expensive grid security standard … would have ample incentive to make sure the EMP threat was not — you can put this in quotes — ‘overestimated.’”
“… When you try and use the so-called best available science and physics and engineering to … avoid a conclusion that would be in conflict with a regulatory agenda, that’s not good science.”
PORTLAND, Ore. — Just as the Western Energy Imbalance Market’s Governing Body was poised to fill the empty space within its ranks, another vacancy immediately popped up.
The EIM Governing Body voted Wednesday to fill the seat vacated by one of its original members — but not before revealing that its newest member had also resigned his position the night before.
Member Travis Kavulla was notably — but not surprisingly — absent from the body’s monthly meeting in downtown Portland. After all, his wife had just recently given birth, Governing Body Chair Carl Linvill told a hotel conference room packed with regional stakeholders.
But Linvill then delivered unexpected news: “We received a letter from Travis that he has been offered an opportunity which he plans to accept, which will mean that he will no longer serve — effective immediately — on the EIM Governing Body.”
Kavulla, a former member of the Montana Public Service Commission, was elected to the Governing Body in June 2018 after being term-limited out of his commission seat. (See CAISO Board Approves More CRR Auction Changes.) He currently serves as the energy director for R Street Institute, a D.C.-based think-tank that advocates for “free markets and limited, effective government.”
Kavulla, who joined R Street last October, shared his resignation letter to the EIM but told RTO Insider, “I’m not in a position to make any announcements at the moment.” The letter said he had accepted a job with a “market participant” and would be starting work next month.
Kavulla’s term as a Governing Body member was set to expire in 2021. His resignation marks the second premature departure from the body since April, when Kristine Schmidt, the group’s inaugural chair, vacated her seat to join the board of embattled PG&E Corp. Allowing Schmidt to hold both positions would have presented a conflict of interest, then-Chair Valerie Fong said at the time. (See PG&E Departure Leaves EIM Vacancy.)
To replace Schmidt, the body on Wednesday confirmed Anita Decker, a familiar name to industry participants in the Pacific Northwest.
From 2014 until earlier this year, Decker served as executive director of the Northwest Public Power Association, an advocacy group representing about 150 community-owned electric utilities in nine Western states and British Columbia. She was chief operating officer of the Bonneville Power Administration from 2007 to 2014, when she also performed a stint as acting administrator for the Western Area Power Administration. Prior to that, Decker had a 27-year career with PacifiCorp, where she rose to the position of a business unit vice president, having worked for the utility in Oregon, Wyoming and Utah.
“We had an incredibly qualified pool of candidates this year,” said EIM Nominating Committee Chair Jennifer Gardner, a senior attorney with Western Resource Advocates. Gardner described the deliberations leading to the nomination of Decker as being “consensus-driven,” bringing together representatives from the EIM’s various sectors in a “time-intensive process.” In addition to seeking someone with subject matter expertise, the committee put a high priority on experience in the West, with a focus on geographic diversity, she said.
“It was a difficult decision because we had some very qualified candidates, which I think speaks well to the Energy Imbalance Market in general,” member John Prescott said. “There’s a lot of interest out there from very qualified people that would like to serve on this Governing Body.”
Decker’s term will run from Sept. 1 until June 30, 2020, when Schmidt’s term was set to expire.
Not ‘Discretionary’
After the Governing Body’s three remaining members voted unanimously to confirm Decker, Fong quickly posed the question of whether the body should prompt the Nominating Committee to begin searching for Kavulla’s replacement.
“That’s technically not on the agenda,” said CAISO Senior Counsel Greg Fisher, who was sitting with the EIM leaders.
“Is it actually an action item? It’s just a recommendation that they move forward,” Fong said.
Fisher advised against proceeding so informally, saying the matter was not “discretionary” for the Governing Body, given the amount of time left before the expiration of Kavulla’s term, which leaves uncertain the process for replacing him.
“So, we’ll wait to hear back with a formal opinion from you on that and we’ll proceed,” Linvill confirmed.
Speaking to RTO Insider about Kavulla’s resignation after the meeting, Linvill said, “We’ll miss his contributions. He was an important member of the Governing Body — and we’ll leave it to him to announce what his plans are.”
“Travis is a big loss. He brings a wealth of expertise to the Governing Body,” Gardner said. But having recently vetted the list of industry hopefuls seeking to take over for Schmidt, she was optimistic about finding yet another replacement.
“I think a lot of folks have an interest in seeing the EIM succeed. I have no doubt we’ll have an excellent pool of candidates.”
