Technical Advisory Committee Chair Bob Helton has canceled the committee’s Aug. 28 in-person meeting because of a “limited number of items” for consideration.
Instead, the TAC will hold an online information session on the Real-Time Co-Optimization Task Force’s (RTCTF) latest work to develop real-time co-optimization (RTC) principles. RTC is a market tool that will procure energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.
Review process for the real-time co-optimization project ordered by the Texas PUC, including the Real-Time Co-Optimization Task Force and the Technical Advisory Committee. | ERCOT
The task force plans to present three key principles (KPs):
KP1.4: telemetry changes associated with any change to the resource-limit calculator logic;
KP1.5: process for deploying ancillary services; and
KP3: reliability unit commitment settlement.
The committee will conduct an email vote on the principles after the meeting.
The task force has until February to draft the principles that will guide RTC’s design in adding ancillary services to the real-time security-constrained economic dispatch engine. The TAC in July approved the task force’s first five RTC key principles. (See “TAC Approves First Real-time Co-optimization Principles,” ERCOT Technical Advisory Committee Briefs: July 24, 2019.)
The Wisconsin Public Service Commission on Tuesday authorized the contentious Cardinal-Hickory Creek transmission line, sanctioning MISO’s last remaining multi-value project eight years after the RTO’s approval.
The unanimous, verbal approval from commissioners for a certificate of public convenience and necessity at its open meeting was considered preliminary (5-CE-146). A PSC staffer told RTO Insider that a written order will now be drafted and put before the commission for final approval in September.
The PSC concluded that the line will reduce congestion charges, improve reliability and boost transfer capability between Wisconsin and wind-rich Iowa to its west. The commission said the line could facilitate up to 8.4 GW of new generation.
“Transmission is the backbone of clean energy alternatives to fossil fuel,” Commission Chair Rebecca Cameron Valcq said in a press release following the meeting. “Getting low-cost, clean energy from where it is plentiful in the west to where it is needed, and at the scale that it is needed, cannot be done without building transmission infrastructure. I support this project because I firmly believe that it will provide tangible economic and reliability benefits to Wisconsin customers and will serve as the cornerstone to achieving a zero-carbon future.”
The nearly $500 million project has pitted environmental and renewable energy organizations against one another, with some arguing the line is needed to transport growing wind power and others contending that it is unnecessary and would destroy portions of the state’s Driftless Area. (See Environmental Groups Divided on Cardinal-Hickory Creek Line.)
Last month, attorneys general for Illinois and Michigan filed a brief with the Wisconsin PSC objecting to the cost of the 345-kV line, which will be shared on a load-ratio basis in MISO. Wisconsin commissioners said they would take the states’ stance under advisement. Democratic and Republican politicians stationed along the line’s route sent opposition letters to the commission as well.
The approximately 100-mile line would connect northeast Iowa with southwestern Wisconsin. It still needs approval from the Iowa Utilities Board, which will hear the case in December. The U.S. Fish and Wildlife Service and the U.S. Army Corps of Engineers also have yet to grant permission for the line to cross the Mississippi River.
Developers American Transmission Co., ITC Midwest and Dairyland Power Cooperative said they will begin to contact Wisconsin property owners along the route this fall. Construction is expected to begin in October 2020, with the line in service by December 2023.
“We are pleased that in addition to the reliability and economic benefits, the PSC has also recognized the importance of this project as a way to support the changing energy mix in Wisconsin and across the Upper Midwest,” ATC Director of Environmental and Local Relations Greg Levesque said in a statement.
Dairyland Vice President of Power Delivery Ben Porath said the line will deliver “substantial benefits to Wisconsin in excess of the costs of the line.”
The line is the last of MISO’s 17-project multi-value portfolio to scale the state approval process.
Lingering Opposition
Public opinion remains divided, however. Driftless Area Land Conservancy Executive Director David Clutter said his organization hoped the Wisconsin commissioners would reconsider their decision before rendering a final order and promised an appeal if the preliminary order stands.
“The commission’s own staff testified that this transmission line is not the most economical option in most modeling scenarios. It’s not needed for energy demand nor reliability to keep the lights on. We expect that this decision will be challenged before federal and other state agencies, and in the courts if necessary,” Clutter said in a statement.
In its analysis, the Wisconsin PSC found Cardinal-Hickory Creek could result in negative economic benefits in several of the hypothetical cases it studied. Projects in MISO’s multi-value portfolio were studied as a package; individual projects weren’t studied in isolation.
Clutter also noted the thousands of Wisconsin residents that submitted comments and testified at public hearings against the project, saying the PSC’s decision was “not supported by expert witness testimony, the PSC’s own staff testimony or thousands of members of the public.”
The conservancy was one of the voices clamoring for a combination of lower-voltage lines, battery storage, solar generation, energy efficiency and other distributed resources as an alternative to the line.
“Wisconsin needs to transition to renewable energy, and we can do so without damaging the natural areas and special places of our Driftless Area. There are better clean energy solutions and alternatives for Wisconsin. The PSC’s decision will result in higher utility rates in Wisconsin and across the Midwest and will allow ATC and ITC to condemn private land through eminent domain,” Clutter said.
The three developers contend that 95% of the selected 100-mile route uses existing utility and interstate or U.S. highway corridors.
Wisconsin Wildlife Federation Executive Director George Meyer said his group “will continue to challenge this destructive transmission line before federal and other state agencies, and in the courts if necessary.”
“The construction and maintenance of the proposed line and very high towers will have significant and undue adverse impacts on environmental values, including land and water resources,” Meyer said.
But the PSC’s preliminary decision was cause for celebration for renewable energy advocacy group Clean Grid Alliance.
Executive Director Beth Soholt said the group was grateful to the commission “for recognizing that more transmission is necessary in order to deliver the clean energy future everyone wants.”
“The demand for more renewable energy is palpable, and the Cardinal-Hickory Creek transmission line will provide the ability to access and deliver renewables. We are seeing an ever-increasing stream of state governments, utilities and corporations announcing plans for more renewable energy because of its low cost and environmental benefits,” Soholt said.
QUEBEC CITY, Quebec — Less than two months after taking over the footprint of the Florida Reliability Coordinating Council, SERC Reliability is planning changes to its board structure and operations, CEO Jason Blake said last week.
In briefing the NERC Board of Trustees on the July 1 transition, Blake thanked FRCC CEO Stacy Dochoda, saying, “She opened the doors. She was a complete partner.” He also thanked the Midwest Reliability Organization — which expanded last year to absorb the footprint of the SPP Regional Entity — for its advice on the transition and NERC Chief Technology Officer Stan Hoptroff for help transferring more than 300,000 files from FRCC.
Three members of the FRCC Board of Directors joined SERC’s Board Executive Committee with the transition.
Blake said SERC is using the transition as an opportunity to improve by benchmarking its operations against FRCC. “That’s resulted in us reorganizing and rethinking how we do a lot of our work,” he said.
SERC also offered jobs to the 13 people left at FRCC at the July 1 transition, and all accepted, Blake said. “The cool thing is … they’re not all concentrated in one spot. They’re actually distributed across our entire organization.”
Three of the new hires are in management positions, including John Odom, who was FRCC’s vice president of compliance, enforcement and reliability performance.
“One of the key things that we have tasked [Odom] to do is to ensure that … we understand integration didn’t stop on July 1. To truly integrate that means that all of the Florida companies have to become completely ingrained and embedded in all of our processes and programs. And we are also very cognizant that of course there will be some growing pains as we move forward.”
Anticipating the integration, SERC formed a board committee to review its structure and research governance best practices, SERC Chair Greg Ford said. “We wanted to go beyond just making changes that felt right,” he said.
As a result, SERC plans to reduce the size of its Board of Directors, which previously allowed seats for all members.
“We went from [more than] 50 to almost 90 entities that could be on that board [with FRCC’s integration]. So, we’re going from that very large board down to an 18-seat board,” said Ford, CEO of Georgia System Operations Corp. At least three of the directors will be independent, Ford said, including representation on the Compensation Committee.
The proposal will be brought to the SERC board for approval in October and the NERC board in November. SERC expects to have its new bylaws fully effective when it signs a renewed delegation agreement with NERC in 2021, Ford said.
QUEBEC CITY, Quebec — NERC’s Board of Trustees and Member Representatives Committee held their third-quarter meetings last week, with discussions on wireless spectrum, cybersecurity and the Electromagnetic Pulses Task Force. Here’s some of the highlights.
DOE’s Walker Updates on Spectrum Issue, Storage Legislation
Assistant Energy Secretary Bruce Walker told the board that he is working with the Department of Commerce to address utilities’ concerns over the Federal Communications Commission’s proposal to require then to share the 6-GHz wireless spectrum with unlicensed users. (See Utilities Warn of Encroachment on Communications Band.)
Walker, who heads the Department of Energy’s Office of Electricity, said he has spoken with Diane Rinaldo, deputy assistant secretary for communications and information at Commerce and “the person,” he said, “who has the relationship with the FCC through the White House.”
“Specifically, we have asked her to look at a dedicated spectrum for the utilities,” Walker said. “I’m not sure what the outcome will be.”
Walker also said he has been working with legislators to consolidate five bills on grid-scale storage into a single piece of legislation. The bills were the subject of a July 9 hearing of the Senate Energy and Natural Resources Committee.
He said DOE’s $5 million budget proposal for a grid storage “launch pad” survived the House of Representatives’ budget markup and awaits action by the Senate. The project, to be based at Pacific Northwest National Laboratory, will seek chemistry-based storage technologies as an alternative to lithium and rare earth materials. “Our target is to drive down the cost significantly,” he said.
Greet REs as Allies on CIP Compliance, RF Chief Urges
ReliabilityFirst CEO Tim Gallagher began his brief appearance before the board by noting it was meeting a day after the anniversary of the 2003 blackout.
“The regions continue to see violations of the [critical infrastructure protection] standards. The penalties associated with violations of these standards are increasing — I’m sure you’ve all noticed that. This is intended to send a message. It is intended to change the behavior. But penalties are nothing compared to what happens to your company if there’s an actual attack as a result of a security breach,” he said. “We cannot enforce our way to excellence.”
Instead, Gallagher said companies should take advantage of the regional entities’ voluntary programs to help companies manage their security.
“These programs are voluntary. They’re free. I’m not aware of any company that’s been harmed from the compliance standpoint from participating in these programs. So, I implore you to take advantage of these programs. The only way we can stay ahead of our adversaries in this area is by an all-hands-on-deck approach. You need to look at us as allies, as another set of eyes.”
Technology and Security Committee Chair Suzanne Keenan said the 2019 GridSecCon, scheduled for Oct. 22-25 in Atlanta, will include a focus on diversity, with a women’s networking breakfast.
“We ask that you invite, first of all, your cyber experts, but especially women and encourage them to attend,” she said.
ERO Enterprise Dashboard: Seeking More Granular Data
Director of Reliability Risk Management James Merlo gave a presentation on trends documented by the ERO Enterprise Dashboard, which tracks eight metrics.
The report found year-over-year improvements on Category 3 events (e.g., unintended loss of load or generation of 2,000 MW or more) and load losses from gas-fired outages or lack of fuel — none in either category so far this year.
Year-over-year performance was worse for protection system misoperations, unauthorized physical or electronic access, and moderate and serious risk repeat violations filed with FERC. There were three disruptions of bulk electric system operations because of physical attacks in the second quarter, including a copper wire theft and an incident in which a gun was used to shoot at the bell housings on insulators, causing a line to fall.
Vegetation encroachment violations are flat on a five-year rolling average.
Chairman Roy Thilly noted this is the first year NERC has used the dashboard and said it will consider refinements in February.
Merlo agreed the dashboard has room for improvement. For example, Metric 4 — events caused by forced outages of gas-fired unit from cold weather or gas unavailability — tracks load shed events. “It’s a pretty coarse measurement, but that’s what we have,” he said.
He said the measures of energy availability — the percentage of potential winter period production lost because of gas-fired unit outages or lack of fuel — are “kind of flatlined because we don’t have quite the granularity that we need to show whether it’s getting better or worse.”
EMP Task Force Update
Howard Gugel, director of engineering and standards, provided an update on the work of the EMP Task Force, which is scheduled to post recommendations for industry comments at the end of the month and produce a report for the board in the fourth quarter. The task force is broken into three subgroups focusing on: system planning and modeling; critical facility assessment; and mitigation, response and recovery.
Trustee Rob Manning asked what the task force will base its recommendations on. “The analysis tools, the models, are lagging,” Manning said. “They’re probably not the tools that … industry needs to do a full assessment or a full remediation.”
“That’s exactly what the [subgroups] are struggling with,” Gugel responded. “[There’s a] very limited pool of expertise that understand what the impacts are to the system from an EMP. As I’ve talked with Randy Horton [co-author of the Electric Power Research Institute EMP report in April], he said you could probably count the number of experts in the U.S. … on one hand or two hands.”
Gugel said NERC has discussed potential tools with power system modeling vendors. The E-3 pulse “looks very similar to [a geomagnetic disturbance], so the tools they’ve developed for GMD will be applicable … but the E-1 pulse is a little bit more of a concern in figuring out how exactly to model it.”
He also noted that EMP wave forms are classified. “I know that various government organizations are trying to come up with some sort of a declassified wave form that could be used. But that kind of leads into the next problem, which is … it becomes very sticky for the U.S. to be able to share something that Canada would be able to use and Canada would be able to share something the U.S. would be able to use.
“One of the other things that we’re also struggling with is, how many pulses do you deal with? Do you look at just one? Three? Four? What is the limit? The team is struggling with a lot of these concepts. They’ll make the best recommendations they possibly can, but I know this is work that will be continued throughout the next several years.”
The New England Power Pool Markets Committee met for three days in Meredith, N.H., last week to discuss ISO-NE’s proposed energy security improvements (ESI), continuing talks that began in April.
The MC has been adding days to its meeting schedule all summer to discuss the RTO’s long-term market proposal to address fuel supply constraints, market impacts of proposed rule changes, as well as various stakeholder concepts to achieve the same. (See “Assessing ESI Impacts,” NEPOOL Markets Committee Briefs: July 8-10, 2019.)
Options and Constraint Pricing
Ahead of a mandatory Oct. 15 FERC filing on the improvements, ISO-NE Senior Market Designer Andrew Gillespie reviewed various aspects of the RTO’s market-based design for ESI and led a discussion on the role of the forecast energy requirement (FER) and close-out parameters. [Editor’s Note: All quotes in this article were drawn from participants’ presentations or were approved by the speakers afterward.]
Slide 19 of the presentation answered a stakeholder question on whether the RTO’s day-ahead energy call option construct is a purely financial option, as compared to the physical day-ahead sale of energy.
Gillespie said physical DA energy sales and DA energy call options have the same financial and physical elements, and that a physical supply resource can cover its day-ahead position by delivering energy in real time in an amount equal to its day-ahead position.
In the Reserve Adequacy Analysis, the FER constraint is used to meet the expected real-time energy demand, which may result in additional unit commitments.
Both day-ahead energy from physical supply resources and energy call options awarded to physical supply resources would contribute to satisfying the FER demand quantity and would be paid the FER shadow price. Virtual supplies (increment offers) are not eligible.
The settlement close-out charge would equal the option award amount times the positive difference between the system real-time LMP and the system energy call option strike price.
“The thing that we set up way in the beginning, on slide 13 of the presentation, is that if you’re helping meet a constraint, you get paid the shadow price, and that same principle applies here,” Gillespie said, referring to slide 26, which explains that the shadow price is the FER price.
The RTO’s presentation described three reasons for including the FER constraint in the day-ahead market:
Ensuring that the market produces a reliable next-day operating plan that can meet the FER;
Improving energy security by providing physical supply that does not receive a day-ahead award but is expected to be needed to meet real-time demand; and
Improving price formation, by preventing the impact on day-ahead market compensation to resources that clear for energy.
External Market Monitor Feedback
External Market Monitor David Patton, of Potomac Economics, said the proposed day-ahead market option products “are going to have a lot of value.”
NEPOOL Chair Nancy Chafetz, of Customized Energy Solutions, had requested his feedback on the RTO’s energy security proposal.
The RTO’s new option “products are going to eliminate what amounts to out-of-market actions being taken both by the models through physical constraints that are imposed in the day-ahead market, and by operators, and result in prices that more reasonably reflect the full set of requirements in the day-ahead,” Patton said.
“Ultimately, to the extent that we are recognizing our requirements in the day-ahead timeframe, it provides schedule and revenue certainty to resources that have to arrange fuel, so I think it does help on the fuel security side,” he said.
Patton said the other options also will be beneficial. Regarding the forecast energy option, he said “right now, to the extent that the day-ahead is under-scheduled, it puts an increased onus on the [Reserve Adequacy Analysis] process to resolve that by making out-of-market commitments, so this would help resolve that issue.”
Patton said he plans to have a fuller discussion on the ESI at the September 3-4 meeting of the MC.
ESI Impacts
Todd Schatzki of Analysis Group presented further analysis of impacts of ESI under scenarios reflecting different resource mixes, fuel resources and weather conditions.
Schatzki emphasized that the study is not a forecast or assessment of future market outcomes, but an analysis of impacts.
The impacts reflect the difference between outcomes under current market rules (CMR) and ESI, and some impacts may not be particularly sensitive to assumptions.
LMP reductions from incremental inventoried energy are larger in the medium case (based on winter 2017/18 with one extended cold-snap) than the high case (based on 2013/14, with multiple, shorter cold-snaps) leading to a larger reduction in total costs. | Analysis Group
Regarding the difference between medium- and high-case scenarios, Schatzki mentioned the impacts they are seeing on the energy and ancillary services markets.
A slide on LMP prices showed what appears to be the major driver of the difference between these cases, he said.
“If one looks at the high case, there are periods of particularly high prices, but in general what we see in terms of reductions in LMPs, with ESI as compared with CMR, those tend to be relatively smaller impacts that occur erratically across the winter given different substitutions or different availability of inventory,” Schatzki said.
“By contrast, in the medium case, where we see particularly high prices in certain hours under the current market rules, and those prices are really tamped down under ESI — and what exactly are the drivers of that we have not quite dove into … but we’re going to see different impacts across different cases and that impacts are really going to depend on the particulars of the market clearing in different hours,” he said.
Market Concepts
Michelle Gardner of NextEra Energy Resources presented proposed replacement energy reserve (RER) and generation contingency reserve (GCR) products, saying the core design was complete, but the company was still open to feedback.
“The real value in our mind is that this product is creating price signals in the real-time market, because it’s when we’re deploying SOR [strategic operating reserves] and using SOR that we then create a shortage, and that’s when we start to see higher prices translated in the real-time market,” Gardner said.
“Because we are re-optimizing in the real-time market and deploying SOR if needed to meet that higher value energy and operating reserve … that’s where we see the value in the pricing, because it is showing when those resources are needed,” she said.
Rebecca Hunter presented Calpine’s forward enhanced reserves market (FERM) proposal, which she said would properly value existing fuel-secure resources in the region and provide a forward price signal that incentivizes fuel supply arrangements or investments.
NextEra Energy proposed creating a strategic operating reserve (SOR) demand curve, which it said would address lumpiness issues and create a strong price signal. | NextEra Energy
FERM would procure fuel-secure megawatt-hours from Dec. 1 through March 15, three years prior to the obligation year, which “aligns it with the capacity market and the decision for when a resource would be leaving the market,” Hunter said.
The RTO would then need to procure a set amount of firm supply to back up the loss of that resource, she said.
There would be two auctions under the proposal: the first one year prior to the obligation start, and the second after the contract verification period of Oct. 1 in the prompt delivery year.
“So, there’s also an auction one year prior, recognizing the fact that the risk might have actually decreased for an uncleared FERM resource, and they’re now eligible to try and take on that [capacity supply] obligation,” Hunter said.
FERM would procure a diverse pool of megawatt-hours and tie the obligation to offering the stored energy under Operating Procedure 21 (subject to penalty), which is activated when the RTO declares an energy emergency event.
Hunter said that FERM tries to bridge a gap in today’s existing products by providing the RTO’s operations group with appropriate in-market tools to manage the grid reliably around forecasted fuel system constraints.
Jeffrey Bentz, New England States Committee on Electricity (NESCOE) director of analysis, reiterated the group’s doubts about the RTO trying to do “too much, too fast” on the fuel security issue.
One issue for NESCOE is that an option will get exercised at times when energy security is not an issue, which they say creates option risk for providers.
A potential solution, but not a NESCOE position at this time, would be to increase the strike price by 20%. “We think at this 20% level, there’s really minor, if any, decrease in incentive for resources to invest if they get the option,” Bentz said.
A higher strike price would shrink the option close-out value, and because offers reflect this settlement, a higher strike price would reduce offer prices and clearing prices. Furthermore, it would reduce the number of market participants whose marginal cost is greater than the strike price, which may make participation somewhat more attractive to these market participants, NESCOE said.
End Notes
The RTO’s director of NEPOOL relations, Allison DiGrande, and its assistant general counsel, Christopher Hamlen, repeated a presentation on proposed Tariff changes to clarify that a resource retained for fuel security will only be retained until the end of the fuel security need, and no longer than the two-year period allowed by FERC. (See “Time Limit on Fuel-security Resources,” NEPOOL Markets Committee Briefs: July 30, 2019.)
The MC will vote on the issue at its Sept. 3-4 meeting.
In addition, the committee referred a request to add search and sort functionality to public reports produced in the Generation Information System (GIS) to the GIS Operating Rules Working Group.
CARMEL, Ind. — MISO has terminated work on a new set of futures scenarios for the 2020 Transmission Expansion Plan (MTEP 20), opting to take the extra year to resolve its lagging renewable growth and retirement projections.
The RTO announced last week that it will recycle its MTEP 19 futures so it can finish MTEP 20 work early to allow time to completely retool the 20-year scenarios for the 2021 cycle. It introduced the idea to stakeholders in June. (See MISO Floats MTEP Time Trade-off.)
At a special workshop Thursday, MISO presented more evidence to back up its claim that a futures overhaul will be both necessary and time-consuming. The RTO said its members’ public announcements and stakeholder feedback indicate that fleet change in the footprint is occurring more rapidly than staff originally thought.
“We’ve seen on the ground [that] in the last three to five years, our members are taking actions that are outpacing even what we bookended. So, our planning is not managing that uncertainty,” MISO Director of System Planning Jesse Moser told stakeholders. “It’s time for a more full-fledged redo.”
Developing futures takes time that the annual MTEP cycles don’t allow, Moser said. “We feel rushed in this current process.”
Moser said utilities’ publicly available integrated resource plans alone indicate that the tempo of new wind and solar generation and coal plant retirements are already set to track above MISO’s highest predictions from MTEP 16, 17, 18 and 19.
Utility integrated resource plans versus MTEP futures predictions | MISO
In contrast with coal dominating in 2005, wind and natural gas generation have overtaken the interconnection queue, with a “huge” recent influx of solar in MISO South, Moser said.
“We’re seeing new resources that will have infrastructure in new locations and will have different operating characteristics. So, change is happening, and it’s happening faster than our scenarios have outlined,” he said.
MISO said the number of man-hours it spends developing futures jumped from about 1,000 hours annually in 2011-2014 to nearly 6,000 hours in 2018.
The Union of Concerned Scientists’ Sam Gomberg asked if MISO is considering ways for members to inform it of confidential retirement and generation plans to inform the futures.
Moser said the RTO is open to working more member communication into the process. He also said it will do more to incorporate state policies, carbon commitments and IRPs.
Clean Grid Alliance’s Natalie McIntire said MISO might consider looking beyond the next 20 years in planning, arguing that its recent transmission projects are not large enough to meet future needs. But consultant Roberto Paliza said the 20-year futures are too far in the future to be accurate, urging 10 or 15 years instead.
MISO is collecting sector opinions through the end of the month on how it should restructure the futures.
Stakeholders Split
Stakeholders offered differing opinions on the decision to reuse the MTEP 19 futures.
Entergy’s Yarrow Etheredge said a majority of MISO transmission owners support the cessation, provided “stakeholders are afforded an opportunity to recommend targeted economic planning studies in MTEP 20.” The Organization of MISO States also expressed support for the decision.
However, MISO’s Environmental sector disagreed, arguing that staff and stakeholders have already put work into the MTEP 20 futures. Invenergy’s Ann Coultas said stakeholders shouldn’t “be forced to choose between accurate MTEP 2020 assumptions and general improvements to the MTEP process.”
Northern Indiana Public Service Co., NextEra Energy and WPPI Energy also said MISO should develop MTEP 20 futures.
The possibility of a MISO–SPP transmission expansion must wait another year, as the RTOs have concluded their third coordinated system plan without recommending a single interregional project.
However, MISO and SPP staff promised they will seek to improve the coordination of their models and make another try in 2020.
The RTOs found no projects for which both would receive at least 5% of the total project benefit, MISO economic planner Gavin Christenson told stakeholders on an Interregional Planning Stakeholder Advisory Committee (IPSAC) conference call Monday.
The RTOs said they were able to “efficiently and effectively” evaluate more than 40 interregional project ideas through each of their regional processes. SPP used two future scenarios, while MISO employed the four future scenarios from its annual Transmission Expansion Plan. SPP requires project candidates demonstrate a 1:1 benefit-to-cost ratio for recommendation, while MISO requires a 1.25:1 ratio.
“While we don’t have a project to approve out of this CSP, it was not because of any process barriers. We still have model differences — this process was designed to take those into account,” SPP’s Adam Bell said.
MISO and SPP reported a smooth changeover to new joint operating agreement rules rolled out this year. The RTOs removed their joint modeling requirement and $5 million cost minimum in addition to calculating the benefits of adjusted production costs (APC) and the avoided cost of other upgrades. Bell said he didn’t notice any “barriers” to the study of potential interregional projects and reported that the RTOs engaged in regular communication throughout.
“We’re comfortable with each set of results. I don’t think these results are any indication that we’ll never have an interregional project,” Bell said. “That’s at least my perspective.”
The lack of interregional projects has long been a topic of debate. The RTOs’ CSP studies in 2014 and 2016 also failed to result in projects. At this month’s Mid-America Regulatory Conference, officials expressed interest in creating a small, interregional project type styled after MISO and PJM’s targeted market efficiency project. (See MISO-SPP Interregional Process Scrutinized at MARC.)
Bell thanked MISO for studying so many projects, especially on SPP’s Riverton-Neosho flowgate on the Kansas-Missouri border, where MISO studied nearly two dozen potential solutions. A new 345-kV line to ease the burden on the congested flowgate was one of the seven initially promising proposals.
“Obviously this area has been on our radar, and we wanted to do our due diligence on it,” MISO Interregional Planning Adviser Ben Stearney said of the RTOs’ most expensive flowgate. (See SPP Briefs: M2M Payments from MISO to SPP Eclipse $32M.)
M2M Payment Consideration
Stearney said MISO’s high market-to-market (M2M) payments on the Neosho-Riverton flowgate aren’t captured in APC savings in its model because generation is not redispatched to ease congestion on the line.
“It’s no secret that our APC methodologies have differences,” Stearney said.
Several stakeholders said M2M payments should factor into benefit analyses.
“I don’t understand why the MISO process hasn’t gotten in front of that Neosho-Riverton issue at all,” Missouri Public Service Commission economist Adam McKinnie said.
“This is leaving me concerned that this is not … properly capturing MISO’s cost” to use the flowgate above its firm service, WPPI Energy’s Steve Leovy said. “Unless I’m misunderstanding things, this looks like an appropriate thing to focus on.”
MISO staff promised a closer look at the impact of M2M payments in future interregional studies.
Models, Futures Coordination
Stearney also said the RTOs will pursue better model coordination but cautioned that their separate future scenarios will remain different, “driven by separate stakeholder processes.”
But later in the meeting, RTO staffs said they might consider creating interregional futures to use in the two separate regional reviews.
“Hopefully this thing will build on itself, and each year we’ll have more and more compatible models,” Bell said. “We do think that since we’re doing this annually, we’re going to get a lot better at incorporating everything we can feasibly. … That’s the hope in what this annual process will allow us to do.
“But there’s always going to be a disconnect,” he added.
He said this year, SPP and MISO made sure that the models, although different, “at least made sense.”
“The reasons we’re pointing this out is a sanity check. The [models] do show different benefits. That wasn’t unexpected,” Bell said.
Joint Model Nostalgia?
Advanced Power Alliance’s Steve Gaw asked if some of the modeling mismatch might have been resolved had the RTOs retained their joint model.
Bell said he thought there would be no difference in results with or without a joint model requirement.
“The joint model could have yielded a different result, but the analysis that we just went through would have been exactly the same in the regional review,” Bell said. “We were going to end up right back where we are.”
“You still have the rejection in the regional review. That’s where these projects get thrown out,” Gaw observed, saying he believed the interregional study process may be “broken.”
Bell said there simply wasn’t a project this year that could stand up to all the criteria.
Stearney added that MISO didn’t want to “compromise itself” by lowering the standards in its regional planning process. “We want to make sure projects stand up to criteria established on both sides of the fence,” he said.
MISO and SPP still must create a final, detailed CSP report to present to the IPSAC. The RTO staffs also said they’re taking early steps to begin the 2020 CSP. Representatives from both RTOs asked for stakeholders to submit additional written feedback on suggested improvements to the process.
“This was going to be a takeaway whether we had 10 projects [to recommend] or none — we’re going to improve the process,” Bell said.
FERC last week denied City Utilities of Springfield’s (Mo.) complaint against SPP’s regional cost allocation reviews (RCARs), saying the utility failed to show the RTO’s administration of the process was unjust and unreasonable (EL19-62).
Springfield filed the Federal Power Act Section 206 complaint in April, charging that SPP’s highway/byway cost allocation methodology has produced unintended consequences in its pricing zone that violated the cost-causation principle and the “roughly commensurate” standard.
City Utilities of Springfield HQ | City Utilities of Springfield
In asking for retroactive relief from its pricing zone’s costs, Springfield cited a 1982 D.C. Circuit Court of Appeals ruling that asserted that “properly designed rates should produce revenues from each class of customers [that] match, as closely as practicable, the costs to serve each class or individual customer.”
The commission rejected Springfield’s relief request, saying it “would be contrary to the filed rate doctrine and rule against retroactive ratemaking.”
FERC said SPP provides two avenues for members to dispute alleged “imbalanced cost allocations”: when the Regional State Committee makes an adjustment recommendation to the Board of Directors, or when a member asks the Markets and Operations Policy Committee to examine an alleged imbalance.
SPP’s transmission pricing zones | SPP
Springfield said SPP’s two RCARs have saddled its transmission zone in southwestern Missouri with the only benefit-cost ratio that does not meet the grid operator’s minimum threshold. The utility said the second RCAR allocated its zone $29 million more in costs than benefits, while customers in other pricing zones “will share in billions of dollars of net benefits.”
The protest drew numerous intervenors, including nearly two dozen SPP members and four state regulatory bodies. The Missouri Joint Municipal Electric Utility Commission supported Springfield’s argument, while Xcel Energy filed comments supporting SPP.
FERC last year approved a regionally funded project near Springfield that is expected to address some of the city utility’s issues. (See “FERC Approves SPP-AECI Morgan Transformer Seams Project,” SPP Briefs: Week of Oct. 8, 2018.)
FOLSOM, Calif. – Members of CAISO’s Market Surveillance Committee and stakeholders wrangled over systemwide market power and ways to limit it during an occasionally testy two-hour exchange Monday.
In March, ISO staff issued an analysis of market power in response to a similar report by the ISO’s Department of Market Monitoring, an independent body within the ISO. The staff analysis found its balancing area was uncompetitive during a limited number of hours in 2018 — primarily during times of peak demand when natural gas generators came online. Hot summer days, especially, allow some suppliers to game the system, staff said.
“If we were to design a systemwide market power mitigation process, how would it look?” Perry Servedio, lead market policy design developer at CAISO, summed up the process.
The DMM’s report had used somewhat different criteria but arrived at similar results and recommended the ISO take action to reduce the conditions in which market power might exist.
To address the findings, the ISO and the Market Surveillance Committee have convened a series of monthly stakeholder meetings with the goal of generating an opinion by October. They’re expected to present their findings on the potential costs and benefits of market-power mitigation to the ISO’s Board of Governors in November.
Among the topics being discussed are how to screen for market power and, if found, how and when to take steps to mitigate it. For instance, should the ISO screen only in the real-time market or also in the day-ahead market? And is it appropriate to mitigate voluntary supply?
Not everyone agrees with the ISO’s market-power assessment.
In a presentation at Monday’s meeting, Market Surveillance Committee member Scott Harvey said the ISO’s test for market power is “very conservative.” Failing to pass it doesn’t show the market is structurally non-competitive, he said.
“The test is designed to err toward over-identifying the potential for the exercise of material market power because it is not possible to apply a more sophisticated test in the time frame of the day-ahead market or real-time,” said Harvey, of FTI Consulting.
Others said the process now underway is moving too quickly toward issuing a November opinion. Instead of the usual straw proposal that’s part of a lengthy stakeholder process, ISO staff are planning to go to the board with a committee opinion, which they jokingly call a “straw dog proposal.”
Michele Kito, a regulatory analyst with the California Public Utilities Commission, told the committee the process seemed rushed.
“My concern is we’re going to go to the board with a (plan) that’s prematurely designed, and they’re going to say, ‘don’t do any further action,’ and I think that is a mistake,” Kito said. She noted many stakeholder initiatives take years to develop and said a measure dealing with market power deserves more consideration.
“I think to prematurely sort of cut the legs out of this, which I kind of anticipate … is a shame,” she said.
Public Citizen asked FERC Monday to rehear its ruling dismissing complaints over MISO’s 2015/16 capacity auction, saying the commission failed to justify its finding that there was no market manipulation.
The public interest group said FERC’s conclusion that Dynegy did not manipulate the market and that the ensuing $150/MW-day clearing price in Southern Illinois’ Zone 4 was reasonable was wrong on both counts (EL15-70).
The Zone 4 clearing price was a nine-fold price increase compared with just $16.75/MW-day a year earlier. MISO’s other nine local resource zones cleared below $3.50/MW-day that year. Public Citizen, the Illinois Attorney General and Southwestern Electric Cooperative had questioned Dynegy’s market behavior because the company controlled a significant portion of the capacity available in Zone 4.
2015/16 MISO PRA results | MISO
In mid-July, FERC wrapped up a three-year-old investigation into MISO’s 2015/16 Planning Resource Auction by finding no market manipulation on Dynegy’s part. The commission also found Zone 4’s $150/MW-day clearing price just and reasonable, declining to set up an evidentiary hearing to possibly recalibrate the auction results. (See FERC Clears MISO 2015/16 Auction Results.) FERC said a clearing price isn’t unjust simply because it’s higher than expected.
“The commission did not include the evidence from the nonpublic investigation in the record, did not allow the parties to address it and did not say in even the most general terms what, in its view, that evidence showed. Nor did the commission address the arguments advanced by the parties as to whether manipulation had occurred,” Public Citizen said. “The commission offered no account of what, in its view, Dynegy had in fact done or of why that conduct did not amount to manipulation.”
FERC ruled that although Dynegy had pivotal supplier status and that substantial price separation occurred between Zone 4 and the rest of MISO, the RTO had conducted the auction in accordance with its Tariff and market power mitigation rules.
Public Citizen said it didn’t appear that FERC examined whether MISO’s circa-2015 market power provisions were effective. The omission was “striking,” Public Citizen said, because just eight months after the auction, FERC ruled that MISO’s rules for the 2016/17 auction were not just and reasonable. FERC said MISO didn’t accurately gauge power exports and its $155.79/MW-day maximum bid should be set closer to $25. (See FERC Orders MISO to Change Auction Rules.)
Commissioners Cheryl LaFleur and Richard Glick expressed displeasure last month that they were not consulted before Chairman Neil Chatterjee closed the investigation. In a dissent, Glick called July’s order a “wholly unsatisfactory response to the allegations of market manipulation,” saying FERC didn’t provide “even the scantiest reasoning to support its finding that the nearly 1,000% year-over-year increase in the MISO Zone 4 capacity price had nothing to do with market manipulation.”
Tyson Slocum, director of Public Citizen’s Energy Program, acknowledged the group’s chances of prevailing in the rehearing request were slim.
“We’re in this for the long haul,” he said in an interview. “The request for rehearing is not necessarily to change the commission’s vote but to get this before a federal court.”
