A new MISO task team this month is seeking stakeholder suggestions to improve the process for choosing the RTO’s board members.
The newly established Board Qualification Task Team is exploring whether to extend to state regulators a one-year “cooling-off” period required of other industry participants before they can apply to serve on MISO’s Board of Directors. The group will also examine other aspects of the board’s makeup and required qualifications.
MISO’s Advisory Committee created the task team in March following last year’s board elections, in which Nancy Lange, then chair of the Minnesota Public Utilities Commission, was nominated to fill a seat on the board without observing the yearlong moratorium. (See New Task Team to Review MISO Board Rules.)
The task team could recommend that the board amend its Transmission Owners Agreement bylaws to adopt improvements, which must be approved by FERC. Neither MISO nor its board is under any obligation to act on Advisory Committee recommendations.
During its first conference call Tuesday, the small task team decided it will issue a public document should it identify any worthwhile recommendations for changing the board selection process. Those recommendations would be reviewed and possibly taken up by the board’s Corporate Governance and Strategic Planning Committee, led by Director Theresa Wise.
However, the task team decided against drafting a white paper on board selection improvements, with Chair Mark Volpe saying such documents should be reserved for technical matters.
In addition to taking stakeholder recommendations, the new team will also review the composition of board nominating committees at other RTOs as possible examples for changing MISO’s Nominating Committee, which vets and selects board candidates for stakeholder voting.
The Nominating Committee currently holds slots for two stakeholders and three directors, prompting some Advisory Committee members to criticize its lack of stakeholder diversity and suggest that MISO should ensure broader representation of stakeholder sectors in selecting board candidates.
Volpe said stakeholders might prefer “broadened and more inclusive” representation and suggested that MISO could add stakeholder seats or rotate sector representation year to year. Task team members may also recommend that directors be required to observe an additional cooling-off period before joining a MISO-related organization after having served on the board.
Volpe asked task team members to come up with draft recommendations in time for the group’s May 28 conference call.
A bipartisan U.S. Senate bill intended to speed development of the next generation of nuclear reactors appears to have broad support, but passage may hinge on the fate of several other bills in the chamber that would address the long lingering issue of building a permanent repository for spent nuclear fuel.
The Nuclear Energy Leadership Act (NELA) (S.903), reintroduced by Sen. Lisa Murkowski (R-Alaska) on March 27, is co-sponsored by 17 senators — nine Republican, eight Democratic — including presidential candidate Cory Booker (D-N.J.). The bill was first introduced in September, toward the end of the previous session of Congress, but the Senate took no action on it.
The bill would direct the Department of Energy to:
Enter into at least one long-term power purchase agreement (10 to 40 years) by the end of 2023 with a commercial nuclear reactor that was licensed by the Nuclear Regulatory Commission after 2018, giving special consideration to “first-of-a-kind or early deployment nuclear technologies”;
Construct at least two advanced nuclear reactor demonstration projects by the end of 2025, and at least two more (but no more than five) by the end of 2035;
Submit a 10-year strategic plan to Congress within six months of the bill’s enactment detailing how the department would “advance the research and development of domestic advanced, affordable and clean nuclear energy”;
Construct a fast neutron-capable research facility for testing reactor components and fuel;
Establish a program within a year of enactment to make available high-assay, low-enriched uranium (HALEU) — uranium enriched 5 to 20% — for advanced nuclear reactors; and
Establish the University Nuclear Leadership Program, which would provide financial assistance for students studying, researching and developing advanced nuclear technologies.
At a Senate Energy and Natural Resources Committee hearing Tuesday, Chair Murkowski said the bill “is designed to reposition the United States as the undisputed world leader in advanced nuclear technology.” She touted it as part of the committee’s increasing focus on climate change. “If you’re seeking lower emissions, look no further than nuclear energy as part of that energy portfolio mix.”
The Senate Energy and Natural Resources Committee meets April 30 to consider the Nuclear Energy Leadership Act.
As USA Today reported in an article published the same day as the hearing, nuclear power’s appeal as an emissions-free source of electricity has begun to win over Democrats, historically opposed to nuclear expansion on environmental grounds.
“It’s imperative for the United States to lead the way on tackling the world’s climate crisis and that must include the development of clean and innovative technologies like next generation nuclear energy,” Booker said when NELA was reintroduced. “This bipartisan bill will spur development of demonstration projects at the Department of Energy, which could become an important source of carbon-free electricity generation.”
And as The New York Times reported the same day, Republicans are starting to cite climate change as a reason for their policies and priorities.
“Nuclear energy is an essential part of our energy portfolio. It is also critical to reducing carbon dioxide emissions,” Sen. John Barrasso (R-Wyo.), chair of the Senate Environment and Public Works Committee, said at a hearing Wednesday. “If we’re serious about addressing climate change, we must be serious about preserving and expanding nuclear energy use.”
A 36-year Debate
“Has the word ‘waste’ been mentioned in this conversation? I don’t think it has,” Sen. Angus King (I-Maine) said when it was his turn to speak at the ENR Committee hearing Tuesday. “I just met with a group of young people. They’re all for carbon-free energy; they’re excited. But they’re not excited about paying the price of our using electricity and leaving to them what to do with the waste. …
“That’s my problem with this bill. I’m not opposed to the technology of nuclear power. I’m definitely in favor of carbon-free power; I think it can be an enormous boon to our economy and our climate. But I just don’t know how we have this discussion and not talk about this really significant problem that isn’t being addressed, and I’m tired of passing burdens on to our children.”
King’s remarks kicked off a lengthy debate among the committee’s members, from which the hearing’s five witnesses, including Nuclear Energy Institute CEO Maria Korsnick, were left out. It was a microcosm of a debate the federal government has been having since President Ronald Reagan signed the Nuclear Waste Policy Act in 1983.
The law directed DOE to site and construct a permanent repository for spent nuclear fuel and other radioactive waste. But in 1987, Congress amended the law to designate Yucca Mountain in Nevada as the only site for storage. The state and the federal government have been battling over the law ever since.
Sen. Lisa Murkowski
Murkowski and Sen. Lamar Alexander (R-Tenn.), another co-sponsor of NELA, attempted to assuage the concerns of both King and Sen. Catherine Cortez Masto (D-Nev.), saying they, along with Sen. Dianne Feinstein (D-Calif.) were introducing legislation later that would solve the problem.
But the bill (S.1234) appears to be the same Nuclear Waste Administration Act that went nowhere in two previous sessions of Congress. It would create an independent agency to replace DOE as the manager of the nuclear waste program. The new agency would be directed to build a pilot storage facility to hold spent fuel from decommissioned nuclear power plants and emergency shipments from operating plants, and to build consolidated storage facilities for nonpriority spent fuel for utilities or defense-related waste for DOE on a temporary basis.
The agency would also have direct access to the Nuclear Waste Fund — which amassed more than $40 billion before fee collection was halted by the D.C. Circuit Court of Appeals in 2013 — rather than its use being subject to the always political appropriations process in Congress. The bill is based on recommendations from the Obama administration’s Blue Ribbon Commission on America’s Nuclear Future in 2012.
Cortez Masto was skeptical of the legislation at the hearing. The bill would not amend the Reagan-era law, which she said left Yucca Mountain as a possible site for the permanent repository.
The next day, at the Senate EPW Committee hearing, Cortez Masto appeared alongside her fellow Democratic senator from Nevada, Jacky Rosen, as witnesses testified against a separate bill drafted by Barrasso.
The Nuclear Waste Policy Amendments Act of 2019 is nearly identical to legislation passed by the House of Representatives last year 340-72 (when Republicans held the majority) but never taken up by the Senate. It would allow DOE to contract with private companies for interim storage sites, while Nevada is allowed to present its scientific case against Yucca Mountain in a legal proceeding.
“We can’t walk away from the law of the land,” Barrasso said Wednesday. “We can’t start over and let another 40 years pass to solve this challenge. The discussion draft before us today is a solution.”
More than 30 states are home to interim nuclear waste storage sites, most of them being decommissioned power plants. | Department of Energy
But Cortez Masto and Rosen said the choice of Yucca Mountain was arbitrary and not based on science. They pointed to Cortez Masto’s bill, the Nuclear Waste Informed Consent Act (S.649), which would require DOE to obtain permission from a permanent site’s state and local governments before using money from the Nuclear Waste Fund. Besides Rosen, the bill’s co-sponsors are all Democratic presidential candidates: Booker, Kamala Harris (Calif.), Kirsten Gillibrand (N.Y.), Amy Klobuchar (Minn.), Bernie Sanders (I-Vt.) and Elizabeth Warren (Mass.).
Barrasso’s bill also drew sharp rebuke from Nevada Gov. Steve Sisolak.
“I said in my State of the State address in January that not one ounce of nuclear waste will reach Yucca Mountain while I’m governor,” Sisolak wrote to Barrasso several days before the hearing. “I fully intend to keep my promise to the people of Nevada and fight against any attempts to restart the failed Yucca Mountain program.”
Maryland Public Service Commissioner Anthony O’Donnell, chair of the National Association of Regulatory Utility Commissioners’ subcommittee on nuclear waste disposal, appeared before the EPW Committee on Wednesday in support of most provisions in the bill, specifically the changes to the waste fund fee structure. DOE would not be allowed to begin recollecting fees until Yucca Mountain is fully approved and would have to prioritize spending money from the fund toward benefiting communities and education programs in Nevada.
O’Donnell said NARUC did not take a position on creating a new agency to manage the fund, as Murkowski’s bill would do, “but what is crucial is that we act soon so that the federal government does not age out its crucial scientific knowledge in these matters, and that’s what’s happening. I would implore you to do something quickly.”
“NARUC agrees with Sen. Murkowski’s sentiment that it is certainly time — past time, actually — to end the nation’s stalemate on nuclear waste,” spokeswoman Regina Davis said in an email Wednesday. “Today’s hearing was a positive first step.”
The Northeast Power Coordinating Council (NPCC) is projecting a summer peak demand of 103,548 MW in the week of July 28, a 0.6% reduction (589 MW) from last year, despite growth in Ontario.
NPCC is the NERC regional entity for New England, New York, Ontario, Québec, New Brunswick and Nova Scotia. | NERC
“This continues an almost decade-long trend of overall flat or declining peak demand forecast due to energy efficiency and conservation initiatives, as well as the significantly increasing role of behind-the-meter PV resources in New England and New York,” NPCC CEO Edward Schwerdt said in a May 2 press release announcing the summer Reliability Assessment.
With the addition of 2,855 MW of net new capacity since summer 2018, NPCC forecasts a minimum operable capacity margin (spare operable capacity less transfer capability limitations) of 12,545 MW (12.2%) for the summer.
NPCC is the NERC regional entity for New England, New York, Ontario, Québec, New Brunswick and Nova Scotia. The U.S. represents 46% of NPCC’s net energy for load with Canada accounting for 54%. NPCC represents about 70% of Canada’s electric demand.
While New England and New York often hit their summer peaks together because of the proximity of their load centers, “there is some potential” for Ontario’s summer peak to occur at the same time, the report said. “Ambient weather conditions remain the most important variable in forecasting peak demand during the summer months,” it said.
The report included regional snapshots of the changes in generation since summer 2018 and the projected peaks for this year:
New York added a net 127 MW, including 158 MW of wind, with 167 MW of coal generation retirements and 446 MW restored with the withdrawal of Selkirk 1 and 2’s mothball notice. NYISO projects a peak of 32,382 MW, a 522-MW drop from the summer 2018 forecast, because of state energy efficiency programs and the growth of BTM, including retail PV, combined heat and power, anaerobic digester gas, fuel cells and energy storage.
New England added a net of 568 MW, including the dual-fuel Bridgeport Harbor expansion (510 MW), Canal 3 (333 MW) and Medway Peaker (208 MW). Wind and solar generation increased by 135 MW. Entergy’s Pilgrim nuclear plant (680 MW), Massachusetts’ only nuclear unit, is expected to retire by June 1. ISO-NE’s forecast peak is 25,323 MW, 406 MW below last year’s projection. The RTO cited demand reductions from energy efficiency, load management, passive demand response, distributed generation and BTM PV.
Ontario’s generation increased by a net of 1,418 MW, including the Napanee gas-fired generator (985 MW), wind (375 MW), solar (98 MW) and hydro (16.4 MW). About 56 MW of gas-fired generation is retiring. Ontario’s Independent Electricity System Operator forecast a 103-MW increase in peak demand, to 22,105 MW. Conservation savings and distribution-connected generation are expected to partially offset increased demand from economic and population growth.
Québec and the Maritimes, both winter-peaking areas, will see a slight increase, with Québec adding 38 MW of biomass and losing 8 MW of other generation for a net change of 30 MW. Québec is forecasting a 471-MW increase in the peak, to 21,005 MW. The Maritimes expect a peak of 3,255 MW, up 20 MW from last summer.
Entergy’s 680-MW Pilgrim nuclear plant will shut down by June 1. | Entergy
Transmission, Pipelines
Although NPCC expects spare operable capacity (capacity above reserve requirements) of 19,884 MW during its coincident peak the week of July 28, limited transfer capability from Québec and the Maritimes will reduce the amount available to the rest of its territory to 14,954 MW.
Since last summer, NYISO has added the Cricket Valley 345-kV substation — on the Pleasant Valley-Long Mountain 345-kV tie line with New England — to serve the new Cricket Valley combined cycle generating station expected to begin operation after the summer.
Unlike in winter, ISO-NE does not expect natural gas deliverability issues to affect generation. The RTO also can call on 340 MW of active demand resources on the peak.
The RE said it foresees “no significant likelihood” of implementing operating procedures for resource shortages (voltage reductions, and reductions of 10- and 30-minute reserves) during the summer for the expected peak load, a forecast based on the probability-weighted average of seven load levels simulated.
NPCC said operating procedures are available if needed to maintain reliability during severe system conditions and extreme heat simultaneously. The assessment also considered scenarios with extended unit maintenance; reductions in DR; reductions in the ability to import power from neighboring regions; transmission constraints; and widespread and prolonged heat waves with high humidity.
Geomagnetic Disturbances
The RE, which has had operating procedures since 1989 to respond to geomagnetically induced currents (GICs) from solar storms, said it expects “quiet levels” of solar activity for the summer.
“The solar coronal regions are stabilizing as the next solar minimum approaches, with fewer coronal holes and fewer extensions to lower solar latitudes that can sweep higher velocity solar winds toward the Earth,” NPCC said, while acknowledging that sunspot formations are difficult to predict.
While “these rogue events can and do occur,” the report said, “the odds of such an event during any particular week of the coming summer are very low.”
Pacific Northwest members reaped an unusually large chunk of the Western Energy Imbalance Market’s $85.38 million in first-quarter benefits, according to a report from market operator CAISO.
Necessity was likely the reason. Evidence suggests Northwest utilities were leaning more heavily on the EIM last quarter to keep up with demand.
Among Northwest participants, PacifiCorp secured the largest portion of benefits by far at $23.76 million, compared with $10.5 million a year earlier. (See CAISO, PacifiCorp Gain Most EIM Q1 Benefits.) The EIM defines benefits as cost savings and the use of surplus renewable energy.
Portland General Electric took in $11.74 million (compared with $3.64 million), while Puget Sound Energy earned $7.21 million (compared with $3.01 million).
Idaho Power and Powerex, which did not begin transacting in the market until the second quarter of 2018, brought home $8.45 million and $7.23 million in benefits, respectively.
Further south, CAISO realized $13.08 million in benefits, followed by Arizona Public Service at $8.20 million and NV Energy at $5.71 million.
The EIM’s total quarterly benefits were the second highest on record, up nearly 103% from a year earlier, in part “driven by increased transfers compounded with higher energy prices” in February and March, CAISO said in its report.
First quarter 2019 benefits in millions USD by month | CAISO
But the CAISO report only hints at how steeply prices rose during the quarter — and where those gains were concentrated.
According to a report released earlier this month by Northwest industry consultant Randy Hardy, a former head of the Bonneville Power Administration, bilateral March 1 day-ahead peak prices at the Mid-Columbia trading hub broke $900/MWh, driven by natural gas prices of $160/MMBtu. (By comparison, CAISO day-ahead prices that day ranged from about $38/MWh to $82/MWh, holding that high for only a one evening interval.)
“These prices were driven by a number of factors including cold temperatures, a prolonged cold period prior to March 1 resulting in depletion of hydro generation and natural gas in storage, a maintenance outage on the DC intertie [linking the Northwest with Southern California] and limitations in supplies of natural gas impacting the ability of some natural gas generation to operate,” Hardy said.
Hardy also noted the high prices occurred despite “all the soon-to-be-retired [Pacific Northwest] coal plants operating at maximum capacity.”
Higher prices and tight regional supplies drove Northwest load-serving entities into the short-term market, including the EIM. That development was a boon for power producers in CAISO, which saw net exports surge from 120,364 MWh in January to 449,417 MWh in March — a 38% jump over March 2018. First-quarter exports from CAISO totaled 724,239 MWh, up 19% from the same period a year ago.
The figures also suggest the deepening of a longer-term trend attending the arrival of spring: CAISO becomes a net exporter of energy as increasing solar output coincides with lower electricity demand stemming from mild weather in California.
CAISO said the first-quarter energy transfers allowed it to avoid the curtailment of 52,254 MWh of renewable energy, down more than 20% from last year but in line with the first-quarter 2017 figure. The avoided renewable curtailments translated into the displacement of 22,365 metric tons of carbon dioxide, based on an assumed default emissions rate of 0.428 metric tons CO2/MWh from other sources of generation. The ISO estimates, by avoiding curtailments, the EIM has helped displace 346,649 tons of CO2 since 2015.
The EIM has yielded $650.26 million in benefits for its members since being launched with PacifiCorp as its first member in November 2014, CAISO estimates.
Estimated wheel through transfers in Q1 2019 | CAISO
EIM Wins New Member in Avista
The EIM is poised to spread into yet another corner of the Northwest, with the announcement last week that Spokane, Wash.-based Avista has signed up to join the market beginning in April 2022. The utility serves about 340,000 electric customers in western Washington and northern Idaho and operates about 2,750 miles of transmission.
Avista also owns 1,042 MW of hydroelectric generation and 1,875 MW of thermal capacity, 222 MW of which is generated by units of the coal-fired Colstrip plant in Montana, which could close as early as 2025 under pressure from Washington legislators.
“Joining the EIM is another milestone in our effort to efficiently use carbon-free renewable resources throughout the region while helping maintain reliability and keeping power affordable for our customers,” Jason Thackston, Avista senior vice president for energy resources, said in a statement.
The Sacramento Municipal Utility District began participating in the EIM in April, while the Los Angeles Department of Water and Power, Arizona’s Salt River Project and Seattle City Light are scheduled to begin participating in April 2020.
New Mexico’s PNM had anticipated joining in 2021 but may face a delayed entry as it works with state regulators to settle issues around recovering costs related to participation. (See PNM Bid to JoinWestern EIM Gets Approved in Part.)
Pennsylvania Democrats want to nearly quadruple subsidies for renewable resources in the first tier of the state’s 2004 Alternative Energy Portfolio Standards (AEPS) mandate, hoping the expansion will push the state closer to its looming carbon-reduction goals.
Rep. Carolyn Comitta (D) and Sen. Art Haywood (D) sponsored companion proposals — House Bill 1195 and Senate Bill 600 — on April 26 that they say would “modernize” the once forward-looking AEPS and bring it in line with neighboring states like Maryland and New Jersey, where lawmakers have passed ambitious energy plans to phase out fossil fuels over the next 30 years. The bills would boost the usage requirement of Tier 1 renewable resources in the AEPS from 8% to 30% by 2030. The plans also dedicate 7.5% of that target to in-state grid-scale solar and 2.5% to distributed solar generation and asks the Public Utility Commission to study the benefits of an energy storage program.
State Sen. Art Haywood, flanked by fellow Democrats, speaks at a rally April 10 about his bill to expand renewable subsidies in the Alternative Energy Portfolio Standards (AEPS) law. | Sen. Art Haywood
“It is long overdue for Pennsylvania to implement new clean energy goals to create good jobs, cut pollution and ensure we are a sustainable and prosperous state for the future of everyone,” Haywood said during a rally April 10 with fellow co-sponsors from the bicameral Pennsylvania Climate Caucus.
“The fierce and immediate urgency of climate change requires a fierce and immediate response,” said state Rep. Steve McCarter (D). “Thirty by ’30 is an excellent immediate goal. It’s reasonable and achievable. It creates jobs in Pennsylvania. And, most importantly, it sets the stage for the much tougher work to come.”
The legislation has 33 sponsors in the House, where Republicans hold a 109-93 edge, and 18 in the Senate, where the GOP holds a 26-22 margin. Only one of the co-sponsors, Sen. Thomas H. Killion, is a Republican, but Killion is vice chair of the Consumer Protection & Professional Licensure Committee, which is also considering subsidies for the state’s nuclear generators.
Gov. Tom Wolf, a Democrat, said he supports the proposals as in line with his own environmental policies, including his decision to join the U.S. Climate Alliance announced on Monday. (See Pennsylvania Joins U.S. Climate Alliance.)
In January, Wolf signed an executive order committing the state to reducing its greenhouse gas emissions by 26% over the next seven years compared to 2005 levels and setting an additional target of 80% by 2050. On Monday, the administration released a third update to the state’s decade-old Climate Action Plan that identified 15 steps toward reducing carbon emissions by 21% by 2025, including investing in renewable energy resources, boosting the use of electric vehicles and incentivizing green building projects.
As of 2017, Pennsylvania ranks as the second largest producer of natural gas nationwide and third for coal, according to the U.S. Energy Information Administration. Just 4.5% of the state’s net electric generation comes from renewable energy resources — well short of the 18% goal by 2021 set in the AEPS.
Critics argue forcing electric suppliers to buy more power from renewable sources will set off a cascade of unintended consequences that threaten the wholesale market.
“In the words of the Independent Market Monitor, subsidies are contagious,” said Glen Thomas, president of GT Power Group. “Subsidies distort markets as policymakers attempt to favor certain resources at the expense of others.”
Thomas, an outspoken fan of deregulated electricity markets, said subsidies interfere with consumer choice. He has criticized plans to add nuclear energy to the AEPS during hearings before the House Consumer Affairs Committee and the Senate Consumer Protection and Professional Licensure Committee.
“As the cost of renewable energy continues to drop, more and more consumers will voluntarily switch to these resources and power producers will respond to the needs and wants of consumers,” he said. “That’s how markets work, and they should be allowed to do so free of mandates on consumers.”
Comitta said on Tuesday she remains open to adding nuclear energy to the AEPS. So far, the House Consumer Affairs Committee has not yet scheduled any hearings on her plan, though discussions continue on nuclear subsidies. (See NukeTalks Continue in Pa. Assembly.)
The Senate Consumer Protection and Professional Licensure Committee has scheduled a joint hearing on updating the AEPS for May 1.
A utility-funded study has concluded a high-altitude nuclear explosion could cause a multi-state electric outage but not the nationwide, months-long blackout some observers have warned of.
The findings are contained in a three-year study by the Electric Power Research Institute on the impact of a high-altitude electromagnetic pulse (HEMP).
Such an attack could result in a multi-state outage, EPRI acknowledged Tuesday, but it said shielded cables, fiber optics, surge protection, enhanced grounding and modifications to substation control houses could reduce the threat.
Although the report did not provide any cost estimates for the mitigation plans, project manager Randy Horton said through an EPRI spokesman that costs could range from $500,000 to $2 million per substation.
EPRI said it conducted the report “because of the extreme differences in views among experts regarding the potential impacts” of a HEMP caused by the detonation of a nuclear weapon 30 km or more above the earth’s surface.
Under the scenarios evaluated by EPRI, “impacts such as regional disruption or damage to DPRs [digital protective relays] and regional voltage collapse could be experienced,” the researchers said. “Research findings do not support the notion of blackouts encompassing the contiguous United States and lasting for many months to years.”
The report comes little more than a month after President Trump signed an executive order requiring the government to coordinate its efforts on EMPs. The order directs the secretary of Homeland Security and other officials to identify the critical functions and infrastructure systems that could be disrupted by EMPs within 90 days.
Generation not Studied
EPRI’s report, which incorporated research from the Department of Energy’s national labs and collaboration with the Defense Threat Reduction Agency and the Electricity Subsector Coordinating Council (ESCC), was funded by some 60 utilities.
It focused on the potential impacts of a HEMP attack on the transmission system and how overhead transmission lines, substations and switchyards could be hardened. It did not look at the potential effects of HEMP attacks on “generation facilities, nuclear reactors, distribution systems, loads or other key elements or infrastructure sectors,” EPRI said, recommending those subjects for further research.
The study looked at the impacts of three “hazard fields” that can be produced by a nuclear detonation, based on the weapon’s yield and the height of the explosion above the surface:
The early time component (E1 EMP), an intense, short-duration electromagnetic pulse characterized by a “rise time” of 2.5 nanoseconds and amplitude of up to 50 kV/meter on the ground;
The intermediate time component (E2 EMP), an extension of the E1 EMP with an electric field pulse amplitude of about of 0.1 kV/m and a length of one microsecond to about ten milliseconds;
The late time component (E3 EMP), a very low frequency (below 1 Hz) pulse with amplitude of tens of V/km lasting from one second to hundreds of seconds. The event would be similar to severe geomagnetic disturbances (GMDs) caused by solar flares, which can last several days.
The area exposed to E1 EMP fields would be limited by the line of sight from the weapon to the horizon; a detonation at 200 km could affect a circular area of 3 million square miles — most of the continental U.S. and portions of Canada and Mexico — albeit at different levels of severity. The pulse can “couple” to overhead lines and cables, exposing connected equipment to voltage and current surges, potentially damaging DPRs, communication systems and supervisory control and data acquisition (SCADA) systems.
EPRI said E1 EMPs would cause “moderate” damage based on modeling from Los Alamos National Laboratory of up to 25 kV/m at the most severe location on the ground. Increasing the pulse to 50 kV/m resulted in “more severe” damage.
Example of the area affected by E1 EMP resulting from a high-altitude nuclear explosion | Electric Power Research Institute
“Based on the assumptions made in the assessments, it was estimated that approximately 5% of the transmission line terminals in a given interconnection could have a DPR that is disrupted or damaged by the nominal E1 EMP environment that was simulated, whereas approximately 15% could be impacted by the scaled (up to 50 kV/m at the most severe location on the ground) E1 EMP environment,” the report said.
Although its testing did not indicate E1 EMP impacts alone would cause immediate, interconnection-scale disruptions, “this finding is not conclusive due to uncertainties regarding how damaged DPRs might respond during an actual event … or how potential E1 EMP damage to generator controls and other systems such as automatic generation control (AGC), not included as a part of this study, might affect the long-term operation of the grid,” EPRI said.
Mitigation Measures
The researchers said their modeling and laboratory testing of DPRs indicated design changes could provide adequate mitigation up to 50 kV/m:
Shielded control and signal cables with proper grounding;
Low-voltage surge protection devices or filters;
Use of fiber optics-based protection and control systems;
Modifications to substation control houses to enhance their electromagnetic shielding; and
Grounding and bonding enhancements.
It also recommended transmission operators maintain supplies of replacement DPRs and other critical assets.
E2 EMPs can couple to overhead lines or cables through the air, like E1 EMPs. “This coupling mechanism is similar to how the field created by a nearby lightning strike couples to an overhead transmission line,” EPRI said. But because of the low amplitude, they are unlikely to affect the transmission system. “Thus, no specific mitigation options were identified as a part of this research,” EPRI said.
Maps of the instantaneous geoelectric field magnitude of an E3 EMP at 20, 40 and 100 seconds | Electric Power Research Institute
But it said E2 EMPs “may be a threat for assets that operate at lower voltages (e.g., low-voltage inverters connected to rooftop PV).”
The low-frequency geomagnetically induced currents (GICs) resulting from E3 EMPs can cause magnetic saturation of transformer cores, causing transformers to generate harmonic currents, absorb reactive power and experience heating in windings and structural parts. “Potential impacts of E3 EMP on the bulk power system can include voltage collapse (regional blackout) and transformer damage due to additional hotspot heating,” EPRI said.
EPRI said E3 EMPs alone could result in a multi-state blackout, “but immediate, widespread transformer damage due to hotspot heating from part-cycle saturation is not expected to occur.”
Researchers said mitigation options used for GMD events would also be effective for E3 EMPs, including:
Preventing protection system misoperations by modifying protection and control schemes to make them resilient to harmonics and system imbalance;
Blocking or reducing the flow of GICs;
Automatic removal of some shunt reactive power compensation devices such as shunt reactors and use of under-voltage load shedding (UVLS); and
Maintaining supplies of spare large power transformers and high-voltage circuit breakers.
EPRI’s analysis of the combined effect of E1 and E3 EMPs indicated DPRs damaged by surges would not cause the immediate disconnection of transmission lines but would prevent the DPRs from performing their protection and control function.
“Significant damage to DPRs and other controls from E1 EMP would be expected to degrade recovery efforts and longer-term viability of controlling system frequency due to potential damage to AGC and other ancillary functions,” EPRI said. “These latter effects could impact the long-term stability (voltage and/or frequency) of an area affected by the HEMP attack.”
Without hardening of the transmission system, “recovering from a HEMP-induced blackout may present operators with challenges that have not been experienced following previous blackouts from more traditional causes. These potential challenges are primarily related to unavailable, inoperable or damaged equipment and impaired situational awareness capability,” EPRI said.
Recovery Efforts
The study recommended transmission operators develop alternatives to their current step-by-step facility energization procedures, noting damaged equipment may interrupt cranking paths following a HEMP event.
“Because damage to large power transformers is expected to be minimal, recovery times following a HEMP-induced blackout would be expected to be commensurate with historical large-scale blackouts if robust E1 EMP protections are deployed such that E1 EMP impacts to equipment, situational awareness, SCADA and other infrastructures that support power system restoration are minimal,” it said.
Southern Co. CEO Thomas A. Fanning, co-chair of the ESCC, said the report “greatly enhances our understanding of the potential impacts EMPs could have on our national energy grid.”
Scott Aaronson, the Edison Electric Institute’s vice president for security and preparedness, said the report “enables electric companies to make science-informed decisions for developing, testing and deploying EMP-resistant grid components.”
Illustration of an substation control house hardened against an E1 EMP | Electric Power Research Institute
“EPRI also tested mitigation strategies and was able to rule out options that don’t work,” Aaronson added. “Multiple electric companies will be piloting those potential solutions to ensure new mitigation strategies do not impact other energy grid equipment or undermine or conflict with mitigation and protective measures that already are in place.”
The report said field testing of mitigation will be needed to avoid unintended consequences and obtain “realistic cost data to inform future decision making.” EPRI said it has begun a new research effort to further evaluate the mitigation options.
Dissenting View
The Secure the Grid Coalition, which claims to have former CIA Director R. James Woolsey among its members, issued a statement blasting the EPRI report as a whitewash “reminiscent of past tobacco industry-underwritten efforts to have putatively independent ‘scientists’ disinform the public about the actual dangers of smoking.”
The group said EPRI made “faulty assumptions” about the damage EMPs would cause to transformers and SCADA systems and ignored “abundant data derived by the Pentagon, civilian agencies and government-sponsored studies.”
FERC on Wednesday approved the dissolution of the Florida Reliability Coordinating Council as a regional entity and SERC Reliability’s expansion into the Sunshine State (RR19-4).
FRCC agreed in October 2018 to relinquish its role following NERC’s determination that its REs — which are deputized to police reliability — should be separate from registered entities subject to NERC reliability standards.
In addition to serving as an RE, Tampa-based FRCC also has a Member Services division, which served as a reliability coordinator and planning authority. FRCC will continue to serve in those functions. “FRCC staff and members will continue to steadfastly pursue our vision to maintain a highly reliable and secure bulk power system for peninsular Florida,” CEO Stacy Dochoda said in a press release.
SERC, based in Charlotte, N.C., is expected to take over FRCC’s RE responsibilities July 1, with FRCC completing its “wind down” of those services by Aug. 31.
Some 37 registered entities in peninsular Florida east of the Apalachicola River will move to SERC, including large utilities Tampa Electric, Florida Power & Light and Duke Energy Florida and small municipal utilities serving Key West and the city of Bartow. (SERC already serves the panhandle west of the Apalachicola.)
SERC is revising its bylaws to expand its Board Executive Committee from 12 to 15 members and divide committee members into two groups with staggered, two-year terms.
SERC expects to add 17 to 21 full-time equivalent staff members to handle the increased workload. NERC and the two REs will use FRCC’s available cash as of July 1, its third and fourth quarter 2019 assessments, and a possible special assessment of up to $630,000 to fund the transition.
FERC also approved a request to allow use of any FRCC penalty funds submitted to NERC between July 1, 2018, and July 1, 2019, toward the transition costs. Penalties submitted between July 1 and Dec. 31 or not otherwise applied to the transition will be reimbursed to FRCC entities on a pro rata basis.
Answering Questions
SERC, which will hold its regular second-quarter “Open Forum” webinar at 2 p.m. May 6, has published a list of frequently asked questions on the transition.
Last year, SERC reorganized from five to six subregions: SERC PJM; SERC MISO-Central; SERC MISO-South; SERC Central (the Tennessee Valley Authority RC area); SERC South (the Southern Co. RC area); and SERC East (the VACAR South RC area).
SERC has one regional standard, PRC-006-SERC-02, governing automatic underfrequency load shedding requirements. SERC said it agreed with FRCC’s recommendation that Florida entities seek a compliance exception from the standard, saying “such action would be the simplest to allow time for the FRCC entity system to be included.”
A utility-funded study has concluded a high-altitude nuclear explosion could cause a multi-state electric outage but not the nationwide, months-long blackout some observers have warned of.
The findings are contained in a three-year study by the Electric Power Research Institute on the impact of a high-altitude electromagnetic pulse (HEMP).
Such an attack could result in a multi-state outage, EPRI acknowledged Tuesday, but it said shielded cables, fiber optics, surge protection, enhanced grounding and modifications to substation control houses could reduce the threat.
Although the report did not provide any cost estimates for the mitigation plans, project manager Randy Horton said through an EPRI spokesman that costs could range from $500,000 to $2 million per substation.
EPRI said it conducted the report “because of the extreme differences in views among experts regarding the potential impacts” of a HEMP caused by the detonation of a nuclear weapon 30 km or more above the earth’s surface.
Under the scenarios evaluated by EPRI, “impacts such as regional disruption or damage to DPRs [digital protective relays] and regional voltage collapse could be experienced,” the researchers said. “Research findings do not support the notion of blackouts encompassing the contiguous United States and lasting for many months to years.”
The report comes little more than a month after President Trump signed an executive order requiring the government to coordinate its efforts on EMPs. The order directs the secretary of Homeland Security and other officials to identify the critical functions and infrastructure systems that could be disrupted by EMPs within 90 days.
Generation not Studied
EPRI’s report, which incorporated research from the Department of Energy’s national labs and collaboration with the Defense Threat Reduction Agency and the Electricity Subsector Coordinating Council (ESCC), was funded by some 60 utilities.
It focused on the potential impacts of a HEMP attack on the transmission system and how overhead transmission lines, substations and switchyards could be hardened. It did not look at the potential effects of HEMP attacks on “generation facilities, nuclear reactors, distribution systems, loads or other key elements or infrastructure sectors,” EPRI said, recommending those subjects for further research.
The study looked at the impacts of three “hazard fields” that can be produced by a nuclear detonation, based on the weapon’s yield and the height of the explosion above the surface:
The early time component (E1 EMP), an intense, short-duration electromagnetic pulse characterized by a “rise time” of 2.5 nanoseconds and amplitude of up to 50 kV/meter on the ground;
The intermediate time component (E2 EMP), an extension of the E1 EMP with an electric field pulse amplitude of about of 0.1 kV/m and a length of one microsecond to about ten milliseconds;
The late time component (E3 EMP), a very low frequency (below 1 Hz) pulse with amplitude of tens of V/km lasting from one second to hundreds of seconds. The event would be similar to severe geomagnetic disturbances (GMDs) caused by solar flares, which can last several days.
The area exposed to E1 EMP fields would be limited by the line of sight from the weapon to the horizon; a detonation at 200 km could affect a circular area of 3 million square miles — most of the continental U.S. and portions of Canada and Mexico — albeit at different levels of severity. The pulse can “couple” to overhead lines and cables, exposing connected equipment to voltage and current surges, potentially damaging DPRs, communication systems and supervisory control and data acquisition (SCADA) systems.
EPRI said E1 EMPs would cause “moderate” damage based on modeling from Los Alamos National Laboratory of up to 25 kV/m at the most severe location on the ground. Increasing the pulse to 50 kV/m resulted in “more severe” damage.
Example of the area affected by E1 EMP resulting from a high-altitude nuclear explosion | Electric Power Research Institute
“Based on the assumptions made in the assessments, it was estimated that approximately 5% of the transmission line terminals in a given interconnection could have a DPR that is disrupted or damaged by the nominal E1 EMP environment that was simulated, whereas approximately 15% could be impacted by the scaled (up to 50 kV/m at the most severe location on the ground) E1 EMP environment,” the report said.
Although its testing did not indicate E1 EMP impacts alone would cause immediate, interconnection-scale disruptions, “this finding is not conclusive due to uncertainties regarding how damaged DPRs might respond during an actual event … or how potential E1 EMP damage to generator controls and other systems such as automatic generation control (AGC), not included as a part of this study, might affect the long-term operation of the grid,” EPRI said.
Mitigation Measures
The researchers said their modeling and laboratory testing of DPRs indicated design changes could provide adequate mitigation up to 50 kV/m:
Shielded control and signal cables with proper grounding;
Low-voltage surge protection devices or filters;
Use of fiber optics-based protection and control systems;
Modifications to substation control houses to enhance their electromagnetic shielding; and
Grounding and bonding enhancements.
It also recommended transmission operators maintain supplies of replacement DPRs and other critical assets.
E2 EMPs can couple to overhead lines or cables through the air, like E1 EMPs. “This coupling mechanism is similar to how the field created by a nearby lightning strike couples to an overhead transmission line,” EPRI said. But because of the low amplitude, they are unlikely to affect the transmission system. “Thus, no specific mitigation options were identified as a part of this research,” EPRI said.
Maps of the instantaneous geoelectric field magnitude of an E3 EMP at 20, 40 and 100 seconds | Electric Power Research Institute
The low-frequency geomagnetically induced currents (GICs) resulting from E3 EMPs can cause magnetic saturation of transformer cores, causing transformers to generate harmonic currents, absorb reactive power and experience heating in windings and structural parts. “Potential impacts of E3 EMP on the bulk power system can include voltage collapse (regional blackout) and transformer damage due to additional hotspot heating,” EPRI said.But it said E2 EMPs “may be a threat for assets that operate at lower voltages (e.g., low-voltage inverters connected to rooftop PV).”
EPRI said E3 EMPs alone could result in a multi-state blackout, “but immediate, widespread transformer damage due to hotspot heating from part-cycle saturation is not expected to occur.”
Researchers said mitigation options used for GMD events would also be effective for E3 EMPs, including:
Preventing protection system misoperations by modifying protection and control schemes to make them resilient to harmonics and system imbalance;
Blocking or reducing the flow of GICs;
Automatic removal of some shunt reactive power compensation devices such as shunt reactors and use of under-voltage load shedding (UVLS); and
Maintaining supplies of spare large power transformers and high-voltage circuit breakers.
EPRI’s analysis of the combined effect of E1 and E3 EMPs indicated DPRs damaged by surges would not cause the immediate disconnection of transmission lines but would prevent the DPRs from performing their protection and control function.
“Significant damage to DPRs and other controls from E1 EMP would be expected to degrade recovery efforts and longer-term viability of controlling system frequency due to potential damage to AGC and other ancillary functions,” EPRI said. “These latter effects could impact the long-term stability (voltage and/or frequency) of an area affected by the HEMP attack.”
Without hardening of the transmission system, “recovering from a HEMP-induced blackout may present operators with challenges that have not been experienced following previous blackouts from more traditional causes. These potential challenges are primarily related to unavailable, inoperable or damaged equipment and impaired situational awareness capability,” EPRI said.
Recovery Efforts
The study recommended transmission operators develop alternatives to their current step-by-step facility energization procedures, noting damaged equipment may interrupt cranking paths following a HEMP event.
“Because damage to large power transformers is expected to be minimal, recovery times following a HEMP-induced blackout would be expected to be commensurate with historical large-scale blackouts if robust E1 EMP protections are deployed such that E1 EMP impacts to equipment, situational awareness, SCADA and other infrastructures that support power system restoration are minimal,” it said.
Southern Co. CEO Thomas A. Fanning, co-chair of the ESCC, said the report “greatly enhances our understanding of the potential impacts EMPs could have on our national energy grid.”
Scott Aaronson, the Edison Electric Institute’s vice president for security and preparedness, said the report “enables electric companies to make science-informed decisions for developing, testing and deploying EMP-resistant grid components.”
Illustration of an substation control house hardened against an E1 EMP | Electric Power Research Institute
“EPRI also tested mitigation strategies and was able to rule out options that don’t work,” Aaronson added. “Multiple electric companies will be piloting those potential solutions to ensure new mitigation strategies do not impact other energy grid equipment or undermine or conflict with mitigation and protective measures that already are in place.”
The report said field testing of mitigation will be needed to avoid unintended consequences and obtain “realistic cost data to inform future decision making.” EPRI said it has begun a new research effort to further evaluate the mitigation options.
Dissenting View
The Secure the Grid Coalition, which claims to have former CIA Director R. James Woolsey among its members, issued a statement blasting the EPRI report as a whitewash “reminiscent of past tobacco industry-underwritten efforts to have putatively independent ‘scientists’ disinform the public about the actual dangers of smoking.”
The group said EPRI made “faulty assumptions” about the damage EMPs would cause to transformers and SCADA systems and ignored “abundant data derived by the Pentagon, civilian agencies and government-sponsored studies.”
The California Public Utilities Commission hosted a forum Friday where some experts urged it to break up Pacific Gas and Electric despite the challenges attending that move, while others favored keeping the troubled utility intact.
Whatever the outcome, PUC President Michael Picker said, the solution is likely to seem as bad as the problem to many people.
“It’s not a question of ‘out of the frying pan and into the fire,’” Picker said. “It’s ‘which fire are we going to pick?’”
Friday’s forum was the second in a series of public meetings on PG&E held by the PUC.
State regulators and other authorities have been discussing PG&E’s future with greater urgency since it filed for Chapter 11 bankruptcy reorganization Jan. 29. The utility cited billions of dollars in potential wildfire liability for its bankruptcy and said it might seek to rescind hundreds of costly power purchase agreements entered into when prices for renewable energy were higher than they are today. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
Recent disasters blamed on PG&E have increased public and political antipathy toward the 114-year-old utility, headquartered in San Francisco.
State investigators have concluded PG&E equipment started wildfires that killed at least 22 people in 2017 and 2018. Not included in that total is the Camp Fire, the deadliest in state history, which killed 85 residents and destroyed most of Paradise, a town of 27,000 in the Sierra Nevada Foothills. Investigators have yet to determine the cause of the fire, but PG&E said its equipment is likely to blame.
After “so much death and destruction,” the utility faces an unprecedented turning point, said David J. Hayes, executive director of the State Energy & Environmental Impact Center at the New York University School of Law. “You’re never going to have a time, I think, when the public is more supportive of extraordinary steps than you have right now,” he told PUC commissioners.
Hayes and others suggested that breaking up PG&E into smaller entities could accomplish several goals, including reducing the risk of cyberattacks. If attackers took down PG&E, it would eliminate gas and electric service for much of California, he noted. But “the system becomes more resilient” if PG&E is separated into smaller units, he said.
‘Culture of Entitlement’
The arbiters of PG&E’s fate go beyond the PUC. They currently include a federal bankruptcy judge and another federal judge overseeing PG&E’s criminal probation in the 2010 San Bruno gas pipeline explosion that killed eight residents of a suburban San Francisco neighborhood. (See Federal Judge to Review PG&E’s Wildfire Plan.)
Gov. Gavin Newsom, state lawmakers and the state attorney general’s office have weighed in. (See Calif. Must Limit Wildfire Liability, Governor Says.) So has FERC, along with ratepayer advocates, fire victims and generators that sell electricity to PG&E. (See Judge Puts Off Decision in PG&E v. FERC.) The FBI is helping local authorities conduct a criminal investigation of PG&E’s involvement in the Camp Fire, according to some news reports.
At stake in all this activity is the future of the state’s largest utility, which supplies electricity and gas to 16 million residents across 70,000 square miles of Northern and Central California, or about 42% of the state.
PG&E’s critics contend the public’s safety hangs in the balance, and that the utility’s finances must not take precedence. The utility is irredeemably flawed, some say.
“No amount of incentives, CEO compensation or board member replacement can fix a company infected with a culture of entitlement,” said Scott Hempling, a regulatory adviser and adjunct professor at Georgetown University Law Center.
PG&E believes it’s entitled “to remain the monopoly franchisee indefinitely, no matter how many rules you break, how much evidence you hide, how many felonies you commit [or] how much damage you do,” Hempling told the PUC.
To stand up to PG&E, state officials must be ready to adopt alternatives to the monopoly, investor-owned utility, he said. “We need to show that ‘too big to fail’ is a myth.”
PG&E insists it’s taking safety concerns seriously and trying to change. It announced plans this month to install a new chief executive and 11 new board members out of 13, touting the new members’ utility and safety experience. (See Former FERC Commissioner Brownell Named PG&E Chair.)
On April 22, however, PG&E provoked more public outrage by asking the PUC to increase its return on equity — a major source of profits — from 10.25% to 16% to help pay for $28 billion in fire safety and other upgrades over the next four years. (Southern California Edison, also blamed for deadly wildfires, recently requested that FERC approve a higher ROE for safety-related transmission line investments.)
“PG&E is proposing a $1.2 billion increase in its currently approved cost of capital, based on a 16% return on equity,” the utility said in a news release. The proposed increase is meant to ensure access to capital markets and would raise an average customer’s electricity bill by about 7%, it said.
“Investors must continue to play a vital role in providing the capital necessary to fund essential safety and reliability infrastructure upgrades,” CFO Jason Wells said in the statement. “These investments allow PG&E to offset the upfront, immediate costs of these long-term projects to our customers.”
Travis Kavulla, director of energy and environmental policy at the R Street Institute, a D.C. think tank, and a member of the Western Energy Imbalance Market’s Governing Body, said the applications for higher returns on equity filed by PG&E and SCE would base a quarter to a third of the companies’ future profits on predicted fire liabilities.
The utilities, especially PG&E, “have already made in essence an opening bid to say what amount of their profit is guided by wildfire-related risk,” Kavulla said. Instead, he said, profits should be connected to measurable results.
“A significant amount of this firm’s profits … should be tied explicitly to achievement of safety outcomes rather than simply being earned as a return paid on capital investments,” Kavulla said.
IOU vs. POU
In the debate about breaking up PG&E, Bere Lindley, assistant general manager of the South San Joaquin Irrigation District, a publicly owned utility, said it would make sense for some areas of PG&E’s territory to become municipal utilities. Publicly owned utilities (POUs) are governed by elected officials and responsible to customers, not shareholders, he said.
POUs have been shown, on average, to lower rates and increase reliability, he argued.
“Customers, owners and the public are the same people in the POU model. They have the same interests,” Lindley said. “The POU structure provides an elegantly simple solution to align natural stakeholder interests for a monopoly business.”
The Los Angeles Department of Water and Power, the Sacramento Municipal Utility District (SMUD) and 39 other public entities provide electric service in California. LADWP — the largest POU in the country — has 3.9 million customers; the smallest POUs serve fewer than 400 residents, according to the California Energy Commission.
Currently, only San Francisco, one of the nation’s wealthiest cities, is seriously considering acquiring PG&E’s equipment and forming a municipal utility, Commissioner Martha Guzman Aceves said. Other communities would likely lack the means, she said, leading to disparities in electric service based on wealth.
Susan Mac Cormac, a partner at corporate law firm Morrison & Foerster, moderated the panel. She said municipal utilities don’t have the resources to cover the billions of dollars in capital expenditures that PG&E likely faces to upgrade its infrastructure and cover wildfire costs. She recommended keeping the utility intact.
John Di Stasio, president of the Large Public Power Council and former CEO of SMUD, said municipal utilities often have top credit ratings and access to capital. Still, he acknowledged, local governments would face significant challenges in trying to take over from PG&E. SMUD faced difficult hurdles in attempting to annex outlying areas of Sacramento from the utility.
“This is a significant hill to climb,” he said.
One example of those challenges came from Sam Weaver, the mayor pro tempore of Boulder, Colo., who participated in the PUC forum by telephone.
Boulder has spent years battling Xcel Energy, the large IOU that serves the city, to take over its poles and lines and create a municipal utility. The results of that effort remain uncertain, and Boulder will likely pursue condemnation proceedings, Weaver said.
Even if Boulder’s municipalization effort ultimately fails, it may still achieve positive results in terms of rates and quality of service, he said.
Xcel committed in December to providing its customers with carbon-free energy by 2050, becoming the first large IOU to make such a pledge. The move was likely a response to Boulder’s pledge to provide all-renewable energy by 2030 if it created its own utility. (See Xcel Pledges to Go 100% Carbon Free.)
“It applies pressure to the [investor-owned] utility because you establish yourself as a customer, and not just as a captive ratepayer,” Weaver said.
CARMEL, Ind. — MISO is accepting proposals for projects designed to relieve its increasingly costly North-South transmission constraint, but it is still zeroing in on an approach to evaluate submissions.
During a Thursday conference call to inform stakeholders about MISO’s expectations of design parameters, staff expressed hope that a viable candidate could emerge from a second round of proposals to relieve the constraint given recent changes to the RTO’s own outlook and the way it values the monetary benefits of large transmission projects.
The submission window for proposals will remain open until June 21. Once ideas are submitted, MISO will perform screening analyses through July to identify possible candidates. After performing more in-depth analysis and cost estimates, the RTO could announce a viable candidate by August.
MISO has added the Midwest-South interface as a constraint to be evaluated under its ongoing Market Congestion Planning Study (MCPS). (See MISO Takes Second Look at North-South Constraint.) Planning Manager Matt Ellis said the constraint was added at stakeholder request.
Ellis said the second look comes as MISO seeks to add a new benefit metric for market efficiency projects that reduce the costs of its settlement with MISO MEP Cost Allocation Plan Goes to FERC.) Ellis said the new metric could render some project candidates more beneficial than they appeared when MISO last studied the constraint in 2017.
The transfer constraints between MISO’s Midwest and South regions contributed to the RTO’s September and January emergency events, CEO John Bear said at an April 23 Informational Forum. He said MISO had adequate resources during both emergencies, but transmission constraints kept it from accessing them to relieve emergency conditions. He said a project could strengthen the RTO’s greatest asset: its footprint diversity. (See MISO Claims up to $3.9B in 2018 Benefits.)
Under the MISO-SPP settlement agreement, MISO pays SPP between $16 million and $38 million in base annual payments based on an annual available system capacity usage factor. Beginning next February, that amount is subject to a 2 to 4% escalation rate, depending on use.
“Fifteen years out, those payments could get pretty high,” Principal Transmission Planning Engineer Shane O’Brien told stakeholders.
O’Brien also said the agreement itself will soon be less certain. Starting Jan. 31, 2021, it may be terminated by any party with a year’s notice. Without a replacement settlement in place, flows would be limited to MISO’s original contract path.
“We could potentially have to revert back to 1,000 MW in the earlier direction,” O’Brien said.
MISO has also said that growing renewable use is set to increase flows on the contract path. By 2033, the RTO has found that interface flows could reach 8,000 MW north to south based on data from its Transmission Expansion Plan (MTEP) futures. Using the accelerated fleet change MTEP future, MISO estimates that its annual settlement payments might reach $70 million, although the other three futures limit costs to below $40 million per year.
In response to stakeholder questions, Ellis said MISO would evaluate the value of avoiding emergency declarations as an additional benefit metric for a Midwest-South transmission solution, even though emergency event reduction is not a Tariff-defined benefit metric.
Design Criteria
The RTO has said proposed projects must terminate on either side of the footprint at facilities owned by MISO transmission owners. However, solutions can have midpoints outside of the MISO system, O’Brien said. Transmission solutions can either increase capacity beyond MISO’s current regional directional transfer limits or eliminate portions of the contract path.
Transmission solutions can also address other transmission constraints in addition to the North-South interface to increase the overall benefits of a project and increase the odds of approval.
“Certainly, if folks are able to provide other benefits in addition to increasing capacity between the regions, that will make a project more beneficial,” O’Brien said.
MISO North-South interface region | MISO
However, MISO is not yet discussing how the costs of projects might be allocated.
WPPI Energy’s Steve Leovy asked if MISO would consider a transmission solution that might be shared with the neighboring Tennessee Valley Authority.
While Ellis said MISO would not foreclose on considering such an idea, he reminded stakeholders that it’s more difficult to evaluate hypothetical agreements against a solution wholly owned by a MISO member.
“We’d have to have some sort of more assurances. What that looks like, I don’t know,” Ellis said.
Missouri Public Service Commission economist Adam McKinnie asked how MISO’s special project submission window might interact with its ongoing interregional coordinated system plan (CSP) with SPP.
“I just don’t want people to have to submit projects twice,” McKinnie said.
Ellis said any projects submitted under the CSP will be evaluated separately by the RTOs first. In the unlikely scenario that a North-South transmission project also qualifies as an interregional project, it will not be overlooked, he said.
