QUEBEC CITY, Quebec — NERC’s Board of Trustees got to hear first-hand some of the concerns over the proposed merger of the organization’s three technical committees during the Aug. 14 Member Representatives Committee meeting.
The proposal by NERC’s Stakeholder Engagement Team (SET) would merge the Planning, Operating and Critical Infrastructure Protection committees into a new Reliability and Security Council (RSC). While the three technical committees have almost 120 voting members, the proposal would limit the RSC to 33.
The proposal prompted written comments from a dozen stakeholder groups, who were nearly unanimous in calling for a longer transition and an increase in the number of sector representatives in the new organization. Some also questioned whether security issues should be combined with operations and planning. (See NERC Weighing Concerns on Reorg.)
Exelon’s Jennifer Sterling, vice chair of the MRC and co-chair of the SET, opened the discussion by citing a need to become more efficient to respond to the increased pace of change in the industry.
“I’d love to say at Exelon we have infinite people to work on all these issues, but we don’t,” she said. “And so, we need to leverage that scarce talent to solve problems and maximize our return.”
Sterling said the SET will consider several potential changes to the proposal at its meeting Aug. 29, including whether the CIPC should be included, potential changes to the membership of the RSC and a longer transition period.
Asked why the team was reconsidering the inclusion of the CIPC, Sterling said, “It’s just an item for conversation at the next meeting.
“I came out of the operations and planning world, and security is more and more what I’m doing in my work,” she added.
Bill Gallagher, special projects chief for the Vermont Public Power Supply Authority and a representative of the Transmission-Dependent Utility sector, agreed on the need for change but said he would have preferred keeping the three committees and adding a Steering Committee between them and the board.
Gallagher said the proposal to have the NERC board select the members of the RSC and set the criteria for membership “turns the NERC process on its head.”
“l don’t think that’s an appropriate role for the board to be playing. I also don’t think it’s an appropriate role for management to be playing,” he said.
Gallagher also said the SET meetings should be open. “These are the stakeholders’ assets we’re talking about. … If you are going to have additional meetings you ought to consider some way of opening them up.”
West Virginia Consumer Advocate Jackie Roberts, a representative of the Small End-Use Electricity Customer sector, said she shared Gallagher’s concern about the selection of the RSC members. “We strongly believe that the member sectors should select their members. … No one knows who should best represent the end-use sectors than the end-use customers,” she said.
“I think we need to be very careful that we don’t make the system more efficient by losing its effectiveness,” she added.
Devin Hartman, CEO of the Electricity Consumers Resource Council, said sector control and the nominating process “will be a sticking point for some of us.”
Dominion Energy’s Lou Oberski, representing the Investor-Owned Utility sector, said the Edison Electric Institute supports the current plan but wants a “measured transition.”
“There’s no impending need to do it quickly,” he said, predicting the RSC will rival the MRC in importance. “So, let’s make sure we can get it right.”
Hydro-Quebec TransEnergie’s Sylvain Clermont, Canadian representative of the Federal/Provincial Utility sector, said he would like to see a smaller RSC. “I’m a bit scared of a committee with 33 voting members, and probably more,” he said.
Sterling responded: “I too share your concerns that if we get too big, we won’t [achieve the goals] that we set out.”
QUEBEC CITY, Quebec — The Reliability Issues Steering Committee (RISC) has added a 10th risk — critical infrastructure interdependencies — to the nine previously identified, Chair Nelson Peeler said last week.
Peeler gave the Member Representatives Committee a preview of this year’s ERO Reliability Risk Priorities Report, which he said was informed by an industry survey that generated 157 responses. The new report for the first time will group risks into those that should be managed and those that only need to be monitored.
“That’s a significant change for us,” said Peeler, of Duke Energy. “If we really want to focus our resources on what is most important … there has to be prioritization.” Risks that need the most attention — mitigation, work plans, etc. — will fall into the manage category. NERC will monitor risks that are “relatively under control or [for which] we have actions in place already,” he added.
The report also groups the 10 risks for the first time into four “risk profiles,” which, Peeler said, “gives us a clearer, more concise view of what’s important and lets us focus resources specifically on them.”
“There’s blurring with a lot of these individual risks, but they come together much better in the overall concept,” Peeler explained. “For example, if you look at grid transformation, there’s a lot of individual risks about planning, resource adequacy [and] complexity. A lot of those issues blur over each other. But they come together under the issue of grid transformation.”
The Reliability Issues Steering Committee is grouping its concerns into four “risk profiles.” | NERC Reliability Issues Steering Committee
The committee also took “a little shorter-term view than we’ve had in the past,” Peeler said, with a greater emphasis on immediate and short-term actions that can be taken.
The committee is now developing recommended mitigations for the report, which will be submitted to the board in the fourth quarter.
Trustee Janice Case said the committee’s work has filled a void for the board. “There’s been a change in [NERC] leadership over the years, and we haven’t missed a beat as you all have progressed this committee. … It has really given the board what we need, which is a good assessment on risk really coming up through the stakeholder organizations that are closest to it,” she said.
Case asked Peeler how he envisioned the RISC working with the proposed Reliability and Security Council (RSC). (See related story, NERC Board Hears Debate over Committee Reorg.)
“There’s still details to work out. … But at a high level, the RISC identifies the risks and prioritizes. And then that needs to go the next step,” Peeler said. “Today it moves to different [committees]. If we move to the [RSC] model … I think this fits very well with the next step in the chain … I think it’s a natural fit.”
Going forward, Peeler said, the RISC wants to make its process “more repeatable” by increasing its use of analytics to provide “objective” measures of risk.
Risk heat map with risks that require management and those that only need to be monitored | NERC Reliability Issues Steering Committee
SPP set a new record for system demand Monday as a heat wave swamped the southern Midwest and Great Plains.
SPP Region | SPP
The system’s demand peaked at 50.66 GW at 4:39 p.m. as temperatures hit 101 degrees Fahrenheit in Oklahoma City. That broke SPP’s historical peak load of 50.62 GW, set in July 2016.
Average prices in the RTO’s footprint dropped from $36.08/MWh at 4:30 to $28.81/MWh at 4:45. The south and north trading hubs did not get above $31.14/MWh during that time.
The low prices likely resulted from strong wind production, which exceeded SPP’s forecast. SPP’s Market Monitoring Unit said in its most recent annual market report that unexpected high wind generation can lead to lower real-time prices. The market’s wholesale prices averaged around $28/MWh in 2018.
Monday’s average day-ahead price was $66.99/MWh, when the National Weather Service placed eastern Oklahoma under an excessive heat warning. The NWS projected heat indexes approaching 115 F in the state and parts of neighboring Arkansas.
PJM stakeholders struck a compromise late Tuesday on language that would expand upon how the RTO includes projects in its Regional Transmission Expansion Plan.
The deal came less than 48 hours before the Markets and Reliability Committee’s scheduled vote on the issue and could signal an end to eight months of debate over revising Manual 14B to stipulate when and how supplemental projects move in and out of the RTEP. (See Tensions Boil over on PJM’s Supplemental Projects.)
Sharon Segner, vice president of LS Power, told RTO Insider her company reached an agreement with American Municipal Power and PJM during a special Planning Committee session on Tuesday. The compromise language “memorializes the policy of supplemental project displacement in PJM Order 1000 windows,” she said.
Supplemental projects are those that PJM considers necessary to address local transmission owner reliability concerns that are not required for compliance with grid criteria governing system reliability, operational performance or economic efficiency.
It was unclear whether the deal would win the support of PJM TOs. But the RTO has authority to unilaterally adopt manual changes even in the face of stakeholder opposition.
Alex Stern, manager of transmission strategy and policy at Public Service Electric and Gas, said Wednesday he was “still digesting” the language.
Segner said only, “I’m hopeful that there will be resolution in a reasonable period of time.”
Specifically, the revisions detail how PJM would alter the RTEP after siting authorities deny a permit for a supplemental project. The RTO has argued that it lacks the authority to remove such projects from the planning model and noted that a project can languish for years of litigation before a TO wins approval or abandons it. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
The revisions state that if the denied application represents a final regulatory order, the developer must notify PJM. Staff would then review the “impacts associated with removing the project from the RTEP or continuing to include such project in light of such final regulatory order” and present its findings to the Transmission Expansion Advisory Committee.
“A project denied siting authority in a final regulatory order by the relevant regulatory siting authority will generally be removed from the RTEP base case as determined by PJM after discussion with the relevant transmission owner(s) or designated entity and vetting with stakeholders at the TEAC,” according to the proposed language.
The agreed-upon language also states “a project will generally not remain in the RTEP base case during the duration of a court appellate action.” PJM would submit decisions about removing baseline upgrades from the RTEP to its Board of Managers, while “decisions to remove a supplemental project from the RTEP base case will be provided to the applicable transmission owner. In those circumstances in which PJM determines the need to deviate from this guidance, PJM will discuss such decisions with the TEAC.”
PJM does not approve supplemental projects but does study them to ensure they won’t harm reliability. However, the new manual revisions clarify that the RTO would notify stakeholders when existing baseline projects could better solve the regional need that prompted a supplemental project proposal.
If a TO agrees with PJM’s assessment, the supplemental project will be withdrawn. If a TO disagrees, however, it must present documentation to the TEAC justifying its continued inclusion in the RTEP. Staff also added a paragraph clarifying that “any disputes arising under Attachment M-3, including any substantive and procedural disputes arising from the transmission planning process, may be resolved in accordance with the dispute resolution procedures in Schedule 5 of the Operating Agreement.”
PJM had planned to present an older set of manual revisions from an Aug. 14 PC meeting to the MRC on Thursday that LS Power would have accepted as a friendly amendment to its main motion — a proposal that dates as far back as January and has been at the center of PC discussions ever since. AMP’s scheduled amendments to the main motion have also been scrapped, Segner confirmed.
Seventy-five percent of 139 participating member companies voted in favor of an Aug. 14 draft, according to a poll PJM circulated last week.
PJM spokesperson Susan Buehler said the compromise proposal represents a collaboration among stakeholders that “balanced the interests and concerns raised by all parties during its development.”
“Our priority is to ensure that the manual faithfully documents PJM’s current planning processes, integrates new processes and procedures consistent with recent regulatory orders/compliance directives, and provides a platform for the future that incorporates stakeholder desires, duties and future direction,” she said in a statement.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the latest revision will likely delay a vote on Operating Agreement language sponsored by the D.C. Office of the People’s Counsel.
The proposed language would prevent PJM from rejecting endorsed rule changes without any recourse for disgruntled members, as it did in January with stakeholder-endorsed transparency language that the RTO found inconsistent with FERC rulings.
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.
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.
