As he is often wont to do, American Electric Power CEO Nick Akins opened his company’s third-quarter earnings call with financial analysts Thursday by quoting a rocker. He used Lenny Kravitz’ hit “Fly Away” to symbolize the shared pain “many of us have … during 2020 with these multiple challenges”:
“‘I wanna fly away.’
“Probably figuratively and literally,” Akins mused. “But there is light at the end of the tunnel.”
AEP’s year-to-date residential sales are up 2.6% when compared with last year, largely because of people spending more time at home during the COVID-19 pandemic, Akins said. Commercial and industrial sales are still down year-to-date, 4.9% and 7%, respectively, but showing signs of life.
“Both our commercial and industrial classes are showing steady improvement from the low we experienced in the second quarter as some businesses reopened over the summer,” he said. “We expect this trend will continue into 2021, barring additional unanticipated negative economic impacts from the pandemic.”
AEP reaffirmed its 2020 operating earnings guidance range of $4.25 to $4.45/share.
Akins headed off questions about the ongoing federal investigation into an alleged bribery scheme tied to the passage of Ohio House Bill 6 during his prepared remarks. (See FirstEnergy, AEP CEOs Deny Wrongdoing.)
AEP’s C&I sales are showing improvement since the pandemic-induced shutdowns. | AEP
“I’ll just say flatly that we have nothing new to report from AEP’s perspective,” he said. “Any potential legislative change is not imminent, particularly given a noisy election cycle. So, perhaps we’ll hear more after the election.
“As we’ve said earlier, any change to the existing legislation is likely to be financially insignificant for AEP, and we will still be pushing for forward-looking legislation regarding clean energy options, energy efficiency and other technology enhancements,” Akins said. “Regarding the legal issues surrounding HB6, also nothing new to report, and my previous comments stand on this subject.”
AEP’s share price, which closed Wednesday at $90.40, closed at $92.20 on Thursday, the highest it been since early March.
SPP staff are busy preparing to address critical comments on the grid operator’s revised Tariff for its Western Energy Imbalance Service (WEIS) as they work to keep the project on track.
The latest filing has drawn more than a dozen intervenors (ER21-3, ER21-4), including repeat protesters Xcel Energy-Colorado, Colorado Springs Utilities and Black Hills Energy. All three Colorado utilities plan to join CAISO’s Western Energy Imbalance Market.
“After a quick read of the comments and protests, the issues are similar to what we have seen in the past,” SPP’s Nicole Wagner said during the Western Markets Executive Committee’s webinar Friday.
RTO staff held a premeeting with FERC staff a couple weeks ago and will meet this week among themselves to determine next steps and how they will reply to comments and protests. SPP has asked for a response by Dec. 1, which would keep the WEIS market on track for its Feb. 1 go-live date.
FERC staff’s primary concern is with the Tariff’s joint dispatch transmission service (JDTS) provisions. SPP staff will collaborate with WEIS transmission providers to ensure their respective tariffs incorporate the correct JDTS language.
David Kelley, SPP’s director of seams and market design, said the regulatory delay has left the WEIS program in yellow status, which the RTO defines as “needing attention.”
Market trials are also considered in yellow status as participants gear up for the start of parallel operations on Dec. 10. Participants are currently testing dispatch signals to resources but will begin “playing” in the production environment during parallel ops.
SPP will launch the WEIS with eight members covering the Western Area Power Administration’s Colorado Missouri and Upper Great Plains West balancing authority areas.
The market, based on the Energy Imbalance Market that SPP operated from 2007 to 2014, continues to attract interest in the West. Bruce Rew, SPP’s senior vice president of operations, recently told the RTO’s stakeholders that several additional utilities reached out to the grid operator following the rolling blackouts in California late this summer. (See Theories Abound over California Blackouts Cause.)
California’s port infrastructure will pose a key — but not insurmountable — obstacle to the development of floating offshore wind (FOSW) projects along the state’s coastline, industry experts said Thursday.
The subject arose during a scoping workshop the California Energy Commission convened to seek public input on its “draft research concept” regarding the development and testing of FOSW technology.
While West Coast offshore wind development lags that of the East Coast, 14 developers responded to the U.S. Bureau of Ocean Energy Management’s 2018 call for information and nominations to develop wind facilities off the coast of California. Development is more of challenge along the West Coast compared with the East because of the very narrow continental shelf and steep drop-off close to shore, necessitating the construction of floating — rather than fixed-bottom — turbines. (See Differences Aside, West Coast OSW Can Learn from East.)
BOEM’s three call areas off the California coast are located in remote areas far from the state’s major ports. | BOEM
During Thursday’s virtual workshop, the CEC laid out a tentative objective that state-funded research projects support “the development and pilot demonstration of innovative floating offshore wind component(s) and installation processes that advance the readiness, reliability and cost-competitiveness of floating offshore wind in California.” It also seeks to increase understanding of how FOSW will affect sensitive wildlife species and habitats in the region.
The final research concept will guide the CEC’s investment plan for dispensing grants through California’s ratepayer-funded Electric Program Investment Charge (EPIC) program, which currently invests about $130 million annually across all energy research and pilot programs.
During the workshop, Alla Weinstein, CEO of Castle Wind, said she thinks a key issue was omitted from the CEC’s stated objective. She noted that a still unreleased report by the National Renewable Energy Laboratory, discussed publicly during a recent California Public Utilities Commission meeting, found that the “distance to port” for projects in federal lease areas will be the “main driver” of the cost of energy for California FOSW.
BOEM’s call for nominations designated three sites for development, including the Humboldt Call Area off California’s remote North Coast and the Morro Bay and Diablo Canyon call areas off the sparsely populated Central Coast.
“The distance to port is one element, but also the port infrastructure and limitations that are visible right now are going to be the biggest challenges the industry is going to face,” Weinstein said.
The CEC failed to include the issue as one of its main focus areas despite the fact that “it is the single most important [factor] for the levelized cost of energy [LCOE], and it should be included as one of the top priorities,” Weinstein said. The CEC’s Silvia Palma-Rojas earlier told workshop participants that the commission is targeting an LCOE of $75/MWh or lower for California FOSW.
Sam Kanner, offshore wind lead for the independent Otherlab, noted that many California ports “are inaccessible to floating wind designs because of transit draft and air draft considerations from bridges or whatnot.”
“In California, there are only a few ports that could handle floating offshore wind, maybe six or so, and the largest ones are quite far away from the current lease areas,” said Markus Wernli, assistant vice president at civil engineering firm WSP USA. “That compares to the East Coast, where you could draw a circle of 50 miles and get 27 ports out of it.”
Wernli advised the CEC to focus on those ports that can most feasibly handle FOSW development. He said the commission should “help people in those communities around those ports understand what it means to have a facility that does work in offshore wind.” He recommended the state develop environmental and economic studies for those areas and assess supply-chain logistics.
Jason Cotrell, CEO of RCAM Technologies, which specializes in 3D concrete printing of renewable energy structure components, emphasized the importance of the state’s role in studying its ports. He recounted how the New York State Energy Research and Development Authority (NYSERDA) performed a 2018 study of that state’s port infrastructure for suitability for OSW development.
That study “identified 11 relatively small ports, many of them behind bridges, many of them underutilized, as potential candidates,” Cotrell said. “Too small for a staging of an offshore wind plant, but certainly potentially valuable.”
Cotrell’s company determined it could have used a small Brooklyn port identified in the report to annually produce “something like $50 million” in offshore wind components using its 3D printing technology. He said wind developer Equinor later chose the site as an operations-and-maintenance base for its offshore facilities.
Studies such as the one performed by NYSERDA are “very important to small companies like ours that have limited means and resources to perform these studies ourselves,” Cotrell said, adding that new technologies could unearth the manufacturing and O&M of ports that have been previously “written off.”
“So, there may be a lot of potential that perhaps some of us have not seen yet in California ports,” Cotrell said.
Pilot Concerns
Some workshop participants took issue with another aspect of the CEC’s objectives, advising the commission against seeking to develop a full-scale FOSW pilot, saying the cost would far exceed EPIC grant budgets.
“If the funding is intended to put hardware in the water and do a physical demonstration, you’re looking at a very large sum of money, and that is in the tens of millions of dollars,” Weinstein said. “I think there needs to be a realization that installing a full-size prototype in the water probably will not happen just because of the amount of money that will be required is beyond the funding that you have and the cost-share that would be required would be effectively prohibitive.”
Weinstein said that, unless a pilot is installed in state waters — which would not be representative of the actual builds in federal lease areas — it will require a lease from BOEM “that takes years and a lot of money and will not really lead to a demonstration project.”
“I think it’s really important for the commission to understand that developers are poised and ready to build utility-scale off the coast of California,” said Ross Tyler, senior developer at RWE Renewables. “Yes, there are still lots of unknowns from a technical perspective, but some of the technical challenges are being addressed as we speak, and I think [EPIC] is a noble effort to be part of that.”
But Tyler agreed with Weinstein that a full-scale pilot would be cost-prohibitive and said the industry is not really seeing demonstration projects, which would have to be permitted by BOEM and completed within the next three years.
“I think you really need to take a look and perhaps eliminate this notion of having pilot-scale in the water. Otherwise, the developers will not really be interested in participating. That’s my take,” Tyler said.
Cotrell agreed with Weinstein and Tyler about the infeasibility of a full-scale FOSW pilot but did see potential benefits from pilot projects for individual FOSW components.
“For example, in our case, we have some concepts and a little bit of funding to explore the 3D concrete printing of suction bucket anchors, which are the third-most capital-intensive component of a floating wind turbine,” behind the turbine itself and its foundation, Cotrell said.
He said his company could manufacture those anchors and even tow them out to sea and embed them at pilot-scale but could not attach them to a full-scale FOSW turbine at EPIC funding levels.
“I just wanted to offer the different perspective of a component developer that pilot-scale tests and projects are certainly possible, but a lot of care has to be taken with the definition,” Cotrell said.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. The MRC will be asked to endorse revisions to Manual 15: Cost Development Guidelines resulting from the biennial periodic review process. The revisions include reformatting and rewording in sections 2.6.1 and 2.6.8 to provide more clarity.
Endorsements/Approvals (9:10-9:45)
1. 2020 Installed Reserve Margin Study Results (9:10-9:25)
Members will be asked to endorse the 2020 Reserve Requirement Study results, including the installed reserve margin (IRM) and forecast pool requirement (FPR). PJM is recommending an IRM of 14.4%, down from 14.8% in 2019. The FPR is essentially the same as 2019, at 1.0865 (8.65%) instead of 1.086 from the previous year. The study determines the IRM and FPR for 2021/22 through 2023/24 and establishes the initial values for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties. (See “Installed Reserve Margin Study Results,” PJM PC/TEAC Briefs: Oct. 6, 2020.)
2. Liquidation Process (9:25-9:45)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions addressing PJM’s rules for liquidating defaulted financial transmission rights positions. PJM is looking to re-establish the ability to liquidate defaulted FTR open positions and to provide flexibility in the way it exercises liquidation rights based on market liquidity, the size of the defaulted portfolio and market conditions. (See “Liquidation Process,” PJM MRC/MC Briefs: Sept. 17, 2020.)
MC endorsement will be sought on the same day.
Members Committee
Endorsements/Approvals (12:45-1:15)
1. Schedule 9-2 Options (12:45-1:00)
Stakeholders will be asked to endorse near-term changes to PJM’s administrative rates as recommended by the Finance Committee. The RTO recovers its operating expenses through Schedule 9 of the Tariff, with 90% of Schedule 9 revenue tied to actual load multiplied by a transmission factor, and the rest connected to transactional activity.
The transactional FTR billing volume, which has increased 97% since 2011, is tied to Schedule 9-2, PJM said, with the FTR administration service revenues exceeding costs because of an increase in the volume of FTR bidding activity. (See “Schedule 9-2 Options,” PJM MRC/MC Briefs: Sept. 17, 2020.)
Shirley Bloomfield, Lonni Dieck and Deborah Wheeler will join the board effective Jan. 1, 2021, the same date the new bylaws take effect (RR20-2).
SERC’s newest independent board members | SERC
Of the three new directors, Dieck has the most direct utility experience, having served as senior vice president and treasurer at American Electric Power from 2008 to 2019 — part of what SERC notes as “37 years of financial experience, primarily in the utility industry.” Currently, Dieck serves as treasurer of the board at Ronald McDonald House Charities of Central Ohio and on The Women’s Fund of Central Ohio’s board.
Bloomfield is the CEO of NTCA – The Rural Broadband Association, a trade association representing small telecommunications companies operating in rural and remote communities. She has been with the group and one of its predecessors, the National Telecommunications Cooperative Association, for more than 30 years. Bloomfield also serves on the board of the National Rural Telecommunications Cooperative and GlobalWin, a professional association representing women in the tech industry, and has previously worked as a senior executive at both Verizon Communications and Qwest Communications International.
Wheeler has served as chief information security officer at a number of companies, including Ally Financial, Fifth Third Bank, the Federal Home Loan Mortgage Corp. and, since 2017, Delta Airlines. She also serves as governing board chair for Evanta’s CISO Forum in Atlanta and works as an adviser at software companies Proofpoint and Forcepoint.
“This is really an exciting moment for SERC as we continue a governance transformation that will improve the reliability and security of the electric grid,” board Chairman Greg Ford said in a press release. “The addition of three independent directors is essential to our continued strategic growth and will help to provide a balanced, independent perspective to our stakeholder expertise.”
With the appointments of Wheeler, Dieck and Bloomfield, SERC now meets the minimum required number of independent directors for its board under the new bylaws. The board is required to have 15 sector representatives and may have up to five total independent directors.
Other structural changes in store for SERC next year include:
requiring that a majority of the board, as well as a majority of the independent directors, be present to have a quorum for meetings;
eliminating the use of alternates and proxies for directors;
formalizing SERC’s membership body by transitioning the existing board structure into a members group, which will include a representative from each member company and meet at least annually to advise the board on the business plan and budget, elect independent directors and approve bylaw changes as needed;
changing the Board Compliance Committee into the Board Risk Committee; and
adding a Human Resources and Compensation Committee, Nominating and Governance Committee, and Finance and Audit Committee.
Implementation measures include revising SERC’s Regional Reliability Standards Development Procedure (RSDP) to reflect the new structure by, among other things, removing references to board representatives and alternates and replacing references to the SERC Executive Committee with the board. NERC earlier this month posted the revised RSDP for stakeholder comments, which are due by 8 p.m. Nov. 20. (See NERC Opens Comments on SERC RSDP.)
Facing growing uncertainty from intermittent resources, MISO and other grid operators must increase use of demand resources and provide market participants with tools to hedge risks, academics, consultants and others told the RTO’s Market Symposium this week.
“The challenge facing ISOs around the world in the next decade or 15 years is quite unprecedented,” said Andy Sun, associate professor at the Georgia Institute of Technology’s H. Milton Stewart School of Industrial and Systems Engineering. “We’re moving into territory I think we haven’t seen before in terms of the uncertainty that will be in the system. Demand and supply are all becoming a lot more stochastic — which means it’s both uncertain and also dynamic.”
Andy Sun, Georgia Tech | MISO
Scott Harvey of FTI Consulting said California’s and Australia’s challenges in managing higher levels of solar output foreshadow MISO’s future and the limits of markets.
“One of the key things we have to look at is: Are the markets consistent with the actions the operators are taking? Are they reinforcing those actions?” he said. “What we’re seeing in California is [that] the failure of some of the tools to deliver — to perform as intended — has led to a continuation of operators taking out-of-market actions.”
Harvey and Sun were among the panelists in a discussion Tuesday on “Addressing Uncertainty, Variability and Risk via Power Markets and Operations.”
Need for DR
Scott Harvey, FTI Consulting | MISO
Harvey and Ross Baldick, professor emeritus in the Department of Electrical & Computer Engineering at the University of Texas, Austin, also called for more emphasis on demand resources.
More than 90% of demand response in MISO is only available in the lead up to an emergency, and there is little DR in much of MISO South, according to testimony by former Ohio regulator Paul Centolella that was filed with a complaint over state DR opt-out policies in MISO on Tuesday. (See DR Firm Challenges FERC, MISO on State Opt-out.)
“I think there is an incredibly invaluable role that needs to be played by the demand side,” Baldick said. “We’re simply, in a high renewable world, moving away from the presumption that we can serve all demand no matter what. And the way I would like to see that worked out is that we have a lot more price-based demand response that gives us gigawatts and gigawatts of flexibility.”
Ross Baldick, University of Texas, Austin | MISO
Harvey said the most important areas for MISO to improve in the operational time frame are DR and ensuring the demand curve and operating reserve demand curve provide resources needed to balance variations in net load and reduce operators’ “ad hoc” actions.
“We need to get demand response into the market — not just have demand response be something you pay for providing phantom response, but actually be there, providing regulation [and] reserves that the operators can see and count on.
“If we’re going to get into energy-limited situations, I think we’re going to need demand-side resources that can provide 30-minute reserves or longer; reserves that can drop off for periods of time to enable us to conserve energy, and not necessarily during emergency conditions,” he continued. “We may need to conserve energy before we get into the emergency so we can get through the emergency. So that’s another [thing] we need to study.”
In a panel discussion Wednesday on “Infrastructure as an Enabler,” Julian Leslie, head of networks for National Grid Electricity System Operator in the U.K, said grid operators will move from dispatching generation to meet demand to dispatching load to meet generation.
“So, on those windy days, the hydrogen electrolyzers are running; people are charging their electric vehicles; they’re charging their batteries in the lofts of their houses. And on those non-windy days, they’ll be using all that stored energy,” he said. “We’ve got one supplier here in Britain that offers you a negative pricing tariff, so when it’s really windy and the demand is low, say on a Sunday afternoon, this supplier will pay its customers to consume electricity.” About 150,000 customers have signed up for the service, he said.
“This is a great resource; it’s cheap,” said James McCalley, a professor of electrical and computer engineering at Iowa State University who appeared on the panel with Leslie. “The only problem there is [is] to identify the right kinds of loads to go after. Not all loads are created equal.”
One desirable type of load, he said, is water treatment plants. “They have an inherent flexibility in when they use their energy as a result of the ability to store water,” he said. “And they’re ubiquitous. … Every region has many, many water treatment plants, so this is a very good target.”
New Products
Harvey said the future will require new products, calling on grid operators to start “radically thinking about regulation in next 10 years.”
“We may need two types of regulating resources — those that can only regulate up five minutes because they’re a battery and they’re going to run out [of energy] … and others that can keep reg up, and as we need more and more and more, they can keep going up and up and up. That’s something the ISOs, as they encounter this, need to talk to each other and do joint research,” Harvey said.
Renuka Chatterjee, MISO’s executive director of systems operations, said she sees change coming also.
Renuka Chatterjee, MISO | MISO
“One of the biggest MISO value propositions is our large footprint. So, we could be having snowstorms up north and hurricanes in the south simultaneously. We operate that market today with 400 MW of regulation, and we don’t use most of it on most days. We operate very, very well within that 400 MW for a 125-GW peak load system.
“I keep wondering when we’ll change the algorithm,” Chatterjee said. “So, the traditional thinking … is about to change.”
Baldick said grid operators might consider a product that addresses the reduced inertia provided by renewables.
“When we’ve defined things like contingency reserves, spinning reserves … we haven’t fully represented all the physics. We’ve captured the essence of the issue, and we find a constraint that is a pretty good surrogate for capturing the issue most of the time,” he said. “Maybe we need to do something like that for inertia or maybe some other products.”
Don’t Act Without Data
Several of the speakers said MISO and other grid operators should put an emphasis on data gathering before thinking about potential solutions.
“Let’s not make choices about how we’re going to build the software or how we’re going to solve the problem too soon. I think [there should be] a lot of looking at this and learning from each other and then deciding which road is the best for everybody,” Harvey said.
He noted that CAISO is trying to calculate the demand for flexibility resulting from intermittent resources, unpredictable load and resources that fail to follow dispatch instructions.
“So, you can try to do that calculation and assign [the costs] to the resources that are creating the uncertainty and perhaps incent them to behave differently,” he said. “But it is complicated, and it’s going to be a burden on your settlement system. … So, you have to make a judgment of: Is this going to make enough difference in behavior and resource choices to improve the outcomes?”
Mark O’Malley, University College, Dublin | MISO
Mark O’Malley, professor of electrical engineering at University College, Dublin, agreed. “Why don’t we experiment? Why don’t we understand it before we do it?” he said. “If you’ve got a product in a market that’s got a zero-price … then you didn’t need it. And I think some of the products thrown out there [are unnecessary]. … I think people go too far with markets sometimes.”
He said grid operators should concentrate on “real measurements after the fact, collecting large amounts of data. … Get enormous amounts of data that’s real and use that. That’s better than any model data.”
Socializing Risk
Baldick said MISO shouldn’t seek to eliminate market volatility resulting from the increased variability of renewables. “We do have to think very carefully about how to navigate who takes on those risks, who hedges them,” he said. “From my own philosophical perspective, the risks that can be borne by market participants are best left with those market participants, and we should only hope to socialize the risks that are truly ones that pose systemic risks to the operation of the system — cascading outages, as a good example. … To the extent possible, [MISO should be] making sure that market participants are seeing those risks and are provided with the right incentives to hedge them whenever its economically efficient to hedge them.”
Even the best data and the most carefully designed market tools will not eliminate the increasing uncertainty, speakers said.
“Ultimately, we need to pay more attention to the underlying statistics of renewables — and particularly wind — to really understand the answers to questions like: If we connect MISO with PJM and average out the wind across that footprint, do we significantly reduce the relative variability or not?” Baldick asked.
“It’s pretty clear to me that there are fundamental stochasticities that aren’t going to be smoothed out by larger and larger footprints until we average coastal [and] far inland wind, for example; until we average storms in the western half of the United States with weather in the eastern half. … So, while I certainly want to improve weather forecasting, it’s not going to take away from the fundamental variability of those renewables.”
Grid emergencies in MISO began increasing in 2016, with 21 of the 28 events occurring in non-summer months that rarely posed reliability problems in the past. | MISO
“What we need to forecast is how big the variability could be,” Harvey said. “Even if we can’t forecast what load can be, can we forecast how high net load could go? That’s complicated enough.”
Forecasts also need to be matched with an understanding of transmission congestion, he added, citing CAISO’s load-shed events in August.
“It’s not just, ‘How much variability is there [and] when?’ It’s when [and] where. Because congestion is critical. A lot of the reasons why the CAISO’s ramp product has completely failed is because of locational constraints. They had enough upward ramp capability, but it was behind transmission constraints. If we’re going to use storage to balance some of this, we not only need to know how much [and] where but for how long and how much energy we’re going to need.”
MISO’s Advisory Committee has voted to allow the RTO’s newly created Affiliate sector voting rights in certain committees.
Sector representatives voted 15-9 during the committee’s teleconference Thursday to recommend that the Board of Directors allow MISO’s 11th sector one vote in the AC and one vote on issues before the Planning Advisory Committee.
The minority of AC members voted in favor of splitting the Environmental Groups sector’s existing two votes with the Affiliate sector. The latter sector was borne from the previous Environmental and Other Stakeholder Groups sector. Currently, it is not allowed a vote in committee matters but had one designated non-voting seat during meetings. (See New MISO Sector Gets FERC OK — with a Catch.)
The decision is considered advisory in nature to the board, where the final determination rests, and came after a failed motion from some members to delay the vote. Some representatives complained that the new sector’s purpose was still too shadowy to yet determine if it is worthy of casting votes like other sectors that have clearer intents.
Representatives have said that the sector should receive one vote when the AC votes on advisory items to the board or RTO leadership. But some members this week seemed split on the issue. Some also said it wasn’t clear how the sector would access or communicate with MISO directors about stakeholder issues.
Environmental Groups representative Beth Soholt called for a “comprehensive” understanding of what exactly is the sector’s purpose before deciding to award it any votes on AC recommendations.
“We’ve heard this is a standalone, catch-all sector, and we’ve also heard this will be an incubator sector. … There is a number of outstanding issues,” Independent Power Producers and Exempt Wholesale Generators representative Travis Stewart said.
During the committee’s Sept. 16 meeting, Public Consumer Advocates representative Christina Baker had also said her understanding of the Affiliate sector was that of an “incubator” for new members until enough like-minded entities joined to branch off into a new sector. She said she was unsure if a collection of miscellaneous entities could get along and agree on a vote.
AC Chair Audrey Penner pushed back on the notion that there was confusion about the Affiliate sector’s purpose.
“I don’t know how else it could be interpreted but that it’s a home for all newcomers that can’t find a place in another sector,” Penner said. She also said she viewed voting rights as a separate issue from how the new sector would interact with the board.
Existing sectors will now draft eligibility criteria and mission statements so it’s clearer where new MISO members should be placed.
Unlike the divergent opinions around Affiliate sector voting rights, nearly all sector representatives have opposed the consolidation of some existing sectors, an idea that was presented earlier as the committee was considering restructuring. (See MISO AC Works on Sector Rules as FERC Timeline Ticks.)
“There’s no desire to consolidate, not even to align,” Penner said.
“We believe that one strength of the MISO stakeholder process is the diversity of opinions,” Soholt said at the committee’s September meeting.
Representatives have also asked that the grid operator allow more informal and less stage-managed access to the board.
“We’re looking for more meaningful interaction with the board,” Stewart said.
Many sector representatives have also expressed the desire to curtail new sector creation in the future.
“We hope that the creation of new sectors will be really limited in the future, and MISO will work hard to find places for new members in the existing sectors,” the State Regulatory Authorities sector’s Julie Fedorchak said.
Unlike spring, when New York City was the epicenter of the COVID-19 pandemic, health indicators are now pointing in the right direction for the city, but its unemployment rate is still about double the national average, according to Moody’s Analytics.
Moody’s expects the recovery of the U.S. economy to extend over one to two years, given the unlikelihood of an effective vaccine becoming available before spring 2021. But after national GDP fell more than 10% last spring, the economy is slightly more than halfway back, Adam Kamins, a director at Moody’s, said Wednesday at the NYISO Fall Economic Conference.
Adam Kamins, Moody’s Analytics | NYISO
The economy was technically in recession for only two or three months before it began to recover, but the hit was “extraordinarily deep,” he said.
“A lot of the lower hanging fruit was plucked, because firms reopened; people started to re-engage with the economy; you started to see a little bit more restaurant reopenings and stores starting to reopen and a return to something resembling normalcy,” Kamins said. “For sports fans like me, it’s almost a microcosm of what you saw over the course of the summer; you saw sports return, but in a weird and different way, with no fans. That’s how you can think of the economy too.”
Moody’s calls the current period “the pre-vaccine recovery” phase, with a “pretty stagnant economy” projected through 2021, Kamins said.
“First, the fiscal stimulus has expired, and our baseline expectation is that there won’t be more stimulus coming from the federal government until probably after the next inauguration in January,” Kamins said. “The other factor is that COVID-19 cases are rising, and they are starting to rise pretty rapidly in a lot of the country,” especially in the Sunbelt states and in the Upper Midwest.
New York’s economic outlook is “still pretty bleak,” he said. The shock from being the national epicenter of the pandemic was so severe that the city’s unemployment rate shot up to 20%, easily an all-time high since statisticians started keeping records 50 years ago.
Moody’s Analytics said that unlike in spring when NYC was the epicenter of the pandemic, indicators are pointing in the right direction but the city’s unemployment rate is still about double the national average. | Moody’s Analytics
The gaps are starting to narrow between the city, the rest of the state and the rest of the country. But the state was the second-worst performing in terms of three-month annualized growth through August, after Hawaii, he said.
State Handling COVID
In terms of its handling of the pandemic, while infection and death rates are rising everywhere in the U.S., New York is actually better off than most of the country, he said.
“We have an alarming trend here where cases are starting to spread out from the middle of the country,” Kamins said. All but two states are experiencing an increase in daily per capita cases, so the country is in “a pretty tough spot” while it waits for a dependable, widely available vaccine, he said.
Moody’s Analytics expects the economic recovery nationally may extend over one to two years, given the unlikelihood of an effective vaccine becoming available before spring 2021. | Moody’s Analytics
Western New York and the capital region have fared particularly well in terms of infection rates, and “two relatively large metro areas are at the top of the list in terms of best performance with respect to COVID-19. … We have fewer than one out of 1,000 residents in both Rochester and Albany that have tested positive, and those are the lowest numbers in the U.S.,” Kamins said.
This fact is all the more impressive considering that New York’s testing capacity is as high if not higher than that of any other state, so it is well positioned to ride out a second wave of COVID infections, he said.
Election Outcomes
Kamins closed out his national presentation with a one-page summary of the policy differences between former Vice President Joe Biden and President Trump.
“Generally, in terms of governing and COVID-19 response, a Biden administration would be looking at a federally led approach, would be looking to strengthen institutions and the federal government,” he said. “The Trump administration’s approach has been more state-led; they’ve taken more proactive steps to weaken government oversight in some ways, weaken some institutions.”
A Democratic-controlled Senate with Biden in the White House would likely pass a hefty fiscal stimulus package, which would create more jobs, he said, noting that the Biden campaign had cited Moody’s numbers. (See ‘Massive’ Clean Energy Stimulus Under Biden Likely)
“Take that for what it’s worth, but our point of view is pretty clear: that that would be the most beneficial outcome for the economy,” Kamins said.
Moody’s model indicates a narrow win for Biden, but “I still remember vividly telling you four years ago that our model predicted a pretty decisive win for [Hillary] Clinton, and then I was sitting in the airport that night flying home, and that’s when,” on Oct. 28, 2016, FBI Director James Comey told Congress the bureau had discovered more of the former secretary of state’s emails sent from a private server. Comey’s letter was “possibly one of the most consequential turning points in the election,” Kamins said.
No one can really diagnose why some of the predictions in 2016 were as off as they were, he said.
“We changed our model a bit to control more for turnout, because that’s what we found was missing. Ultimately, Trump was much more successful in turning out his base than Hillary Clinton was,” Kamins said.
Missouri regulators have opened a working case to determine whether the state’s investor-owned utilities’ continued RTO membership “is in the ratepayers’ best interest.”
The state’s Public Service Commission issued an order on Oct. 14 that directs each IOU to participate in a workshop that has yet to be scheduled and to cooperate with the “investigation.” PSC staff will file a report with their findings by June 30, 2021 (EW-2021-0104).
The order applies to Evergy Missouri Metro, Evergy Missouri West, Empire District Electric and Ameren Missouri. Evergy Metro and Empire are SPP members; Ameren is a MISO member; and Evergy West is a member of both.
The PSC said it “believes there are benefits” to the IOUs’ RTO memberships but that they “exceed the long-term costs and commitments of RTO membership, especially given that the structure, services and membership of both Southwest Power Pool and the Midcontinent Independent System Operator continue to change significantly with the passage of time.
“The commission must inquire into the nature of the benefits of RTO membership, the monetized value of those benefits and what time horizons should be employed to compare asset lives (costs) to the values of benefits streams,” the PSC said.
According to the order, the workshop will determine:
the information needed to respond to the commission’s current and previous orders on RTO membership;
whether such information is reasonably and economically available, and if not, what kind of information could be used as a proxy to control costs and expeditiously respond to the commission;
the cost of gathering, analyzing and interpreting such information; and
whether there are any identifiable “deal breaker” events or event categories that would make it unreasonable for an IOU to remain in an RTO.
SPP said it welcomes the study and stands ready to support its members’ efforts to “evaluate the cost and benefits of their membership.”
“We fully respect that the states and utilities we serve need to ensure they’re receiving adequate value from their membership in SPP,” spokesman Derek Wingfield said. “We remain committed to continually finding new ways of adding value in collaboration with our stakeholders.”
MISO said it is aware of the investigation and is waiting for further guidance on how to assist.
The issue stems back to the early aughts, when the PSC initially placed contingencies on IOUs wishing to transfer functional control of their transmission systems to the RTOs. That allowed the commission to maintain jurisdiction and better understand whether RTO membership would provide the IOUs’ expected benefits, former Commissioner Steve Gaw said.
“At that time, there was no track history to go by in the Midwest, and the net-benefit calculations were estimated,” said Gaw, now with Advanced Power Alliance after six years on the PSC.
The problem has been that the IOUs have continually kicked the proverbial can down the road.
In 2011, the Evergy companies — then operating as Kansas City Power & Light — filed an interim report requesting the commission approve their continued participation in SPP beyond October 2013. In May 2013, the commission approved an interim agreement between KCP&L, PSC staff, the Office of the Public Counsel (OPC), SPP and Dogwood Energy that extended its approval through September 2018 (EO-2012-0136).
Four years later, the commission accepted the companies’ motion to extend the interim period to 2021 and to absolve them of the requirement to file the 2017 interim report.
Ameren Missouri, which does business as Union Electric, received PSC approval in 2012 to transfer functional control of its transmission system to MISO, subject to certain conditions. Those conditions required the utility to file a new case addressing its continued participation in the RTO in 2015. At Ameren’s request, the commission extended the date to November 2017 and then March 2020 (EO-2011-0128).
In March 2019, the commission granted a motion by Ameren, commission staff, the OPC and the Missouri Industrial Energy Consumers to delay the rate-case filing until March 2023.
Acknowledging Ameren’s contention that “it would be unduly expensive to perform the comprehensive cost-benefit study” necessary to assess the value of its MISO membership, the PSC agreed that the study’s cost “outweighs the importance of the study.”
The growth of renewable energy resources stemming from technological developments and the resulting cost reductions has caused more than a few skirmishes, FERC Commissioner Richard Glick said on Wednesday.
“We’re seeing growth on renewable energy, and we’re seeing conflict as well: friction between the states’ efforts to promote renewable energy … and FERC’s regulation of wholesale electric markets,” Glick said in opening the first day of Renewable Energy Vermont’s annual conference. This year, the group is holding the conference online and over the course of three months.
FERC Commissioner Richard Glick | Renewable Energy Vermont
“I don’t think there’s necessarily a natural competition or divergence there, but we’ve seen for a variety of reasons traditional electric generators, primarily natural gas and coal, fighting it out in regional electricity markets,” particularly in the Eastern RTOs, Glick said.
“States want their decisions to be heard in these regional markets,” Glick said. “From my perspective, FERC’s responsibility is to figure out a way to help these RTOs design their markets and oversee [these] design changes to ensure that state policies are accommodated, not blocked. If we don’t do that, I think we’re headed towards a bad situation in which some states are going to drop out of RTOs, and certainly states aren’t going to do anything further that would give FERC additional authority over resource decision-making.”
REV Chair Josh Bagnato asked what FERC is doing that impacts Vermonters who are pushing for the clean energy transition.
REV Chair Josh Bagnato | Renewable Energy Vermont
“The commission has quite a bit of jurisdiction over the New England electricity market through our oversight of ISO-NE, so almost all wholesale transactions throughout the region are subject to FERC regulation and oversight. So, the decisions we make have a great deal of impact on the resource mix, prices and on reliability,” Glick said.
“I don’t think the people at ISO New England … get up in the morning and say, ‘How can we frustrate or block state programs?’ I don’t think they do that at all, but they are looking at the markets from a different perspective. They want to make sure that the lights stay on and that they provide power at a relatively reasonable price.”
The federal government right now “is relatively AWOL on greenhouse gas emissions, [so] it’s really up to the states at this point to address those issues, and I don’t think the commission blocking state policies, whether it be intentional or inadvertent, is the way to go at this point,” Glick said.
He cited a recent Lazard analysis that said wind and solar are now the most cost-competitive energy technologies, not only in the U.S., but around the world.
“That’s certainly been a pretty dramatic change,” Glick said. Though federal and state policies have helped somewhat, he said, far and away the biggest driver has been consumer demand, and that will certainly continue in the future.
Individual consumers as well as corporate America have concerns about climate change and would like to see a much greener mix in their utilities’ resource portfolio.
FERC Commissioner Richard Glick cited a recent Lazard study that shows that when U.S. government subsidies are included, the cost of onshore wind and utility-scale solar is competitive with the marginal cost of coal, nuclear and combined cycle gas generation. | Lazard
At first it was just Big Tech companies, “but now we’re seeing it all over the place, with Proctor and Gamble, Anheuser-Busch, Walmart — companies that you wouldn’t normally think of in terms of the energy space,” Glick said. “They’re saying, ‘We want to be 100% green and have a 100% net-zero emissions portfolio as quickly as possible.’ And they’re demanding that of utilities, which are going out and substantially changing the resource mix.”
Bagnato asked what three magic buttons Glick would push to help the transition to renewable energy.
“The first is more of an esoteric one, which is follow the science,” Glick said. “The U.S. is the only country in the world having this debate. … Two, massively build out the transmission grid to be able to accommodate offshore wind and … onshore wind and solar. Third, we have to have a federal policy. States have been doing a great job, but whether on carbon pricing or whatever, cooperation on a regional basis doesn’t work without a federal overlay.”
