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.)
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.
“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.
The New England Power Pool Markets Committee on July 8 voted to recommend that the Participants Committee support ISO-NE Tariff revisions requiring solar resources to provide meteorological and operational data to support power production forecasting. One member from the Supplier Sector abstained.
The changes would also consolidate wind and solar data requirements within Market Rule 1 of the Tariff, as proposed by ISO-NE.
Analyst Jonathan Lowell presented the RTO’s case for the advisory vote on wind and solar data requirements in the large generator interconnection agreement. The RTO anticipates changes to Market Rule 1 to become effective no earlier than December.
The NEPOOL Transmission Committee at its June 13 meeting supported related changes to remove the existing wind data requirements from the LGIA, and the Participating Transmission Owners Administrative Committee will review and vote on the changes when it meets Sept. 24.
Easing Import Resource Transactions
The MC also voted to recommend that the PC support revisions to Market Rule 1, Manual M-11 and Operating Procedure No. 9 to simplify external transaction submittal requirements for capacity import transactions and to remove outdated Tariff provisions, as proposed by the RTO.
The motion passed based on a show of hands, with one opposed and two abstentions from the Supplier Sector, one opposed and three abstentions from the Generation Sector, one opposed and three abstentions from the Alternative Resources Sector, and two opposed from the End User Sector.
RTO staffer Matthew Brewster presented the proposed Market Rule 1 revisions, which would streamline the requirements for submitting external transactions associated with import capacity resources and better align the requirements with Pay-for-Performance rules. They also include clean-ups to remove outdated provisions relating to coordinated transaction scheduling and dynamic scheduling.
The updates were motivated by the technical project to replace the software platform for submitting external transactions, which is scheduled for implementation by October.
In voting against the motion, Brett Kruse of Calpine said that imports that count as capacity should be from a specific generating resource that owns point-to-point firm transmission, ensuring the import is treated the same as internal capacity and not exposed to external curtailment.
“Otherwise, I believe that this is a very liberal interpretation of ‘capacity,’” Kruse said.
Assessing ESI Impacts
Todd Schatzki of Analysis Group presented preliminary results of his firm’s assessment of the impacts of the RTO’s proposed energy security improvements (ESI).
The proposed changes potentially affect market participant resource decisions and economic offers in ways that improve energy security, he said, including by creating incentives for resources to secure fuel inventory to merit an ESI award.
The study will run two scenarios: one a business-as-usual (BAU) case and another that assumes both the presence of ESI market products and some change in the actions resources take to ensure they have inventory to meet an energy commitment, Schatzki said. The differences between the two model runs will provide an estimate of impacts.
Analysis Group will assume that ESI will incentivize generators to obtain a sufficient number of LNG forward contracts to utilize all available pipeline transport capacity, he said.
The firm will return to the committee July 30 to present further preliminary results, including comparison between future BAU and ESI scenarios. In August, it will present preliminary scenario results and respond to stakeholder feedback, and then present a draft report in September ahead of an October filing.
ISO-NE market development economist Chris Geissler presented the RTO’s analysis of ESI impacts on entry/exit decisions and Forward Capacity Auction outcomes.
Geissler said the RTO expects the introduction of ESI to push the resource mix in a way that improves energy security, but that various factors would influence the magnitude of that effect and the impact on FCA prices, including the extent to which resources that are marginal or nearly marginal under BAU increase or decrease their FCA bid prices under ESI; the degree to which resources that sell capacity under ESI provide more energy security than those they displace; and resource intermittency.
ESI could reduce the likelihood and size of positive real-time price spikes that may otherwise occur because of limited available energy, while the costs of taking actions to improve energy security (such as storing more fuel oil) are netted against incremental revenues.
Geissler highlighted that there could be many mechanisms by which ESI is likely to affect net revenues.
ESI Conceptual Design
The MC spent the second day of its meeting discussing ESI conceptual design elements as presented by ISO-NE Principal Analyst Andrew Gillespie and Lead Analyst Ben Ewing.
The RTO is continuing to assess approaches to mitigation, and detailed mitigation rules will be part of related efforts in 2020, subject to FERC approval of the core ESI design filing in October, Gillespie said.
An Internal Market Monitor memo supplied by David Naughton said that the Monitor understood that participation in the day-ahead market for ESI products will be voluntary.
The Monitor tried to strike a balanced tone in the memo, neither for nor against voluntary participation. It noted that a voluntary market will allow physical withholding, a substitute for exercising market power through economic withholding. The RTO may need to address physical withholding with ex ante market rules, which would be preferable to using claw-back mechanisms, Naughton said.
Speaking on the RTO’s proposed multiday-ahead market (MDAM), Ewing said it would use the same standard settlement logic of deviations used to settle the real-time energy market today.
A forecast energy requirement price (FERP) settlement quantity will be paid to all resources meeting the forecast energy requirement on the prompt day, Ewing said, adding that the FERP is paid to a resource’s full energy position on the prompt day and is not a deviation settlement.
The RTO will further address the relative benefits of MDAM and the single-day-ahead market (SDAM) with opportunity cost bidding at the August MC meeting.
Stakeholder Concepts
The MC on Wednesday heard and discussed stakeholder concepts to enhance energy security from NextEra Energy Resources, Calpine, FirstLight and Energy Market Advisors.
Michelle Gardner and Sam Newell of Brattle Group presented NextEra’s concept for strategic operating reserves, a physical reserve held by ISO-NE as backup to protect against adverse conditions, consistent with reliability objectives.
New products to be purchased by ISO-NE in the day-ahead market would include replacement energy reserves and generation contingency reserves. (See “NextEra: Reserve Products,” NEPOOL MC Debates Energy Security Models.)
The RTO used a dashed line for the ramping of replacement energy reserves (RER) and generation contingency reserves (GCR) because it does not know their ramp pattern, but they do know where it should be at the end of 10 or 30 minutes. | ISO-NE
NextEra continues to evaluate the RTO’s proposal and still feels strongly that it doesn’t quite hit the mark — but emphasizes that it must see the benefits, Gardner said. Under NextEra’s proposal, units can have up to 12 hours notification time for deployment, and unlike traditional reserves, these units are valued because of their security, not because they are fast-start units.
Rebecca Hunter, senior analyst for government and regulatory affairs, delivered Calpine’s longstanding case for a forward enhanced reserves market (FERM) to retain resources at risk of retirement.
Calpine proposes that suppliers bid at auction for a total minimum or maximum amount of megawatt-hours they will commit to offer from stored fuel during an Operating Procedure 21, activated when the RTO declares an energy emergency event. (See “Calpine: More Precise; More Cautious,” NEPOOL MC Debates Energy Security Models.)
Hunter said the design changes and updates since June included making clear that natural gas resources would only qualify for FERM with firm transportation and a gas supply contract.
Calpine is also considering removing the cap for the eligible amount of megawatt-hours and establishing a floor to manage varying starting fuel inventory levels.
Tom Kaslow presented the FirstLight concept, which argues that the RTO can avoid sending inaccurate market signals at times when winter capacity is actually not in surplus by assuring that each procured megawatt can be fueled. (See “FirstLight: Filling Buckets,” NEPOOL MC Debates Energy Security Models.)
Mass. Attorney General Update
Christina Belew of the Massachusetts attorney general’s office quickly updated the MC on its proposal prepared by London Economics that recommends a simple auction format of sealed bids with a uniform clearing price. (See “Massachusetts AG: Simpler, More Physical,” NEPOOL MC Debates Energy Security Models.)
Belew said her office was still fleshing out the design details of its forward stored energy reserve proposal and that she may be back to present additional information at the August MC meeting.
Enhanced Storage Participation
ISO-NE Principal Market Development Analyst Catherine McDonough led a presentation and discussion of the RTO’s proposed manual revisions consisting of conforming changes to support implementation of the enhanced storage participation and FERC Order 841 compliance projects.
The proposed manual revisions reflect two sets of Tariff changes: the enhanced storage participation changes, which became effective on April 1, and additional Order 841 compliance changes, which will become effective on Dec. 3, pending FERC approval.
The proposed manual revisions also include changes to address a stakeholder concern from the June MC meeting about how the maximum discharge limit of an electric storage facility is set when it has less than one hour of available energy, which McDonough said she expects to become effective March 1, 2020.
Other proposed manual changes since last month include adding conforming and clean-up changes to Definitions and Abbreviations, conforming changes to Regulation Market, and clean-up changes to Registration and Performance Auditing.
Stakeholders said they wanted to focus on increasing the dynamic change function of the grid, so that a storage resource switching to charging is not necessarily cut off from being a source of power if the situation changes in five minutes, for example.
ISO-NE advised FERC on Friday that it is revising its fuel security analysis for Forward Capacity Auction 14 to assume more natural gas use and bigger contributions from renewables.
The RTO made the disclosure in its first annual informational filing comparing actual winter conditions with the triggers, assumptions and scenarios it used in the fuel security analysis.
The filing was required by the commission’s December 2018 order (ER18-2364) accepting the fuel security evaluations the RTO will perform to assess whether resources submitting retirement bids are needed during stressed winter conditions. The evaluations were approved as an interim measure for FCAs 13, 14 and 15 until the RTO can implement market-based mechanisms to address its fuel security challenges. (See ISO-NE Fuel Security Measures Approved.)
The commission required the filings in recognition that the fuel security study “is a newly developed process, is based upon a number of assumptions and is not addressed by the NERC reliability standards. As ISO-NE gains additional information and experience, we expect that the study assumptions, methods, scenarios and triggers may need to be further refined and updated.”
The initial analysis compares the assumptions used in FCA 13 — conducted in February for the 2022/23 delivery year — with winter 2018/19.
PV average hourly capacity factors | ISO-NE
However, ISO-NE said it is not prudent to draw significant conclusions about its review methodology from last winter because it was very mild in comparison to the severe winter of 2014/15 used to develop the modeling assumptions.
The RTO nonetheless said it will adopt several revisions for FCA 14, based on input from the NEPOOL Reliability and Participants committees. (See NEPOOL MC Debates Energy Security Models.)
“Broadly speaking, these refinements increase the amount of natural gas and fuel oil that is modeled in the analysis, and further increase the capacity values of certain renewable resources. Collectively, these revisions tend to move the analysis in a less conservative direction,” the filing said.
RTO officials and other stakeholders participated in a public meeting with FERC staff on Monday on efforts to develop market-based mechanisms to ensure fuel security (EL18-182, et. al.). (See FERC Staff Hear Doubts on ISO-NE Fuel Security Plan.)
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.)
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.
“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.
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.
| SPP
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).
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.
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).
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.
Diane Burman, NYPSC
“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.
Tracey Edwards, NYPSC
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).
John B. Rhodes, NYPSC
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.
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.
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.”
“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.”
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, 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.
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?”
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.”
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.
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.
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 Planning 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.
| SPP
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.
