MISO must flesh out more details around its already lengthy proposal for allowing energy storage resources to participate in its markets, FERC said Monday.
In an April 1 letter requesting more information on the plan, FERC said it could not process MISO’s Order 841 compliance filing until it clarifies several points regarding its phased participation approach, proposed commitment statuses, complexities for storage resources on the distribution system, conflicting offers and bids and make-whole payments (ER19-465). MISO has 30 days to respond.
FERC Order 841 requires RTOs and ISOs to revise their market participation models to allow storage resources 100 kW and larger to provide the capacity, energy and ancillary services they are technically capable of providing. MISO and its stakeholders spent the better part of last year negotiating rules that culminated in a 1,300-page filing. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.)
In its compliance filing, MISO said it “anticipates significant uncertainty and risks related to the ability of MISO’s system and software to handle the participation of large numbers of very small” energy storage resources. The RTO asked for a “phased approach in the accommodation of very small” storage resources that would limit participation of small storage resources to 50 in the first year of compliance and 150 in the second year.
MISO said that approach would give it time to “further develop and fine-tune its system and software to be able to handle potentially increasing numbers of very small” storage resources.
But FERC directed MISO to specify what year it expects to provide market access to all storage resources that meet the 100-kW minimum threshold.
MISO must also explain how its must-offer requirement is affected when storage resources elect to use the RTO’s proposed dispatch status of “not participating” or other commitment statuses, the agency said. MISO’s filing proposed owners of storage resources could choose between several commitment modes, including charge, discharge, continuous, available, not participating, emergency charge, emergency discharge and outage. MISO has said its discharging, charging and continuous modes will carry must-run designations.
Tesla Powerpack lithium-ion battery storage | Tesla
FERC said MISO must clarify whether it proposes to levy transmission charges on storage resources when they are charging to resell energy later. MISO must also explain how it will help storage on the distribution system from making double payments — at both retail and wholesale — for charging energy.
FERC also asked if MISO would propose metering practices to manage the “complexities” of selling energy to a storage resource that will then resell the energy at the wholesale LMP.
MISO’s proposal requires storage owners to secure agreements with distribution companies that can deliver stored energy to the transmission system. However, FERC asked if MISO would require the same agreements when energy is moved from the transmission system to distribution-level storage, and it asked the RTO to explain a provision that prohibits distribution-level storage resources from pseudo-tying into a different balancing authority.
The agency also told MISO to cite Tariff provisions that will allow owners of storage resources to self-manage their state of charge.
FERC additionally said if MISO were to rely on existing Tariff provisions for a storage participation model, it should provide the commission with citations to the applicable market rules and pseudo-tie requirements for transmission-level resources. MISO must also describe how its filing will give storage resources access to all capacity, energy and ancillary service markets, as well as non-market services such as black start, primary frequency response and reactive power.
FERC told MISO to explain how its filing will prevent the same resource from submitting conflicting supply offers and demand bids for the same market interval. It also seeks to know if the participation model allows for make-whole payments when a resource is dispatched as load and the wholesale price is higher than the bid price and when a resource is dispatched as supply and the wholesale price is lower than the offer price. The commission also asked if resources available for manual dispatch will be eligible for make-whole payments.
Finally, FERC asked MISO to cite how its compliance filing will allow storage dispatched as supply and demand to set the wholesale market clearing price as both a wholesale seller and buyer, as Order 841 dictates. The agency also asked for citations to support that storage resources can set the price in the MISO capacity market, that MISO will accept wholesale bids from storage owners and that self-scheduled storage resources can participate in the market as price-takers.
ERCOT market participants last week grilled staff over the grid operator’s requests to delay generation outages in advance of an early March cold-weather event that led to a new monthly peak but ultimately did not require emergency actions.
Members rained their concerns on Dan Woodfin, ERCOT’s senior director of system operations, for more than two hours at the Technical Advisory Committee’s March 27 meeting. They contended the grid operator didn’t give the market a chance to work and that it had an insight into the market not shared with its participants.
When it was over, TAC Chair Bob Helton teased Woodfin to be careful drinking water “because of all the holes punched in you.”
Citigroup Energy’s Eric Goff (left) and Morgan Stanley’s Clayton Greer question ERCOT’s Dan Woodfin (not pictured).
Cold Weather, High Loads
In late February, weather forecasters projected an arctic cold front to cover much of Texas during the first week of March. ERCOT’s earliest assessments indicated peak loads of more than 58 GW, “substantially higher” than is typical for early March.
Complicating matters was the more than 7.7 GW of capacity scheduled to begin maintenance outages on March 1 and 2, in addition to more than 12 GW of outages already underway. Meanwhile wind forecasts from ERCOT vendors indicated the grid operator could face low wind output during peak times through March 5.
ERCOT issued an operating condition notice (OCN) just after noon on Feb. 27, warning of a “potential cold weather system” affecting its footprint March 3-7. Staff said they followed up by asking the generators’ qualified scheduling entities to review their fuel supplies and urging them to delay maintenance or return from outages early. ERCOT said it asked about 6 GW of outages to be delayed, but by the following afternoon, only one unit had delayed its outage.
“Normally, when we issue an OCN of this type, we see a lot of response from the pertinent units,” Woodfin said. “It’s not a matter of OCNs causing us to do things; it’s a matter of OCNs causing the market to respond. The idea is to look at your outages … it should cause people to sit up and look closer, and delay the outage because things look tight.”
On Feb. 28, ERCOT projected it had 58 GW of capacity available, which included 2 GW of wind and load resources. However, expected gas curtailments and forced outages led to what ERCOT called a “more reasonable scenario” of a 5.5-GW shortage and a “potential for more extreme conditions” — considering a projected 60-GW peak and a need for 3.5 GW of reserves.
But when ERCOT posted market information at 8 a.m. on Feb. 28, it indicated a surplus of 3.4 GW, boosted by 7 GW of wind energy. Later that day, ERCOT switched to a second vendor’s more conservative forecast of wind production.
ERCOT assessments on Feb. 28 for a March 5 peak | ERCOT
‘Voluntary’ or not?
Generator representatives objected to ERCOT’s descriptions of the event. Calpine’s Brandon Whittle noted ERCOT used the terms “ask” and “voluntary” in reviewing the event, but said it was “not the case for my shop.”
The OCN “was just a notice. We get many of those during the year,” he said. “[ERCOT said,] ‘We issued an OCN, no one did this, now you have to respond.’ Ultimately, this is an issue for operators and generators to determine when it is to their economic advantage to start a plant or do whatever they need to do.”
“When we issued the OCN, our expectation was people on their own would respond to it,” Woodfin replied.
“The language I heard over and over that afternoon and the next morning, in discussions with ERCOT staff and management, was that because no one responded to the OCN, you have to do this,” said Whittle, using “strong arm” to describe the underlying message he received from staff. “Part of the instruction to generators was if you don’t move your outage, we’ll cancel it, or you will have it forced.”
When Woodfin explained ERCOT was requesting outage delays so generators could maintain their place in the schedule, Whittle responded, “Is that not a threat in some way?”
“We were trying to help them,” said Woodfin, who observed communications between ERCOT operators and market participants. “All those communications were very cordial. There was no animosity.”
Calpine’s Brandon Whittle (left) and Luminant’s Ian Haley
Eventually, more than 6.5 GW of generation originally scheduled to begin planned outages was available through the cold spell.
Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitor, said that while she was supportive of the grid operator’s description of events, it also reminded her of the “offerhecouldn’trefuse” line from “The Godfather.”
“‘Either your brains or your signature will be on the contract.’ Either your outage will be moved, or it will be withdrawn,” she said. “That’s what it sounds like right now. That’s not a good situation.”
“No doubt ERCOT was doing what they think they needed to do to maintain the reliability of the system,” Reliant Energy Retail Services’ Bill Barnes said. “We would certainly have a different view when ERCOT declares an OCN and there would be some expectation to take action. The OCN, to us, is information that is interesting, but the No. 1 thing that will drive our behavior is what the prices are doing.
“If the prices are high enough, that would encourage us to change our outage schedule around. I don’t think ERCOT should have that expectation that people are going to start taking all this action unless the market sends the price signal to do so,” he said.
ERCOT “complained of a lack of voluntary outage deferrals after it issued the OCN, but based on the forecasts … there was no reason for the market to expect an extreme situation,” Whittle told RTO Insider on Monday. “Without an expectation of scarcity, the forward prices for the cold snap were not high enough to incent generators to defer outages on their own.”
The generators also complained about a lack of transparency in ERCOT’s development of planning scenarios for March 3-7 and what they saw as a delay in issuing the OCN.
“We want to wait as long as possible to let the market respond on its own,” Woodfin said. “On the 27th, we realized no one was adjusting and we see this [cold weather] coming. Hello? That was what the OCN was for.”
“Issuing the OCN earlier would have prompted more response,” South Texas Electric Cooperative’s Clif Lange said.
Lack of Transparency?
“Why didn’t market prices reflect what was going on?” Barnes asked. “[There was] a lack of transparency in some of the information [provided]. There were also likely expectations that ERCOT would intervene with reliability actions. That should be the focus of what we try to address. There should be confidence in the market.”
Reliant Energy Retail Services’ Bill Barnes
“We try to let the market respond, and hopefully, it will, so we don’t have to take command-and-control actions,” Woodfin said.
ERCOT set a new monthly record for demand on March 5 at 60.7 GW, breaking a mark set in 2014. The grid operator wound up with 66.5 GW of capacity to work with, and it canceled the OCN at noon on March 6.
Prices briefly eclipsed $1,300/MWh in the real-time market and approached $800/MWh in the day-ahead market during the morning hours. There were also periods of lower operating reserve demand curve (ORDC) reserves and higher ORDC price adders during the same period.
Asked whether ERCOT believed it had completed all reasonable options before issuing the initial OCN, COO Cheryl Mele responded, “We’ve heard that message.”
“We’re already talking about the ways we can ensure we’re portraying to the market all the things we are looking at,” she said. “The root of the problem is we didn’t do a good job of selecting the forecast early enough that would be what we thought was going to be the most likely outcome.”
Pricing outcomes for March 5 | ERCOT
ERCOT staff will review its existing Protocols governing the use of OCNs and other market notifications, and it has already begun discussing improvements to its communications processes. Separately, Helton said he would work with TAC Vice Chair Diana Coleman to assemble a group to review how ERCOT distributes planning information data, its definitions or levels of emergencies in the planning horizon, and the timing of market notifications.
Texas Public Utility Commission Chair DeAnn Walker was among the interested observers during the two-hour discussion. Walker did not join in the discussions, but the PUC has opened a docket (Project 49378) to review ERCOT’s “outage scheduling processes” and has placed it on the agenda for its April 4 open meeting.
Despite record-high capacity factors and reduced operating costs, the U.S. nuclear power industry is threatened by federal and state policies and an “increasingly distorted” energy market, Nuclear Energy Institute CEO Maria Korsnick said last week in her annual state of the industry address.
Maria Korsnick | NEI
“Our capacity factor and generation has never been higher, and our operation costs have not been this low since 2004,” said Korsnick, citing the 2018 capacity factor of 92% and a 25% drop in “average total generating costs” since 2012. Nuclear power produced 20% of the nation’s electricity in 2018 and more than 55% of emissions-free power, she added.
But Korsnick said nuclear’s role in limiting carbon emissions is at risk from both RTO energy markets that fail to compensate them fairly and renewable portfolio standards in more than half of the states that limit their carbon-free technologies to wind and solar. “They ignore nuclear, and that’s shortsighted,” she said.
‘Not a Bailout’
She noted that the Nature Conservancy and the Union of Concerned Scientists have become more supportive of nuclear power, calling it a recognition of nuclear’s role as the “workhorse” of emission-free generation.
“I think it’s a realization that this idea of 100% renewables is not gonna happen,” she said in a Q&A session with NEI’s senior director of external communications, Monica Trauzzi. (Although Trauzzi asked some questions from viewers, Korsnick did not take questions from the media.)
Korsnick praised state officials in Illinois, New York, New Jersey and Connecticut, who have authorized new revenue streams to keep their nuclear plants operating, while noting that 12 plants nationwide are planning early retirements. (See related story, Clock Ticking on Pa. Nuke Subsidy Bill Hearings.)
“Saving nuclear plants is not a bailout. It is not a subsidy. It’s helping to right wrongs in an increasingly distorted energy market,” she said.
Korsnick said the industry also is at risk of losing its competitiveness internationally, saying two-thirds of the reactors being built around the world are from China or Russia. She called on Congress to reauthorize the Export-Import Bank and restore its quorum to ensure the financing needed to compete internationally.
Bright Times Ahead?
Korsnick was nevertheless optimistic about the future, saying 2020 could see the Nuclear Regulatory Commission approve its first application to renew a plant license for a second time; it would add a second 20-year extension, for a total of 80 years. Next year also could see NRC certification of NuScale’s design for a small modular reactor.
NEI has high hopes for bipartisan legislation introduced last week to create public-private partnerships to develop, test and deploy new nuclear technologies. It follows President Trump’s signing in January of the Nuclear Energy Innovation and Modernization Act, which seeks to accelerate the development of new reactor designs.
Korsnick said she was hopeful NRC’s Transformation Initiative would result in “off ramps” that allow the commission to terminate proceedings involving issues of “low-safety significance.”
The Electric Power Research Institute “came out with a report recently and mentioned that the current designs … are over 100 times safer than the original safety goals that the NRC set many years ago. … The industry is mature,” she said. “Let’s come up with ways — we’re calling it off ramps — so that we’re not spending an inordinate amount of time … churning on an issue that quite frankly just has low safety significance.”
Korsnick’s speech came the day before the 40th anniversary of the partial meltdown at Three Mile Island, which ended the expansion of nuclear power in the U.S. for decades.
Vogtle Milestone
Korsnick celebrated progress on Georgia Power’s Vogtle plant, which reached a milestone March 22 with the installation of the containment cap on Unit 3. Vogtle will be the first new U.S. nuclear plant built in three decades.
She did not mention the delays and massive cost overruns that have plagued Vogtle, and which led to the cancellation of a nuclear project in South Carolina. She said only that “massive infrastructure projects are always messy. They don’t always go as planned.”
Vogtle nuclear plant construction | Georgia Power
In 2008, Georgia Power estimated that Vogtle Units 3 and 4 would cost $14.3 billion and begin commercial operations in 2016 and 2017, respectively. The most recent estimates put the total cost at about $28 billion and the completion dates in November 2021 and November 2022, according to Taxpayers for Common Sense.
The Department of Energy last month approved an additional $3.7 billion in loan guarantees for the project, bringing total taxpayer liabilities to more than $12 billion, the taxpayers group said.
The ERCOT Technical Advisory Committee last week tabled a request to lower the grid operator’s peaker net margin (PNM) threshold pending further direction from the Public Utility Commission of Texas, which is debating the threshold’s continued existence.
The PNM threshold is used to determine the point at which ERCOT’s systemwide offer cap is reset from the high limit of $9,000/MWh to the low cap (the greater of $2,000/MWh or 50 times the daily effective fuel index price).
The ERCOT Protocols require the PNM threshold be set at three times the cost of new entry (CONE) for a power plant, historically a combustion turbine. The threshold has been $315,000/MW-year in recent years, but a Brattle Group report in December identified the latest CONE for a CT to be at $88,500/MW-year.
ERCOT has proposed the PNM threshold be reduced to $265,500/MW-year, which is three times the recently determined CONE.
“We’re taking something that came out of an academic exercise. This needs more vetting,” Reliant Energy Retail Services’ Bill Barnes said.
“Several of us have commented at the commission,” said Direct Energy’s Sandy Morris, representing the Independent Retail Electric Providers segment. “You might have a resolution from the commission. If we don’t hear from the commission, then we can proceed with what we hear here. That’s fine with me. … I want to see a lower CONE.”
ERCOT’s Dan Woodfin addresses the TAC at its March 27 meeting.
RTC Task Force to Begin Work April 4
The TAC endorsed the creation of a task force to establish market rules for implementing real-time co-optimization (RTC), which PUCT Chair DeAnn Walker hopes will bring “economic benefits that exceed its costs” and “operational benefits for ERCOT as well.” The PUC has directed ERCOT to proceed with RTC’s implementation (Project 48540).
The Real-Time Co-optimization Task Force (RTCTF) will be led by ERCOT Compliance Director Matt Mereness and Bryan Sams, director of regulatory affairs for Lone Star Transmission. Mereness will serve as either chair or co-chair alongside Sams, depending on the task force’s determination.
“It’s an honor to do this. It’s a big deal,” said Mereness, who promised up to three meetings a month. ERCOT has said it will take four or five years and about $40 million to implement RTC.
The RTCTF will report directly to the TAC and comprise stakeholders and staff from ERCOT, the PUC, the Independent Market Monitor and Office of Public Utility Counsel. It will hold its first meeting April 4.
ERCOT staff have said RTC will efficiently coordinate the provision of energy and ancillary services (AS) in the real-time market and price AS shortages according to their defined demand curves.
ERCOT Gathering Input for Storage Workshop
ERCOT staff briefly reviewed a list of issues to be discussed during an April 23 workshop on energy storage. Staff are still gathering input on the workshop, which will also include a brief overview of an April 25 workshop on inverter-based resources.
The PUC opened a rulemaking on energy storage ownership (Project 48023) following last year’s rejection of AEP Texas’ request to connect two West Texas battery storage facilities to the ERCOT grid. Transmission and distribution providers have squared off against generators over the devices’ ownership. (See “Commission Welcomes Legislative Input on Energy Storage,” Texas PUC Briefs: Jan. 17, 2019.)
TAC Approves RMS Leadership, 15 Revision Requests
The TAC approved American Electric Power’s Jim Lee as chair and Just Energy’s Eric Blakey as vice chair of the Retail Market Subcommittee, which serves as a forum for resolving retail market issues directly affecting ERCOT and its Protocols. Lee and Blakey are exchanging the positions they held through much of 2018, maintaining the RMS’ unofficial practice of having a utility representative and a retail electric provider representative share the leadership positions.
The committee also endorsed 11 Nodal Protocol revision requests (NPRRs), two changes to the Retail Market Guide (RMGRRs), one to the Resource Registration Glossary (RRGRR) and one system change request (SCR):
NPRR891: Removes the 50-kW threshold for non-opt-in entities to report unregistered distributed generation to ERCOT for its unregistered DG report.
NPRR900: Addresses inconsistencies in the current Nodal Protocol language that don’t align with current processes, PUC rules and system design.
NPRR906: Streamlines the Protocol language and removes ambiguity over how ERCOT systems handle the decision-making entity during security-constrained economic dispatch’s (SCED) mitigation processes.
NPRR908: Aligns RMG references and updates mass transition notification requirements for emergency qualified scheduling entities to match with RMGRR159’s revisions.
NPRR909: Resolves a gap in the Protocols by addressing the unplanned unavailability of emergency response service (ERS) loads and generators.
NPRR912: Addresses the settlement of switchable generation resources (SWGRs) that receive a reliability unit commitment instruction to switch from a non-ERCOT control area to the ERCOT control area. The change provides a make-whole payment for an SWGR when its real-time ERCOT revenues are not sufficient to cover certain specified costs the resource may have incurred in complying with the RUC instruction.
NPRR914: Adds data points unique to a controllable load resource available for dispatch service or dispatch with a real-time market bid to the existing 60-day SCED disclosure report.
NPRR916: Sets the mitigated offer floor to $0/MWh for “combined cycle” and “gas/oil steam and combustion turbine” resource categories, replacing the fuel index price-based calculation. The change also eliminates the grey-boxed language from NPRR664.
NPRR920: Modifies the resource ramp rate logic in the Protocols (Section 6.5.7.2, Resource Limit Calculator) to dynamically adjust the amount of ramp rate reserved for regulation service in real time based on the percentage of regulation service being deployed in the opposite direction.
NPRR922: Aligns the DC tie import forecast with forecasts of other resources in ERCOT’s Capacity, Demand and Reserves (CDR) report that are deployed during ERS and other energy emergency alert events. The revision also addresses a reporting gap in the CDR by specifying an approach for forecasting expected capacity imports for planned DC tie projects.
NPRR925: Increases the minimum quantity that can be submitted for point-to-point (PTP) obligation bids from 0.1 MW to 1 MW, matching the minimum quantity for energy-only offers and energy bids.
RMGRR158: Codifies competitive retailer responsibilities during an extended unplanned system outage.
RMGRR159: Clarifies the mass transition processes and communications by: shortening required minimum timelines for initial notification to affected parties from two hours to one hour; allowing preliminary notification of mass transition to affected transmission and distribution service providers, providers of last resort and PUC staff, as long as protected information is not disclosed; and clarifies that ERCOT may coordinate periodic testing of mass transition systems and processes with market participants.
RRGRR020: Corrects certain submittal requirement fields inadvertently left blank during RRGRR007’s implementation by replicating requirements from the full interconnect study column to the planning model column for the affected rows. The request does not add any new data requirements to the glossary.
SCR798: Introduces a limit on the total number of PTP obligation bids that can be submitted into the day-ahead market per qualified scheduling entity and per counter-party. The limit will apply to the number of bid IDs per operating day.
CARMEL, Ind. — FERC on Friday granted MISO permission to implement the remaining two proposals in its three-part short-term resource availability and need project.
Facing baseload generation retirements, more frequent emergencies and diminishing capacity margins, MISO had proposed stricter outage scheduling rules and annual real power testing for demand response. FERC said MISO could implement both provisions, though it wants the RTO’s Maintenance Margin tool chronicled in its Tariff.
In February, FERC approved a MISO proposal requiring owners of load-modifying resources to provide firmer and more clearly documented commitments regarding their availability. (See MISO LMR Capacity Rules Get FERC Approval.)
Taken together, the three filings are geared toward freeing up an additional 10 GW of supply as MISO navigates its spring maintenance outage season and the arrival of warm weather.
Stricter Outage Planning
MISO can now impose new generator accreditation penalties for planned outages taken during what it deems “low margin, high risk periods” (ER19-915). RTO staff have said the rules will incent the forward scheduling of planned generation outages.
FERC approved the proposal effective Monday and said it expected the rules will promote advanced scheduling, improve outage coordination and help MISO address its recent spate of shoulder period emergencies.
“MISO’s proposed Tariff revisions add specificity and incentives to the Tariff’s existing provisions governing the scheduling of generator planned outages,” FERC said.
MISO generation resources now must provide 120 days’ notice for planned outages. However, outages scheduled between 14 and 119 days in advance will be exempt from the RTO’s accreditation penalties, provided the outages are scheduled during predefined periods with adequate margins. Generator planned outages and derates scheduled fewer than 14 days in advance and occurring during a declared maximum generation emergency would be subject to accreditation penalties. The proposal also provides safe harbor provisions for resources that adjust a planned outage at MISO’s request.
The RTO also has instituted a transition period to the new set of outage rules. Outages scheduled prior to April 1 will not be subject to the accreditation penalty, while requests and revisions submitted April 1 and beyond for outages starting April 15 through July 29 would be exempt from the penalty if the request is submitted no later than 14 days in advance and MISO foresees “adequate projected margin at the time of the request.” The full set of outage requirements will go into effect for outages scheduled to start July 30 or later.
MISO said that although it has so far managed generation outages through voluntary rescheduling, “there has been a significant increase in the number of maximum generation emergencies that are at least in part driven by highly correlated generator planned outages.” The RTO said only 30% of planned outages are scheduled 120 days or more in advance, with most being scheduled just weeks in advance.
A group of state regulators and Prairie Power argued that MISO wasn’t providing enough detail into what load forecasts it uses in its Maintenance Margin tool, the nonpublic webpage the RTO maintains to help members schedule outages during adequate supply conditions.
The two also contended that MISO mischaracterized the accreditation penalty as an “incentive”; violated its stakeholder process by allowing just 11 days for stakeholders to review the final proposal; and that the proposal “ignores the real world of utility operations” in which previously unknown problems can be uncovered as equipment is disassembled. Indiana Municipal Power Agency and Southern Minnesota Municipal Power Agency also derided the 14-day deadline as “arbitrary.”
But FERC said the tiered approach “provides MISO with the forward transparency it seeks, reduces the risks associated with correlated [outages] and maintains sufficient flexibility for generator owners to schedule their [outages] without risk of an accreditation penalty.” FERC also pointed out that outages scheduled fewer than two weeks in advance aren’t automatically subject to an accreditation penalty unless the outage occurs during an emergency.
However, FERC agreed with WEC Utilities and American Municipal Power that MISO needs to define the Maintenance Margin in its Tariff. The tool “is the sole factor in determining whether there is an ‘adequate projected margin’ under the proposed Tariff revisions,” FERC said, and as such, should be recorded in the MISO Tariff.
“We find that the Maintenance Margin can have a significant impact on rates, terms and conditions of service,” the commission said, directing MISO to make a compliance filing by the end of April.
Real Power Testing for DR
FERC on Friday also approved MISO’s proposal to require annual actual power tests from its DR resources (ER19-651).
The RTO had asked for permission to conduct the tests to get more certainty about resources’ ability to perform when needed during tight operating conditions.
At MISO’s recent Board of Directors week in New Orleans, RTO executives said the move will put DR on a more level playing field with other resources, which are already beholden to the annual power tests.
DR resources that complete the annual testing will receive credit for one of the five deployments required of them in a planning year. MISO has said that resources that are deployed and follow all scheduling instructions in a planning year will not be subject to the testing in the following year.
MISO has also said it will waive the testing requirements for DR resources “that are subject to regulatory restrictions that preclude testing.” Additionally, a DR resource that simply wants to opt out of testing can do so, provided it agrees to pay MISO three times the cost of demand reduction for non- or underperformance.
Some MISO member companies protested the filing, arguing that the RTO failed to justify the need for annual testing; the testing would cause DR to exit the market; the proposed penalty cost was arbitrarily punitive; and an annual testing requirement would result in increased production costs and risk to equipment.
But FERC disagreed on all fronts.
“To the extent that MISO’s proposal increases costs on demand resource owners, they can reflect those costs in their submitted offers into the auction,” FERC said.
WASHINGTON — Transportation Security Administration officials last week defended their efforts to protect the country’s natural gas pipelines, telling FERC they are adding more staff to the effort.
The importance of securing gas infrastructure was a recurring theme at a technical conference organized by FERC and the Department of Energy on security investments for energy infrastructure — an acknowledgement of the fuel’s growing importance to the country’s electric generation mix (AD19-12).
TSA — established under the newly created Department of Homeland Security after the Sept. 11, 2001, terrorist attacks — has come under increasing scrutiny in the last year over its role in securing pipelines.
Last June, the Houston Chronicle published an op-ed by FERC Chairman Neil Chatterjee and Commissioner Richard Glick that called on Congress to move responsibility for pipeline security from TSA to “an agency that fully comprehends the nation’s energy sector and has sufficient resources to address the growing cybersecurity threat to gas pipelines.”
The Government Accountability Office issued a critical report in December that noted TSA’s Pipeline Security Branch had only six full-time equivalent employees watching over more than 2.7 million miles of natural gas, oil and hazardous liquid pipelines.
In January, the U.S. Intelligence Community’s Worldwide Threat Assessment warned that Russia and China can launch cyberattacks that cause “localized, temporary disruptive effects on critical infrastructure,” such as pipelines. (See GAO Critical of TSA Pipeline Security Efforts.)
At a Senate Energy and Natural Resources Committee hearing on energy cybersecurity in February, some senators questioned whether Congress should give the pipeline job to a different, energy-focused agency. (See Senators Call for Urgency on Energy Cybersecurity.)
The GAO report suggested TSA’s pipeline role has been neglected by the agency in favor of airport security, a conclusion TSA Administrator David Pekoske did not dispute at Thursday’s hearing.
One of the criticisms of the GAO report was that “the agency has a detailed allocation plan for strategically aligning resources to screen passengers at TSA-regulated airports, but not for the entire agency.” Pekoske said that currently, all the agency’s inspectors, including those designated for surface transportation, are on the staffs of the 440 airports under TSA jurisdiction. “But we’re going to make a change to that,” he said.
Pipeline is one of the six modes of transportation under TSA’s jurisdiction, along with Aviation, Freight Rail, Highway & Motor Carrier, Postal & Shipping, and Mass Transit, according to the agency’s Cybersecurity Roadmap.
Pekoske also said he was consolidating the agency’s multiple “policy shops” into one. “I think there is a lot to be learned from security in other sectors that apply across the board, so all of our policy is going into one place.” He said he is also establishing regional offices co-located with the Federal Emergency Management Agency in New York City, Atlanta, Chicago, Dallas and Seattle.
“We already have a [regional presence] in place right now; it’s primarily purposed to support our aviation security mission,” he said. “I’m repurposing that … to advance the surface transportation security mission and also advance our contingency and planning response capability.”
Another criticism of the GAO report was that TSA lacked a strategic workforce plan to identify the skills required of its employees, such as cybersecurity expertise. Pekoske said the agency was “working very hard on” investing in staff with cybersecurity expertise. It currently relies on DHS’ Cybersecurity and Infrastructure Security Agency, “but it’s my desire to have specific, industry-related cybersecurity expertise within TSA,” he said.
“We believe TSA has both the tools and the authority to address any threats within the pipeline industry,” said Sonya Proctor, the agency’s assistant administrator of surface operations. “As a result of the realignment of resources that the administrator has undertaken, we’re going to be able to increase the number of personnel focused on pipeline security, which means we will have a presence in the pipeline community on a very regular basis.”
Though TSA has the authority to issue mandatory standards, its voluntary Pipeline Security Guidelines “provide us the flexibility to address threats outside of the time-consuming regulatory process, which could conceivably take months or even years to go through,” Proctor said. She also noted that as administrator, Pekoske has the authority to issue mandatory directives to pipeline companies in the event of an emergency or serious threat.
Pekoske urged those listening to visit the agency’s website and view its 2018-2026 Strategy and Administrator’s Intent. Neither of these documents, however, specifically mentions pipelines.
Neither Pekoske nor Proctor mentioned current staffing levels, or how many people would be added.
Questions of Standards
TSA published the documents Pekoske mentioned shortly before the Chatterjee-Glick op-ed. Chatterjee has backed off somewhat on the recommendation that pipeline security be reassigned, telling senators and the National Association of Regulatory Utility Commissioners that he had been impressed by Pekoske’s and the industry’s efforts since the article’s publication.
“TSA and industry should have an opportunity to better address cybersecurity concerns on a voluntary basis before anyone imposes mandatory cybersecurity standards for gas pipelines,” he said Thursday.
Glick pressed Proctor about how the agency prioritizes its pipeline oversight. According to the GAO report, TSA takes the top 100 critical pipeline systems, ranked by the volume of fuel transported a year, and re-ranks them through a risk assessment that calculates threat, vulnerability and consequences to determine their priority in getting reviewed.
“Putting aside the 100, what do you do with regard to the rest of the pipeline system around the country, including the distribution pipelines?” Glick asked.
Proctor said that the agency isn’t limited to the top 100 when it conducts its reviews, “but clearly we’re looking at risk, and we’re looking at the resources we have to apply to that risk so that is where our focus is first.” She said the agency will have the capability to review more than the top 100 with Pekoske’s resource realignment.
The GAO report said that operators of at least 34 of the top 100 had identified no critical facilities, speculating that this was because TSA’s guidelines lack a clear definition of the criteria to determine facilities’ criticality. Glick asked Proctor if the agency only did reviews of pipelines that had identified critical facilities.
“That is the language in the Pipeline Security Guidelines, and that’s something we continue to discuss with the pipeline systems, so that’s an area we continue to work with,” Proctor responded.
Glick also asked Don Santa, CEO of the Interstate Natural Gas Association of America (INGAA), why the industry doesn’t support mandatory standards.
“INGAA thinks the current collaborative model with the Transportation Security Administration works well, and in fact it is improving,” Santa replied. “We think that, as Assistant Administrator Proctor described, it enables us to be more agile and reacting quickly to things than if we were in a mandatory situation. …
“Let’s focus on improving [TSA’s work], making it better [and] getting it to be what it can be, rather than on changing the model,” he concluded.
NERC CEO Jim Robb was noncommittal over whether there should be mandatory pipeline standards.
“The gas system and the electric system are so intertwined right now from a reliability perspective that the gas system has to have at least equivalent secure reliability to serve its needs as the electric system that’s built on top of it,” he said in response to a question from Glick. “So, whether it’s through a mandatory standards regime or some other regime than what TSA is doing today or just through the work that TSA is doing, I don’t really care so much about that. What I do care about is making sure that the gas is there when we need it.”
PJM filed its energy price formation proposal with FERC on Friday, after a yearlong discussion with stakeholders produced no consensus.
The RTO said its plan — submitted unilaterally under Section 206 of the Federal Power Act — appropriately values energy reserves during times of stress. It said the proposal relies on concepts that have been used successfully by other RTOs to capture the real-time actions of grid operators, including a revised operating reserve demand curve (ORDC); improved utilization of existing capability for locational reserve needs; alignment of the day-ahead and real-time markets; and increased penalty factors (EL19-58).
“Proper price formation is critical to ensuring that prices reflect the value of the reserves required to operate the system. PJM’s proposal represents a major step forward in the design of the market,” said Stu Bresler, senior vice president of operations and markets, in a press release Friday. “These resources are not just critical to reliability today and in the future, they will provide the backup flexibility needed so that the grid is prepared for the continued integration of alternative sources of energy.”
PJM’s realignment of its reserve market under the proposal it filed with FERC | PJM
Bresler said renewable portfolio standards for D.C. and the RTO’s 13 states call for adding 25,000 MW of wind and 12,000 MW of solar by 2034, adding a level of complexity to reserves that existing rules don’t address. Ensuring reliability — and ultimately more competition and lower prices — depends on the reserve market reflecting the value of operator actions, Bresler said.
“There’s ample evidence that our reserve pricing needs to be reformed,” he told RTO Insider on Friday. In “41 out of the 48 hours of the polar vortex in January [2019], the price for synchronous reserve was at or near zero. To have the reserve price so close to zero, it doesn’t really make sense.”
Synchronized reserves are those able to provide power or remove demand within 10 minutes.
A Contentious Process
Despite meeting 23 times over 13 months beginning in January 2018, the Energy Price Formation Senior Task Force was unable to reach consensus. Tired of the stalemate, the PJM Board of Managers in December demanded staff move forward without member support if no consensus was reached by Jan. 31.
The Markets and Reliability Committee voted on five proposals in January, none of which cleared the two-thirds threshold required for a Section 205 filing under the FPA. Members protested the board’s deadline as “arbitrary,” but a last-ditch effort at compromise fell short on Feb. 6. (See Last Gasp Bid on Energy Price Formation Falls Short.)
Staff, however, did grant the unusual step of seeking feedback from stakeholders on the filing before submitting it to FERC. The March 14 meeting produced “helpful” input, said Bresler, who noted that staff asked the commission for an extended 45-day comment period to give members ample time to weigh in.
“Frankly, I hope we never have to use this [Section 206] process again,” he said. “But we do think that it is beneficial to get stakeholder feedback, because they usually do point out things that are a benefit to clarify in the language.”
American Municipal Power CEO Marc Gerken said on Wednesday he believed the board’s deadline pressured staff into filing prematurely, leaving the door open for market flaws. (See related story, Rushing Price Formation Filing Unwise, AMP Tells PJM.)
He also criticized the RTO for tweaking the language in its proposal after the Jan. 24 MRC meeting. PJM posted slides detailing these revisions just 24 hours before the March 14 meeting, he said, which wasn’t enough time to review and respond to such “significant” alterations.
Bresler disagreed with Gerken’s characterizations of the process. “I think it’s reasonable to expect that with a proposal like this there are many details that fall under the major components, if you will, that are in constant flux. You saw that with the voting process during stakeholder meetings,” he said. “It’s reasonable to expect that that’s going to be the case. I think we were getting down to a level of detail that we needed to ensure that we had a complete proposal.”
Section 206 filings come with no statutory deadlines, though PJM requested the commission rule by Dec. 15 in order for the RTO to implement changes by June 1, 2020.
ATLANTA — The ballroom at NERC’s Human Performance Conference was pin-drop quiet Wednesday as Joseph W. Pfeifer, former chief of counterterrorism and emergency preparedness for the New York City Fire Department, gave an hourlong speech recounting his experience leading firefighters into the World Trade Center on Sept. 11, 2001.
Pfeifer’s experience was captured in brothers Gédéon and Jules Naudet’s documentary, “9/11.”
One of the filmmakers accompanied Pfeifer, then a battalion chief, as he and his men rushed to the World Trade Center after the North Tower was hit by the first highjacked airliner at 8:46 a.m. The film captured the chaos and confusion when the second plane hit the South Tower at 9:03 a.m., then the collapse of the South Tower at 9:59 a.m., which left the glass-walled lobby of the North Tower pitch black.
It was then that Pfeifer ordered his firefighters to abandon rescue efforts and evacuate the North Tower, he told the conference, which was co-hosted by the Department of Energy and the North American Transmission Forum.
“That sounds like a simple order when you look back in hindsight. I had no idea that the whole [South Tower] had collapsed. I thought the only people in trouble were us. But giving an order where you are pulling the rescuers out and leaving a thousand people behind is not an easy order at all. But it’s using that two parts of the brain — the intuitive part and the analytical part.”
Pfeifer was back out on the street when the second tower collapsed at 10:28 a.m., sending him and others running away.
Pfeifer said the event illustrated “organizational bias” — how firefighters, EMTs and police tend to stay in their own groups even when working together.
Battalion Chief Joseph W. Pfeifer at the World Trade Center on 9/11 before the collapse of the South Tower | Jules and Gédéon Naudet
After the first tower collapsed, police in a helicopter circling the North Tower reported that the building’s top 15 floors were “turning red” and the corner of the building was starting to buckle. “‘Pull everybody back three blocks,’” Pfeifer said the copter warned, fearing the second building’s collapse.
“That message never got through to the fire department, and the fire department never asked,” Pfeifer said. “Here you have two great organizations — NYPD and FDNY — and they didn’t talk to each other at the most critical time.”
Some 71 law enforcement officers and 343 firefighters — including Pfeifer’s brother — died that day, along with almost 3,000 civilians. Among those killed were the top-ranking firefighter on the scene and other command chiefs.
“We had no command staff. They were all gone. So how do you re-establish command?” Pfeifer asked.
Battalion Chief Joseph W. Pfeifer (right) and other commanders at the World Trade Center command post on 9/11 | Jules and Gédéon Naudet
After the second building toppled, Pfeifer recalled, his immediate boss, Deputy Assistant Chief Peter Hayden, got on top of a burned-out fire truck and gathered the surviving firefighters and reinforcements together.
“The chief said, ‘I want you to take off your helmets, and we’re going to have a moment of silence, because we lost a lot of people today,’” Pfeifer recalled. “And we took off our helmets.
“And then he asked us to put back on our helmets. And in the moment of putting back on the helmets, he re-established command, because there was a lot of stuff to do. There were rescues to be made, and fires to be put out. But what he did, he used what I’m calling now ‘crisis empathy.’ … He listened to what we were feeling.
“We knew it was bad, and we knew we lost a lot of people, but by him being able to recognize that and then articulate it, [it] made all the difference in the world and it re-established command. So, sometimes those small gestures mean a lot more than it sounds.”
In a case that’s grown increasingly convoluted, state regulators last week granted two of the approvals Public Service Company of New Mexico (PNM) had requested to join CAISO’s Western Energy Imbalance Market, but they denied one concession the utility deemed key (18-00261-UT).
The New Mexico Public Regulation Commission found that PNM had complied with state filing requirements and authorized the utility to create a regulatory asset that would allow it to seek cost recovery in a future rate case.
The commission had approved the same two requests for joining the EIM in December, but it vacated the order in February and reconsidered the matter, to the surprise of PNM and environmental groups that supported the move.
Public Service Company of New Mexico has sought to join the Western EIM partly because it facilitates trade in renewable power across the West. | PNM
In its latest order, issued Wednesday, the PRC balked at a third request by New Mexico’s largest utility to “find that it is reasonable to join the EIM and expend necessary funds to do so.” The commission decided PNM was asking it to approve the costs to join the market in advance, without proof of a net public benefit.
PNM estimated it would incur about $29 million in capital costs and expenses, including for 19 new staff positions and computer systems.
“No party objects to the most obvious interpretation [of the reasonableness request], i.e. that PNM seeks approval to join the EIM. But PNM states that it is not seeking commission approval to join the EIM,” Hearing Examiner Ashley Schannauer wrote in her recommended decision, which the PRC’s five commissioners unanimously adopted.
PNM contended it didn’t need the PRC’s approval to join the EIM because it wasn’t necessary for the provision of adequate service, nor was it required by any commission rule or regulatory mandate.
What the utility wanted, Schannauer wrote, amounted to a guarantee that it would get reimbursement of its expenses plus a return on its investment in the form of profits. The hearing examiner concluded PNM was trying to shift the financial risk of joining the EIM from its shareholders to ratepayers.
“PNM asks that it be allowed to recover its costs as long as they are consistent with the estimates provided in this case and as long as the specific costs it incurs are reasonable,” Schannauer wrote. “Ratepayers would be required to pay all of those costs whether the EIM actually produces savings or not.”
The commission agreed with Schannauer that it lacked legal authority to approve “ratemaking treatment in advance of a rate case.” Regulators in other states hadn’t granted their utilities such preferential treatment for joining the EIM, the PRC noted. In a 2014 filing with Oregon regulators, PacifiCorp, the EIM’s first member, asked to defer until a future general rate case the recovery of $20 million in start-up costs required to bring its six-state system into the market.
PNM issued a statement saying it was “profoundly disappointed” that the PRC hadn’t clearly acknowledged the prudency of joining the EIM.
“Membership in the EIM has resulted in cost savings exceeding a half billion dollars for utility companies’ customers since 2014,” PNM said. “In New Mexico, that would produce savings conservatively projected at $10 million annually for PNM customers, increasing to over $20 million annually in the next decade.”
Convoluted Case
The case has taken a series of unexpected turns since PNM declared its intent to join the EIM last August. (See PNM Seeks to Join Energy Imbalance Market.) Initially it seemed as if the utility were merely looking for a nod of approval from regulators, along with a mechanism for eventually recovering its upfront costs.
PNM serves more than 500,000 customers across New Mexico. | PNM
The EIM is entirely voluntary and largely noncontroversial. Proponents have credited the intra-hour, interstate market with increasing the exchange of electricity among Western states, especially power generated from wind and solar resources, and with saving its participants nearly $565 million in the past five years.
On Dec. 19, the commission approved PNM’s application to join the EIM and said the utility’s next general rate case would bear the burden of showing its costs were reasonable and consistent with the estimates presented to the PRC. (See New Mexico Regulators Say PNM Can Join EIM.)
In that decision, the PRC acknowledged staff’s recommendation “that the commission make clear that approval to create the regulatory asset is not a guarantee that the actual costs will be found to be reasonable or prudent. Staff notes that PNM will have the opportunity to support the reasonableness of those costs during its next general rate case and further notes that PNM has acknowledged that the commission will retain final ratemaking review and authority over costs in PNM’s next rate case.”
Then, in mid-January, the Albuquerque Bernalillo County Water Utility Authority, which had opposed the creation of a regulatory asset all along, asked the PRC to reconsider its December order. The commission granted that request Feb. 6 after two new commissioners were sworn in. The news had worried EIM backers that it could delay PNM’s membership in the market for another year and cost ratepayers $10 million in projected annual benefits. (See State Regulators to Re-examine PNM’s EIM Membership.)
Latest Order
The PRC dealt with the matter on an expedited schedule to meet the April 1 deadline.
In its Wednesday order, the PRC said it “does not oppose” PNM joining the EIM, and it gave PNM authority, in the form of an accounting order, to create a regulatory asset to record its expenses and to seek compensation.
However, the commission said the utility’s EIM-related costs and the reasonableness of its expenditures should be decided in the future rate case.
“Preapproval of reasonableness at this juncture in the case would be premature, given that a future determination ultimately must be made that such costs are proven to be reasonable or unreasonable,” the commission said.
It ordered PNM to file annual reports of its EIM costs and savings and CAISO’s quarterly reports on EIM benefits.
PNM did not say if still intended to move forward with joining the EIM in 2021. (See New Mexico Moves Toward Clean Energy, EIM Participation.) “We will not have any further comment until we have time to fully review and evaluate the final order,” the utility said in an email.
ATLANTA — When NERC considers a new reliability standard, it convenes drafting teams heavy on engineering expertise and system operations. But for its eighth annual Human Performance Conference last week, NERC brought in firefighters, psychologists and speakers from the airline industry to provide lessons.
“We find that all industries have people, people who actually operate the same way, whether they’re moving electrons or moving aircraft,” explained NERC Vice President and Director of Reliability Risk Management James Merlo, who served as master of ceremonies for the three-day event, co-hosted by the Department of Energy and the North American Transmission Forum (NATF).
The conference attracted more than 400 attendees from 180 organizations, including linemen, control room operators — and at least one utility billing analyst, who said he attended because his company uses root-cause analysis on billing errors.
At the beginning of the conference, NERC CEO Jim Robb signed a new memorandum of understanding with NATF, whose 7,400 subject matter experts conduct peer reviews to promote “excellence and continual improvement.”
The nearly 90 companies in NATF operate 80% of transmission of 200-kV and higher. “It’s an impactful set of members,” NATF CEO Tom Galloway said. “If we get the forum oriented on a topic, we can typically move the ball forward pretty well.”
Representatives of MISO, Arizona Public Service and Tri-State Generation and Transmission Association shared their experiences with inviting NATF to visit.
MISO’s John Rymer, who formerly worked in transmission substation operations for Duke Energy, said he asked NATF to help transfer human performance (HP) tools from the field to the RTO’s control room. “These assistance visits really help you pinpoint where you need to concentrate your efforts,” he said.
Rymer said he is looking for “low-hanging fruit” in spreading the HP message in real-time and control-room operations first. “You can move that upstream or downstream in our organization, because engineering, IT, all these groups, can utilize the same tools,” he said.
Sage Williams, manager of Tri-State’s Eastern maintenance region, agreed. “HP can affect not just field guys. It’s your entire organization: engineering, system operations,” he said.
Sharing Mistakes, Using Technology
Digger derricks — utility trucks with augers for digging holes for poles and boom-mounted hydraulic lifts for working on wires — played supporting roles in stories by several speakers who shared mistakes they made as linemen.
In a talk titled, “How strong character improves safety and reliability,” former lineman Jeff White, now an HP consultant with Applied Learning Science, recounted how his truck flipped on its side when soft ground gave way underneath its outriggers while he was installing a pole on a new golf course.
After the crew used a second truck to get the first one back on its tires and wiped off the mud, the lead lineman told White and the other crew members not to report the incident. “‘This was a nonevent. What you just witnessed, erase from your memory.’”
White initially agreed, but after a sleepless night, he told his foreman of the incident the next day, fearful that the truck might have sustained unseen damage that could result in an injury to another worker.
“What if the bolts on that turntable — half of them are broken and we can’t see them? What if there’s factures in that steel that we can’t see? I need to speak up,” White said.
In another presentation, MidAmerican Energy displayed 3D recreations of field accidents, crafted by 3DInternet.
Mike Buntz, a MidAmerican line crew foreman, narrated an animation of a near tragedy that occurred while replacing a rotten utility pole. The truck became fully energized when its boom contacted an overhead wire, setting the grass around it on fire. Luckily, no one was injured.
“It wasn’t one of my prouder moments,” Buntz said. “But I agreed [to participate in the animation] hoping that I could help somebody down the road.”
“One of the things that we learned about using these 3D animations is it helps us to have a better appreciation of what actions made sense at the time … what happened and why,” said Sam Reno, MidAmerican’s performance improvement program manager. MidAmerican also is using GoPro cameras mounted on hardhats to produce training videos.
He demonstrated a pilot program using visualization technology that turns an iPad into a situational awareness tool that shows real-time data on substation equipment’s health and other metrics.
Jackson said the tools can help utilities deal with the loss of experience as more of their aging workforce retires.
“We think that this really helps our guys build a deeper knowledge of the tasks and how to do it right,” he said. “We also think there’s an application potential for everything from troubleshooting to [simulations of] high-risk tasks.”
Michelle Miller and former colleague Monika Bay recounted their efforts to improve worker safety at Baltimore Gas and Electric after the electrocution of a worker at a substation.
“You can have the best intervention design in the world, but if you cannot convey it in a way that connects with the head and the heart of these front-line empl
oyees you will not be successful,” said Bay, who left BGE a year ago to start her own company, Safety & Operational Risk Solutions.
Bay said sustaining improvement “is by far the hardest part. This is really about line leaders keeping the language alive — keeping these concepts alive in their own workgroups.”
After her and Miller’s work, workers in the field started bringing risks to them, Bay said.
One such issue: the potentially fatal consequences of confusing a black, yellow-striped electric line with a nearly identical black, yellow-striped, three-quarters-inch, high-pressure, plastic gas pipe.
At BGE, gas lines are supposed to be buried 2 feet below ground, with electrical lines a foot below them. In practice, however, the lines can get transposed, meaning a worker expecting to cut a gas line could end up getting electrocuted by cutting the electric cable. The only apparent difference between the two: The gas pipe has four stripes; the electric cable only three.
“It’s 2 o’clock in the morning, I’m a gas mechanic, I’m 2 feet down in the hole, it’s raining and muddy, and I’m going to tell the difference?” Bay said.
“It wasn’t just this: We had 16 pairs of assets where the gas and electric looked very similar.”
Although BGE had changed to all yellow gas service pipe about 1998, the risk of confusion remained with older pipe. In response, Bay said, BGE formed a joint team of field workers, engineers and training personnel to address the risk through enhanced training, instrumentation and work practices.
“System design often puts risk into the hands of the employees,” she said. “Sometimes we don’t know some of the risk that front-line guys are dealing with because they’re just dealing with it.”
Lessons from the Airlines
Christian Vehrs of Delta Air Lines used an example of how a fuel heater valve was confused with a nearly identical engine anti-icing valve because of time pressures, insufficient paperwork, unfamiliarity with the task, and confirmation bias.
David Marx of Outcome Engenuity used dice to illustrate resilient systems. The more dice you roll, he said, the more redundancy — like setting multiple alarm clocks to prevent oversleeping.
The redundancy provided by multiple “dice” is essential in aeronautics, he said, because while Federal Aviation Administration rules require a 1 in 1 billion chance of failure, “nobody can design a part that will never fail.”
Marx used the experience of pilot Chesley “Sully” Sullenberger, who famously landed his Airbus A320 on the Hudson River when his engines failed after striking a flock of Canada geese shortly after takeoff from LaGuardia Airport in 2009.
Airline engines are expected to fail only once in every 50,000 hours. Because planes must have two engines, the chances of both failing simultaneously should be 50,0002, or 1 in 2.5 billion, Marx noted.
In Sullenberger’s case, however, LaGuardia was near a landfill that attracted birds, meaning the dice were “stuck together,” Marx said. (Airport officials increased their bird-killing programs after the incident.)
In another example, Marx cited a woman who died in 2017 after mistakenly being given a paralytic, vecuronium, instead of the mild sedative midazolam — marketed under the brand name Versed — that had been prescribed for her during a PET scan.
Hospital procedures set four “dice,” starting with an automated dispensary stocked with the drugs. A nurse mistakenly chose the wrong drug when the autocomplete function gave her options after typing the letters “V-E.”
The nurse then failed to check the drug at the dispensary or later when she delivered it to the patient. Finally, the fourth die was the nurse’s failure to remain with the patient to monitor her reaction to the drug.
“What should have been four dice became one,” he said — the active failure of choosing the wrong drug compounded by the nurse’s failure to perform the other three safeguards. The nurse is now facing reckless homicide charges.
Marx said the incident illustrated why many of us ignore speed-limit signs but slow down when we see a police car.
“We are not inherently rule followers; we are hazard and threat avoiders,” he said. “The police officer represents consequence. The sign just represents the rule.”
Lessons from the Football Field
Dave Sowers of KnowledgeVine used a video of the play known as the “Prayer at Jordan-Hare” — Auburn University quarterback Nick Marshall’s unlikely 2013 game-winning touchdown pass over the University of Georgia — in a discussion on the role of luck.
It was 4th and 18 with 36 seconds left in the fourth quarter. Auburn Head Coach Gus Malzahn called for a pass to get the first down, which would have put the team into field goal range. And the intended receiver was wide open as a second receiver went deep, drawing triple coverage. Marshall unwisely threw the ball to the deeper receiver, but two of the Georgia defenders collided, one tipping the ball into the hands of the receiver, who ran into the end zone untouched.
Marshall was lucky in that instance, but his gunslinger judgment ultimately proved his undoing, as too many of his passes ended up intercepted. “That’s why he’s not playing on Sundays” in the NFL, Sowers said. Instead, he plays for the Canadian Football League’s Saskatchewan Roughriders.
HP in the Control Room
Mohammed Alfayyoumi recounted the changes he made since becoming director of Dominion Energy’s transmission system operations center.
He spread out the workload by scheduling switching orders throughout the week rather than having them all on Mondays. He doubled the operations staff to four per shift after benchmarking Dominion’s staffing against similar-sized utilities.
He also increased simulator training, began near-miss reporting and training in root-cause analysis, and eliminated work that didn’t add value by automating 6,000 phone calls per week.
Operator hiring was improved by adding testing and screening, including more complex behavioral interviews.
“We invest a lot in steel and copper but not a lot in humans,” Alfayyoumi said. “Operator selection is vital to human performance, because you cannot fix poor selection. If you hire the wrong operator, there’s nothing you can do to make him better,” he said.
Adaptive vs. Procedural Systems
Consultant Jake Mazulewicz made the case for “adaptive” over “procedural” systems, recounting a conversation with an employee for an unnamed company who complained it had become excessively dependent on procedures.
“He said when an incident happens, even something small — someone cuts themselves with a knife, no stitches, very small stuff — everybody hears about it. And within two or three weeks you can bet your next paycheck that [the] safety and training [department] is going to say … ‘Here’s a new and updated procedure to make sure that never happens again.’
“Nobody even bothers reading the new procedures … because it doesn’t matter, because it’s going to change,” Mazulewicz continued.
Under system-based thinking, he said, “when you see an error … you don’t think who’s wrong, you think that’s a signal that my … system could use some improvement. … Almost every incident we’re talking about is triggered by human error, but it’s caused by a whole lot of other things: latent organizational weaknesses, previous decisions, things like that.
“How do you minimize errors in a system-based thinking? You improve your system. … You make it hard for people to do the wrong thing, and you make it easy for people to do the right thing.”
