WILMINGTON, Del. — An informational update on PJM’s Transmission Replacement Processes Senior Task Force at the end of the Markets and Reliability Committee meeting last week turned into a hotly contested debate and impromptu vote.
The result was that the task force is still on target to resume on July 28. It has been on hiatus since an MRC vote in September, about a month after PJM and Transmission Owners received an order to show cause from FERC to determine whether the TOs are complying with their local transmission planning obligations for supplemental projects under Order 890. The hiatus, requested to focus on responding to the show cause order, was extended until July at the February MRC. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
In his presentation, PJM’s Fran Barrett noted the “predominate desire” of TOs to continue the suspension of the task force and transmission customers’ “uniform desire” to lift resume task force meetings.
The TOs filed their initial response to the show cause order on Oct. 25 and followed up with responses to comments on its filing a month later. The TOs insisted their Operating Agreement already complies with Order 890 but proposed a Tariff amendment providing additional detail regarding the process for planning supplemental projects (EL16-71).
FERC assured the order would be finalized by January, according to Barrett. But the commission didn’t rule on the TOs’ response before losing its quorum in February.
“We’re locked in the horns of an MRC-directed process versus a FERC-directed process, and we’re looking for guidance for how to take that forward,” he said.
Chris O’Hara, PJM deputy general counsel, stressed that the RTO doesn’t have approval authority over TO supplemental projects. “PJM is ready to engage on these topics. However, that engagement might be more productive after FERC takes action on” the situation, he said.
Representatives of several TOs — including Public Service Enterprise Group’s Alex Stern, PPL’s Frank “Chip” Richardson, Exelon’s Gloria Godson and Duquesne Light’s Tonja Wicks — all advised that they would attend task force meetings once the hiatus has ended, but they likely will not be able to make many decisions until the FERC action is resolved. The circumstances that precipitated suspending the task force in the first place haven’t changed, they said.
Godson motioned to continue the hiatus, and Stern offered a friendly amendment to extend it until FERC rules on the issue and reconsider options if nothing has changed by December. “I don’t think our attorneys would sanction our involvement under a show cause order,” Stern said.
Carl Johnson of the PJM Public Power Coalition said he appreciated the “intellectual honesty,” but that he would oppose the motion because there are other issues on which the task force could be productive. Susan Bruce, representing the PJM Industrial Customer Coalition, and American Municipal Power’s Lisa McAlister also opposed the proposal.
“AMP thinks there’s valuable work to be done [before] a FERC order,” McAlister said. “We’re getting a piecemeal change process that’s the result of, frankly, AMP being a very squeaky wheel. … We don’t think that’s the best procedural way for making these changes.”
American Electric Power’s Dana Horton said there are plenty of other issues to focus on at PJM that aren’t under the auspices of a show-cause order. He supported extending the hiatus so stakeholders don’t have to waste time on unproductive discussions. “We don’t want to expend resources to just look at each other,” he said.
The motion to extend the hiatus failed with 1.79 in favor in a sector-weighted vote that had a 3.335 threshold for passage.
WILMINGTON, Del. — The PJM Markets and Reliability Committee on Thursday endorsed a plan to change compensation in the RTO’s regulation market, despite howls from some market participants that units would be shouldered with more work while receiving less pay.
PJM’s Eric Hsia said the changes resulted from staff observation that the RegD, fast-responding signal would sometimes move in the opposite direction of the area control error, exacerbating the frequency regulation problem.
Additionally, many resources were self-scheduling into the market, which amplified the response to the signal, he said. Howard Haas, the Independent Market Monitor’s chief economist, later added that the current market design incentivizes self-scheduling to receive surplus payments.
PJM and the Monitor developed a package of revisions to the market that received 75% approval from the Regulation Market Issues Senior Task Force. The package would, among other revisions, replace the “mileage ratio” portion of the regulation performance credit, which proponents say doesn’t correctly compensate RegD and causes load to overpay for the service. Hsia noted that discrepancy also contributed to the oversupply issue.
In connection with the task force, PJM produced a new regulation signal and requirements that were implemented on Jan. 9. (See “New Regulation Rules Improving ACE Control,” PJM Operating Committee Briefs.)
Transitioning to the revised signals could drive the value of RegD compensation to zero, Hsia said, so the package includes a minimum “regulation rate of technical substitution” (RRTS) value of 0.65 for the first 12 months of implementation and 0.5 for the following 12 months. The RRTS terminology would replace the previous “benefit factor.”
“Really, what we’re trying to do there is ensure that there is going to be compensation even though there will be oversupply,” he said.
Tom Rutigliano, representing the Energy Storage Association, argued that PJM’s plan omits necessary changes. He urged stakeholders to defer voting on the package until it includes greater detail on regulation providers’ obligations, how resources’ physical limitations will be incorporated into the signals and how the metric that replaces the mileage ratio will be calculated.
“We feel the Tariff language seeking endorsement today is unacceptably vague on several key market features,” he said.
The revised regulation signal changed a longstanding, material market rule that the RegD product energy neutral, Rutigliano said. Making the change without revising the Tariff bypasses FERC review in violation of the Federal Power Act, he said. Ten unaffiliated organizations built about 285 MW of storage designed to charge and discharge equally in a 15-minute time frame, he said, but the new signal implemented on Jan. 9 has no firm energy limit and substantially changes performance requirements. Analysts at ICF say the neutrality requirement means that during steep ramp-up or ramp-down hours, RegD resources alone will not be adequate; thus RegA resources will set the market clearing price.
“This is an entire industry that received clear guidance [on] their performance obligations, invested hundreds of millions of dollars in single-purpose machines to meet those obligations and, frankly, had the rug pulled out from under them,” he said. “We are asking that no participant in this market should have that happen to them without getting their day at FERC.”
Hsia had noted earlier that PJM has been working with market participants to address some issues created by the new signal. He said instances of resources being asked to follow a signal for more than 15 minutes dropped to just two in the first half of June. No resources were asked to follow a signal for more than 30 minutes.
The package of revisions will also change how regulation payments are calculated, all without being codified in the Tariff. Rutigliano called this an “unprecedented” situation “where you have what is essentially an administrative pricing curve, and that curve is left entirely to the RTO’s discretion.”
Speaking on behalf of client Beacon Power, Gabel Associates’ Gabbi Hudis said the revisions “have those resources performing additional work while receiving significantly less compensation than the RegA resources.”
“I can appreciate the desire to get this right,” said Gabel Associates’ Mike Borgatti, representing client NextEra Energy. The rule changes are “significant” for some market participants, he said, and neglecting to include them in the Tariff set “an unhealthy precedent.” Additionally, FERC’s lack of quorum means it’s unlikely that delaying the vote a few months will significantly impact how soon the commission will consider the issue, he said.
Haas said all of Rutigliano’ s concerns were discussed by the RMISTF and that FERC orders established the RTO’s authority to make changes to the regulation signal and the rate-of-substitution curve.
“What we’re seeing here in terms of the PJM/IMM proposal is the result of all of those discussions, and those discussions led to ‘we need to fix this issue,’” he said. “We can hold off and continue to talk about this forever, or we can take this proposal to the commission. ESA wants this issue to be in front of the commission. Allowing the PJM/IMM proposal to go forward will allow [that] to happen. … I think that’s the appropriate place to take this.”
Susan Bruce, representing the PJM Industrial Customer Coalition, agreed that the decision should now be in FERC’s hands. “These issues are now before FERC, and we would like to move the PJM/IMM package to allow that to occur because, in our view, currently customers are overpaying relative to the benefit that they’re receiving, so we want to make sure that that doesn’t continue,” she said.
“Something isn’t right about what we’re paying for regulation right now,” the PJM Public Power Coalition’s Carl Johnson said in agreement. “If we do defer [a vote], we risk just taking even longer before we get to a solution on the market side.”
Calpine’s David “Scarp” Scarpignato added that the current processes also harm resources that provide the traditional, slower RegA service. Exelon’s Jason Barker also voiced support for the revisions package.
Proponents of the deferral attempted to negotiate for a specific deadline for making a FERC filing, but Bruce and Johnson were skeptical that additional, more-focused debate — “this time, for reals,” as Bruce put it, invoking youth slang — would produce any better results.
“It’s hard to know whether or not there’s the prospect of consensus,” she said. “It seems like that conversation’s happened, and there’s not consensus. I’m not sure what more could be done to get there in the next two months.”
Many other provisions that affect resources aren’t included in the Tariff to that level of detail, Scarp said, but that’s a separate conversation that goes beyond regulation rules.
“I don’t think all stakeholders are in agreement that all of this should even go in the Tariff,” Scarp said. “If we put every similar provision in the Tariff, instead of being 6-inches-thick, it would be 6-feet-thick.”
Bob O’Connell of Panda Power Funds warned that moving the language into the Tariff instead of the Operating Agreement would shift control away from stakeholders to PJM. He later proposed developing a manual specific to the regulation market that aggregates in one place the market rules currently embedded in multiple manuals.
“If that is what the stakeholders want, I encourage you to move forward with the motion to defer,” he said. “If you don’t want that, if you want to continue to retain some voice in the process other than just an advisory voice, I recommend that you move forward with the RMISTF package and figure out a different way to address how to get the changes you’d like to see changed worked into the Tariff.”
Borgatti made the motion to defer the vote, but it failed, receiving 1.61 in favor in a sector-weighted vote that had a threshold of 3.335 for passage.
John Horstmann of Dayton Power & Light reiterated disapproval with the revisions package that he’s expressed previously, calling it “the final nail in the coffin” for anyone who built to the 15-minute standard.
“It’s very disappointing that this can occur basically unilaterally,” he said. “If we build you [PJM] a one-hour battery today, could the same thing happen a year or two down the road that you want a two-hour battery? Unfortunately, the signal it sends … is that PJM’s a pretty risky place to do business because you really don’t have a lot of rights when it comes to rule changes. … I’ve heard an awful lot of reasons why this is such a wonderful process that got us to this point, but largely, the small number [of] owners that are hugely impacted have been pretty much stonewalled through the process.”
Stakeholders approved the revisions package with a 3.89 sector-weighted vote.
CHICAGO — The Mid-America Regulatory Conference last week drew an above-capacity assembly of public utility regulators, legal counsel and other industry insiders to the shores of Lake Michigan. Registration was initially capped at 550, but 62 more attendees signed up for a conference that featured panel discussions on cybersecurity, energy storage, artificial intelligence and other challenges facing regulators.
Acting FERC Chairman Cheryl LaFleur addressed the commission’s lack of a quorum during her keynote, saying there’s been a “little bit of a plot twist” in D.C.
LaFleur sits in the chairman’s seat for the third time in seven years following Norman Bay’s departure in February, which also left FERC without a quorum. LaFleur is one of only two remaining on the five-person commission. Commissioner Colette Honorable has announced she will not seek a second term when her current one expires June 30. (See Honorable: Leaving FERC, but not Sure When.)
While Honorable has not said how long she might stay on, LaFleur made clear she intends to finish her term, which expires in June 2019. In the meantime, LaFleur and Honorable await the arrival of recent appointees Robert Powelson and Neil Chatterjee, who still await Senate confirmation.
“This will add a line to my obituary and hasten its appearance,” said LaFleur, noting that one of her staffers has grown a “quorum beard” similar to hockey playoff beards.
“And it’s really quite shaggy.”
Orders awaiting a final ruling are piling up. FERC’s regular monthly open meeting is still on the calendar for July 20, but it is expected to be canceled. The commission doesn’t meet in August, meaning FERC might not conduct its second open meeting of the year until late September.
“We’re trying to triage [the orders],” LaFleur said. “We’re assessing the comments, and we’ll frame the issues for the new commissioners. Since we’ll [eventually] have four new commissioners, it’s not for me or Colette to say which way we’ll go.”
In the meantime, the commission is keeping an eye on price formation (“It’s important to send clear and concise signals.”), energy storage (“We’ve gotten a pretty strong signal there’s a lot of work on that.”) and the “issue du jour” — the interplay between wholesale markets and state policies.
“We’ve seen a decoupling of what resources are being built and invested in, driven by federal tax policies and state policies,” she said, citing as examples CAISO’s curtailment of solar and hydro energy, and efforts by SPP and MISO to integrate more than 20 GW of wind energy.
“The states are not satisfied with the resources markets are choosing for them,” she said. “They are subsidizing some resources [nuclear units in New York and Illinois] and requiring utilities to buy resources. Are we going to let the markets choose, or the states choose?
“I always say there are three basic values: what is the cost, the reliability and the environmental impacts? The markets weren’t set up to take the environmental impact into account. They would have to be redesigned,” LaFleur said.
She offered three solutions to the problem: 1) redesign the markets to allow the states to become the “resource payer and selector,” but set a market for nonsubsidized resources and allow the markets to price in carbon; 2) litigation, as is taking place in Illinois and New York; and 3) changing how states handle resource adequacy.
“I’m fine with that,” LaFleur said, “as long as we do it on purpose, and don’t tumble into anything by accident.”
Southern Diversifies
With 46 GW of generating capacity and vast natural gas assets, Southern Co. bills itself as “America’s premier energy company.” But like others in the industry, the utility is weaning itself off coal.
“Carbon is a big issue around the world,” Southern CEO Tom Fanning said during a “fireside chat” with Ellen Nowak, chair of the Wisconsin Public Service Commission. “We have to think about ways to transition our fleet in a responsible way, while balancing the issues of clean, safe, reliable and affordable energy. The transition to that is a big, big deal.”
The company plans to add 1,900 MW of renewable resources, along with 1,000 MW of nuclear capacity and 500 MW of “21st century clean coal.” Its wholesale subsidiary, Southern Power, has added or announced more than 2,400 MW of new capacity from renewable resources and more than 1,400 MW of natural gas capacity since 2010.
Before Fanning arrived at Southern in 1980, the company’s generation was 70% reliant on coal. Coal still made up 67% of the resource mix in 2002, but that number dropped to 31% last year. Natural gas meanwhile increased from 11% to 47%, while renewables now account for 5% of the portfolio.
“It’s all part of our long-term strategy. We really wanted to be long on gas,” Fanning said. “It was clear to us the transition of the fleet had to occur.”
To that end, Southern in recent years acquired a 50% equity interest in Kinder Morgan’s Southern Natural Gas pipeline and created the nation’s largest natural gas-only distribution company by merging with AGL Resources.
“One of the keys to success in building this portfolio of the future is the notion of infrastructure creating options,” Fanning said. “It gives you the scale to withstand stormy seas. Who would have predicted Westinghouse [Electric] would have gone bankrupt?”
Southern and Westinghouse recently reached an agreement to complete two units as part of the troubled Vogtle nuclear plant expansion. Whether the construction is ever completed remains to be seen, but Southern will continue to diversify its portfolio.
“[The U.S.] has the ability to set policy based on the notion of abundance,” said Fanning, who co-chairs the Electricity Subsector Coordinating Council, an advisory board to the federal government. “One of the challenges we saw in the last presidential election was that so many people are viscerally losing faith in the institutions of government and the people running them. We in the industry have to step into the middle and get rid of the red and blue.
“I’m one of the optimists. At the end of this decade, we can easily be net energy exporters, creating wealth, creating a better experience for everybody. We have the public-private partnerships to grow the finances of the states we serve. I believe we can make a difference.”
A panel of Midwest commission chairs agreed that state legislators and regulators will continue to set energy policy direction regardless of what happens in D.C.
Nancy Lange, chair of the Minnesota Public Utilities Commission, said the state’s long-time fuel mix of coal, natural gas, nuclear, Canadian hydro and wind energy is changing in the face of modest load growth (less than 1%). Each of Minnesota’s three investor-owned utilities are adding more wind generation to the mix, driving out coal in the process.
“It’s not because of policy but because of price,” Lange said. “Minnesota utilities are still offering coal as a must-run resource, but they’re on the margin in some cases, and that’s led to some of the retirements we’ve seen. The interesting thing about coal is some of the coal units are not operating as baseload units in the market, largely because they’re not clearing the market price.”
The Illinois Commerce Commission’s Brien Sheahan said renewable energy and energy efficiency will earn 70% of the economic benefits flowing from the Future Energy Jobs Bill, approved in December, which includes zero-emission credits for nuclear plants.
“Some have estimated that at $12 [billion] to $15 billion,” he said. “It’s not just about supply. … It’s really about energy policy and getting the state to lower carbon in the future. Whether we continue to have [a] leadership position depends on what the courts do and what FERC does. There was a lot of discussion at the FERC technical conference about accommodation, harmonization or mitigation. Some of [FERC’s] proposals lean to mitigation too strong.
“Markets exist to serve state purpose. They don’t exist in and of themselves,” Sheahan said.
DTE Energy announced recently that it would phase out coal by 2030, accelerating what the Michigan Public Service Commission’s Sally Talberg called a “fundamental transition in [the state’s] energy supplies.” She said the slow pace of energy policy decisions at the federal level makes it difficult for state regulators and planners to find certainty.
“Often, by the time an investment is made, you get a court ruling,” Talberg said. “Regardless of what we see at the federal level, states are taking the initiative. Naturally, they’re looking at cleaner suppliers. It does provide us the opportunity to move to cleaner and more efficient resources, such as natural gas.”
Nowak pointed to the difficulty of assessing a social value for various fuel resources, asking, “Why are we pricing just wind and solar?
“I’ve always struggled with choosing just one resource to apply that to,” she said. “We don’t do it for nuclear, and we don’t do it for gas. What’s the social benefit for coal? It provides jobs. Nuclear is carbon-free. … Are we going to put social value on that?”
“The [legislative] directive to look at externalities and the social cost … is a very difficult thing for our commission to grapple with,” Lange said. “As these [distributed energy resource] valuations and methodologies move along … we think of them as supply resources and not social resources. Not having to add on that externality piece, which some legislators added on because of some imperative they want to take … will have the carbon fee showing up as costing less in [integrated resource planning] scenarios.”
The staid, hidebound grid operator, with its granular focus on engineering models and studies, has seldom been an attractive landing place for America’s brightest young students. Acronyms like PJM and MISO don’t carry the same cachet as Apple, Google or Microsoft.
However, that is changing quickly, agreed a panel of RTO leaders.
“When I first joined SPP, I kept hearing about this guy, Doug,” said Paul Suskie, an Arkansas commissioner before joining the RTO in 2011. Eventually, Suskie, SPP’s executive vice president of regulatory policy and general counsel, came to learn that “Doug” actually stood for Dumb Old Utility Guy.
No more.
“One of the benefits we have … in the industry is we are kind of cool now,” ERCOT CEO Bill Magness said. “That’s hard to get used to. They see how we integrate wind and solar on the system and how we’re developing markets for the future. They’re introducing us to other students as, ‘They’re doing cool stuff.’ Our mission, to a lot of younger employees, is a very critical thing. We’re doing something that’s important and needs to be done.”
Asked how MISO markets to the younger generation when it can take 10 years to build a transmission line, CEO John Bear said, “Once we bring them into the control room and show them what we’re up against and where we’re headed in the future, that’s very exciting for them.”
They’ve “significantly changed our working environment,” Bear said. “Our offices look more like Starbucks than they did before. That, and the issues we are trying to solve are very intriguing to millennials. They love the mission of the RTOs. They’re not looking to go to Wall Street, but helping people who can’t look out for themselves.”
MISO’s internship program currently brings in 30 to 50 students each cycle. Of course, not all students wind up with a job, Bear said, “but they all go back and talk about what we’re doing. It’s word of mouth. We’re not a big brand, but the compounding effect is very high.”
PJM CEO Andy Ott extolled the virtues of his RTO’s Arc Program, an engineering development initiative designed to provide talent with “career-broadening opportunities.” Participants in the 36-month rotational program spend nine months apiece focused on core learning sessions for markets, system operations and planning.
“It not only gets people excited to work for PJM but improves our diversity,” Ott said.
A diverse team of PJM employees interviews roughly 60 college students a year, hiring only the top three, he said.
“It’s highly competitive. Over the past six years, nearly two-thirds of the candidates we’ve hired are diverse candidates. There’s no mandate. It just happened organizationally.”
Suskie said SPP has also “beefed up” its internship program and has reached out to historically black colleges. “The demographics of the industry are changing,” he said.
Energy storage proponents said battery technology and cost improvements make storage more commercially viable, but regulatory and policy actions still pose challenges.
“Energy storage and distributed generation all offer something we’ve never had in the utility industry before. It gives the customers the ability to choose,” said Betty Watson, senior manager of energy policy for Tesla. “Energy storage … is the ultimate streamlined technology. We now have the ability to react to what’s going on the grid. If you look at ways utilities are incentivized, they need to invest in infrastructure.
We’re talking about a technology that reduces the amount of money you invest [in infrastructure]. There are a lot of current opportunities under current existing regulations, but this technology will drive change in the industry,” she said.
“A market means an opportunity to earn a return on the work we do,” said John Fernandes, Invenergy’s director of regulatory affairs. “Developers are frequently told, ‘Well, show us something. We’d like to take a look at it.’ We need reassurance not that we will get selected, but assurance it’s not an exercise in regulation. It’s an opportunity to compete.”
“By the time someone publishes a cost for energy storage, it’s already improved by the time the ink dries. That’s how fast this market is moving,” pointed out Brent Bergland, general manager with Mortenson Construction. “By the time a report gets to the commissions, it’s old news. It took six months to create, but over six months, you might have a significant drop in the cost of services.”
“It’s up to us to keep the momentum going to understand the technology,” said Kiran Kumaraswamy, AES Energy Storage’s market development director. “Pilots waste years. If we’re making a decision on a study, we ought to be planning now.”
“My frustration with pilots is that they’re too narrow. It’s one location, one set of conditions,” Watson said. “We learned from renewables that when you expand the scope, expand regions and aggregate things, these conditions change. We need to get storage on the system and see how it interacts at multiple uses, so we can integrate it.”
As SPP and ERCOT continue to see periods when wind accounts for at least 50% of energy production — a share SPP predicts could reach as high as 60% — Beth Soholt, executive director of Wind on the Wires, sees no reason renewables couldn’t account for 35 to 40% of energy production at any time.
“I think that’s very doable,” said the Midwestern renewables advocacy group’s leader. “One of the greatest shifts we’ve seen is learning how to operate the system with much more wind. It’s not just technical issue, but a mind-changing issue that you can have a reliable system with a lot more variable generation. We’re seeing coal plants being ramped to the market [like intermittent resources]. I think utilities will get smart about their new role in the integrated market.”
Melissa Seymour, MISO’s executive director of customer and state affairs in the Central Region, said the RTO, which is dominated by vertically integrated utilities, could see between 23 and 41 GW of wind on its system by 2025, creating a greater need for transmission. Most MISO states are on track to meet or exceed their renewable portfolio standards, she said.
“Markets need to really incent the types of products the market needs,” Seymour said. “We have the same issues as we do with storage. Conversations with stakeholders are very important as we continue to grow. We have a lot of resources on the system that want to come offline. MISO is trying to ensure they can do this in a safe way. Enabling effective retirements is something we can do going forward.”
“Now is the time for states and the RTOs … to figure out ways to better coordinate the retail planning of the markets with the wholesale design of the market, optimizing clean-energy resources on the system, to ensure just and reasonable rates and prudently occurred costs, for the assets,” said John Moore, director of the Sustainable FERC Project at the Natural Resources Defense Council.
A panel focused on artificial intelligence and machine learning assured its audience there is nothing to fear as today’s smart grid gets even smarter. AI, which uses complicated algorithms to detect unseen patters, and machine learning, the ability of computers to learn without being explicitly programmed, simply enable utilities to use predictive analytics to forecast consumption, monitor assets to reduce outages and improve efficiencies across the grid.
“Artificial intelligence allows you to use a scalpel, rather than a sledgehammer, to make effective use of your dollars,” explained Anna Lising, senior manager of regulatory affairs for Oracle Utilities.
Jeff Gleeson, a product manager with Nest Energy Services, provided a real-life example with the Nest Learning Thermostat. Owned by Alphabet (parent company of Google), the Nest uses AI and machine learning hidden from the customer to yield more efficient results from their energy usage.
“The grid is getting more complicated. People’s usage needs to match the complexity of the grid,” Gleeson said. “We believe you don’t need to know the complexity. We want you to be comfortable. We’re working in the background … using artificial intelligence and machine learning behind the [thermostat]. The thermostat knows what your [time-of-use] rate is. It nicely corresponds to the grid’s challenges … the solutions are also getting more complex, but the good thing is, we can do it in certain ways that make it very easy.”
“The neat thing about artificial intelligence and machine learning is that it’s been used in the utility industry for over a decade,” said Sean Gregerson, a global director with Schneider Electric Software. “We’re ahead of the curve. Ultimately, machine learning is going to be used for self-healing grids … automatically healing grids that are under stress or failing in unforeseen ways.”
“It’s important for everyone to understand, this is not necessarily as complicated as it sounds. It’s heavily stats-based,” Gleeson said. “If you’re wondering whether the machines are coming for us, know machines have a hard time telling the difference between a plate of fried chicken or a picture of a poodle. If you see the pictures next to each other, you feel bad for the machine, because they look the same.”
There are also unforeseen drawbacks. Gregerson related a story about his children playing with Alexa, Amazon’s voice-responsive “intelligent personal assistant.” After his kids mistakenly signed up for a product agreement, Gregerson said he tried to undo the damage.
Alexa responded: “I’m sorry. I don’t understand that.”
ERCOT’s Technical Advisory Committee has canceled its June meeting because of a lack of voting items.
The TAC’s next scheduled meeting is July 27. The Board of Directors does not meet again until Aug. 8.
TAC Chair Adrianne Brandt, of San Antonio’s CPS Energy, asked committee members to vote by email on a pair of revision requests, setting a 5 p.m. deadline Wednesday for responses:
NOGRR170: Revises the Nodal Operating Guide to be consistent with NPRR824 language related to NERC Reliability Standards EOP-011-1 (Emergency Operations) and BAL-001-2 (Real Power Balancing Control Performance).
RRGRR014: Conforms the Resource Registration glossary to the as-built release, which captured baseline updates before the approvals of RRGRR006 and RRGRR007. The RRGRR adds solar resource registration inputs omitted from the greybox tab for RRGRR009.
New Hampshire regulators on Friday took the first step toward an overhaul of their net metering rules, reducing compensation for rooftop solar owners while ordering a study of the value of distributed generation that will inform long-term changes.
Solar Panels at Exeter High School
The Public Utilities Commission ordered utilities to implement a new alternative net metering tariff that retains monthly netting for small distributed generation system owners while moving to instantaneous netting for non-bypassable charges. The rules, “to be in effect for a period of several years,” will begin Sept. 1 (Order 26,029).
The commission chose a quasi-adjudicative process to reconcile two settlement proposals on how to develop and implement a new alternative net metering tariff, as directed by the state legislature last year in House Bill 1116.
Two Proposals
One settlement proposal came from a coalition of utilities and consumer parties (UCC), including Eversource Energy, Liberty Utilities, Unitil Energy Systems, the state Office of Consumer Advocate, the New England Ratepayers Association, Consumer Energy Alliance and Standard Power of America.
The other proposal was filed the same day by a coalition of distributed generation industry advocates and environmental organizations known as the Energy Future Coalition (EFC), which included the Acadia Center, The Alliance for Solar Choice, the Conservation Law Foundation and eight other organizations and companies (docket DE 16-576).
In its unanimous 74-page order, the commission ruled that:
Small customer-generators with renewable energy systems of 100 kW or less will continue to net meter their DG resources monthly. Those customer-generators will receive monthly net export credits equal to the monetary value of kilowatt-hour charges for energy service and transmission service at 100% and distribution service at 25% — a 75% reduction — while paying the full amount of non-bypassable charges, such as the system benefits charge, stranded cost recovery charge, other similar surcharges and the state electricity consumption tax. Previously, they received kilowatt-hour credits.
Large customer-generators will continue to be net-metered as they are currently but will also receive monetary credits rather than kilowatt-hour credits on a monthly basis. To qualify for alternative net metering, large customers must consume at least 20% of their actual or estimated annual distributed generation system electric production behind the meter.
DG systems installed or queued during the period the new net metering tariff is in effect will have their net metering rate structure grandfathered until Dec. 31, 2040.
Pilot projects will be proposed and a value of DER study will be designed and completed to “inform the development of the next version of net metering or another alternative regulatory mechanism.”
“As the penetration level of DG in the state is quite low in both absolute and relative terms, there is little evidence of significant cost-shifting from DG customers to customers without DG,” the commission said. “Payment of non-bypassable charges by all net-metered customers and a reduction in the distribution credit for net exports should serve to mitigate the potential for such cost-shifting, even if DG penetration levels increase significantly above their low levels.”
The commission said it accepted common elements in the two settlement proposals and resolved differences between them based on the legislative purposes of HB 1116. The bill called for “the continuance of reasonable opportunities for electric customers to invest in and interconnect customer-generator facilities and receive fair compensation for such locally produced power while ensuring costs and benefits are fairly and transparently allocated among all customers.”
The order requires Eversource, Liberty (Granite State Electric) and Unitil to file revised tariffs within 30 days. The commission also approved an automatic rate adjustment mechanism for the companies to recover lost revenue, under the process approved for Unitil in February (Order No. 25,991).
Value of DER Study
The order provides that the alternative net metering tariff take effect while the utilities and stakeholders collect further data, implement pilot programs and conduct a study on the value of DERs.
It directs stakeholders to convene working groups within 60 days to develop proposals on the commission’s mandates. It also requires them to file quarterly progress reports with the PUC. The order also gives concerned parties 30 days to submit written briefs or comments on grandfathering issues, such as the clause that “customer-generators that receive a net metering capacity allocation while the new alternative net metering tariff is in effect to be ‘grandfathered’ at the applicable net metering design and structure then in effect through Dec. 31, 2040.”
Reaction
“The ruling is a mixed bag,” CLF attorney Melissa E. Birchard said.
While the order is an overall win for the state because it sets a path forward to value the broad benefits of clean energy resources and accelerates grid modernization, Birchard said she was dismayed by the cut in the distribution credit.
“It is disturbing to see cuts to an important program like net metering at the same time that New Hampshire is lagging behind the rest of the region on solar penetration and energy efficiency,” Birchard said. “If we’re not careful, other states in the region are going to reap the financial benefits of strong solar and energy efficiency programs while Granite Staters pay more on their electric bill for a disproportionate share of the costs.”
Nashua, New Hampshire Dam
While the distribution portion of the credit is only one piece of the overall credit, “this cut is arbitrary in the sense that there was no real data in the docket to support it, and it will affect the pace of clean energy investments,” Birchard said.
Gradual Change
The commission said that an abrupt change from monthly netting to instantaneous netting would likely confuse customers and send potentially inefficient price signals.
“For example, instantaneous netting may be confusing to customers who lack real-time data about their electricity usage,” said the order. “It may also provide financial incentives for maximum on-site electric consumption during periods when the benefits of DG exports to the system may be greatest, such as at the time of late afternoon system peaks, thereby decreasing the potential system-wide benefits of those energy exports.”
Birchard believes the cuts in net metering will be temporary.
“There should be a new rate established after the commission carries out a value of distributed energy resources study, particularly distributed solar and hydro, and after that study it’s going to open a proceeding to revalue it,” said Birchard. “So the credits that those resources receive will be based on the broad benefits, potentially including climate change and health benefits. That kind of value-based rate can make clean energy innovation more competitive in an open market way so that different kinds of resources can compete with each other based on their value.”
California regulators last week advanced on a plan to study the potential for eliminating the Aliso Canyon natural gas storage facility.
The move came as Southern California Gas reiterated warnings about the impact of gas shortages on grid reliability this summer.
The state’s Public Utilities Commission issued a draft request for proposals to develop an “Aliso Canyon Reliability and Economic Analyses.” The central question to be answered, according to the draft: “should the commission reduce or eliminate the use of the Aliso Canyon storage facility, and if so, under what conditions and parameters, and in what time frame?”
The commission seeks public comment on the draft by June 29 and expects to issue the RFP on July 6. It is considering what elements of the proposal work or could be improved, if any important questions are missing and whether instructions are clear.
Location of Gas Leak at Aliso Canyon Natural Gas Storage Facility | SoCalGas
Injections into the 86 Bcf facility near Los Angeles have been halted since the leak was discovered in October 2015. The restriction was kept in place even after the leaking well was finally plugged in February 2016.
State Senate Bill 380 prohibited reinjection of gas into Aliso until completion of a safety review and required the PUC to determine whether use of the facility can be reduced or eliminated while still maintaining electric and gas reliability.
Winning bidders on the RFP will be required to hold stakeholder workshops and public hearings, as well as perform hydraulic model analysis of the reliability of the Aliso system under a variety of scenarios, using forecasted electricity demand and contribution of renewables to the generation mix.
The PUC is looking for bidders experienced with Synergi Gas software — or an equivalent — and working on gas-electric coordination. Also desired is a background running community forums and “developing models to assess the market, consumer and economic impact of significant changes to the natural gas or related markets.”
Bidders’ proposals are due on Aug. 24, and the contract award date is tentatively set for Sept. 29.
“From our perspective, we are cautiously optimistic that, based upon the CAISO forecast, we will be able to meet the demands on our system. Of course, this is dependent on there being no unplanned outages on either the electric or gas systems,” SoCalGas CEO Bret Lane said in a June 16 letter.
Lane’s letter was accompanied by another June 13 letter from a group of municipal utilities to State Sen. Henry Stern, saying that they have serious concerns with the continuing moratorium on injections that the legislature required until a root cause of the leak is identified. The analysis is not needed because the wells have been retrofitted and gas no longer flows into outer casings, the practice that led to the gas leak, the utilities said.
“We are concerned that the bill constrains the transmission of natural gas, which could limit local electric supply, resulting in electric outages,” says the letter from Burbank Water and Power, Pasadena Water and Power, and Vernon Public Utilities.
The utilities also said that the legislation failed to define a process for emergency gas injections, “suggesting that a response to a blackout might come too late.” They backed SoCalGas’ recommendation that the current gas inventory at Aliso Canyon be increased to prevent blackouts.
The utilities caution that temperatures were moderate last year, which has so far not been the case this year. A heat wave last week swept areas of California, cutting electricity to about 190,000 Pacific Gas and Electric customers and prompting CAISO to issue a conservation alert. (See California Heat Wave Prompts CAISO Flex Alert.)
WESTBOROUGH, Mass. — ISO-NE Director of Regional Planning Mike Henderson on Wednesday presented the schedule for stakeholder comments on the grid operator’s 2017 Regional System Plan, which are due July 24. The plan will be discussed at the August Planning Advisory Committee ahead of a Sept. 14 public meeting in Boston. The draft plan will be posted online by July 7.
“Our view is that the report should be viewed as a [critical energy infrastructure information] document,” Henderson told the PAC during a June 21 teleconference. “In past years, we have noted some, frankly, mistakes that the ISO made in the report where we may have inadvertently included some CEII materials, and as a draft document, that would present a major issue. … We’d hate to see something that does not reflect your [PAC members] input … put out in the public domain.”
Transmission planner Jon Breard presented an update on transmission projects and asset condition as part of the RSP drafting process. One participant asked if, based on the presentation, the growth in transmission spending was coming to an end in 2019.
“I’d be careful about ‘coming to an end,’” said Brent Oberlin, director of transmission planning. “It’s just what we have planned so far [is] really slowing down, and that’s our expectation going forward.” He added that the RTO must still complete reassessments for Maine, New Hampshire and central Massachusetts.
RTO will not Conduct Public Policy Tx Study for 2017
Oberlin presented ISO-NE’s conclusion that no federal or state public policy requirements are currently driving transmission needs, precluding the need for a special study on the subject this year. The RTO’s position aligns with a similar assessment submitted by the New England States Committee on Electricity (NESCOE) last month. (See ISO-NE: Won’t Override States on Public Policy Tx Needs.)
A May 16 letter from the Conservation Law Foundation asked the RTO to conduct the analysis despite NESCOE’s conclusion. NESCOE responded that ISO-NE should evaluate potential projects only after states have indicated transmission needs resulting from their policies.
Paul Dumas of Avangrid asked when the Tariff stipulates that the RTO must start another public policy process.
“At least every three years,” Oberlin said. “So the farthest that we would go out would be initiating the process in 2020. I think we’re going to keep an eye on where the states are with [requests for proposals] and things like that and make our determination if we would go earlier.”
Eversource to Replace ‘Vintage 1950’ Equipment
Eversource Energy’s George Wegh presented CEII material on the utility’s work to modernize several outdated substation control houses in its Eastern Massachusetts service territory. Wegh apologized for informing the PAC after the work had already started. He said Eversource would fix whatever internal communications problem created the lapse in planning protocol.
Two of the control houses being refurbished are “vintage 1950” and still use some of the original equipment, including analog meters and electromechanical relays.
Woodpecker Woes on 345-kV Lines in Eastern Mass.
Woodpecker damage, pole rot and splitting | Eversource
Eversource’s Chris Soderman presented evidence of woodpecker damage and decaying support structures along a 345-kV line in Eastern Massachusetts and similar problems on the Southern Connecticut Loop, where the company will not only replace structures but install optical ground wire to enhance communications and reliability.
The company will replace with steel approximately a fifth of the 262 wooden structures along the 29-mile Northfield-to-Ludlow line in Massachusetts. The estimated $8 million cost includes installing new hardware and insulators.
Southern Connecticut Loop | Eversource
Along the Connecticut line, which runs about 38 miles, Eversource will spend an estimated $68 million to replace 258 structures, many of which have decaying, laminated wood cross arms. Soderman emphasized that the light-duty weathering steel poles being installed on both projects were not custom ordered but off-the-shelf equipment.
National Grid Implements Reliability Scheme on Tx Circuits
Jack Martin of National Grid presented the utility’s plans to install dual high-speed protection systems on 45 major transmission circuits over the next decade to meet standards set by the Northeast Power Coordinating Council.
NPCC Directory 1 mandates that all New England transmission owners meet the performance reliability requirements on Bulk Electric System elements by Sept. 10, 2025.
National Grid will pursue a five-stage rollout and estimates the cost for Phase 1 at $1.8 million. The company expects substantially higher costs for the ensuing phases, which include significant installation of optical ground wire and a number of control house rebuilds. The utility has started conceptual engineering for the other four phases and will update the PAC once it has estimated the costs.
CAISO last week proposed to eliminate from its Tariff an annual state transmission concept plan that it says is obsolete because of changes at the federal level.
The move has support from Southern California Edison and the California Office of Ratepayer Advocates (ORA).
CAISO has developed the Statewide Conceptual Plan each year since 2010 as part of its lead role in the California Transmission Planning Group (CTPG), the transmission owner and operator group once responsible for coordinating local and regional planning across the state under FERC Order 890.
But since the implementation of FERC Order 1000 — the federal process that supersedes the previous planning process — the CTPG is no longer operating, and utilities have generally stopped responding to CAISO’s conceptual plan.
“There is little if any value in the ISO alone developing the conceptual statewide plan, and it detracts limited ISO resources from focusing efforts on the extensive and important planning activities they must otherwise undertake,” CAISO said in its draft proposal.
CAISO Says the Annual Conceptual Transmission Plan is Obsolete | Berkshire Hathaway Energy
The planning process under Order 1000 now covers regional and interregional planning, and the CTPG has not held a meeting in four years, has none scheduled and has no chairperson. The ISO Tariff still requires the grid operator to develop the plan to determine transmission requirements to meet reliability, economic and public policy needs.
SCE, the state’s second largest investor-owned utility, said it “concurs with the proposal’s conclusions and the recommendation to remove the Conceptual Statewide Plan from the California ISO Tariff.”
ORA agreed that the conceptual plan “no longer serves its intended purpose” but said the impact of eliminating the plan should be evaluated after the completion of the next interregional transmission planning process. It should be determined whether the revised process adequately incorporates California’s specific transmission needs into interregional plans, the agency said.
Order 1000 identified CAISO as a planning region with Pacific Gas and Electric, SCE and San Diego Gas & Electric as members. Other participants in the conceptual plan are now associated with WestConnect as a planning region.
“Absent the active participation of all statewide planning entities in developing a conceptual statewide plan, development of the plan amounts to little more than a unilateral ISO exercise,” CAISO said.
The ISO is asking that stakeholders submit comments on the final draft proposal by June 29.
WASHINGTON — A decade of mandatory standards has improved the grid’s reliability, but it’s time for regulators to prune unnecessary rules, speakers told FERC on Thursday.
At its annual technical conference on reliability, the commission delved into the weeds on compliance enforcement, gas-electric coordination and cybersecurity (AD17-8).
NERC received accolades from many who spoke at the conference for its continual improvement of the grid’s reliability; its transparency and coordination with other stakeholders; and its Reliability Assurance Initiative, a risk-based approach to compliance enforcement approved in 2015 that allows facilities to self-log minor violations — and NERC to focus on the most serious issues. The initiative also included the creation of Inherent Risk Assessment (IRA) profiles for facilities, which help NERC decide what standards to focus on.
FERC’s conference came days after the 10th anniversary of the first mandatory reliability standards under FERC Order 693 and a week after NERC released its State of Reliability report, from which CEO Gerry Cauley recounted some key statistics in his opening remarks. (See NERC: Despite Solid 2016, Grid Threats Remain.)
Cauley
“Bulk Power System reliability remains very high and continues to show year-over-year improvement,” Cauley said. “Industry has been very responsive to our risk-based approach and has been shifting resources to fix the most critical challenges to reliability. … These standards have had a major impact on reducing risk. Over time, we’ve seen a dramatic decline in the number and severity of compliance violations.”
But Cauley and many other panelists said it was time for another “Paragraph 81” process, referring to a provision in the commission’s March 2012 approval of NERC’s Find, Fix, Track and Report process that directed the organization to identify requirements that do little to protect reliability and could be removed. FERC ended up approving the retirement of 34 such requirements (RC11-6, et al.).
“It may be time to focus again on streamlining the requirements to ensure the investment in compliance is commensurate with the reliability gains,” Cauley said.
Risk-Based Approach
Speaking on behalf of the Large Public Power Council, Steven Wright, general manager of the Chelan Public Utility District in Washington state, wanted to go a step further. The risk-based approach hasn’t reduced Chelan’s documentation requirements: Of the 1,236 requirements and sub-requirements applicable to the utility, only four qualify for self-logging, Wright said.
He suggested that entities be granted waivers from certain standards if the IRA indicates their implementation of them doesn’t affect the grid.
Cauley disagreed with that idea, calling it an “optional menu.” NERC’s Regional Entities “legally have the discretion today to monitor and enforce whichever standards we feel suit an individual entity. And that’s really the purpose of the Inherent Risk Assessment. … I think the regions could do a better job of explaining that and explaining what could be looked at.
“But I don’t think it makes sense to take a North American set of standards and create sort of a little checklist matrix for each entity. The standards are the standards.”
Wright also suggested that there be more incentives for entities’ standard compliance, which Commissioner Colette Honorable pushed back on.
“I have a 16-year-old daughter, and she gets good grades. But I think she could get better grades,” she said. “So do I reward her for … getting the grades she should be getting anyway?”
Wright did not directly respond to the question of carrot vs. stick, but he made clear he felt LPPC’s members haven’t gotten enough “bang for our buck.”
“We are spending a lot of money” on IRAs and Internal Controls Evaluation, another RAI component, he said. “And I think it’s a good thing because we’re improving reliability, but if we can find efficiencies we should get them.”
‘Special Assessment’ on Gas Dependence
Acting FERC Chair Cheryl LaFleur asked what the commission or NERC should be doing to account for the increasing reliance on natural gas pipelines for baseload power. She pointed out that FERC has no jurisdiction over the reliability of natural gas pipelines (which belongs to the Transportation Department’s Pipeline and Hazardous Materials Safety Administration), but it does have jurisdiction over those who burn the gas.
LaFleur
“Should we be changing our planning standards in some way to take that potential loss of the pipeline into account or the gas storage” site? she asked. “Aliso Canyon brings that into the front of the discussion.”
Cauley responded that NERC is working on a special assessment report on the issue. The organization has been analyzing key pipelines and storage facilities and the potential impact of losing them on the grid.
“It will be clear from this report, I believe, that you should be planning for the loss of a most critical, most impactful facility, including if it’s on a gas system,” he said. “I am concerned that you have certain reliability standards and expectations on an electric system and what I consider a foundational piece — the fuel deliverability piece — doesn’t have an equivalent.”
Hoffman
Patricia Hoffman, acting assistant secretary of the Energy Department’s Office of Electric Delivery and Energy Reliability, suggested that grid operators do assessments to determine how dependent regions are on one fuel source.
Cybersecurity
The threat of cyberattacks took up a sizeable portion of the daylong conference.
NERC Chief Security Officer Marcus Sachs revealed that the organization had only learned about the most serious threat to date — malware known as CrashOverride — days before it was made public by two cybersecurity firms earlier this month. The program, which can control circuit breakers via supervisory control and data acquisition (SCADA) systems, was used last December to briefly cut power to about one-fifth of Kiev, Ukraine. (See Experts ID New Cyber Threat to SCADA Systems.)
Sachs recounted that NERC learned of CrashOverride on the afternoon of Friday, June 9. ESET, a Slovakian antivirus software provider, had contacted Maryland-based Dragos, asking it to review its findings before it publicized them on Monday. Dragos then contacted NERC, which worked over the weekend reviewing ESET’s work and producing a report. Dragos also produced its own report over the weekend.
Sachs
“If we didn’t have those public-private partnerships already existing, we would have failed that weekend, and you would have had a huge media splash on Monday morning that none of us would have been ready for,” Sachs said.
Many experts believe hackers based in Russia are behind the attacks on Ukraine, which Sachs said has been under “relentless assault” for the past couple years: Banking, railroads and Internet service providers have all experienced disruptions.
But while everything points to Russia, it is also possible individuals posing as Russians are behind the attacks, Sachs said.
Speaking to RTO Insider, Sachs pointed to the Solar Sunrise incident in 1998, in which two teenagers from California attacked Defense Department systems and led the military to believe they were from Iraq. “Just because it looks like a duck, smells like a duck, quacks like a duck — it may be a moose,” he said.
There was considerable discussion about understaffing at the entities responsible for protecting against cyber threats. Many agreed that the supply of qualified cybersecurity workers is too small to meet the very high demand.
Scott
“At the state level, we’re generally not staffed for this type of thing,” New Hampshire Public Utilities Commissioner Robert Scott said. “We don’t have the expertise.”
“The electric utility, 30 years ago, was the place to go to out of college,” said Greg Ford, CEO of Georgia System Operations, a cooperative that provides power to half the households in the state. “Today it’s harder and harder to lure those college students.”
“It’s easier to find individuals who are familiar with cybersecurity when it comes to traditional [information technology] and Windows-based infrastructure,” said David Ball, director of AEP Transmission Dispatching. “The more difficult skill set to find today is … a power-based background” and familiarity with SCADA.
“People with these type of skills are very marketable and they’re very mobile,” Scott agreed. “At the state level, we can’t hope to attract those type of people.”
Honorable
Sachs pointed out, however, that middle and high schools are increasingly sponsoring competitive cybersecurity exercises and students are competing in “hack-a-thons.”
“This is good news,” he said. “And it’s something we need to leverage. … Getting into cybersecurity is absolutely what we want these young kids to do.”
“All I can say to that is ‘Amen,’” Honorable replied.
BRANSON, Mo. — The MISO Nominating Committee has waived Board of Directors term limits and unanimously voted to allow current Director Baljit Dail to stand for an additional term, board Chairman Michael Curran said last week.
Dail, who this year reached the board’s limit of three three-year terms, will be included on a slate of qualified candidates being prepared by consulting firm Russell Reynolds.
With five first-time directors added since 2015, the veteran agreed to seek re-election for an additional three-year term, but that required the waiver. (See “Committee Could Lengthen Board Member’s Tenure,” MISO Board of Directors Briefs.)
Curran said the committee approved the waiver with an understanding that it should be used sparingly.
“Only in very unique situations should we hand out a waiver. It’s not something that we should use all the time,” Curran said at a June 22 board meeting. The committee cited Dail’s much-needed information technology experience as the reason for the waiver.
The board is unlikely to confront another waiver situation within the next six years based on the terms of current directors, Curran said.
The terms of Thomas Rainwater and Paul Bonavia also expire at the end of this year, but neither have reached the term limit and both will seek re-election.
At the June 21 Advisory Committee meeting, Wisconsin Public Service’s Chris Plante said retaining Dail for an additional term can help educate MISO’s newer board members and keep valuable institutional knowledge in the board.
“This should not be seen as a routine thing,” cautioned Arkansas Public Service Commissioner Ted Thomas.
MISO expects to finish the year 1.2% over budget, Chief Financial Officer Melissa Brown said during a quarterly finance report to the board.
Year-to-date, MISO is $1.5 million under budget, mostly because of late start times on projects and delayed employee travel, according to Brown. The RTO will also save about $1.1 million during the year, in part because of the cancellation of a forward capacity market in retail-choice areas. Still, that savings will be erased by a lower-than-expected employee vacancy rate, resulting in an unexpected $1.5 million spend.
| MISO
Brown expects the unusually low vacancy rate will persist for the remainder of the year. That, coupled with unforeseen expenses related to upgrading IT systems and miscellaneous overages, could push spending to $241.4 million, against the 2017 budget of $239.1 million. However, expenses could range anywhere from $238.8 million to $241.9 million.
Curran said the RTO should be able cover the forecasted overages with reductions in other spending. “We’re hopeful that we can dial that in with six more months to go,” Curran said, adding that savings shouldn’t come at the expense of project progress.
With labor costs comprising about 60% of MISO’s annual budget, it will be difficult to find cuts that don’t impact labor, Brown said.
Director Todd Raba also requested that the RTO make up the overage with other cutbacks.
Additionally, MISO has so far spent about $15.1 million of its $29.9 million capital budget, which should leave spending on target by year-end, according to Brown.
