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December 22, 2025

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PJM MRC Briefs: Oct. 31, 2019

VALLEY FORGE, Pa. — PJM staff and stakeholders kicked off Thursday’s Markets and Reliability Committee meeting with an homage to Denise Foster, the RTO’s vice president of state and member services, on her last day with the organization.

“Denise has always been committed to the success of PJM,” said Stu Bresler, senior vice president of market services. “She was very adept and very skilled at building, maintaining and, if I may, fostering relationships.”

Foster resigned in September, much to the disappointment of stakeholders — particularly state consumer advocates — who described her as engaging, personable and sharp. Bresler echoed those warm sentiments in his send-off, saying that Foster served as a mentor to other staff and provided great “insights on the substance of what we do at PJM.”

“She made tough decisions when she needed to and followed through on those decisions when she needed to and really earned the respect of staff here at PJM,” he said.

PJM
Members Committee Chair Chuck Dugan presented Denise Foster with a gift from stakeholders on her last day at PJM. | © RTO Insider

New Load Management Test Rules Endorsed

The MRC endorsed new load management and price-responsive demand testing rules for Capacity Performance resources after PJM said old measures failed to mimic real-life emergency procedures. (See PJM Stakeholders Support More Realistic DR Testing and “Stakeholders Urge Consensus on Load Management Testing Requirements,” PJM MRC/MC Briefs: Sept. 30, 2019.)

The new rules, effective with the 2023/24 delivery year, would give PJM authority over scheduling tests — instead of the resource itself — and provide advanced notification so participants can prepare. The changes would implement a three-step system that gives resources first notice of an upcoming test one week prior to the two-week testing window, with additional alerts by 10 a.m. the day before and the day of the scheduled test. There will be one test per year when there is no event, with half of resources tested in winter and the other half in summer.

The current rules, developed when demand response availability was limited to just six hours a day over the summer, require one test during the summer. They give resources a two-day warning — down to the exact hour — and provide unlimited retesting.

Enel X North America, sponsor of an alternative package that provided a week-ahead notification of a one-week testing window, withdrew its proposal Thursday and encouraged members to support PJM’s plan instead.

“Both sides gave some blood here,” Enel’s Brian Kauffman said. “There’s some philosophical questions that won’t be answered here and will ultimately end up before FERC.”

Stakeholders Mull Tx Asset Management Discussion

Stakeholders will once again consider assembling to discuss how incumbent transmission owners make asset management decisions and whether those projects should stay outside of the regional planning process.

Ed Tatum, vice president of transmission for American Municipal Power, proposed a problem statement and issue charge that would create a special session of the MRC to discuss what criteria TOs should observe before determining their infrastructure has reached the end of its life and whether those determinants could be — or even should be —standardized across all zones.

“It’s important for the stakeholders to weigh in as to how they think this process should work,” Tatum said. “There’s going to be some disagreement, and we need to get some clarity from Washington, D.C., as we go to Federal Energy Regulatory Commission.”

Currently, PJM considers projects related to local asset management as supplemental to the Regional Transmission Expansion Plan and only studies their impacts on the grid’s reliability — not whether the proposals are necessary or the most cost-effective solution. AMP and others have argued that local replacement decisions have regional implications and, therefore, PJM should take over planning in order to assure new projects will not just solve reliability concerns, but also support the “grid of the future.”

“We have talked around this issue so much in recent years, perhaps there’s a degree in fatigue in thinking about it,” said Susan Bruce of the PJM Industrial Customer Coalition. “The first time we went through this, we didn’t have as much clarity as to how PJM was viewing these issues. I think we have a better appreciation for PJM’s asset management concerns in this space.”

Both staff and PJM’s Board of Managers maintain that FERC precedent leaves asset management up to the discretion of TOs, where the local planning expertise lies. Incumbent TOs agree.

PJM
Pulin Shah, Exelon | © RTO Insider

“By having PJM responsible for end of life, you are putting more liability on PJM and its membership,” said Pulin Shah, director of transmission strategy and contracts for Exelon. “Even if an artificial end-of-life criteria is established, the transmission owners will still need to move forward with their own end-of-life decisions. Having PJM develop or create some may result in significant increase in supplemental spend if PJM now has to take on this responsibility.”

Tonja Wicks, manager of federal regulatory and regional affairs for Duquesne Light Co., said the term “end of useful life” is what both the industry and FERC have defined and accepted. She then reiterated that the commission concluded that planning for these particular assets is “beyond the scope of PJM’s authority” and questioned whether the newly created term “end of life” was an oversight or if AMP concedes that the FERC term and definition “are what we are working from.”

Tonja Wicks, Duquesne Light Co. | © RTO Insider

“There is no industry accepted definition of ‘end of life,’ so we are trying to understand how to work out this issue based on a term that has not been defined,” she said. “We are trying to get an understanding of what we are talking about because there is no such term.”

Tatum said he hopes “TOs will indeed come to the table and come up with some creative solutions that hopefully we can find a consensus around.” While PJM didn’t move off of its long-held position on its authority over supplementals, staff said the conversation was still worth having.

“We will not be put into a position to do condition decisions or asset management-type decisions,” said Ken Seiler, PJM’s vice president of planning. “It’s not our authority to do that, but there is solution space here.”

The MRC will vote on the initiative at its Dec. 5 meeting. Notably, the Planning Committee turned down the problem statement at its September meeting. (See “PC Says ‘No’ to End-of-life Transparency Discussion,” PJM PC/TEAC Briefs: Sept. 12, 2019.)

FTR Market Rule Changes

PJM presented the first round of recommended rule changes for its financial transmission rights market in the wake of the GreenHat Energy default.

Brian Chmielewski, manager of market simulation, said the recommendations will improve PJM’s credit risk policies after the Financial Risk Mitigation Senior Task Force delegated a more holistic FTR market review and possible design changes to a separate MIC task force.

First, PJM suggests hosting five long-term FTR auctions a year, instead of just three, in order to increase oversight and visibility into portfolio conditions so that more collateral can be collected if necessary.

“One of the things we saw with GreenHat, between December and June there was a massive devaluation in that portfolio, so this would have an auction right in March to catch that sooner,” Chmielewski said.

A second recommendation would alter the structure of Balancing of Planning Period FTR auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter.

The FRMSTF voted 75% in favor of the changes. MRC endorsement is scheduled for Dec. 5, with implementation effective in 2020/21.

Endorsements

– Christen Smith

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At International Tx Summit, Interstate Challenges the Focus

By Michael Brooks

WASHINGTON — The International Summit on the Electric Transmission Grid was billed by trade group WIRES as an opportunity “to discuss and support the robust interregional and cross-border grid of the future.”

But though it was hosted at the Canadian Embassy and featured several Canadian speakers, the discussion mostly centered on the first part: interregional transmission lines — and, more specifically, those that cross state borders rather than international ones.

After all, as more than a few speakers noted, building interstate transmission lines in the U.S. is hard enough without the additional burden of getting a presidential permit to cross national boundaries.

International Transmission Summit

WIRES held the International Transmission Summit on the Electric Transmission Grid at the Canadian Embassy on Oct. 24. | © RTO Insider

The drive to build both interstate and international long-distance, high-voltage transmission is the same: moving vast amounts of renewable resources to serve growing state demand, itself driven by state and company emissions goals.

In the U.S., California and the Desert Southwest have abundant solar, and the Midwest and Texas are replete with wind, while Canada has more hydropower than it needs to serve its load, located mostly along the U.S. border.

It’s so abundant that the word “hydro” is often used as shorthand for “electricity,” even if it’s “not necessarily generated by hydro assets,” said former U.S. Ambassador to Canada Gordon Giffin, now a partner with Dentons. “In Ontario, there’s probably 50% nuclear power generation, and it’s all called ‘hydro.’”

But Canada does not face all the same challenges as the U.S. when it comes to building long-distance, high-voltage transmission lines.

One reason comes down to simple geography. Canadian provinces are much larger than America’s states: Though the two countries are about the same size, Canada only has 13 provinces. Lines need to run vast distances from the water in the north to the load centers in the south, but most of the northern land is “open and expansive and owned by the Crown,” said Mike Martelli, president of renewable generation for Ontario Power Generation (OPG), referring to the government.

There’s also no federal entity similar to the Department of Energy or FERC that oversees interprovincial transmission. Provinces need only work with each other to site lines, and many provinces own their own utilities, “Crown corporations” such as OPG, BC Hydro, SaskPower, Manitoba Hydro and Hydro-Québec.

“All the provinces have 100% jurisdiction … so it’s a much easier discussion, and it’s a discussion where we can talk more about … the economic benefits, the jobs, the benefits to First Nations and our communities, and all that information is used in making that informed decision at a provincial level,” Martelli said.

Still, interprovincial transmission is uncommon, Martelli said. “All the provinces put up barriers. They like to develop a homegrown solution. And that’s where I think we have to change our thinking, and the true solution is going to be a more integrated approach.”

International Transmission Summit

Left to right: Panel moderator Rod Kuckro, E&E News; Mike Martelli, Ontario Power Generation; Katherine Gensler, SEIA; Amy Farrell, AWEA; and Michael Skelly, Lazard | © RTO Insider

The final major difference between the U.S. and Canada: politics.

The summit was held Oct. 24, just a few days after Canada’s federal elections. “When the people were interviewed on the street about what’s their No. 1 issue, it’s climate change,” Martelli said. “It wasn’t their taxes. We’re tremendously taxed. … We have high, very high taxes. It wasn’t taxes; it wasn’t health care; it was climate change.”

In May 2009, Ontario passed the Green Energy Act, which created feed-in tariffs for renewable resources. As a result, Martelli said, the province retired all 7 GW of its coal plants and now has 6 GW of wind and 3 GW of solar. “Prices went up about 40%, and people were terribly upset,” he said. “But Ontarians seem to be warming up to the idea” because of their prioritization of emission reductions.

Canada’s generation is “just over 80% emissions-free, and we’re working to make it even cleaner by phasing out coal-fired generation across the country by 2030 and developing small-modular nuclear reactors to transition remote and northern communities off diesel,” Martin Loken, minister of political affairs at the embassy, said in opening the conference.

South of the Border

“For the United States, the integration with Canada, and the opportunities for getting additional carbon-free electricity is absolutely essential” to reaching the targets under the 2015 Paris Agreement on climate change, said Ernest Moniz, former secretary of energy under President Barack Obama. “We have to get the infrastructure to support it.”

International Transmission Summit

Ernest Moniz, Energy Future Initiative | © RTO Insider

He talked about “an absolutely beautiful case” under Section 1222 of the Energy Policy Act of 2005, Clean Line Energy Partners’ Plains & Eastern Clean Line. “It was a beautiful example to implement, and the only problem was called ‘Arkansas.’”

Michael Skelly, co-founder and former president of Clean Line, was there to talk about the lessons learned of his company’s failure. Some of them he only learned “after reading the book” on the subject, he said, referring to The Wall Street Journal reporter Russell Gold’s “Superpower.” (See Book on Tx Developer Transmits Climate Hope.)

One lesson he focused on was the mistake of putting transmission before generation. “We may have been too early. If you look at how transmission is built around the world, [people] often enough build the generation first,” said Skelly, now a senior adviser with Lazard. “The good news in the United States is we’re doing exactly that. … We have a huge renewable expansion taking place, particularly in the center of the country. …

“We sort of thought that would happen” when Clean Line was proposing its projects, “but sometimes people need to see it actually happening before they realize, ‘Wow we have to do something about this problem,’ as opposed to a projected problem.”

Skelly clarified that he was not saying this “bass-ackwards” way of designing the grid was good. “It’s only a good thing to the extent that we go, ‘Oh wow, we have to go build this transmission because we just spent all this money on generation.’”

Discussion on Skelly’s panel — which included Martelli, the American Wind Energy Association’s Amy Farrell and the Solar Energy Industries Association’s Katherine Gensler — turned to criticism of RTOs and their transmission planning processes. Farrell and Gensler agreed that the RTOs underestimate the amount of renewables expected to come online when they plan their grids.

“Planning transmission to meet policy goals; planning for interregional transmission: These are the right goals, and nobody has cracked that nut yet on how to do it,” said Gensler, SEIA’s vice president of regulatory affairs. “Outside of California, no future scenario, not a single one, has 20% solar in it. Some of them don’t even have 20% renewables in them. … We have to plan for a rapidly decarbonizing future, and that is hard for people.

“A lot of the planners want to be very conservative,” Gensler continued. She pointed to wind consistently outperforming what RTOs expected within their 10-year scenarios.

Farrell, AWEA’s senior vice president for government and public affairs, noted that FERC is reviewing its transmission incentives policy, but “there hasn’t been a desire to really [review] Order 1000,” the goal of which was partly to encourage transmission planning between RTOs. “You have to look beyond just incentives and existing transmission improvements, and start looking toward fixing this planning process, because … it’s not about enabling renewable deployment as it is … leaving money on the table. Part of FERC’s mandate is to help drive toward a lowest-cost solution, and we don’t have a process for that right now.”

“The turf wars and feuds between RTOs are legendary; MISO and SPP, these people, for reasons that are often lost to the mists of time, they don’t really like each other that much, and they don’t work well together,” Skelly said. “So the notion that FERC’s going to pass something that says, ‘Hey, you guys, coordinate and work together’ … come on. It has not happened, and it’s not going to happen.”

In a later panel, MISO President and COO Clair Moeller disputed that, saying, “I’d submit we don’t actually have a planning problem. We have an objective problem. The reason we don’t get the answers that everybody agrees with is that people’s objectives are different.

“Lanny and I had a fistfight in the bathroom because RTOs don’t get along well,” he joked, referring to Lanny Nickell, SPP senior vice president of engineering, who was in the audience. “Well, that’s simply not true. The simple fact is the objectives are different. … Until we can get the objectives so they line up [around a policy consensus], the planners are going to be frustrated because we can’t tell them what we like.” He noted that the last of MISO’s multi-value projects, approved by the RTO in 2011, “won’t go into service until probably 2022. That’s not a planners’ problem. That’s a regulatory problem.”

Skelly also described the confusion that state regulators have to endure when being pitched multiple interstate lines. “We need policy mechanisms so that the RTO shows up and FERC shows up. Somebody needs to show up from some sanctioned body to say, ‘Yes, this makes sense.’”

But FERC commissioners “hate telling state regulators what to do,” Gensler said. “That is a fate worse than death for most FERC commissioners.”

As a potential solution, Skelly pointed to Sen. Martin Heinrich’s (D-N.M.) announcement that he would introduce bills to create an investment tax credit for “regionally significant” transmission projects and to direct FERC “to improve its interregional transmission planning process.” Heinrich, however, has been introducing similar legislation since 2015 to no success.

“I thought, up until a few minutes ago, that our process was very political,” Martelli said. “But listening to this, I’ll take our process any day.”

“You guys were smart enough to organize your provinces in a north-south fashion,” Skelly quipped.

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Competitive TOs Push Against PJM Supplementals

By Christen Smith

BALTIMORE — Competitive transmission developers made a familiar argument at the Organization of PJM States Inc.’s annual meeting last week: Supplemental projects undermine regional planning efforts and PJM should do something about it.

But PJM staff aren’t willing to accept the risks that come with managing supplementals and insist that FERC precedent prohibits the RTO from intervening anyway. Incumbent transmission owners agree, insisting that decisions about when to replace aging infrastructure come with many specific caveats that a regional planning organization doesn’t necessarily understand.

It’s a viewpoint FERC endorsed in two CAISO orders in September 2018 (EL17-45 and ER18-370), Ken Seiler, PJM’s vice president of planning, said while participating on an OPSI panel with the D.C. Office of the People’s Counsel, LS Power, American Municipal Power and FirstEnergy.

In the former proceeding, the commission rejected a complaint from local and state regulators that said Pacific Gas and Electric violated Order 890 because the majority of its transmission planning occurs behind closed doors. FERC said asset management projects that only produce “incidental” increases in transmission capacity aren’t beholden to the transparency provisions of the order. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)

PJM
The Organization of PJM States Inc. convened for its annual meeting Oct. 28-29 at the Marriott Waterfront Hotel in Baltimore. | © RTO Insider

The commission reiterated this opinion in the latter proceeding that turned down the California Public Utilities Commission’s request for a show-cause order finding that Order 890 governs transmission owners’ planning for self-approved projects.

“A lot of this issue around end-of-life projects has been formed by us based on these orders,” Seiler said. “The orders specifically state that end-of-life criteria is not within the RTO’s purview and it’s not their expertise. The ISO shall do the planning, and the TO shall do replacement.”

LS Power and AMP interpreted FERC’s comments in the California dockets differently, however.

“In FERC’s California order, the commission said supplemental projects in PJM are a matter of PJM choice,” said Sharon Segner, vice president of LS Power. “Not a FERC mandate.”

“I don’t think you guys are reading that right,” Ed Tatum, AMP’s vice president of transmission, told PJM staff. “I think the commission took great pains to differentiate between what’s going on in California and what’s going on in PJM. We’ve really got to get it straight as to what we are talking about here, as far as PJM being able to set its own destiny.”

The commission only briefly addressed the PJM matter in the 2018 CAISO orders, calling its February 2018 ruling on PJM supplementals (EL16-71, ER17-179) “inapposite” to the issue at hand in California.

“The question of whether asset management projects and activities that do not increase the capacity of the grid must go through an Order No. 890-compliant transmission planning process was not at issue in the Feb. 15 PJM order,” FERC wrote in both CAISO orders. “Instead, the Feb. 15 PJM order examined the PJM transmission owners’ implementation of the process for planning supplemental projects, a process that is set forth in the PJM Operating Agreement and Tariff.”

No Authority, Expertise

PJM estimates members spent $6 billion on supplemental projects in 2018 — triple the amount invested in baseline upgrades that same year. Tatum said members have spent $29.9 billion on supplemental projects over the last 14 years, more than half of which TOs proposed after 2013. Baseline spending, meanwhile, will reach $30.1 billion by the end of the year, he said.

“Locally cost-allocated projects don’t go out for competition,” Segner said. “If you can do everything through local planning, then all of a sudden there’s not regional needs. There’s no coincidence that this world started aggressively in 2013 when FERC Order 1000 went into effect.”

“It’s very clear in our mind that TOs have the obligation to maintain their system, but as we go through and decide what is asset management … if you’re replacing it, that’s something called planning, and we think there is a bright line there,” Tatum said.

PJM
PJM-TO baseline and supplemental projects by proposal year, 2005-2019 | AMP

Under current rules, incumbent TOs submit supplemental projects for inclusion in PJM’s Regional Transmission Expansion Plan. The RTO studies the proposals for impacts on the grid’s reliability but doesn’t make determinations about whether the projects are necessary or the most cost-effective solution. Further, these projects often encompass asset replacement and upgrades that incumbent TOs say they are best prepared to handle. Seiler agreed, noting that PJM isn’t in the business of “condition assessment” and isn’t involved in the day-to-day management of TOs’ infrastructure.

“When we talk supplemental projects, we are talking aged infrastructure … that’s predominantly the type of projects we are focused on,” said Robert Mattiuz, vice president of transmission for FirstEnergy. “We do not want to be in a position where we run our transmission system to failure, so we are proactively addressing this issue.”

There’s no uniform set of standards for determining when an asset has reached the end of its life, Seiler later told RTO Insider, meaning that PJM must rely on local TOs to provide that knowledge. While he couldn’t verify AMP’s data about the growth in supplemental spending, he said PJM’s last wave of transmission buildout occurred more than three decades ago and suggested that the increase in spending over the last few years could be expected based on the age of the current system alone — though age isn’t the only factor TOs consider when replacing infrastructure, he clarified.

He also noted that PJM’s spending looks much less dramatic in comparison with other RTOs and ISOs when investments are load-weighted.

“I’d say PJM spending looks to be about average or even below-average in those terms,” he said.

PJM
ISO/RTO load-weighted transmission investments. Light blue represents future estimated investments. | PJM

Seiler’s comments reflect sentiments shared by Dean Oskvig, chair of the PJM Board of Managers’ Reliability Committee, on Oct. 4 that the managers’ review of supplemental projects concluded that the RTO’s role “can be expanded in some areas but also remains appropriately constrained in others.”

“PJM does not have the authority or expertise to assume responsibility for asset management decisions or to determine when a facility is at the end of its useful life or otherwise needs to be replaced,” he said. “Those decisions are the sole responsibility of the transmission owner. PJM has the authority, expertise and the obligation to develop the RTEP. In some circumstances, PJM may be in the best position to determine the more cost-effective regional solution to replace a retired facility. PJM welcomes input from stakeholders to determine under what circumstances PJM might assert that authority.”

Erik Heinle, of the D.C. OPC, said PJM’s ability to foster competition and innovation should naturally extend to supplemental project planning.

“We don’t want to just replace 50-year-old substations with the newer version,” he said. “One of the great successes of PJM is competition in the marketplace. … Why can’t we have that in the transmission space too? We need to make sure we are replacing these aging facilities … not with what we need now, but with what we need in the future.”

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SPP Board of Directors/MC Briefs: Oct. 29, 2019

LITTLE ROCK, Ark. — After a one-year drop, SPP’s administrative fee will resume its upward climb in 2020 with the Board of Directors’ approval last week.

The directors signed off on a 9.1% increase in the fee to a record high of 43 cents/MWh. The fee dropped to 39.4 cents last year following an $8 million overcollection in 2018. It is projected to reach 46.6 cents in 2022.

The Finance Committee based its recommendation to the board on a net revenue requirement (NRR) of $172.3 million next year, compared with $157.5 million the year before. The NRR is composed of operating expenses (excluding depreciation and FERC assessment), principal payments on loans for capital expenditures and a capital reserve fund.

The board also approved the committee’s recommended budget, which includes a 6.5% increase in operating expenses to $209.1 million and a slight uptick in capital expenditures of $15.7 million.

SPP
Director Bruce Scherr explains the recommended budget. | © RTO Insider

Oklahoma Gas & Electric, Public Service Company of Oklahoma and Southwestern Public Service were among those that raised concerns over the increases. Director Bruce Scherr, who chairs the Finance Committee, told members that they were looking at a “cash-flow” budget, not a “profit” budget.

“Your comments are not new to us,” he said. “We’re going to keep a close eye on cash-flow improvement. What you should be concerned about is if we didn’t care about that, and we let [the increase] go to be institutionalized without further evaluation.”

SPS opposed the motion to increase the budget, while OG&E and Liberty Utilities abstained. All three companies abstained from the Members Committee vote to approve the administrative fee.

SPS’ David Hudson reacted negatively to the increases, pointing out that his company is “fighting hard” to keep its operating and maintenance expenses flat.

“We see this year after year,” he said. “This goes into retail rates. A 10% increase is too high.”

“We’re concerned with the revenue requirement and the increase in costs we continue to see,” OG&E’s Greg McAuley said. “We understand the nature of most of it, but in the world we operate [in] today, we continue to keep our operating costs flat. We look for the organization to meet us, because that’s what the customers demand of us.”

SPP
Chart reflects the actual NRR and admin fee charged for 2019-2018 and the budgeted/forecasted NRR and admin fee for 2019-2022. The NRR excludes prior-year true-up amounts. | SPP

Board Chair Larry Altenbaumer took slight umbrage at the comments, reminding members of what they get for the costs.

“The organization has done a phenomenal job of living within its budget,” he said. “I’m not trying to minimize any of the comments, but the thing that continues to gnaw at me a little bit is the other side of the equation … the pushback is always on costs. There’s never any recognition of what members get for that cost.

“I continue to believe this organization is providing significant benefits that outweigh the costs you are paying. That doesn’t reduce our efforts to keep the pencils as sharp as we can, but constantly hearing one side of the argument is unfair to this organization,” he said.

The budget does not include costs for SPP’s reliability coordination functions in the Western Interconnection, which Scherr said have been budgeted separately and will be financed through debt and paid back over time.

SPP expects its employee headcount to increase to more than 650 by 2021 because of RC West needs and additional engineers added to handle the generation interconnection studies’ workload.

2019 ITP Portfolio: 44 Projects, $336M

The directors signed off on the 2019 Integrated Transmission Planning (ITP) 10-year assessment that SPP said will reduce congestion costs by 21% on average and lead to projected future net savings of up to 23 cents on average monthly residential bills in the footprint.

The portfolio’s 44 projects have an estimated engineering and construction cost of $336 million and include 166 miles of 345-kV transmission. Lanny Nickell, SPP’s senior vice president of engineering, said the assessment projected considerable wind and solar growth, conventional generation retirements and the effect of new technologies.

Members resumed a discussion begun at the Markets and Operations Policy Committee in mid-October over the futures used in the 2021 10-year assessment. A carbon-reduction future envisioning as much as 55 GW of wind and solar energy in 2031 was eliminated. (See SPP Debate: How Green is Our Future?)

NextEra Energy Resources’ Holly Carias pointed out that stakeholders “already know we’re going to exceed” the assessment’s base case future, which projects 2 GW of additional wind energy by 2029 beyond the 22 GW already on hand. Nickell said that it’s “more likely” that 8 GW of wind capacity will be added over the next 10 years.

“Having realistic futures is extremely important. What we’re seeing out of the 2021 futures is a lot more realistic than we’ve seen previously, so I think we’re on the right track,” Carias said. “We need to look differently at how we’re looking at benefits. Currently, we’re looking at benefits to load. Maybe it’s time to look at benefits to generation. Maybe [generation] should pay for more of the costs.”

“We did assess benefits to generators not committed to load. It’s a fairly large number,” Nickell said. “What we haven’t done yet is figure out a way, or opportunity, for other parties with generators not committed to load to participate in the funding. We don’t have the Tariff mechanism.”

“We have questions, or concerns, with the way the new ITP process favors [the emerging technologies] future with more wind, which drives more transmission … and drives further costs,” McAuley said. “We’re waiting to see a confirmation that the benefits that come out of these studies will continue to increase at the same rates we’re being told they will. We’re really unsure at this point, after a year of this, about the benefits and cost allocation.”

Sunflower Electric Power opposed the recommendation during the Members Committee vote. OG&E, Oklahoma Municipal Power Authority, Golden Spread Electric Cooperative and Tri-County Electric Cooperative abstained.

Board Sends Fast-start Tariff Change to FERC

The board approved a Tariff revision that complies with FERC’s directive to allow fast-start resources to set clearing prices, while also supporting the Market Monitoring Unit’s opposing filing with the commission.

MMU Executive Director Keith Collins told board members that the Monitor has identified two major market-design flaws in the revision request (MWG RR375): It applies the mitigation process in the price calculation and not the dispatch instruction’s calculation, allowing market participants to potentially manipulate the market; and it allows market participants to change start-up offers and no-load offers after the fast-start resources’ commitment has occurred.

Collins said that because the offers can set price for other resources, the MMU believes “this sends an inappropriate price signal and allows market participants to manipulate the market.” The Monitor has proposed applying the mitigation process in calculating both the dispatch instruction and price, and that the start-up and no-load offers evaluated at the time of commitment be used in the fast-start resource’s modified energy offer. (See “Members Endorse Quick-Start Revision,” SPP MOPC Briefs: Oct. 15-16, 2019.)

SPP staff said RR375’s scope was limited to meet only FERC’s requirement. The Members Committee voted unanimously in favor of the motion.

Golden Spread opposed the revision at the MOPC and said it would likely file comments at FERC.

“This is an incremental step,” the co-op’s Mike Wise said, noting it has engaged the Brattle Group for support. “We don’t believe SPP has complied with FERC’s desire on this.”

“I’m concerned some of what has to be done has to be resolved by FERC,” Altenbaumer said. “We can appropriately get the issue to FERC and have them resolve it in a constructive manner.”

The commission in June found the grid operator’s quick-start pricing practices to be unjust and unreasonable because they don’t allow prices to reflect the marginal cost of serving load and directed the RTO to make six Tariff changes in response. (See FERC Orders Fast-start Rules for SPP.)

FERC’s order wrapped up an investigation of several RTOs begun in December 2017 under the Federal Power Act. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)

Last Meeting for Eckelberger, Skilton, Bernard

Expressing a need for “fresh thinking and planned transition,” SPP CEO Nick Brown announced to stakeholders that the board meeting was the last for Directors Emeritus Jim Eckelberger and Harry Skilton, and Director Phyllis Bernard.

SPP
(From left) CEO Nick Brown, board Chair Larry Altenbaumer and members honor Director Emeritus Harry Skilton with a standing ovation. | © RTO Insider

The three have served together since 2003 and have a combined 55 years of experience as directors. Eckelberger served as the board’s chairman for 14 years before stepping aside last year. (See Eckelberger, Skilton Step Down from SPP Board.)

SPP
Former Chairman Jim Eckelberger listens to words of praise for his service. | © RTO Insider

Eckelberger, Skilton and Bernard were all honored with resolutions from SPP and standing ovations from its members. Bernard participated by phone.

The board’s membership currently stands at nine active members following the approval of Julian Brix and Mark Crisson to three-year terms that begin in January. Brix has been a director since 2008 and Crisson since 2017.

The Corporate Governance Committee later this year will interview candidates for Bernard’s vacancy.

SPP to Pay up to $8.6M in Pension Benefits

Directors approved the Human Resources Committee’s recommendation to offer lump-sum payments to terminated SPP employees vested in the RTO’s pension plan but not yet drawing a benefit. The proposal would amount to an $8.6 million payout if all 164 eligible former staffers draw from it.

Based on annual premium savings of $100,000, current interest rates and actuarial tables, SPP would break even with just one participant in the buyout, staff said. They said advisers have told the RTO to expect a “take rate” of about 100 eligible participants.

Members and the board also approved the Value and Affordability Task Force’s recommendation to accept its report and recommendations and dissolve the group. (See SPP Value Group Finds No ‘Silver Bullets.)

Consent Agenda Clears Project Resets

The consent agenda was passed without dissent, resulting in the approval of APEX Clean Energy’s upgrade to the Neosho-Caney River 345-kV line in Kansas, scheduled to go in service next year, and a pair of baseline resets:

  • Evergy’s $54.1 million update for a 345/138-kV transformer and 138-kV transmission line project, estimated at $67.1 million in 2017.
  • Evergy’s $34.4 million update for network upgrades on a 138-kV circuit, which was originally projected to cost $58.3 million.

Two revision requests were on the consent agenda:

  • TWG RR363: Defines existing transmission facilities’ “material modification” as being “based on engineering judgment” in NERC’s facility interconnection studies (FAC-002) compliance.
  • TWG RR364: Reduces the planning criteria’s language on equipment rating, which is already covered by NERC Reliability Standard FAC-008.

— Tom Kleckner

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California Could Restructure PG&E, Governor Says

By Hudson Sangree

SACRAMENTO, Calif. — Gov. Gavin Newsom said Friday he has summoned Pacific Gas and Electric and its creditors, including wildfire victims, to the State Capitol this week to try to broker a deal to pull the utility out of bankruptcy more quickly.

Newsom said the negotiations will include a professional mediator appointed last week by the judge overseeing PG&E’s Chapter 11 reorganization in U.S. Bankruptcy Court in San Francisco. (See PG&E Bankruptcy Judge Appoints Mediator.) The utility filed for bankruptcy early this year after being blamed for last year’s Camp Fire, the deadliest and most costly wildfire in California history, as well as a series of catastrophic fires in California’s wine country in 2017.

PG&E needs to exit bankruptcy by June 30, 2020, if it wants to participate in a $21 billion wildfire insurance fund established by AB 1054, a bill Newsom pushed through this summer. (See Calif. Lawmakers Rush to Pass Utility Wildfire Aid.)

California Restructure PG&E
California Gov. Gavin Newsom urged the passage of AB 1054 in July and said Friday that PG&E must exit bankrutpcy quickly or the state will restructure the utility. | Cal OES

The governor said his backup plan is for the state to reorganize PG&E, possibly with an “ISO-like structure” akin to CAISO, a public-benefit corporation with leaders appointed by the governor and confirmed by the State Senate.

“If the parties fail to reach an agreement quickly to begin this process of transformation, the state will not hesitate to step in and restructure the utility,” Newsom said in a statement.

Newsom reiterated his threat in an hourlong press conference, broadcast on Twitter, at which he studiously avoided using the word “takeover” but often stopped just short of it. He provided no specific timeline for when the parties to the bankruptcy must come to an agreement before the state would intervene with its plan.

The governor appointed a team to deal with the PG&E situation that will be led by his cabinet secretary, Ana Matosantos, whom he called the state’s new “energy czar.”

He announced his strategy after a week of touring wildfires burning in Northern and Southern California. The active blazes include the Kincade Fire, in Sonoma County, which may have been sparked by a broken PG&E transmission line. (See PG&E Stock Plummets amid Wildfires, Shutoffs.)

The utility blacked out more than 2 million residents twice in the past two weeks to try to prevent wildfires as part of its public safety power shutoff (PSPS) program. In some cases, residents were without power for seven days.

Newsom insisted such widespread, long-lasting power shutoffs could not be the state’s “new normal.” The state will review the PSPS policies established in SB 901, a major wildfire bill that then-Gov. Jerry Brown signed in September 2018.

The California Public Utilities Commission has started a formal inquiry into PG&E’s power shutoffs.

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NiSource Earnings Feel Aftershocks of Gas Explosions

By Amanda Durish Cook

NiSource earnings

NiSource lost money last quarter as the company continues to face costs stemming from a string of gas pipeline explosions in three Massachusetts cities last year.

The Indiana-based parent of Northern Indiana Public Service Co. meanwhile continued to replace its coal plants with wind and solar resources.

NiSource reported a net operating loss just short of $2 million, compared with earnings of $35 million ($0.10/share) a year earlier.

Speaking to analysts Wednesday, NiSource CFO Donald Brown attributed the loss to higher financing costs and increased safety-related spending in response to last year’s string of gas explosions in three Massachusetts communities.

NiSource said it has dedicated $1 billion to stepped-up safety protocols after the explosions, which killed a teenager, injured 21 other people and destroyed multiple buildings in Lawrence, North Andover and Andover. The blasts occurred as the company’s Columbia Gas subsidiary was replacing cast iron pipelines with plastic lines.

“We expect to recover a substantial portion of our Greater Lawrence incident costs through the $800 million of casualty insurance coverage and $300 million of property insurance in place at the time of the event,” Brown said. He noted the company started submitting claims in December 2018 and has collected casualty insurance recoveries of $670 million through September — and expects to collect the remaining $130 million early next year.

NiSource earnings
Meadow Lake wind farm | Rose Water Wind Generation

In July, NiSource resolved multiple class-action lawsuits brought by business owners and residents for $143 million. The utility has also settled two other lawsuits brought by the communities and the victim’s family.

Columbia Gas last month experienced a second major gas leak in Lawrence as it continued rebuilding pipelines. The Massachusetts Department of Public Utilities has since placed a moratorium on the company’s nonemergency work and has opened an investigation into possible safety violations.

NiSource CEO Joe Hamrock said the company is working to win back the public’s trust and has added a chief safety officer, instituted a safety management system based on a framework for pipeline operators from the American Petroleum Institute, and installed safety improvements on its low-pressure gas distribution systems.

“Teams have installed more than 1,000 automatic shutoff devices across the NiSource footprint this year, including completing all installation of these devices in Massachusetts and Virginia,” Hamrock said.

He said NiSource will continue to factor the financial impacts of the leaks into its 2020 guidance, “but on a fairly moderate basis.”

NIPSCO Update

NIPSCO issued three requests for proposals for replacement capacity on Oct. 1, including for 2,300 MW of solar generation and solar paired with storage, and 300 MW of wind generation and wind paired with storage. The utility is also requesting an unspecified amount of thermal or other capacity resources. The RFP window closes Nov. 20.

NiSource earnings
| Rose Water Wind Generation

The RFPs come in response to a forecasted capacity need by 2023 as the utility gradually phases out its coal fleet. NIPSCO pledged in its 2018 integrated resource plan to cut 80% of its remaining coal-fired generation by 2023 and all coal by 2028. That translates into retiring its 1,625-MW R.M. Schahfer coal plant in 2023 and the 469-MW Michigan City coal plant in 2028.

NIPSCO last quarter also received approval from the Indiana Utility Regulatory Commission for a certificate of need for the 102-MW Rosewater wind project in northwestern Indiana. NiSource and Texas-based EDP Renewables also filed with the IURC to build the 302-MW Indiana Crossroads wind farm, also in northwestern Indiana.

Hamrock also said NIPSCO expects to hike electric rates by about $11/month for an average residential customer beginning in January 2020, with a rate case order due from the IURC by the end of the year.

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Renewable, Utility Members Tangle over SPP Seat

By Tom Kleckner

LITTLE ROCK, Ark. — A battle over a seat on SPP’s Members Committee last week exposed a divide between the RTO’s traditional utilities and the renewable energy companies fueling the growth of generation.

SPP
Rob Janssen, Dogwood Energy | © RTO Insider

Dogwood Energy’s Rob Janssen retained the independent power producer/marketer’s seat on the committee, one he’s held for 12 years, following a nomination from the floor and a membership vote during SPP’s Oct. 29 annual meeting of members and the Board of Directors. The result overturned the Corporate Governance Committee’s recommendation that Enel Green Power North America’s Betsy Beck fill the seat.

David Mindham, EDP Renewables’ regulatory market affairs manager, told RTO Insider that several members of the IPP sector “find it troubling” that they don’t get to choose their representatives and said the wind industry is “underrepresented” on SPP committees.

“Members who may have different agendas select who represents our industry,” Mindham said.

Candidates are nominated for SPP committees by their organizations or through third parties. The CGC then considers their nominations and makes its recommendations to the broader membership.

The 21-member committee discusses issues with the board and casts nonbinding votes meant to inform the independent directors.

Janssen said in an email Thursday that he looks forward continuing work with renewable generation and storage segment representatives of the IPP sector “to broaden opportunities for increased representation on SPP working groups and board-level committees.”

“I believe that more diversity in representation in SPP’s stakeholder process leads to better outcomes for all SPP members,” Janssen said.

SPP did not divulge the final vote total, a practice it maintains for all board votes. After announcing the result, Chair Larry Altenbaumer turned to Beck and said, “I hope you will continue to be engaged with us and involved.”

Golden Spread Electric Cooperative’s Mike Wise, a member of the CGC, told members that the committee “really struggled” in choosing a candidate for the IPP seat’s three-year term.

“The recommendation out of the committee took us a long time,” he said. “We want people to know that the Corporate Governance Committee really did struggle and spend time on all the issues brought up today about these two individuals.”

SPP
| © RTO Insider

Nebraska Public Power District’s Tom Kent nominated Janssen from the floor, citing his “long track record of reasonable and fair representation of both the IPP/marketers sector and the SPP membership as a whole.”

Kent and Janssen served as chair and vice chair, respectively, on the Holistic Integrated Tariff Team, which recently wrapped up a year of work. (See SPP Board Approves HITT’s Recommendations.)

“I’ve gotten to know Rob very well over the last year and a half, watching him work on the HITT team with all the HITT members, asking in-depth, challenging questions to help move the organization forward,” Kent said. “For a person with the type of expertise that Rob has … having that expertise on the Members Committee is very important to me.”

Janssen is president of Dogwood Energy, which owns a 650-MW combined cycle generating facility near Kansas City, Mo. He’s also is a senior vice president with Kelson Energy, an asset management company that has owned or operated more than 7,700 MW of generation businesses at more than a dozen sites in North America.

The Kansas Municipal Energy Agency, which had six votes through its affiliate members, seconded Janssen’s nomination. Calpine and Kansas Electric Power also filed letters of support.

No letters of support for Beck, Enel’s director of organized markets, were included in the board’s background materials. Mindham said the letter he filed backing Beck’s nomination missed the submission deadline.

Walmart, Google Energy and Evergy’s Denise Buffington spoke in support of Beck. Kent and the Oklahoma Municipal Power Authority’s David Osburn offered statements backing Janssen.

“I think wind needs to be part of the strategic vision and part of the company moving forward,” Buffington said. “Allocating costs in the [generator interconnection] queue, stopping load from paying for all of these wind assets … that’s why I think wind needs to be a part of this group.”

‘A Lot of Expertise’

Beck has more than 10 years of experience in the electric sector and has spent time as an energy adviser with the U.S. Senate, at FERC and with the American Wind Energy Association. While with the Senate Energy and Natural Resources Committee, she advised members and drafted legislation with a focus on energy trading derivatives regulation, the Public Utility Regulatory Policies Act and public power.

“The IPP sector is made up of diverse stakeholders with interests in project operations, development and power marketing. It is vital that the IPP sector’s representation on the Members Committee accurately reflects those broad interests,” Mindham said in his letter.

He pointed out that renewable energy companies have one seat among the three “high-level” committees that report to the board — the MC, CGC and Strategic Planning Committee — while Dogwood Energy sits on all three.

“It is essential that these committees represent all stakeholder interests and that no single company is over-represented. This diversity maintains the integrity of the stakeholder process,” Mindham said. “The failure to select Betsy for the Members Committee is disappointing. She would have brought needed diversity and a wealth of industry knowledge to the SPP governance process.”

SPP
Betsy Beck, Enel, explains her qualifications to the membership. | © RTO Insider

Beck declined to comment following the vote but advocated for herself before the members, as did Janssen. Saying she sees FERC as taking a stronger role in directing SPP’s policies, Beck said her diverse background would be helpful to the members.

“Honestly, I think our industry is a little behind the ball in engaging with SPP,” she told members. Noting Enel’s 4 GW of wind resources in SPP’s footprint, which delivered about 5% of the RTO’s energy last year, Beck said, “I bring lot of expertise with me as far as interconnection and trading issues. I think our company really represents the diversity of interests in our sector.”

“Over the years, I’ve developed a significant knowledge of SPP, the way the organization operates and where it’s going in the future,” Janssen said. “I’ve always tried to look out for all the interests of the members in our discussion, knowing we’ll get a better product and a better result for the power pool if we come together.”

Osburn, while supporting Janssen, suggested adding seats to the Members Committee in recognition of wind energy’s contributions to SPP and the growing importance of solar and energy storage. Wind (47.5 GW), solar (29.4 GW) and battery (6.8 GW) account for all but 331 MW of resources in SPP’s generation queue.

“You’re going to have a new group of participants with solar coming on board,” Osburn said.

A FERC-mandated two-thirds reduction of SPP’s exit fee to $100,000 will certainly make membership more acceptable to smaller renewable energy companies. (See SPP Board of Directors/MC Briefs: July 30, 2019.)

Members also approved the following nominations for three-year terms to the Members Committee: Basin Electric Power Cooperative’s Tom Christensen and Sunflower Electric Power’s Stuart Lowry to the cooperative segment; NorthWestern Energy’s Bleau LaFave and Public Service Company of Oklahoma’s Peggy Simmons to the investor-owned utility segment; City Utilities of Springfield’s (Mo.) Chris Jones to the municipal segment; and ITC Great Plains’ Brett Leopold to the independent transmission company segment.

Tri-State Generation & Transmission Association’s Joel Bladow (cooperative) and Google Energy’s Jeff Riles (large retail customer segment) were elected to fill vacancies that expire in December 2020.

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SPP Regional State Committee Briefs: Oct. 28, 2019

LITTLE ROCK, Ark. — SPP’s Regional State Committee last week unanimously endorsed the elimination of revenue credits for sponsored transmission upgrades and the 2019 10-year transmission planning assessment.

Regulators asked to hear from renewable energy stakeholders, who participated in the Markets and Operations Policy Committee discussion of the Tariff revision earlier in October. The MOPC unanimously approved the change, which replaces Attachment Z2 credits for sponsored upgrades with incremental long-term congestion rights (ILTCRs), effective February 2020. (See “Stakeholders Endorse Eliminating Z2 Revenue Credits,” SPP MOPC Briefs: Oct. 15-16, 2019.)

EDP Renewables’ David Mindham repeated the industry’s position that the revision doesn’t comply with FERC’s policies on interconnections (Order 2003) and long-term firm transmission rights (Order 681).

“We don’t oppose removing Z2 credits,” he said. “We don’t feel there’s enough value in ILTCRs to be complying with FERC Order 2003.”

“I do agree there are some things that need to be fixed,” South Dakota Public Utilities Commissioner Kristie Fiegen said. “But I believe MOPC’s action is appropriate. I believe Z2 credits need to eliminated sooner rather than later.”

SPP General Counsel Paul Suskie argued that Z2 credits are not required by FERC policy and are instead a “self-imposed requirement” implemented through the stakeholder process.

“If an entity thought our ILTCRs do not comply with FERC, we would not appeal to FERC,” he said.

The RSC also signed off on SPP’s Integrated Transmission Planning 10-year assessment, a portfolio of 44 transmission projects with a total engineering and construction cost of $336 million. The 2019 ITP, the first after stakeholders revised the planning process, includes 166 miles of new extra-high-voltage transmission and 28 miles of rebuilt high-voltage infrastructure.

“We hope to solve both reliability and economic needs in a way that optimizes performance,” Senior Vice President of Engineering Lanny Nickell said. He said the portfolio is expected to lower congestion costs by more than 63 cents/MWh, a 21% reduction.

Nickell said he expects two of 345-kV projects, a 60-mile line in Oklahoma and a 105-mile line in Kansas, to become competitively bid. The projects have engineering and construction costs of $85.9 million and $162.6 million, respectively.

Louisiana’s Campbell: SPP Spending ‘Extravagant’

In a rare appearance before the RSC, Louisiana Public Service Commissioner Foster Campbell laid into SPP for what he termed “extravagant” spending on corporate facilities and executive salaries.

SPP
Louisiana PSC Commissioner Foster Campbell confers with staff following his comments. | © RTO Insider

Campbell, a self-described politician whose colorful career includes 26 years in the Louisiana State Senate and multiple failed bids for Congress and the governor’s office, was elected to the PSC in 2002. He normally gives his RSC proxy to PSC legal staffer Dana Shelton. That Campbell is up for election in 2020 led many onlookers to call his comments “political.”

“I’m not trying to be blunt, but telling it like it is,” he said. “The first time I came here, I never saw a building like that. I’ve been to a lot of places: capitols, the White House, fancy hotels … this building costs $67 million. That goes to my customers. I represent my customers, all in North Louisiana, and we have a lot of poor people.”

SPP CEO Nick Brown listened stoically as Campbell criticized him for a salary he said was $950,000. According to the RTO’s 2016 IRS Form 990, the last available through nonprofit tracker GuideStar, Brown’s total compensation was $1.2 million. By comparison, MISO’s 2017 990 lists CEO John Bear’s total compensation at $2.8 million.

“I know the good you’re doing. I hope you realize there are lots of poor folks out there, and I represent a lot of them,” Campbell said. “I would not want my people I represent to know we spend money like this. It’s too much.”

SPP Chairman Larry Altenbaumer cut Campbell off, saying Brown’s salary was commensurate with others in the industry and extolling the work of the Value and Affordability Task Force he chaired. (See SPP Value Group Finds No ‘Silver Bullets’.)

“I spent an entire year, with stakeholder involvement, looking at value and affordability of the organization with respect to our costs and the value delivered,” Altenbaumer said. “I feel very good about the comments we received.”

SPP
CEO Nick Brown listens to Campbell. | © RTO Insider

“I’m sure our architects would be amused that you think that this building is lavishly furnished,” Brown said, describing the building’s use of reclaimed materials and poured concrete for the floors. “Our Finance Committee, that consists predominantly of member companies, oversaw every specific of this building. This building is significantly cheaper than the leased space we were in over multiple locations in the area. To say we’re lavish with our money is simply not true.”

SPP clarified that Campbell’s $67 million figure applies to the value of its infrastructure assets, which includes the $52 million in construction costs for the Corporate Center’s four-story office building, modern operations data center and parking deck, and the backup ops center in nearby Maumelle. The operations center costs include required measures such as storm hardening, backup generation and fuel sources to ensure continued operations, the RTO said.

The RSC took a break after the exchange between Campbell, Brown and Altenbaumer. When the meeting resumed, Shelton was sitting in Campbell’s seat.

The Louisiana PSC is expected to vote on new RTO assignments in January.

Nebraska’s Grennan Elected as RSC President

Regulators approved the slate of officers for the committee’s leadership in 2020, with the Nebraska Power Review Board’s Dennis Grennan succeeding Arkansas Public Service Commissioner Kim O’Guinn as president.

South Dakota’s Fiegen will replace Grennan as vice president, while North Dakota Public Service Commissioner Randy Christmann will replace Fiegen as the RSC’s secretary.

SPP
Incoming RSC President Dennis Grennan, of Nebraska, and Iowa’s Geri Huber | © RTO Insider

“We have a lot on our plate for the next few months,” Grennan said. “We’ll be working on all of those items.”

O’Guinn in October was appointed to the National Association of Regulatory Utility Commissioners’ board of directors.

Arkansas’ Thomas to Lead OMS Half of Seams Group

Arkansas PSC Chairman Ted Thomas will replace Missouri Public Service Commissioner Daniel Hall as the Organization of MISO States lead on the RSC-OMS committee working to resolve seams issues between the two grid operators. (See OMS Panel Debates Merits of MISO-SPP Seams Projects.)

Missouri PSC economist Adam McKinnie told the RSC that Hall is leaving the commission when his term expires this month.

The committee will meet in an open session on Nov. 17 during NARUC’s annual meeting and education conference in San Antonio. Registration will be available through the OMS website.

— Tom Kleckner

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NYISO Management Committee Briefs: Oct. 30, 2019

NYISO CEO Rich Dewey told the Management Committee that the ISO will delay deployment of a new energy management system (EMS) and business management system (BMS), missing the Oct. 31 deadline rather than risk any reliability problems.

As reported to the committee in September, the last day of October was the latest the ISO could cut over to the new system and still issue a necessary System and Organization Controls report to stakeholders by the Jan. 15, 2020, deadline. (See “Parallel Testing of EMS/BMS,” NYISO Management Committee Briefs: Sept. 25, 2019.)

“We encountered a number of problems related to both stability and synchronization of data,” Dewey said. “We made the decision not to deploy the new software, but to deploy it as soon as possible in the new year. We’re extremely disappointed in missing this deadline but don’t doubt we made the right decision in order to have a fully reliable system.”

Chief Information Officer Doug Chapman reported at the last MC meeting that March 1, 2020, is the next available deployment date.

Dewey said NYISO will work aggressively to correct the remaining known issues, complete the integrated testing and position the system to deploy as early as possible in 2020. Among other factors in deciding the new target is the need to maintain schedule flexibility to avoid deploying the new system in the middle of a cold snap when the electric system is under stress.

Howard Fromer, director of market policy for PSEG Power New York, asked how, with a three-year project, it was possible to learn at the “11th hour” that the new system doesn’t work.

“We break the system functionality into chunks, and only after it passes those tests do we piece it all together as a complete system with the real telemetry and real-time data inputs,” Dewey said. He explained that some of the more recent issues could only be discovered while the more complicated scenarios were performed by the operations team.

The control center has had double shifts for the past few weeks, running both old and new systems side by side, and while the ISO is “satisfied with the standalone applications … we decided we were better off taking a little extra time with their integration,” Dewey said.

Public Policy Tx Cost Caps OK’d

The MC voted to recommend that the Board of Directors approve a plan to allow developers to put voluntary cost caps in their proposals for projects falling under the ISO’s public policy transmission planning process.

NYISO Senior Manager for Transmission Planning Yachi Lin presented the proposal as approved by the Business Issues Committee earlier in October with 98.91% in favor. It passed the MC with 100% in favor with abstentions. (See NYISO Business Issues Committee Briefs: Oct. 16, 2019.)

Contingent on the board approving the measure at its November meeting, the ISO is prepared to make a Federal Power Act Section 205 filing with FERC in December for revisions to sections 6.10, 31.1, 31.4, and 31.7 of the Tariff. The changes would provide developers of projects selected to meet public policy needs the opportunity to make binding commitments to limit the amount of the capital costs of their projects. The commitments would be enforced through the tariffs and development agreements that NYISO enters into with each developer. Certain categories of unpredictable capital costs, such as unforeseeable environmental contamination, would be excluded from the cost cap, or cost recovery would be allowed if an excusing condition occurs, such as delays caused by interconnecting transmission owners.

“The principle we are establishing in the Tariff is if there are actions truly beyond the control of the developer, they should be excused from the cap,” Assistant General Counsel Carl Patka said.

Asked about a hypothetical case where the developer’s partner is responsible for actions or inactions that lead to exemption from the cost cap, Patka said, “That would be a fact-specific inquiry that would have to be evaluated on a case-by-case basis.”

Couch White attorney Amanda De Vito Trinsey, representing New York City, said that the city still continues to have concerns with the consumer protections but was withdrawing its opposition to the motion and abstaining from the vote, based on NYISO’s promise to police developer commitments and its Tariff to ensure that cost containment was being carried out as intended.

As at the BIC, Jane Quin, vice president of energy policy and regulatory affairs for Consolidated Edison, said her company and its Orange and Rockland Utilities subsidiary supported the concept but would also be abstaining because of concerns over changes to the evaluation process, which needs to include provisions for a TO to upgrade its own facilities.

Yes to Enhanced Credit Requirements

The MC also voted to recommend that the board approve changes to enhance credit reporting requirements and remedies.

Sheri Prevratil, manager of corporate credit, presented the proposal, including Tariff revisions that would require FERC approval, as she did earlier in the month when the BIC approved the changes.

NYISO proposed the changes after certain market participants last year defaulted on their payment or credit obligations. Some of those parties filed for Chapter 11 bankruptcy, while others were expelled from the ISO.

If the board approves the changes at its November meeting, NYISO will file Tariff revisions with FERC in November, Prevratil said.

The proposed Tariff changes add appropriate experience and resources to satisfy obligations to the ISO as minimum participation criteria. They also clarify that investigations that could have a material impact on the customer’s financial condition need to be reported to NYISO, if legally permitted, and add an obligation for a customer to take reasonable measures to obtain permission to disclose information on nonpublic investigations when possible.

A new provision allows NYISO to reject a new applicant determined to be an unreasonable credit risk based on a credit questionnaire and other review.

Survey Says: ISO Customers Happy

An annual customer satisfaction survey conducted by the Siena College Research Institute (SCRI) shows the ISO’s performance continuously increasing over the past four years.

SCRI Director Don Levy said a combined customer satisfaction and performance assessment score of 85.5% was the highest in four years, and that an executive approval score of 76% was better than it sounds, in that all respondents grade the ISO at better than “very good” in customer service.

Opportunities for improvement include conducting comprehensive long-term planning for the electric power system, advancing technological infrastructure and providing factual information to policymakers, stakeholders and investors.

NYISO
An annual customer satisfaction survey conducted by the Siena College Research Institute shows the ISO’s performance continuously increasing over the previous four years. | NYISO/SCRI

2020 NYISO Budget

The MC approved a flat budget of $168 million for next year, which the board will consider at its Nov. 19 meeting.

Budget and Priorities Working Group Chair Alan Ackerman, of Customized Energy Solutions, presented the final budget proposal to the committee.

The working group made slight changes since he provided an overview last month, reflecting the delay in deploying the new EMS/BMS system, but the bottom line remains unchanged at $168 million allocated across a forecast of 154.3 million MWh.

The budget calls for a Rate Schedule 1 charge of $1.089/MWh. Comparatively, this year’s budget was $168.2 million allocated across 157.1 million MWh for a Rate Schedule 1 charge of $1.071/MWh.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, commended the ISO for working hard to deliver a conservative budget with no increase.

Breidenbaugh Elected New Vice Chair

Stakeholders elected Aaron Breidenbaugh of Luthin Associates as vice chair of the committee for 2020.

Breidenbaugh, whose firm also represents an unincorporated group of nonprofit institutional customers known as Consumer Power Advocates, has been serving as BIC chair this year.

— Michael Kuser

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Robb Sees Calmer 2020 After ‘Turbulent’ Year

By Rich Heidorn Jr.

NERC CEO Jim Robb told board members Thursday he’s “feeling very good about” his senior executives after what he acknowledged was a “turbulent year” for the management team.

“We’ve had a pretty turbulent year in terms of the makeup on that team, but … I keep reminding myself that every time a door closes, a window opens,” he told the Corporate Governance and Human Resources Committee on a conference call.

NERC Robb
NERC CEO Jim Robb | © ERO Insider

Since Robb joined NERC from the Western Electricity Coordinating Council in April 2018, the corporation has seen the retirement of General Counsel Charles Berardesco, and the departures of CFO and Chief Administrative Officer Scott Jones and Senior Vice President and Chief Security Officer Marcus Sachs. James Merlo, vice president and director of reliability risk management, abruptly left the company in September. (See Merlo Out at NERC.)

“We have spent a lot of time over the last quarter really getting the senior team into alignment around a whole bunch of priorities … and I think we really have a very sound, and most importantly, a very aligned, team of executives leading the company right now,” Robb told the committee.

He said it was “pretty astounding, given all the change we’re going through, that our attrition level is hovering below 10%. We obviously would like to drive that number down.”

“Some of that attrition is regretted,” he added. “Some not.”

Robb said a “steering committee” of officers working with Director of Human Resources Damon Epperson “on renewing our HR programs” is paying dividends.

“One, we’re getting more heads against some thorny issues of how to continue to modernize our approach to HR to be aligned with the transformational aspirations we have for the company [NERC] and [ERO] Enterprise,” he said. “The other thing that it’s doing is also taking away everybody’s ability to complain about HR, because we’re now all part of the problem.”

He said the team is considering changes to its recruiting and onboarding practices and is “going to be taking a hard look at our performance management approach.”

Diversity and Inclusion

“Most importantly, we’ve laid out a series of aspirations for ourselves both in terms of the workplace environment we want to create for our staff, but also the importance we want to place on diversity and inclusion — that, as we continue to evolve the organization, we’re making it more reflective of the society that we live in and serve.”

Robb’s approach won an endorsement from Director Kenneth W. DeFontes Jr.

“If you design [a company in which] HR is the HR organization’s responsibility — not line management — you won’t be successful,” he said. “It sounds like you’re off on the right track to engage your leadership team [into] accepting this responsibility.”

Vacancies Remaining

NERC’s 2020 business plan reduced Robb’s direct reports to five from eight, two of which — chief financial and administrative officer, and the general counsel — are the subject of an ongoing search. Robb said last week he expects to announce the new executives by the end of November.

Sonia Mendonca, Berardesco’s former deputy, is interim general counsel, and Controller Andy Sharp, who served under Jones, is interim CFO.

Janet Sena, senior vice president for policy and external affairs, and Mark Lauby, senior vice president and chief engineer, are the only direct reports to Robb who remain from the executive team under former CEO Gerry Cauley.

Robb’s other direct report, Bill Lawrence, chief security officer and director of the Electricity Information Sharing and Analysis Center, replaced Sachs in August 2018. Lawrence was mysteriously absent last week at GridSecCon, E-ISAC’s annual conference, which drew more than 600 people. (See related story, Overheard at GridSecCon 2019.)

Robb said Lawrence was “taking some time off” but expected him to return.