Members of the Western Electricity Coordinating Council’s Member Advisory Committee heard a number of proposed changes to the MAC charter at Wednesday’s meeting, most prominently a plan to authorize electronic voting.
The idea to allow electronic voting arose in last December’s strategic planning meeting, when members discussed ways to improve efficiency, said Utah Office of Consumer Services Director Michele Beck, who presented the proposals to the committee. As proposed, the measure would permit the MAC chair to call for a vote on specific issues discussed in at least one previous committee meeting, with seven to 10 calendar days’ notice before voting begins and at least three business days for members to submit their votes.
Utah Office of Consumer Services Director Michele Beck | NASUCA
In response to questions from some members about the wisdom of conducting committee business online, Beck emphasized that the electronic voting system is not envisioned as a replacement for MAC’s current approach. Online voting would initially be limited to “yes or no” votes, and normal quorum rules would still apply. The requirement that the issue under consideration was discussed at a prior meeting would ensure that MAC members have had an opportunity to suggest amendments or modifications before the vote.
“This is … a way to keep the business of the MAC moving forward, in particular in a case where we have … a very fulsome discussion in one meeting, that folks want to think on it a little further before making their actual vote, and it keeps our work moving forward in between meetings,” Beck said. “[But if] MAC representatives aren’t committed to that process, then … it won’t increase our efficiency and we should delete it.”
Also discussed at the meeting was a proposal to change the way MAC measures nonparticipation. Under the current standard, if a member has not attended six consecutive meetings, the chair may designate the position as vacant. However, this rule was created when MAC met every month; the committee now meets about every six weeks, and some members have expressed concern that this could result in seats being effectively unfilled for prolonged periods.
Several alternative measurements were proposed, with most members supporting vacating a seat after four consecutive missed meetings. This would ensure that the chair has the ability to remove a member after six months without contributing.
“Unless they’re ill, which would be an extenuating circumstance … [if you miss] four meetings, you’re out of here. There’s no excuse for that,” said Grace Anderson of the California Energy Commission. “I would be as clear and strong as possible here and say, definitely not less than four meetings would be a good approach.”
Other proposals brought to the committee included standardizing the formats of documents on WECC’s website, implementing term limits for MAC members and updating the charter to formalize the role of liaisons with other committees. These generated less discussion at the meeting, but Beck left the door open for members to request changes via email. Suggested changes will be considered for incorporation into the final version of the proposals, on which MAC members will vote at the next meeting in December.
National Grid’s U.S. division saw half-year profits rise 16% on new rate agreements and cost-cutting measures, but the company is now facing political pressure from New York Gov. Andrew Cuomo over its decision to deny natural gas service to residents of New York City and Long Island under a moratorium on new hook-ups.
“I’m confident that we’ll be able to address the issues raised by the governor in his recent letter within the expected time scales,” CEO John Pettigrew told analysts last week on a call covering the first half of the U.K.-based company’s accounting year ending Sept. 30.
Cuomo on Nov. 12 gave the company 14 days to connect all customers or he would seek “to revoke National Grid’s certificate to operate its downstate gas franchise.”
New York Public Service Commission Chair John Rhodes on Oct. 11 signed an order directing National Grid subsidiaries Brooklyn Union Gas (KEDNY) and KeySpan Gas East (KEDLI) to connect 1,100 of 3,300 customers that had been denied natural gas service connections (Case 19-G-0678).
National Grid CEO John Pettigrew | National Grid
“A decade ago, National Grid identified the need for incremental gas supplies to serve low growth in the downstate region,” Pettigrew said.
National Grid relied on a pipeline being developed by Williams Co. called the Northeast Supply Enhancement project, otherwise known as the NESE pipeline, which includes an underwater line across New York Bay to service the city and Long Island.
“In May this year, following further delays to permits for this project, and therefore the potential lack of incremental supply to serve that load, we took the difficult decision to stop processing applications for new or expanded gas services in our service territory,” Pettigrew said.
Badar Khan, recently appointed interim president of the U.S. business, was managing the situation in New York and was unable to join the earnings call, Pettigrew said.
Following the PSC order last month, the company has sought to expand demand response and energy efficiency programs, and to arrange for compressed natural gas to be delivered by barge and truck to service those mandated customer hook-ups, he said.
“So in terms of the downstate New York, as I’ve said earlier, the projections are that we’re going to see demand increasing over the next decade,” Pettigrew said. “So the work that we’re doing is really to understand what are the options that are non-pipeline options and potentially how far can that stretch out. The costs are recoverable through our rate filings in terms of provision of service to customers.”
The CEO highlighted the company’s $300 million Metropolitan Reliability Infrastructure project for the Brooklyn gas system, expected to be complete in December 2020.
“On the electricity side, we’ve invested $110 million in the Gardenville substation rebuild in upstate New York,” Pettigrew said. “This substation is critical to the local region, providing residents and businesses with affordable sources of renewable power and is vital to system reliability.”
National Grid reported it successfully completed a rate filing for Massachusetts Electric with new rates going into effect Oct. 1.
The company said that in the second half of the fiscal year, it will continue work on moving its KEDNY/KEDLI rate filing at the PSC, as well as grid modernization, electric vehicle and advanced meter infrastructure plans across its jurisdictions.
“With the KEDNY and KEDLI rate case, we provided data to support a four-year settlement with a proposed base return on equity of 9.65%,” the company said.
National Grid also announced a goal to become net zero for its own carbon dioxide emissions by 2050.
“We set ourselves a target in 2008 to reduce them by 80% by 2050,” Pettigrew said. “Actually, when we got to the end of the last fiscal year, we’d achieved 68% reduction against 1990, so we thought it was really right to demonstrate a more ambitious target … [and] we also know that we’ve got a role to play in enabling net zero more broadly in the economy.”
VALLEY FORGE, Pa. — Transource Energy’s alternative configuration for its Independence Energy Connection project doesn’t pass PJM’s cost-benefit test, LS Power said last week.
Sharon Segner, vice president of LS Power, told the Transmission Expansion Advisory Committee on Thursday that her company’s review of the newly proposed path for the eastern segment of the project only carries a benefit-cost ratio of 1, far below PJM’s 1.25 threshold.
Transource’s proposed alternative plan for the eastern segment of its Independence Energy Connection project | Transource Energy
PJM’s analysis, however, produces a 1.6 cost-benefit ratio. Nick Dumitriu, of the RTO’s market simulation department, said the new configuration — which scraps plans for a nearly 16-mile-long transmission line in favor of tying into existing infrastructure in York County, Pa., and Harford County, Md. — will cost $496.17 million and realize $844.81 million in congestion benefits.
Segner said PJM’s base case used to calculate the ratio doesn’t consider the impact of a nearby project that would alleviate congestion on the Hunterstown-Lincoln 115-kV line. PJM plans to present both projects to the Board of Managers in December for inclusion in the Regional Transmission Expansion Plan, Dumitriu said.
“We just want to get to the right answer, and I think that’s everyone’s objective,” Segner said. “These areas are somewhat interrelated, and that’s where it gets kind of complicated. … We have reason to believe the cost-benefit ratio will look pretty different when the Hunterstown project is in the model.
“It may make sense to go ahead with the settlement version, but it should be based on the correct analysis,” she added.
Transource filed the second configuration for the IEC East project with Maryland and Pennsylvania regulators last month after settling with landowners and state officials long opposed to the original route. (See Transource Files Reconfigured Tx Project.)
PJM selected the original configuration for the $383 million IEC — its largest market efficiency project to date — during the 2013/14 long-term planning window to address congestion in the AP South interface. The RTO has since reviewed its benefits to the grid six times, determining in each round that the project remains the most effective way to reduce load costs.
The RTO’s most recent analysis, completed in September, determined the original configuration would generate a $856 million reduction in congestion costs over the next 15 years, with a benefit-cost ratio of 2.1 — well above PJM’s 1.25 threshold required for inclusion in its RTEP.
Protesters argued, however, that the need for the eastern segment of the project could be met by using towers for existing 230-kV lines. Maryland’s Power Plant Research Program urged the state’s Public Service Commission to suspend the project while PJM studied the market efficiency of this alternative and three others — a request that was granted in January. (See More Info Needed on Tx Line Options, MD PSC Says and Cancel Transource Line, Md. Panel Says.)
PJM’s analysis determined that the protesters’ preferred configuration would require upgrades at the Furnace Run substation in York County in order to alleviate potential reliability violations. The plan will cost $125 million more than the original IEC and produce $12 million less in congestion benefits to the region, according to PJM’s most recent market efficiency update.
Still, Transource and the protesters have settled on the alternative configuration, despite the reduced benefits and additional cost. Both plans sit before regulatory agencies in Maryland and Pennsylvania awaiting a final decision.
Meanwhile, PJM must update its RTEP to include the alternative plans for the IEC.
“We are going to give the board the complete picture of what’s going on,” said Ken Seiler, PJM’s vice president of planning. “There’s a lot of moving parts and a lot of variables, and we will make sure the board has the right information.”
Seiler added that “at some point,” the plans must move forward. “The area is congested and will be congested until we get some of these projects built,” he said.
Alex Stern, manager of transmission strategy and policy for Public Service Electric and Gas, agreed.
“At some point, you need to focus on what needs to get done,” he said. “I think PJM is doing that and obviously that’s part of prioritizing, and you need to prioritize what’s in the best interest of planning and developing a cost-effective grid versus what’s in the best interest of needlessly perpetuating a competitive process.”
MISO’s 2019 Transmission Expansion Plan (MTEP 19) will advance to the Board of Directors without any recommended changes tacked on by the RTO’s Planning Advisory Committee.
The plan cleared the committee’s October email vote with six sectors in favor, none opposed and three abstentions. The PAC’s vote is only considered advisory.
The $3.97 billion, 479-project plan now moves to the board’s System Planning Committee for a comprehensive review Friday. The full board will vote whether to approve it at its Dec. 10 meeting as part of MISO Board Week in Indianapolis.
The PAC proposed no changes to the expansion plan, with a pair of motions to convert the Helena-to-Hampton Corners project into a market efficiency project and to delay MISO’s first storage-as-transmission project for more analysis both failing in the same email vote. (See Changes Proposed for MTEP 19 as PAC Vote Nears.)
At the same meeting, MISO proposed to conduct a special North Region operational limitation impact study for MTEP 20 in addition to the usual slate of planning studies.
Project Manager Sandy Boegeman said the study, added at stakeholders’ behest, will analyze the Minnesota-Wisconsin transfer limitation, known as MWEX.
“Due to the voltage stability nature of this constraint and its location between high renewable penetration areas and customers in the eastern areas of MISO, it presents a valuable opportunity to better understand the implication of a non-thermal constraint within the MISO footprint,” the RTO said.
“This study got a fair amount of support from stakeholders. And we think we have the bandwidth to do this,” MISO Director of Planning Jeff Webb said. The RTO will discuss the scope and objectives of the study at the PAC early next year, he said.
MISO promised unique, targeted studies to identify possible transmission projects in lieu of a fresh set of planning futures for MTEP 2020. (See “Special MTEP 20 Studies,” Changes Proposed for MTEP 19 as PAC Vote Nears.)
Even with MTEP 19 not yet finalized, MISO is already expediting a substation expansion for MTEP 20. Michigan Electric Transmission Co. is planning to expand its Riverview substation to accommodate new load requested by Consumers Energy near the city of Kalamazoo, Mich. The RTO said the 18-month project deserved fast-track status to avoid overloads. It will add the substation expansion to the Appendix A list of projects in MTEP 20.
The New York Public Service Commission on Thursday granted the New York Power Authority a certificate of environmental compatibility and public need to rebuild about 86 miles of upstate transmission lines (Case 18-T-0207).
The NYPSC held its regular monthly session in Albany on Nov. 14.
The Moses-Adirondack 1 and 2 lines extend from the St. Lawrence Power Project’s Moses-Saunders Power Dam switchyard in Massena to the Adirondack substation in Croghan. Thursday’s order also grants NYPA the right to build several upgrades to both the switchyard and the substation.
Chair John Rhodes
“I see this as a smart, careful, timely project that’s valuable for the statewide system needs and the statewide renewable energy needs,” PSC Chair John B. Rhodes said. “It’s well designed, has good minimization of impact with the very good use of existing right of way, attention to land use, attention to habitats and as a result is, on balance, very much in the public interest.”
NYPA proposed to divide the project into two phases, the first consisting of replacing 78 miles of the two lines currently configured as single circuits on separate wooden H-frame structures with two new single-circuit lines on steel monopoles.
The initial operating voltage would be 230 kV, with the second phase involving replacing the remaining length of the transmission lines with two single circuits on steel monopoles and upgrading the Moses-Saunders switchyard and the Adirondack substation to operate at 345 kV.
NYPA proposed to construct the project entirely within an existing right of way, except for a 1-mile reroute at the State University of New York at Canton campus.
CES Budget for 2020
The commission also approved a 2020 operating budget of nearly $13 million for the New York State Energy Research and Development Authority to run the state’s Clean Energy Standard and related programs (Case 15-E-0302).
Commissioner Diane Burman
The order authorizes NYSERDA to reallocate up to $12,138,093 of uncommitted system benefits charge, energy efficiency portfolio standard and renewable portfolio standard funds and $824,791 of previously authorized — but unspent — 2018 CES compliance period funding to cover administrative costs for next year’s RPS and zero-emission credit programs.
Commissioner Diane Burman dissented on the CES budget, saying, “I appreciate the work that NYSERDA does, but this budget request seems very bulky to me.”
The commission performs good due diligence by “not just accepting from utilities a bulky budget, and we work with them in streamlining that as much as we can and really trying to figure out what is absolutely appropriate and necessary,” Burman said.
Consent Agenda
The PSC approved nearly $5.2 million in sales of street lighting by National Grid to three municipalities in order for the towns to install and profit from more energy-efficient lighting. The sales were for Utica ($4.1 million), Dunkirk ($1 million) and Medina ($70,000).
Burman abstained from several items on the consent agenda, including those related to National Grid’s natural gas subsidiaries in Brooklyn and Long Island, and to Consolidated Edison’s gas business, because “we are not addressing some of the core issues around gas, and therefore, looking at these in isolation is very troubling to me.”
The National Grid items were for tariff filings to modify the companies’ gas tariff schedule to establish non-firm demand response service classes. The Con Ed items regarded revisions to its daily delivery service to institute a voluntary physical storage program, and to interruptible gas service program violations or strike rules.
Rhodes on Oct. 11 signed an order forcing National Grid subsidiaries Brooklyn Union Gas (KEDNY) and KeySpan Gas East (KEDLI) to connect 1,100 of 3,300 customers that had been denied natural gas service connections (Case 19-G-0678). KEDNY has approximately 1.2 million customers, and KEDLI has 590,000 customers.
National Grid found itself at odds with Gov. Andrew Cuomo last week when he issued a letter demanding that its gas subsidiaries connect all customers to whom it had denied service under a moratorium on new hook-ups or he would seek “to revoke National Grid’s certificate to operate its downstate gas franchise.” (See related story, National Grid Vows to Expand NY Gas Service.)
Commissioner Tracey Edwards
Commissioner Tracey Edwards said she wanted “to make sure that the definition of critical care customers is inclusive, so that it speaks to areas of refuge; it speaks to hospitals and nursing homes. I want to make sure that it includes assisted living facilities and homeless shelters, so I would like some follow-up information to make sure we’re looking at critical care in an overall perspective and not leaving anyone out.”
Burman also concurred with comment on items related to municipal tariff filings to modify the municipalities’ electric tariff schedules to include rules and regulations governing the purchase of renewable energy from new distributed generators and to implement net metering schemes.
The two items “appear to be addressing in a proper way the need for these tariffs. … These cases as well as others have sought to modify the tariffs on a voluntary basis because they’re not subject to the utility tax,” Burman said. “I’m flagging this because I want us to be looking at how the munis are doing it differently. … However, we really do need to watch if there are any negative ramifications to the customers, especially on the cash-out that goes to the developers.”
Burman concurred on a petition by 1115 Solar Development for compensation according to the Alternative 2 capacity value calculation set in the Value of Distributed Energy Resources (VDER) transition order, noting that a PSC staff white paper on the subject from last January did not mean that the commission thought of it “as a done deal.”
FOLSOM, Calif. — CAISO is moving ahead expeditiously with a plan to stem systemwide market power, even though not everyone is convinced the effort is necessary or needs to move so quickly.
The project stems from analysis by CAISO staff and the ISO’s Department of Market Monitoring earlier this year that detected a limited number of hours when the potential for the exercise of systemwide market power existed.
The report led to a sometimes tense meeting in August of the ISO’s Market Surveillance Committee, in which participants voiced opposing views on the need for market power mitigation measures and the speed at which the process was moving. (See CAISO Stakeholders Split on Market Power Efforts.)
On Wednesday, Brad Cooper, CAISO’s senior manager of market design policy, briefed the Board of Governors on the ISO’s decision to kick off a stakeholder initiative to design a mitigation program. Staff issued a conceptual proposal in September and last month released a scoping document setting out the guiding principles for the effort.
Cooper said it has proven tricky to design a process that limits market power without unintended negative consequences. Of particular concern, he said, is being careful not to deter electricity imports from other states by controlling prices too much. Those imports will be necessary for meeting California’s needs going forward, he said.
“We want to make sure we don’t cut off our nose to spite our face, so to speak,” Cooper said.
The predicted potential for noncompetitive conditions occurs at the ISO’s balancing area level, not the local level, he said. It can involve hours when supply is constrained by transmission bottlenecks or a lack of resources, he said.
Though the problem isn’t immediate, CAISO leaders and staff members are concerned that system market power could become more of a factor in the next few years. Starting in 2021, the retirement of fossil fuel plants and the inability of solar power to meet evening peak demand will create a much tighter energy market than today, according to CAISO projections.
Stakeholders, however, remain divided on the need for mitigation efforts, Cooper told the board. Electricity suppliers have argued there’s no real evidence of the exercise of systemwide market power — only the potential for it to happen.
“PacifiCorp agrees with other stakeholders that nothing in the CAISO’s system market power analysis indicates an urgent need for the CAISO to conduct a policy initiative to design and implement new price mitigation procedures to address system-level market power,” the utility, a major exporter of energy into California, wrote in comments filed with the ISO.
The state’s investor-owned utilities and the California Public Utilities Commission have contended the effort is critically important, he said.
“System market power mitigation is vital to ensure competitive outcomes in a market that has become structurally uncompetitive at the system level in a higher number of hour and intervals. When the market is structurally uncompetitive, market power can be exercised, and uncompetitive bidding practices can successfully drive up the price,” Pacific Gas and Electric said in comments.
Staff plan to issue a straw proposal next month and bring a final plan to the board early next year so that it can be implemented by the spring of 2021 — before the anticipated shortfalls of summer that year. The designers are looking at a phased-in approach that will first address issues in the real-time market and then move to the day-ahead market in phase two, Cooper said.
Some commenters Wednesday took issue with the two-phased approach.
Raisa Ledesma Rodriguez, with the CPUC’s Energy Division, said the phased-in effort may be insufficient to head off the exercise of market power. A representative from PG&E said the day-ahead market is where the greatest potential for problems occurs.
CAISO CEO Stephen Berberich told the board that applying market power mitigation measures in the day-ahead market is more complex than in the real-time market. Staff are moving ahead on the project with a sense of urgency, he said.
“Our analysis doesn’t show a burning bridge at this point,” but it’s important get ahead of the issue, Berberich said.
WASHINGTON — Deputy Energy Secretary Dan Brouillette appeared well on his way to taking over for his outgoing boss after facing little substantive questioning at his confirmation hearing Thursday and little, if any, opposition from Democrats.
Much of the hearing was taken up by members of the Senate Energy and Natural Resources Committee, on both sides of the dais, extolling the virtues of a particular technology and cordially asking Brouillette for his commitment and assurances that he would continue the Department of Energy’s work in advancing the research and commercialization of those technologies, including LNG, carbon capture and sequestration, battery storage, and advanced nuclear energy.
Brouillette has been serving as deputy to Energy Secretary Rick Perry since August 2017, when the Senate confirmed him 79-17. He was considered by the committee in May of that year alongside eventual FERC Chairman Neil Chatterjee and former Commissioner Robert Powelson. (See No Fireworks for FERC Nominees at Senate Hearing.) Chatterjee was among those in a packed audience Thursday that included five National Laboratory directors and Brouillette’s nine children.
Brouillette previously worked at the department in the George W. Bush administration as assistant secretary for congressional and intergovernmental affairs from 2001 to 2003. He worked as staff director for the House Energy and Commerce Committee for a year after leaving the department. Before returning to DOE, he had been a senior vice president for USAA since 2006.
President Trump formally nominated Brouillette on Nov. 7. Calling him “the obvious choice to replace Secretary Perry,” Senate ENR Committee Chair Lisa Murkowski (R-Alaska) told Brouillette it was her “intention to try and move you through the committee process just as rapidly as possible.” But regardless of if — or when — the Senate confirms him, Brouillette will take over leadership of the department, at least in an acting capacity, when Perry retires on Dec. 1.
Baseload and Resilience
Sen. Steve Daines (R-Mont.) said his state’s “balanced energy portfolio is coming under attack with the premature, forced closures” of two units at the coal-fired Colstrip plant because of “extreme, radical groups that litigate.” He told Brouillette he believed “that there is a role for you and the Department of Energy to play in order to maintain baseload supply in Montana” before asking him to “commit to working with me and this committee to protecting and growing baseload power like Colstrip and maintaining a secure and balanced energy portfolio.”
“It’s been the policy of this administration, and possibly the previous administration, to pursue an all-of-the-above energy strategy,” Brouillette replied. “In our view, diversity of energy supply means energy security, not only for our nation but for our allies across the world. … Until we are able to develop battery storage that has more capacity, is longer lasting [and] is perhaps more flexible in some respects, it is important that baseload power exist, because without it, if we are objective and candid, the introduction of renewables to our electric grid is very, very difficult.”
Through the department’s in-development North American Energy Resilience Model, “we’re going to look at these types of facilities and see if they fit that potential model and see if there’s anything that we should be concerned about potentially about the loss of those” plants, he said.
Asked by reporters after the hearing how he would go about saving baseload plants, Brouillette answered, “It’s not about saving the plants. It’s about working with regulators; showing them the things that we’re seeing; allowing the FERC to do its job.
“It’s not about simply ‘saving the plants.’ It’s about looking at the entirety of the grid, looking at the entirety of the energy sector and making sure that we have either distortions or artificial impacts on it that might preclude us from either adopting renewable technology or create some level of a security risk. … We’re looking at that resilience model as a way to show us in real time what’s happening on the grid.”
Ukraine Matters
The breezy hearing intersected briefly with the political firestorm taking place on the other side of Capitol Hill. Brouillette said he had no knowledge of or involvement in conversations with Ukrainian officials about matters at the heart of the House of Representatives’ inquiry into impeaching Trump.
“I have not been involved in any of the conversations that are related to the House’s inquiry,” Brouillette told ranking member Joe Manchin (D-W.Va.). He did say the department has worked with Ukraine, “at their request, to help them interconnect their electricity grid [and] their pipeline grid,” and that it has advised U.S. allies in Eastern Europe on building LNG import facilities as part of an effort to lessen their dependence on Russian natural gas.
Perry — along with U.S. Ambassador to the E.U. Gordon Sondland and Kurt Volker, special U.S. envoy to Ukraine — is one of the White House’s “three amigos” on Ukraine policy, according to Sondland. Perry had traveled to Ukraine in May for the inauguration of President Volodymyr Zelenskiy and provided him with a list of suggestions for the supervisory board of Naftogaz, the country’s state-owned energy company.
Sen. Ron Wyden (D-Ore.) asked if Brouillette was aware of “any contacts between Secretary Perry, or any other senior DOE officials, and representatives of Naftogaz.”
“I am aware that the secretary met on occasion with individuals who were asking for assistance with the restructuring” of the company, Brouillette replied. But he said he was not aware of any conversations between Perry and Trump’s personal lawyer, Rudy Giuliani, or anyone in the Ukrainian government about the makeup of the board.
CARMEL, Ind. — MISO’s grid will be only minimally susceptible to the impacts of possible water scarcity in the future, in part because of increased adoption of renewables, new RTO models show.
The RTO will only have a “relatively modest” need for incremental new generation to meet demand under water scarcity, Senior Adviser Eli Massey told stakeholders at a Planning Advisory Committee meeting Wednesday.
“The results of this first round of modeling suggest that MISO isn’t susceptible to either a short-term or long-term water scarcity scenario,” Massey said.
The modeling relied on data from Sandia National Laboratory to estimate the “water intensity factor” for MISO generation, which represents the relationship between the amount of cooling water and fuel needed to produce 1 MWh of energy. That data point was cross-referenced with estimates for the volume of water available for generation under short- and long-term scarcity conditions.
The Fermi 2 Power Plant on Lake Erie | DTE Energy
Most water scarcity concerns can be mitigated by economically redispatching MISO’s resource portfolio “around low to moderate water scarcity.” He also said the continued evolution of the resource portfolio toward renewables “is moving MISO in a direction that makes it less susceptible to water scarcity in the future.”
“Wind doesn’t need water,” he said.
MISO doesn’t collect cooling water use statistics from its members, and Sandia could only provide usage stats for about half the generation in its footprint, Massey said. He said MISO consulted with Sandia and the National Renewable Energy Laboratory on their methodology to fill in missing estimates.
MISO modeled both a six-year drought and recovery, and a 15-year water scarcity scenario in which water available for generation is limited by varying degrees. Scientists have repeatedly predicted that climate change, bringing long dry spells and more severe flooding, will intensify water shortages in some geographic areas. RTO staff did not mention climate change during the presentation.
Massey said energy served by MISO’s thermal resources is disrupted only in the most extreme water shortage scenarios.
“MISO is always looking at environmental issues or operational risks to reliability,” Massey explained to stakeholders. “We always felt like we thought we were OK, but we never quantified it.”
The effort is MISO’s first attempt to understand the potential impacts of water scarcity, Massey said, adding that the RTO will perform more analyses, possibly on a seasonal or subregional level, to understand the impacts of water constraints in the footprint.
“This isn’t the only avenue we’re exploring. MISO is partnering with NREL and other labs to understand water risk,” Massey said.
He also said MISO may explore requesting more accurate water use statistics from its thermal generation operators. He asked stakeholders to communicate their interest in having the RTO analyze more detailed data.
CARMEL, Ind. — MISO on Wednesday dismayed some stakeholders when it doubled back on a cost allocation proposal that would have lowered voltage thresholds and raised cost minimums for economically beneficial transmission projects.
FERC rejected MISO’s first cost allocation filing in June, finding it would have violated the principle of cost causation because projects proposed under the local economic transmission category would be required to demonstrate regional benefits while only being cost-shared on a local level.
That plan also sought to lower the regional market efficiency project (MEP) voltage threshold from 345 kV to 230 kV while keeping the current $5 million cost minimum for those projects, a measure that FERC did not address in its rejection.
In September, MISO circulated a proposal that sought to address the local project issue by lowering the voltage thresholds for regional MEPs to 100 kV, while increasing cost minimums to $25 million, a move intended to cover local projects with wider benefits. The plan would have also set a 100-kV threshold for interregional MEPs with Key Details Change in MISO MEP Cost Allocation Plan.)
MISO’s latest proposal, revealed during a Wednesday conference call of the Regional Expansion Criteria and Benefits Working Group (RECBWG), would restore key points of the original filing, including setting the voltage threshold for regional MEPs to 230 kV and observing a $5 million cost minimum. It would also require that local economic projects between 100 and 230 kV be allocated only locally.
But unlike the rejected plan, the proposal would also stipulate that local projects be reviewed on a local basis only, and not have to show regional benefits. MISO Senior Manager of System Planning Jarred Miland said the RTO now plans to perform only local benefit-to-cost analyses for local economic projects that are based on transmission pricing zones. If the lower-voltage projects show at least a 1.25:1 benefit-to-cost ratio to the transmission pricing zone where the project is located, then the costs of that project would be allocated to that zone.
MISO would first screen projects for possible benefits, then test them in modeling, Miland explained during Wednesday’s call.
“Since there’s not regional test, there’s not regional allocation. The difference is the local economic projects are going to be locally allocated to the local” transmission pricing zone, Miland said.
Blind to Benefits?
But several stakeholders said MISO’s new proposal is still at odds with cost causation.
They said MISO is wrongly presuming that all sub-230 kV projects cannot deliver regional benefits. Some asked if the RTO planned allocation exceptions for highly beneficial lower-voltage projects.
“I would say right now, the plan is what the plan is. There’s no intention to try to make those projects regional,” Miland responded. He said the new proposal is similar to MISO’s current practice, where all projects below 345 kV cannot be considered MEPs.
“We’re still dropping down from 345 kV to 230 kV. So that still helps,” Miland said, adding that MISO would still be positioned to approve more MEPs than it does now.
LS Power Manager of Transmission Policy Pat Hayes argued that because MISO would already screen lower-voltage projects for footprint-wide benefits, it wouldn’t take much additional effort to estimate regional benefits.
“You just can’t turn the model off and shield yourself from seeing adjusted production costs,” he argued.
MISO officials confirmed that they would see possible regional benefits in modeling lower-voltage projects but wouldn’t share them externally.
‘Head in the Sand’
WEC Energy Group’s Chris Plante said the regional economic benefits of projects 230 kV and below exist even if MISO doesn’t name them.
“The first proposal failed because we failed to identify beneficiaries of projects. This proposal is akin to putting a bucket of sand in the corner and sticking your head in it. Just because we don’t look elsewhere and don’t identify beneficiaries, doesn’t meant they don’t exist. … I think that this thought process is dead-on-arrival at FERC — it’s not going to fly,” Plante said.
Clean Grid Alliance’s Natalie McIntire agreed, saying MISO is choosing to be willfully blind to some project benefits and setting itself up to block some beneficial projects from proceeding.
“There isn’t a clear path forward for lower-voltage projects that bring wider benefits to zones,” she said.
However, other stakeholders said the new allocation plan was reasonable and that the 230-kV threshold isn’t arbitrary. Some pointed out that MISO only discloses regional benefits for projects 345 kV and above.
Plante said MISO might “temper” its proposal by making cost allocation “optional” for the zone that might host a regionally beneficial local economic project. That way, single zones wouldn’t be forced to foot the bill on projects positioned to benefit other transmission pricing zones, he said.
Miland said stakeholder opinions on the September proposal can be broken down into “those that didn’t like what we did and those that did like it.” MISO said a majority of its state regulators wanted it to follow FERC’s June rejection and refile the proposal, this time scrapping the local economic project category altogether, leaving projects below 230 kV again relegated to the RTO’s “economic other” project category, which also dictates that smaller economically beneficial projects are allocated to the transmission pricing zone where they are located.
Still other stakeholders said they didn’t support MISO’s proposed $25 million threshold or the competitive bidding exception for reliability projects that it determines have an immediate need. As in the first filing, the new plan would exempt from competitive bidding any MEPs needed within three years to mitigate reliability issues. The new proposal preserves that option.
MISO maintains that its proposal will better “align who pays with who benefits over time from a regional transmission expansion perspective.”
Stakeholders on the call asked if MISO has met with FERC staff to vet its newest proposal. Staff said they had not.
“We’ve been trying to weigh the feedback we received with what we think is the best path forward,” Miland said. “This hasn’t been taken lightly by any means internally here in MISO. This has been a full-time job for several of us for a handful of months.”
The change in tack on lower-voltage projects pushes out MISO’s refiling target.
“We were hoping to get a filing out the door before Thanksgiving. That’s probably not going to happen now,” Miland said.
A simulated social media hack was among the surprises lobbed at participants in GridEx V, the latest entry in NERC’s series of exercises testing industry preparedness for cyber and physical attacks.
More than 425 organizations across industry and government participated in the two-day exercise, which began on Wednesday with a distributed play model representing a wide array of threat vectors that Steve McElwee, PJM’s chief information security officer, called a “true doomsday scenario.”
Along with utility companies and regulators, the drill included representatives from farther-flung sectors, such as natural gas, electrical equipment manufacturing, telecommunications and even finance, in an attempt to game out the broader social impacts of an attack on the shared electrical grid.
An unnamed staffer at NERC’s Electricity Information Sharing and Analysis Center (E-ISAC) participates in day one of GridEx V. | NERC
Stacking the Deck
“One of the important design parameters that we use when we develop GridEx is we essentially break the system,” NERC CEO Jim Robb said in a media briefing Thursday. “That’s how the electricity industry learns: We break things, and then we figure out how to fix them and prevent the breakage from happening next time. So, it’s purposefully an overwhelming act of violence.”
This year’s challenges included the takeover of one utility’s Twitter account by malicious hackers that then used it to spread disinformation to the public and other participants, which one player described as the major “curveball” of the scenario. Additional threats included technological incursions such as the use of rogue USB devices and ransomware, which — along with physical attacks such as intruders in headquarters buildings and vehicle fires at regional facilities — put essential infrastructure out of commission. Utilities were tested both on their ability to handle the initial attacks and their capacity to ride out the damage and get their systems back online.
NERC CEO Jim Robb (left) with Southern Co. CEO Tom Fanning at a press briefing | NERC
The distributed play exercise was joined in its second day by a similarly comprehensive but more targeted scenario in Thursday’s executive tabletop session, which presented an attack on the northeastern part of the North American grid. Test designers decided on this scenario, the first region-specific exercise in the history of GridEx, in hopes of gaining deeper insights than were available in previous years. The northeastern setting gave participants the opportunity to explore characteristics of the region such as U.S.-Canada relations, the interdependence of the electric and natural gas sectors, and the impact of a prolonged outage on financial players in New York City.
“There are very few cyber-only or physical-only incidents, and as our world grows more interconnected and our infrastructure grows more interdependent with other systems and functions, we must look at our risks [from] both a physical and cyber perspective,” said Brian Harrell, assistant director of the Cybersecurity and Infrastructure Security Agency at the Department of Homeland Security. “The scenario is real, it’s relevant, and it focuses on industry and government partnerships and how we [can] collectively get better.”
Fighting Back
As Harrell suggested, risk is not the sole focus of GridEx. The scenario also provides a sandbox for the public and private sector to test mitigation tools without danger to the general public. This year’s scenario was no different, with participants aiming to address vulnerabilities identified in previous GridEx iterations.
One focus for industry players in this year’s scenario was to actively engage with the vendor supply chain. Vulnerabilities often center on specific equipment, yet in the public report following GridEx IV, NERC called out utility operators for failing to engage with vendors to the degree they did with other utilities, government, and law enforcement. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.) The criticism spurred greater efforts in this year’s exercise, though participants acknowledged that considerable work is still needed.
Kevin Wailes (left), Lincoln Electric, and Brian Harrell, DHS, at a press briefing | NERC
“The supply chain issue is extraordinarily complex and hard to think about over time, because the threat vectors change continuously and … a good device today may be exposed tomorrow,” said Southern Co. CEO Tom Fanning, co-chair of the Electricity Subsector Coordinating Council. “So, it isn’t [enough to] have certified equipment in our supply chain. … We must have a process of cyber hygiene and collaboration over time.”
On the public side, GridEx V provided a chance to test out the responsibilities granted to the Department of Energy since the last exercise under the FAST Act, amended in 2018 to designate the department as the lead agency on cybersecurity for the energy sector. The change gave broad new authority to DOE to coordinate with state and local governments, in addition to utilities, and GridEx provided an opportunity to test the practical limits of these powers prior to a real emergency.
“What we don’t want … is to be in an actual situation where we’re figuring out the right policies and how we share that information, and what type of information [to share], so that we can have the situational awareness to advise the president,” said Karen Evans, assistant secretary in DOE’s Office of Cybersecurity, Energy Security and Emergency Response.
Ongoing Development
The GridEx exercises have expanded considerably since the first iteration in 2011, which involved just 75 industry and government organizations across the U.S. and Canada. Unlike that scenario, which was inspired by the Stuxnet attack in Iran and focused exclusively on cybersecurity, GridEx now aims to include the widest possible range of participants so that every aspect of the system can be tested.
ERCOT staff participate in GridEx V. | ERCOT
This has led to criticism that the scenarios presented are unrealistic, with participants in previous years comparing the prepared situations to a “disaster movie” rather than helpful practice for recovery. NERC acknowledged these issues but said they overlook the true goal of the exercise.
“The grid is designed with a tremendous amount of redundancy, it operates in real time, and the loss of even a major power station in many cases is not a catastrophic consequence because the industry is prepared for that and designs around it,” Robb said.
“That makes a scenario [such as the one] we’ve laid out implausible but still worth testing,” he added, citing the potential to uncover unsuspected vulnerabilities and suggest new avenues of cooperation.
NERC will release its report on GridEx V by March 2020.
RTOs Take Part
RTO officials also gave their take on the exercise Thursday.
Keri Glitch, MISO’s vice president and chief information security officer, said the scenarios included “network breaches caused by an internal source, a potential intruder in the headquarters building, as well as a vehicle fire near a regional facility.”
“Our employees and industry partners collaborated well and learned a lot from the drill,” Glitch said.
About 120 CAISO employees took part in the exercise, along with representatives from federal, state and local agencies and 39 RC West participants, IT Enterprise Support and Campus Operations Director Matt Turner said.
“We assessed how employees reacted and communicated the scenario injects, which included a plan to return to normal operations. During the simulation, we injected additional issues, such as making key personnel unavailable, to evaluate the depth we have on the team and their ability to adapt to the situation,” Turner said. “Our exercise is designed to push the limits, as far as we could, to identify areas for improvement.”
New York state was “hit” hard during GridEx V, which included a “focused regional attack in the Northeast,” according to NERC CEO Jim Robb. Above, New York Power Authority staff participate in the exercise. | NYPA
SPP said more than 200 staffers took part, after more than a year of preparation by the RTO’s leadership team. “SPP’s incident coordination team led IT, operations and other staff in response to simulated threats to system reliability, communications channels and cyber assets, all in the interest of strengthening defenses, enhancing resilience and refining emergency response procedures,” spokesman Derek Wingfield said. “In the weeks leading up to the go-live of our Western reliability coordination service, GridEx also gave us the opportunity to test our preparedness alongside some of our new customers in the Western Interconnection.”
NYISO, ISO-NE and ERCOT also confirmed their participation. “Physical and cybersecurity measures are a constant practice of vigilance and focus of attention,” NYISO CEO Rich Dewey said.
“Past GridEx exercises have proven to be valuable training opportunities for many departments within ISO New England, and we look forward to practicing and improving our response capabilities,” RTO spokesman Matthew Kakley said.
While PJM regularly conducts simulator drills with its transmission owners and other critical players, GridEx allows the RTO to test its operations under extreme conditions, McElwee said. “It’s far beyond any situation we’ve experienced.”
Amanda Durish Cook, Tom Kleckner, Michael Kuser, Hudson Sangree and Christen Smith contributed to this article.
