Page 1224 – RTO Insider

July 14, 2019January 15, 2025

Monitor Splits with MISO on Summer Readiness

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Independent Market Monitor has a different opinion of the RTO’s summer supply picture three weeks into the season.

Although MISO predicts a 70% chance that it will declare an emergency to call on load-modifying resources (LMRs) this summer, it said its base case shows a 19% reserve margin, with 149 GW of resources on hand to cover a 125-GW projected peak. Its planning reserve margin is 16.8%. (See MISO Foresees Summer Emergency, LMR Use.)

David Patton, Potomac Economics | © RTO Insider

But Monitor David Patton said that while his base case of MISO’s capacity picture also shows a more than 2% excess beyond the planning reserve margin, a more realistic scenario including outages shows a 12.2% margin and an even lower 8.3% margin when accounting for resources that are unavailable to cover emergencies because of their long notification times.

Patton first shared his concerns at the June Board Week in Traverse City, Mich. (See Emergencies Prompt MISO to Re-examine LMR Protocols.) He expanded on them during a Market Subcommittee meeting Thursday, saying, “The way in which we calculate these margins aren’t as accurate as they could be.”

Patton said some hot, high-demand days this summer show margins dipping as low as 2%.

“These margins would raise concerns for some RTOs, but MISO has the unique advantage of having huge import capacity in many directions. … It’s a powerful shock absorber in terms of reliability,” Patton said.

“Our intention is not to scare anybody,” he added, saying he would be concerned if MISO’s footprint were more isolated, like New York’s or New England’s.

MISO staff said that while they don’t dispute the results of the Monitor’s analysis, they haven’t calculated their own additional summer scenarios to compare against it. However, they pointed out that their base case calculations and the Monitor’s were about equivalent.

Patton has called for changes to “an accumulation of rules that aren’t optimal.” He said MISO should carry reserves on the regional dispatch transfer limit on transmission between MISO Midwest and South to temper regional emergency conditions. The suggestion is one of Patton’s State of the Market recommendations this year. (See MISO Monitor Poses 6 New Market Recommendations.)

“It’d be a win-win for the joint parties and MISO,” Patton said. The joint parties are neighboring transmission systems Southern Co., Tennessee Valley Authority, Associated Electric Cooperative Inc., Louisville Gas and Electric, Kentucky Utilities and PowerSouth Energy Cooperative.

Patton wants more transparency around MISO’s decision-making when emergencies are declared and clearer emergency declaration protocols.

“These regional emergencies just began at the end of 2017, beginning of 2018. So, you have [control room] operators exercising a lot of discretion. It’s important to think about what triggers these emergencies,” Patton said.

“There’s nothing written down on what they’re supposed to be doing and how they’re supposed to be weighing these factors. … It should be clear how those factors should be weighed and processed. … We should write down what these triggers are.”

But he also praised MISO operators for taking relatively few out-of-market actions when compared to other RTOs/ISOs. MISO appropriately keeps its out-of-market actions confined to emergency situations, Patton said.

Extended Outages and the Capacity Auction

Patton has continued his criticism of MISO’s capacity auction availability requirements, which he said are too generous.

“We approved and cleared a unit that’s going to be on planned outage for the entire planning year,” Patton said at the June Market Subcommittee meeting, referring to a large generator in Michigan. MISO as a rule does not divulge which generators have taken outages.

“We’ve seen a number of units cleared that won’t be available over the summer peak” over multiple auctions, Patton continued at last week’s meeting.

Had MISO not counted the Michigan generator on extended outage as available in the 2019/20 planning year, Patton said, Michigan’s Zone 7 would have cleared near the $240/MW-day cost of new entry.

“That $24/MW-day is not representative,” Patton said of Zone 7’s auction actual clearing price. (See Most MISO Zones Clear at $3/MW-day in 2019/20 PRA.)

“Zone 7, as we sit here right now, is incapable of meeting its local clearing requirement,” argued the Coalition of Midwest Power Producers’ Mark Volpe at Wednesday’s Resource Adequacy Subcommittee meeting. He said MISO should immediately work with stakeholders to remedy the situation by creating some availability requirements.

“This is about reliability,” Volpe argued. “Resource adequacy in MISO is broken. This should not be permitted to persist.”

MISO Director of Resource Adequacy Coordination Laura Rauch said any new availability requirements should be worked through carefully to avoid unintended consequences.

RASC Chair Chris Plante said “it doesn’t seem right” for MISO to fully accredit a resource that’s on a planned outage for the entire year.

“We completely agree in concept; we’re looking at the potential unintended impacts [of a solution] and how likely it is this will occur again in the next planning year,” Rauch said.

MISO staff said they will provide the RASC a timeline for when new availability requirements could be implemented.

July 14, 2019

SPP Seams Steering Committee Briefs: July 10, 2019

SPP and MISO are finalizing evaluations of potential interregional projects and determining whether any can be mutually beneficial, SPP staff told the Seams Steering Committee last week.

However, it appears the 2019 Coordinated System Plan (CSP), which has been revamped to study seams transmission issues previously identified in the RTOs’ regional planning processes, will be unable to identify any interregional projects. Two previous CSPs, conducted under different processes, failed to select interregional projects as well.

SPP Interregional Coordinator Adam Bell told the SSC on Wednesday that both parties have evaluated more than 50 potential interregional projects and shared possible solutions to resolve joint needs.

But only one project with noted issues by both RTOs’ regional processes is still being analyzed. Three other projects with seams needs in either SPP’s 2019 Integrated Transmission Planning (ITP) study or MISO’s 2019 Transmission Expansion Planning (MTEP) process are still being evaluated.

The 2019 CSP marks the first study since the RTOs agreed to revise the process last year. A proposal to remove a joint modeling requirement in favor of individual regional analyses and other changes to the MISO-SPP joint operating agreement was filed with MISO, SPP to Ease Interregional Project Criteria.)

Initial stakeholder feedback was underwhelming.

“I’m just worried we’ll be stuck in this situation every time we do one of these things going forward,” Advanced Power Alliance’s Steve Gaw said. “The problem has always been the regional model.”

“Different results [from adjusted production cost (APC) calculations] were not an unanticipated outcome. This is exactly what we were afraid of,” the Missouri Public Service Commission’s Adam McKinnie said. “This should be something that both sides come up with an agreement on, yet we’re back to the same process when we get to joint planning.”

Jeff Knottek, planning director at City Utilities of Springfield (Mo.), pointed to the Neosho-Riverton flowgate along the Kansas-Missouri border, a frequent constraint that has accounted for 40.8% of the market-to-market settlements between the RTOs ($26.9 million of $66.1 million since March 2015).

SPP — Adam McKinnie, Missouri PSC | © *RTO Insider*

The congested flowgate was identified as a CSP joint need by both regional planning processes, but MISO’s MTEP 19 results show negative or insignificant APCs, Bell said. None of the more than 25 solutions is being considered for approval in the CSP, he said. SPP is still regionally evaluating the flowgate.

“Obviously, [MISO’s planning models] aren’t reflecting operational reality,” Knottek said. “The $26 million, almost $27 million on this one flowgate is not getting MISO’s attention. Where do we go?”

“The joint planning process is absolutely an avenue we should look at it for addressing seams needs,” Bell said. “SPP is showing significant benefits from resolving Neosho-Riverton. SPP is showing benefits to SPP for doing that.”

“SPP needs to fix it, but I don’t think we should pay for it ourselves,” Knottek responded.

Bell said the conversation needs to be held at the RTOs’ next Interregional Planning Stakeholder Advisory Committee meeting on July 31.

The lack of interregional projects between SPP and MISO is also likely to be a subject of conversation when the Seams Liaison Committee meets July 21 in Indianapolis during the National Association of Regulatory Utility Commissioners’ Summer Policy Summit. The committee, composed of state regulators in both RTOs, is trying to improve the grid operators’ interregional coordination.

M2M Settlements Reach $66M in SPP’s Favor

MISO racked up a $3.6 million tab in May’s market-to-market (M2M) settlements with SPP, pushing its overall bill to $66.1 million. It was the eighth-highest total for a month since the RTOs began the M2M process in March 2015.

Five permanent flowgates accounted for nearly $2.7 million of the total, binding for 315 hours. Temporary flowgates were binding for 835 hours, resulting in a $914,000 settlement to SPP.

An operations congestion management task force under the Operating Reliability Working Group has begun a general review of flowgates, “driven by a desire to better our practices,” SPP’s Will Ragsdale said.

The group is also looking at M2M power swings, he said, with the “main resolution” being updating the M2M software.

— Tom Kleckner

July 14, 2019

NYPSC OKs Westchester Plan, Expands EV Charging

By Michael Kuser

New York regulators Thursday approved a consumer awareness and incentive campaign for clean energy development in Westchester County, developed jointly by the county and the New York State Energy Research and Development Authority (Case 19-M-0265).

NYPSC — The PSC held its regular monthly session in Albany on July 11.

“Transitioning to a carbon-neutral economy requires all hands on deck, and New Yorkers are eager to do their part,” New York Public Service Commission Chair John B. Rhodes said. “NYSERDA’s Westchester County awareness program, developed in response to Con Edison’s natural gas moratorium for new customers, represents a smart and strategic approach to assist Westchester’s communities, businesses and residents in accessing reliable clean energy alternatives to natural gas and to become more energy efficient.”

The action plan includes $165 million from Con Ed to support installation of heat pumps and energy efficiency and $32 million in financing provided by the New York Power Authority for its Westchester customers to retrofit heating systems with clean energy alternatives.

NYSERDA will also kick in $28 million to help new customers, including low-income residents, access alternative heating and cooling systems and energy efficiency services, and $25 million for energy efficiency measures for existing customers.

“If we’re being honest, what drove the action plan was the moratorium, so we need to look at what were the root causes of that moratorium … and has the action plan alleviated any of those,” said Commissioner Diane Burman, who voted against the measure.

Commissioner Tracey Edwards, attending her first session, voted for the program but said, “What I would ask is that we do a little bit more on the consumer side, the residential consumer side, because when I received the information on the workshops that had already taken place, it [was] really geared toward the business community.”

Amended Electric Emergency Plans

The PSC also approved amended electric emergency response plans (ERPs) for the state’s major utilities (Case 18-E-0717).

The ERPs outline processes and procedures needed to respond to a wide array of emergencies, and this year the commission expanded staff review to include recommendations from their investigation following five large storms that occurred between March 2 and May 20, 2018.

The most substantial recommendations revolved around road clearing, damage assessment, estimated times of restoration, and utility communication with customers and municipalities, the commission said, with most improvements related to the inadequate performance of New York State Electric and Gas, Con Ed and its subsidiary, Orange & Rockland.

“All three utilities did not adequately address road closures and failed to properly coordinate and communicate with counties and localities,” the commission said.

Gas Pipes: Cautionary Tale

National Grid may face a financial penalty for failing to properly train and supervise natural gas pipe installers at its two downstate gas utilities — Brooklyn Union Gas Co. (KEDNY), serving Brooklyn, and KeySpan Gas East Corp. (KEDLI), serving Long Island.

After an investigation spurred by an anonymous tip, the PSC ordered the company to explain why it should not commence a penalty action after the utilities failed to comply with the commission’s safety rules related to gas infrastructure work in their service territories (Case 17-G-0317).

The commission also alleged the companies failed to inspect work completed by its contractors during construction at sufficient intervals to ensure compliance and that it allowed work to be completed by plastic fusers and plastic fusion inspectors not properly qualified to do the work.

“We will hold utilities strictly accountable when they do not comply with our gas safety rules, designed specifically to protect life and property,” Rhodes said. “In this instance, staff’s investigation presented credible information warranting the commission to require National Grid to respond formally to the investigation’s findings.”

The commission ordered National Grid to respond within 45 days and is also considering a prudence proceeding to ensure that ratepayers don’t bear the costs incurred to correct hundreds of construction deficiencies.

The order starts an enforcement proceeding and is not a final determination by the commission concerning the allegations.

On top of the Department of Public Service’s 2015 findings that National Grid had committed safety violations during construction of the Northern Queens Pipeline Project, in late 2016 an anonymous tipster alleged that work by Network Infrastructure, a contractor working on behalf of National Grid, did not comply with state safety regulations.

The anonymous letter also alleged that Network employees had been given the answers to online operator qualification tests. The letter alleged that, in one instance, high schoolers took the tests and snapped cell phone pictures of test questions from which answer sheets were created.

DPS staff confirmed the cheating allegations and required National Grid to re-dig much of its completed work from 2015 and 2016, which resulted in finding at least 1,500 regulatory violations, the commission said.

KEDNY has approximately 1.2 million customers and KEDLI has 590,000 customers.

EV Chargers Across the State

The PSC approved expanding its DC fast-charging infrastructure program for electric vehicles by making fast-charging plugs at newly constructed charging stations eligible for an incentive (Case 18-E-0138).

The incentive applies if the station includes a standardized plug type of equal or greater charging capability as the other proprietary plugs being installed at the station.

“Electric vehicle deployment will play a key role in meeting the dramatic carbon-reduction goals set forth in the Climate Leadership and Community Protection Act,” Rhodes said. “We must electrify the transportation sector to achieve a carbon-neutral economy.”

In February, the PSC approved a $31.6 million initiative to make nearly 1,075 new, publicly accessible fast-charging plugs eligible for annual incentives. Those stations can charge a long-range EV in 20 minutes, compared to 20 hours using a typical home charger, or four to eight hours using a level 2 charger.

As of July 1, New York reported more than 4,000 EV charging stations installed statewide.

The commission denied Tesla’s request that its proprietary charging technology alone be eligible for the incentives, but it said the company may earn the incentives if a standardized plug is co-located at the same site. Another company, ChargePoint, operates the most EV charging stations in the state, according to the DPS.

July 14, 2019

New England Officials Speak on Grid Transformation

By Michael Kuser

WESTBOROUGH, Mass. — State and regional officials last week updated the Environmental Business Council of New England (EBCNE) on the rapid progress of renewable energy development across the region.

grid transformation — EBCNE President Daniel Moon welcomes regional state energy officials to update his members at the Massachusetts Division of Fisheries and Wildlife Headquarters on July 11. | © *RTO Insider*

The debriefing took place at the Massachusetts Division of Fisheries and Wildlife headquarters, the first state-owned building to achieve net zero energy use. Director Mark Tisa said he was proud of having served as the agency’s lead on its construction in 2012, and that the LEED Platinum certified building sits on 1,000 acres of protected and open space, a small slice of the more than 225,000 acres of such land under its management in the state.

“We’re very lucky to live and work in this region, in this sector, with these leaders that you’ll hear from today,” said Catherine Finneran, director of environmental affairs at Eversource Energy, introducing the speakers. “They’re really leading innovative programs that are ahead of many other states and regions to tackle both energy and environmental challenges that we face as a region.”

Wind Jumps the Queue

“When we think about the resource mix, what’s been proposed in the region, we think of this as the generator interconnection queue … for many years it was dominated by gas-fired generation,” said Eric Johnson, ISO-NE director of external affairs, who serves as president of the Connecticut Power and Energy Society.

Natural gas “has actually dropped to about third place in the queue, and by far the largest resource now is wind, primarily offshore wind,” he said.

“Most of the wind used to be proposed in Maine, but now we’re seeing a lot of that happen in southern New England, in the offshore space, with Massachusetts alone at over 6,000 MW,” Johnson said. “We see that in Rhode Island and Connecticut.”

The region will not need 20,000 MW of new resources on a system that peaks at 28,000 MW, so not every project that developers propose will get built, but every proposal must go through the RTO’s study process, he said.

“Battery storage was not even in my presentation a couple years ago, then it showed up at about 50 MW, then 100 MW, then 200 MW, then 800 MW, and now it’s out of date as soon as we print it,” Johnson said. “So now we have almost 2,400 MW of battery storage in New England, and a lot of that is driven by policy direction set by the states.”

New England has also experienced tremendous growth in solar, he said: “In 2010, we had 40 MW of solar on the system, and if you go in the control room now, that doesn’t even show up. That’s noise.”

Land Ho is Wind Woe

Judith Judson, Massachusetts DOER | © *RTO Insider*

Commissioner Judith Judson of the Massachusetts Department of Energy Resources responded to a question about the Edgartown Conservation Commission having the previous day denied a permit for Vineyard Wind’s cables to come ashore on Martha’s Vineyard — and about the Bureau of Ocean Energy Management in June having declined to issue its final environmental impact statement on the 800-MW offshore wind project.

“We’re absolutely committed to offshore wind. We just doubled down on it very recently, and I think developing projects is challenging,” Judson said. “That is a fact. I think siting large projects is challenging because of the amount of neighbors and the amount of entities impacted. Hopefully we can work through those challenges … you sometimes get setbacks. We’re out now with our second solicitation for offshore wind, and I’m hoping for a robust response. It’s unfortunate and no one wants to see these types of delays.”

Rhode Island Office of Energy Resources Commissioner Carol Grant said, “The offshore industry comes from Europe, and honestly, their interactions with different states have them scratching their heads sometimes. They’ll say, ‘Really, we’ve dealt with the feds, now there’s another state and another state and another state.’”

Matthew Mailloux, energy adviser in the New Hampshire Office of Strategic Initiatives, said his state has formed an offshore wind task force, begun the formal lease application process with BOEM, and initiated a regional collaboration on offshore wind with Maine and Massachusetts, aided by EBCNE.

Mailloux said a letter from Gov. Chris Sununu to BOEM in January led to creation of the agency’s Intergovernmental Renewable Energy Task Force.

Dan Burgess, Maine GEO | © *RTO Insider*

Dan Burgess, director of Maine Gov. Janet Mills’ Energy Office, touted his state’s direction toward offshore wind.

“The previous administration, in power for eight years, had not focused on offshore wind, but we’re bringing it back,” Burgess said.

He highlighted the revival of the Maine Aqua Ventus project to test a floating turbine off the coast, which he said is “important because the water is too deep off Maine for fixed-bottom turbines.”

Burgess also said that a bill in the Maine legislature (LD 1646) to have the state take over and own the Central Maine Power and Emera Maine utilities “has gotten a lot of attention” and will be the subject of a Public Utilities Commission study.

Grid Transformation

Anne Margolis, Vermont DPS | © *RTO Insider*

Anne Margolis, assistant director of planning for the Vermont Department of Public Service, said her state has a strong focus on modernizing rate design and getting people to use electricity at times of lower demand.

“We’re distinct from the [Public Utility Commission]. … We’re the body that advocates on behalf of ratepayers and the state’s energy policies,” she said, adding that one utility, Green Mountain Power, serves 75% of load, and that Vermont represents 4% of New England load.

Margolis complimented ISO-NE’s Johnson on the RTO’s recent Grid Transformation Day and said she appreciates the grid operator “flagging a potential issue” and offering a solution. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)

Massachusetts’ Judson asked, “How do we think about a grid that is no longer big power plants going on the transmission, stepping down onto distribution, but now is small generation, in aggregate large amounts of generation on a system that was never designed for that?”

Eric Johnson, ISO-NE; Anne Margolis, Vermont DPS; Matthew Mailloux, New Hampshire OSI; Dan Burgess, Maine GEO; Commissioner Carol Grant, Rhode Island OER; and Commissioner Judith Judson, Massachusetts DOER. | © *RTO Insider*

Electricity constitutes 27% of the energy use in Massachusetts, behind transportation at 44% and thermal (building heating) at 39%.

“When we electrify the heating of buildings, we get a huge leverage effect from the investments we’ve already made. … Combine that with energy efficiency, and you’re getting massive benefits,” Judson said. “We invest a tremendous amount in [energy efficiency]; [we’ll] invest $2.7 billion over the next three years … whereas California invests around $1 billion on a grid three times as large … but we get great returns.”

The DOER projects $9.3 billion in savings from the state’s EE investment over the next three years.

“We still have these times of the year when we’re overly dependent on natural gas, where our system, because of demands for heating and generation, has to switch to oil and other resources,” Judson said. “We continue to need to think about that reliability constraint on our system. If you can do LNG, that can be something in the short term, that may be one solution, but how do you have that storage capability for that type of fuel given that longer term … you’re planning to transition away from it.”

July 14, 2019

MISO Resource Adequacy Subcomm. Briefs: July 10, 2019

CARMEL, Ind. — MISO’s Independent Market Monitor intends to reduce its monitoring of physical withholding by small behind-the-meter generators in the footprint.

Most of MISO’s BTMGs are about 2 MW, and the Monitor is proposing only monitoring for physical withholding by units of at least 10 MW. It would still not recommend enforcement action for any possible economic withholding from BTMGs.

“Excluding these resources will improve efficiency, allowing for more focus on resources that may have market power,” the Monitor explained.

IMM staffer Michael Chiasson told the Resource Adequacy Subcommittee on Wednesday that he would only scrutinize aggregated nodes of BTMG for physical withholding if one of those groups contained a generator larger than 10 MW. Groups that contain multiple smaller generators that exceed 10 MW combined would still be left alone.

According to the Monitor’s count, MISO contains 826 BTMGs, with 547 of those serving as load-modifying resources. BTMG comprises just 5,089 MW of MISO’s Generation Verification Test Capacity and 4,582 MW of unforced capacity.

Minnesota Public Utilities Commission staff member Hwikwon Ham asked if the Monitor foresees large groups of small BTMGs exercising market power.

“We still think that they’re unlikely to have market power,” Chiasson said. “If we do see something that’s alarming, that doesn’t prevent us from taking action and filing a recommendation with FERC. Our hands really aren’t tied here.”

“Is this in the spirit of [ERCOT’s philosophy that] ‘small fish swim free?’” MISO’s Michael Robinson asked.

Chiasson said he wasn’t familiar with ERCOT’s controversial protections for small generators that control less than 5% of the Texas wholesale energy market. Such generators are dubbed too small to hold market power and are exempt from penalties for market power abuse.

“The small fish can be pivotal in certain circumstances,” Customized Energy Solutions’ David Sapper said.

MISO staff said that if supplies ever became so scarce that small BTMGs become pivotal suppliers and rake in higher prices, they would deserve the high compensation for providing a critical service.

Staff said the new BTMG physical withholding rule would likely be included in a monitoring rule update filed at FERC before fall.

Additionally, the Monitor plans to add default technology-specific avoidable costs for solar generation and battery storage at $64.11/MW-day and $109.59/MW-day, respectively.

Most of MISO’s capacity market participants elect to use the Monitor’s default avoidable costs, saving time and effort rather than calculating and documenting individual refence levels for generation. The Monitor relies on the same values PJM currently uses, although PJM does not maintain values for solar and storage.

MISO Reviews OMS Survey

MISO staff took time to reassess with stakeholders the results of last month’s annual Organization of MISO States resource adequacy survey.

The survey forecasts a generation surplus of about 3 to 6 GW in 2020, about 1 to 4 GW in 2021 and about 1 to 3.4 GW in 2022. The range of possibilities in 2023 and 2024 varies the most, with the forecast indicating anything from a 1.3-GW shortfall to a 7-GW surplus in 2023, and a 2.3-GW shortfall to another 7-GW surplus in 2024. This is the sixth iteration of the survey. Last year’s forecasted a possible 0.1-GW shortfall in 2020. (See Supply Future Brighter, OMS-MISO Survey Shows.)

“Quite a few resources have firmed up their availability over the last year,” MISO’s Stuart Hansen said. “We’re resource-sufficient for the next three years. It’s 2023 and 2024 when we may have a problem area.”

But Hansen said that even in those years MISO by no means has a guaranteed adequacy risk. He said changes in load and new resource additions from the approximately 100-GW interconnection queue could come online and mitigate possible shortfalls.

“Every single year, we’re going to see this change,” he said, adding that 2020 “looked bad” from last year’s perspective but has since become “3 GW long.”

MISO is circulating survey results with state public service commissions in its footprint.

“I’m not too concerned,” Hansen said of forecasted potential deficits. “This survey is a tool to open dialogues with state commissions [and] utilities.”

The Coalition of Midwest Power Producers’ Mark Volpe asked why MISO is initiating outreach on the survey with state commissions when it is market participants that respond.

Hansen said the RTO is simply ensuring states are aware of the survey’s resource adequacy results. He said MISO does not cross-check survey results against states’ integrated resource plans.

Volpe also asked if MISO may recalibrate survey results based on new public announcements regarding retirements and new plant construction.

“We may look at that, but we do have a cutoff period. At some point, those would become part of the 2020 survey. If you’re asking if we would open it up now, probably not,” Hansen said.

But Hansen reassured stakeholders that the survey results include the Illinois Pollution Control Board’s June 20 announcement of the retirement of 2 GW of coal-burning generation in the state. Southern Illinois’ Zone 4 is one of three local resource zones in MISO that could experience capacity shortfalls from 2020 to 2024.

— Amanda Durish Cook

July 14, 2019

MISO Market Subcommittee Briefs: July 11, 2019

MISO is now aiming for a six-day horizon for its new, comprehensive multiday operating margin forecast.

“Our plan is to roll this out incrementally,” said Chuck Hansen, of MISO’s market design team.

The first iteration of the forecast will look ahead six days, be updated once daily and estimate a daily peak hour on the systemwide, MISO Midwest and MISO South levels. Future versions of the forecast may contain multiday hourly load and wind forecasts, behind-the-meter generation forecasts, interchange forecasts and data on emergency resources.

Hansen said the idea is to build a “data warehouse” and flexible analytical platform so that MISO can easily add new sources of information for a more nuanced forecast.

“We want to be able to change the report without starting from scratch,” Hansen said.

MISO introduced the concept last month, although it offered few specifics on what the forecasting would entail. (See MISO Adding Week-ahead Forecasts.) The new forecast will be purely informational for market participants and won’t be tied to financial commitments.

Since last month, MISO has analyzed more than five years’ worth of its systemwide load and wind generation forecasting and found it has been “generally accurate,” Hansen said.

He said he would return to the Market Subcommittee in August with more details and a more precise timeline on the project.

Short-term Reserve Filing Coming Shortly

MISO will file with FERC in mid-August a proposal to create a short-term reserve product, staff told the Market Subcommittee.

The RTO said it hopes to roll out the product in mid-2021, supported by a soon-to-be-replaced market platform. It also plans a post-implementation review in 2023 to gauge the product’s performance and delivered cost savings.

Based on simulations, MISO expects the reserves to deliver an estimated $5 million in net annual production benefits and a $1.6 million reduction in annual revenue sufficiency guarantee payments.

After stakeholders questioned the analysis behind the $5 million savings, staff said the RTO performed a rough estimate of the benefits based on the best available information.

The product will be designed to furnish capacity within 30 minutes. MISO expects it will help better manage the regional directional transfer limit and help local areas that lack available and flexible resources, especially in southeastern Louisiana in Zone 6 and East Texas in Zone 7, both of which have local reliability issues. (See MISO Prototyping Short-term Reserve Product.)

MISO has set a $100/MW market-wide demand curve for the reserves, so the market is designed to naturally clear energy before it clears the reserve product. The product will be subject to monitoring for physical and economic withholding just like ancillary services, with mitigation measures only applied in constrained regions and zones, not market-wide. Offers below $10/MWh will be excluded from economic withholding monitoring.

— Amanda Durish Cook

July 12, 2019

SPP Seeks Slimmer Stakeholder Group Structure

By Tom Kleckner

SPP has launched an initiative to trim the number of stakeholder groups in its organizational structure, saying it will improve the RTO’s effectiveness.

Staff is currently gathering feedback from SPP members on various proposed combinations of merged working groups and committees and how best to ensure important work is not lost in the shuffle.

SPP is targeting 14 working groups and the Seams Steering (SSC) and Balancing Authority Operating (BAOC) committees. Exceptions include the committees that report to the Board of Directors and Members Committee, the Market Monitoring Unit, and the Credit Practices (CPWG) and Cost Allocation (CAWG) working groups. The CPWG reports to the Finance Committee, and the CAWG reports to the stand-alone Regional State Committee.

“With the organization’s focus on value and affordability to our stakeholders, we’re looking at a variety of potential measures to streamline processes, improve effectiveness and provide the highest degree of value possible,” SPP Vice President of Engineering Lanny Nickell said in a statement.

Nickell said the effort originated in the Value and Affordability Task Force (VATF), which was formed in January to review the cost recovery of transmission investments as well as the ongoing benefit from those investments and SPP’s operation. (See “Altenbaumer Continues to Exert his Influence” in SPP Strategic Plan n ing Committee Briefs: Jan. 16, 2019.)

He said the task force requested an assessment of SPP’s organizational structure “that considers whether we can achieve more value by consolidating and improving coordination among groups and reducing meetings and travel across our sizeable footprint.”

Staff has been gathering feedback on four proposed combinations:

The BAOC, SSC, Operating Reliability (ORWG) and Operations Training (OTWG) working groups
The SSC and the Transmission, Economic Studies and Project Cost working groups
The Business Practices, Regional Compliance, Regional Tariff, Security and System Protection and Control working groups
The Business Practices, Change, Market and Supply Adequacy working groups

Two of the combinations involving the SSC would see the committee disbanded, with its responsibilities picked up by either the Operating Reliability, Economic Studies or Transmission working groups. Staff has also suggested in one scenario the OTWG be disbanded, with an advisory panel or the ORWG picking up its training responsibilities.

“The discussions are in the early phases,” SSC Staff Secretary Clint Savoy told his group during its July 10 meeting. “In my personal opinion, I believe we should operate as if the Seams [Steering] Committee will continue.”

Staff has also been gathering general suggestions from members on SPP’s organizational group structure. Stakeholders have suggested reducing the number of face-to-face Markets and Operations Policy Committee (MOPC) meetings and using conference calls to address less contentious Tariff changes.

The MOPC meets quarterly two weeks before the board meetings and is responsible, through its organizational groups, for developing and recommending policies and procedures related to SPP’s technical operations.

Stakeholders also suggested improving the working groups’ effectiveness by having longer meetings with more work, coordinating meetings with similar groups, creating more “meaningful, action-oriented” agendas and facilitating information sharing through focus groups.

Nickell will update MOPC on the effort during its July 16-17 meeting in Des Moines, Iowa. MOPC Chair Holly Carias, with NextEra Energy Resources, and Vice-Chair Denise Buffington, with Evergy Companies KCP&L and Westar, will also play a part in the presentation.

The VATF is to weigh in with its own feedback by July 31. MOPC is scheduled to see draft recommendations during its October meeting and the Corporate Governance Committee (CGC) in November. The CGC will then recommend changes to the board in December or January, with the changes implemented in 2020.

July 12, 2019

PJM Stakeholders Push Unified Cost Calculator

By Christen Smith

VALLEY FORGE, Pa. — PJM generators urged fellow stakeholders to support a unified opportunity cost calculator capable of wiping out the compliance risks of the dual systems currently offered through the RTO and its Independent Market Monitor.

PJM discussion of opportunity cost calculator — Bob O’Connell, Panda Power Funds | © *RTO Insider*

“PJM wants the status quo with respect to its calculator and the Monitor wants its calculator, and we are still in this situation where market participants can’t get one calculator to eliminate compliance risk,” said Bob O’Connell, director of regulatory affairs and compliance for Panda Power Funds, during a Market Implementation Committee meeting on Wednesday.

Under current procedure, market participants can either use PJM’s calculator in Markets Gateway or the Monitor’s modeling system to build energy cost offers with appropriate adders that help ensure a generator will recoup losses when its resources are scheduled outside of their most economic operating intervals. Some of these opportunity costs arise when regulatory agencies impose environmental run hour restrictions, physical equipment limitations trigger operational restrictions, and force majeure events constrain access to fuel.

“The objective is to make the generator whole,” said Glen Boyle, manager in PJM’s operations analysis and compliance. “Neither PJM nor the IMM will be presenting packages, because we are OK with the status quo.”

Clearly, stakeholders are not.

A New Path

O’Connell presented the MIC with three proposals — drafted in consultation with Dominion Energy — that streamline the calculators to varying degrees.

The first makes small changes that don’t force PJM to rewrite its calculator, O’Connell said. The second revises PJM’s modeling process to mimic the Monitor’s, which many stakeholders prefer for its reliability. The third consolidates the former package into one single calculator, “eliminating all compliance risk,” O’Connell said.

“When you use the Market Monitor’s calculator, the market participant’s only risk is taking the adder the Monitor provides and incorporating into its offer properly,” O’Connell said. “While there is some compliance risk, it’s very limited. As long as you know how to cut and paste, you’re usually in pretty good shape.”

The PJM calculator, however, gives the market seller more control over the modeling process, allowing more room for error and raising compliance risks — the source of O’Connell’s concern when he proposed a task force to revise the calculators in March 2017, he said.

“I’m concerned we won’t be able to get there [one consolidated calculator],” O’Connell said. “We basically decided to offer three packages so we could at least get to something that improves the situation a little more.”

Panda and Dominion will seek endorsement of one of the proposals at the August MIC meeting, O’Connell said.

The packages come five months after O’Connell made a motion at the February Members Committee meeting to table a vote on Operating Agreement language that would force PJM to accept the IMM’s calculator. (See “Calculator Vote Place in a ‘Parking Lot,’” PJM MRC/MC Briefs: Feb. 21, 2019.)

At the time, O’Connell said the unusual motion puts the issue in a “procedural parking lot,” giving members flexibility to bring up the issue on short notice in case PJM suddenly decides the Monitor’s calculator is no longer valid.

O’Connell drafted the language after PJM told members last August it would reject the Monitor’s opportunity cost calculator, the culmination of a yearlong dispute over the “increasingly” divergent results produced by the two organizations. (See Stakeholde r Proposal Aimed at Ending PJM-IMM Dispute.) The PJM Board of Managers approved Manual 15 revisions in January that governed the use of the IMM calculator as an alternative, effectively reversing the RTO’s earlier decision.

Boyle said Wednesday that PJM must maintain a calculator as mandated by the Tariff and will make clarifying u p dates to Manual 15 regarding immature units, dual-fuel units and application functionality.

July 12, 2019

Newsom Names New California PUC President

By Hudson Sangree

California Gov. Gavin Newsom announced his choice Friday for a new leader of the state’s Public Utilities Commission.

Gov. Gavin Newsom named his new CPUC president during the signing ceremony for a landmark wildfire bill Friday. | © *RTO Insider*

Marybel Batjer, currently the state’s government operations secretary, will soon replace retiring President Michael Picker, Newsom said. He called Batjer “one of the best in the business.”

“She is about reorganization,” Newsom said. “She is about governance.”

Batjer’s official biog r aphy says she was appointed by former Gov. Jerry Brown in 2013 to head the Government Operations Agency, a new entity charged with improving efficiency and accountability in state government as part of Brown’s reorganization efforts.

Newsom kept her on in that role and gave her the job of reforming the Department of Motor Vehicles, one of the state’s most inefficient bureaucracies.

Marybel Batjer will be the new CPUC president. | *State of California*

“She has led forward-looking efforts to revamp the way the state approaches data and technology, modernized the civil service system, and has led the implementation of key initiatives to green state government and promote renewable energy,” Newsom’s office said in a news release.

“Prior to taking office at CPUC, Batjer will complete her work later this month as head of Gov. Newsom’s DMV Strike Team, which has already begun implementation of key changes to transition the California Department of Motor Vehicles into a more customer-friendly and user-centered culture, to better serve Californians,” it said.

She’s expected to take office at the CPUC at the beginning of August.

Previously, Batjer was vice president of public policy and corporate social responsibility for Caesars Entertainment. Her state and federal government experience includes stints as Gov. Arnold Schwarzenegger’s cabinet secretary, special assistant to the secretary of the Navy in the George H.W. Bush administration and a national security advisor in the Reagan administration.

Newsom made the announcement during a press conference and signing ceremony for Assembly Bill 1054, a major new wildfire law that will be implemented in part by the CPUC. (See Calif. Utility Relief Bill Speeds to Governor.)

The CPUC has come under fire in the last year for moving slowly in response to California’s wildfire crisis. There were rumors months ago that Newsom intended to appoint his own CPUC president to replace Picker, a former aide to Gov. Jerry Brown.

Picker said in a recent interview with RTO Insider that Newsom hadn’t asked him to leave, but that he felt it was time to retire. (See Retiring CPUC President Still Has Lots to Say.)

Newsom thanked Picker for his service Friday.

“Michael has brought deep expertise in energy policy and a commitment to advancing the state’s climate goals,” the governor said in a statement. “His knowledge, vision and commitment has been critical as the state examines the role of utilities following recent catastrophic wildfires, and necessary changes in an era of climate change.”

Picker was unavailable Friday, according to an aide. Batjer could not immediately be reached for comment.

July 12, 2019

UPDATED: Calif. Wildfire Relief Bill Signed After Quick Passage

By Hudson Sangree

SACRAMENTO, Calif. — Gov. Gavin Newsom signed a bill Friday that’s intended to shore up California’s investor-owned utilities against wildfire liability.

Newsom pushed lawmakers to quickly pass Assembly B ill 1054, which they did in less than a week after it was amended to reflect the governor’s wildfire plan. It takes effect immediately as an urgency measure.

“I want to thank the Legislature for taking thoughtful and decisive action to move our state toward a safer, affordable and reliable energy future,” the governor said in a statement after the Assembly gave the bill its final approval Thursday. “The rise in catastrophic wildfires fueled by climate change is a direct threat to Californians.”

The bill does not give utilities the relief from California’s strict liability standard, known as inverse condemnation, that they wanted. But it creates a $21 billion fund to pay for wildfire damages, to be bankrolled equally by ratepayers and the state’s three large investor-owned utilities.

Under the measure, the IOUs could opt in and contribute an initial $7.5 billion in aggregate and pay $3 billion more over the next 10 years. Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric would cover 64.2%, 31.5% and 4.3%, respectively, based in part on the size of the utilities and the miles of power lines that run through high-fire-risk areas.

Ratepayers would fund their $10.5 billion share through charges on electric bills, averaging a few dollars per month.

Elected officials hope the fund will head off further downgrades by credit rating agencies of SCE and SDG&E and alleviate concerns those utilities, like PG&E, could wind up in bankruptcy.

(The bill allows utilities to opt for a $10.5 billion state-backed line of credit in lieu of the wildfire fund. They must choose within 15 days. The general belief is they will opt for the wildfire fund.)

PG&E filed for bankruptcy in January, citing billions of dollars in wildfire liability from November’s Camp Fire, the deadliest in state history with 85 fatalities, and a series of devastating blazes in 2017.

SCE’s equipment is suspected of starting the Woolsey Fire, also in November 2018, which killed three people and destroyed more than 1,600 structures. The utility also faces massive liability for 2017’s Thomas Fire, which it admitted may have been sparked by its equipment. That fire killed two people, while ensuing mudslides caused by rain drenching charred hillsides caused 21 deaths. (See Edison Takes Partial B l ame for Wildfire in Earnings Call.)

SCE and SDG&E each had their credit ratings downgraded, although the latter hasn’t had a significant utility-sparked fire in years, since it began a major grid hardening effort that’s often citied as a model.

Stabilizing California

Those who supported the bill said bolstering the utilities against insolvency would allow fire victims to be compensated more quickly and maintain stable rates for customers.

“We’re talking about victims, ratepayers and the industry that keeps the lights on,” said Assemblyman Chris Holden, one of the bill’s three co-authors and chairman of the Assembly Utilities and Energy Committee.

The measure requires PG&E to exit bankruptcy by June 30, 2020, and pony up its share of the initial $7.5 billion before it can recoup costs from the wildfire fund.

It also requires the IOUs to pay a combined $5 billion for fire-safety upgrades without recouping profits from ratepayers through a return on equity.

The Woolsey Fire killed three people in the Malibu area last year. | *Department of Defense*

Assemblywoman Eloise Reyes said she struggled with the bill but decided to vote “yes” because she felt it would compel PG&E to leave bankruptcy and prioritize safety, while stabilizing electric service and rates in California.

“In the end our job is to stabilize California,” Reyes said.

While speakers on the Assembly floor Thursday generally praised the bill and urged its passage, others remained troubled.

Assemblyman Al Muratsuchi, a Los Angeles-area Democrat, asked “whether we could have done better if we had more than two weeks” to weigh the measure. The bill, in its current form, was first printed two weeks ago and then heavily amended July 5 over the holiday weekend.

It cleared two state Senate committees Monday before being passed by the upper house, all in a matter of hours. (See Calif. Lawm a kers Rush to Pass Utility Wildfire Aid.)

Last year, lawmakers hastily passed Senate Bill 901, another major wildfire bill, under pressure from then-Gov. Jerry Brown and legislative leaders. They were told if they didn’t pass the bill, PG&E would go bankrupt, which it did anyway.

“Now we’re being asked to pass this bill, and if we don’t pass it [by July 12] according to the governor … then Edison is going to be downgraded to junk bond status and may face bankruptcy,” Muratsuchi said. He questioned whether the utility would follow the same course as PG&E.

Assemblyman Marc Levine, a Democrat who represents a district north of San Francisco, voted “no” on the measure and said it was not right to offer PG&E assistance when it had yet to upgrade its power lines to prevent fires.

The Caribou-Palermo transmission line that sparked the Camp Fire was 100 years old, and maintenance had been deferred repeatedly, leading to 85 deaths, he said. Other PG&E lines in high-risk areas may be in similar condition, he said.

“It is hard not to see this bill as a reward for monstrous behavior,” Levine told his colleagues. “They have not done the work. They should not be rewarded.”