NERC: Grid Resilience, Reliability Improved in 2017
By Rich Heidorn Jr.
The bulk power system showed improved ability to rebound from severe storms last year while continuing to improve on most other reliability metrics, NERC said last week.
NERC cited two Category 5 events — the most severe — last year in hurricanes Harvey and Irma. “While wind and water damage were record setting, the restoration efforts and subsequent recovery times were improved from historical benchmarks,” NERC reported in its State of Reliability 2018 report.
Harvey damaged 85 substations and more than 850 transmission line structures in South Texas, resulting in 225 transmission line outages. But utilities’ use of amphibious vehicles, airboats and aerial drones allowed them to perform damage assessments even before roads were clear of flooding and storm debris, NERC noted.
Irma caused a record number of electric outages in Florida, with 4.45 million customers losing power in Florida Power & Light’s territory, up from 3.24 million from Hurricane Wilma in 2005. But system hardening between the two storms reduced restoration time to 10 days from 18, NERC said.
The report recommended NERC encourage increased use of mutual assistance programs and drones and increase information sharing by publishing event reports and conducting other outreach on the lessons learned from the storms.
The storm observations were among six findings in the NERC report. The organization also found that:
The report said the only metric “indicating cause for concern” is planning reserve margins, with all regions except for the Texas Regional Entity projecting sufficient reserves for the next five years.
It cited ERCOT’s preliminary summer seasonal assessment of resource adequacy (SARA), which reported that operational tools such as load management and distribution voltage reductions could be needed to maintain sufficient operating reserves.
FERC last week denied a rehearing request of its November 2017 order on remand regarding transmission cost allocation in the WestConnect planning region. WestConnect’s transmission providers requested the rehearing in December after FERC affirmed its original order in the proceeding (ER13-75-012).
In 2016, the 5th U.S. Circuit Court of Appeals remanded a commission order rejecting the utilities’ Order 1000 compliance filing.
Western U.S. transmission lines | Southwire
The utilities’ initial compliance filing included a provision stipulating that costs for projects selected in a regional plan would be allocated only to beneficiaries who agreed to participate in those projects. Other WestConnect members participating in the planning process would not be obligated to pay for those projects’ costs, a measure designed to avoid discouraging nonpublic utility transmission providers from participating in planning.
FERC found that WestConnect’s “non-binding” process did not comply with Order 1000, which prohibits planning participants from claiming an exemption from cost allocation merely by asserting they receive no benefits from the resulting infrastructure. The commission noted that the “fundamental driver” of Order 1000 was to minimize “free ridership” within the system.
WestConnect Planning Region | WestConnect
The court asked FERC for “additional factual findings” on WestConnect’s planning process, saying the commission’s mandates regarding the role of nonpublic utility transmission providers were arbitrary and capricious and that it had not shown its orders would not produce unjust rates.
The WestConnect transmission providers argued the order on remand did not address deficiencies identified by the court and therefore violated “both the express purpose of Order No. 1000 and the principle of cost causation under the Federal Power Act.”
FERC countered that the rehearing request relied primarily on WestConnect’s free-rider argument, and it said that its order on remand explained “at length” why the commission often “expects nonpublic utility transmission providers will accept allocation of the costs of transmission projects that benefit them (i.e., they will pay their share of the costs of those projects), and why any potential free ridership would occur for only a limited subset of transmission projects.”
“We continue to expect that free ridership in the WestConnect region will be limited, and we note that the complete elimination of free ridership is not required by the just and reasonable standard of the FPA or Order No. 1000,” FERC said.
The commission said attempts to eliminate free ridership “may not be feasible” given the region’s “uniquely integrated nature” and the fact that Order 1000’s requirements do not apply to nonpublic utility transmission providers. The group’s planning region covers Arizona, California, Colorado, Nevada, New Mexico, South Dakota, Texas and Wyoming.
“We continue to believe that the approach to regional transmission planning and cost allocation accepted in the compliance orders and order on remand is consistent with Order No. 1000 and will result in just and reasonable rates while taking into account the unique characteristics of the WestConnect region,” FERC said.
Federal courts last week rejected two challenges from MISO stakeholders involving FERC Order 1000.
Court Upholds Minn. ROFR
The U.S. District Court for Minnesota on June 21 dismissed competitive developer LS Power’s challenge to the state’s right of first refusal law (17-4490).
The ruling allows Minnesota to continue to grant in-state transmission owners a ROFR to build new high-voltage transmission lines that connect to their facilities. LS Power had claimed that state ROFRs essentially invalidate Order 1000’s elimination of the federal ROFR and undermine FERC’s goal of competition. The U.S. Justice Department had joined the company’s challenge, claiming Minnesota’s law unconstitutionally regulates interstate commerce, in violation of the Constitution’s dormant Commerce Clause. (See Justice Department Joins Challenge to Minn. ROFR Law.)
But the court said the law neither overtly discriminates nor imposes a burden on interstate commerce.
The ROFR “is part of Minnesota’s broader regulation of the provision of electricity to the consumer market,” the court said.
It cited 1997’s General Motors Corp. v. Tracy, in which the U.S. Supreme Court allowed Ohio to continue to tax natural gas sales differently depending on whether they were made to in-state regulated public utilities or out-of-state marketers. The Supreme Court determined that when evaluating a challenged state statute, controlling weight must be given to the possibility of negative consequences on the ability of regulated utilities to serve their captive consumers in a monopoly market.
In last week’s decision, the district court said many of the entities that own existing transmission facilities in Minnesota are regulated public utilities that serve captive markets and operate as monopolies.
“The reasons cited in support of giving greater weight to the monopoly market in Tracy apply here; namely, to avoid any jeopardy or disruption to the service of electricity to the state electricity consumers and to allow for the provision of a reliable supply of electricity,” the court concluded.
As in Tracy, the court said it could not predict the economic consequences of upending the ROFR.
“Minnesota not only gives existing owners a right of first refusal to build new transmission lines that will connect to their existing facilities, but in return Minnesota also places extensive regulatory burdens on those owners. Any intervention by the court could upset the balance between those burdens and regulation.”
The court’s ruling recognized that both Congress and FERC have said Minnesota has a right to adopt a ROFR for new transmission lines. It also said the state’s statute does not discriminate against out-of-state entities because it “draws a neutral distinction” between existing TOs whose facilities will connect to a new line and all other entities, “regardless of whether they are in-state or out-of-state.”
Were it not for the state’s ROFR, the Huntley-Wilmarth line — ITC Midwest and Xcel Energy’s planned 50-mile, 345-kV transmission line in southern Minnesota — would have been opened for MISO’s competitive bidding process in 2016 under Order 1000.
Review of MISO-SERTP Allocation Denied
In a separate case, the D.C. Circuit Court of Appeals on June 22 denied Ameren’s petition for review of a cost allocation proposal under Order 1000 because the appeal introduced an argument that was not first raised in a FERC proceeding (16-1150).
Ameren Transmission | Ameren Corp
The case dates to 2013, when MISO filed a cost allocation methodology under Order 1000 for interregional projects developed with seams neighbor Southeastern Regional Transmission Planning (SERTP). The RTO had proposed to allocate its costs for those projects based on a cost-avoidance method that would include the estimated costs of displaced regional transmission projects rendered unnecessary by the interregional project.
However, MISO proposed that its calculation would include only those costs for avoided projects that had been identified in its annual Transmission Expansion Plan but not yet approved, while excluding costs for approved projects.
FERC rejected the proposal, saying that excluding approved regional projects from the analysis would undervalue potential benefits of an interregional project, especially because approved projects tend to be the most cost-effective. Order 1000 requires the costs of an interregional project to “be allocated in a manner roughly commensurate with the project’s benefits.”
In appealing FERC’s decision, Ameren argued that the commission’s mandated change in cost allocation could harm developers — and by extension, their customers — that had already invested in MTEP-approved projects that were later displaced.
The company also raised a new concern in the appeals case: that FERC’s decision did not comport with its obligation to ensure just and reasonable rates.
The D.C. Circuit seized on the new argument and said that petitioners must first raise arguments in front of FERC before approaching an appeals court.
Ameren contended that the argument of just and reasonable rates lies at the heart of every FERC rate order and should not be considered a new argument in a petition for review, but the court countered that the company misunderstood the Federal Power Act’s requirement that arguments be exhausted at FERC before an appeal.
“If we were to accept petitioners’ rationale, parties would never need to raise specific legal arguments before the commission as long as they broadly challenge the justness and reasonableness of rates,” the court said.
At any rate, the court said, FERC had already adequately explained its decision requiring MISO to account for approved MTEP projects in its SERTP cost allocation methodology.
“In the end, we conclude that the commission adequately responded to petitioners’ concerns about the possible effects of including approved regional projects in the cost allocation calculation. Petitioners ultimately disagree with the commission’s policy judgment about whether the importance of properly calculating an interregional project’s benefits outweighs the effects of potentially displacing approved regional projects. Petitioners’ disagreement with the commission’s resolution of that issue does not render the commission’s explanation any less thorough or reasoned,” the court concluded.
FERC ruled last week that inconsistencies between the termination provisions in MISO’s generator interconnection procedures (GIP) and pro forma generator interconnection agreement were unreasonable, but it simultaneously accepted the RTO’s proposed Tariff changes to remedy the discrepancy (EL18-17).
In an October 2017 order, FERC found that an interconnection customer’s ability to extend the commercial operation date (COD) of a project by up to three years without MISO seeking termination under its pro forma GIA conflicted with a provision in the RTO’s GIP stating that any extension required a material modification of the interconnection request, or the project risked removal from the queue.
FERC originally took issue with the differences in 2012, and MISO at the time contended that the two provisions did not conflict because its GIP applied before the execution of a GIA, with the GIA provisions taking precedence after an agreement is executed.
But the discrepancy arose again after MISO successfully sought to terminate a GIA with EDF Renewable Energy’s 150-MW Merricourt wind project in North Dakota. (See FERC Upholds MISO Cancellation of GIA.) While FERC sided with the RTO in the termination, it instituted an investigation over the inconsistency in late 2017.
As part of a paper hearing in the proceeding, MISO late last year submitted a proposal to clarify within the GIP section of its Tariff that the COD for a project that completes the definitive planning phase of the interconnection queue will be spelled out in a GIA.
“MISO states these proposed revisions also remove any ambiguity as to which Tariff provision determines the COD and any permissible extension beyond the COD, thereby providing greater certainty,” the commission noted.
FERC said that MISO’s approach addressed its concerns.
“We also agree with MISO that the GIP and pro forma GIA are intended to work together, and although the pro forma GIA ‘memorializes the arrangements reached in the GIP,’ the GIP does continue to apply even after execution of a GIA; therefore, specifically referring to the correct section of the GIP in the pro forma GIA is preferable to separating the two documents entirely in these circumstances,” the commission wrote.
FERC also directed MISO to make a further Tariff filing to make it more clear that an interconnection customer can extend its COD by up to three consecutive years before risking withdrawal from the queue.
FERC last week accepted Great River Energy’s slimmed-down annual revenue requirement for reactive supply and voltage control at eight of its generating stations.
The cooperative’s revenue requirement is reduced by a little more than $1 million per year with the June 21 order (EL18-45).
Stanton Station | Great River Energy
Great River settled for the lower amount after FERC opened an investigation in early January into whether the rates were just and reasonable. The company had originally proposed an approximately $5.2 million requirement for the eight plants but lowered it to $3.9 million after settlement proceedings. The individual requirements for the plants now range from $8,371 to $1.7 million per year, lowered from the original range of $24,908 to $2.3 million.
The co-op had claimed the $5.2 million figure was based on previous requirements accepted by FERC in 2010, with adjustments made to reflect the 2017 retirement of the 189-MW coal-fired Stanton Station in Stanton, N.D., and the addition of three generating facilities since 2010: the 170-MW natural gas-fired Cambridge Station and the 19-MW Maple Lake and 23-MW Rock Lake oil-burning stations, all in Minnesota.
But FERC questioned the figure, saying Great River did not adequately support its revised reactive power revenue requirements, including “development of multiple fixed charge rates, its accessory electrical equipment allocator and its generator/exciter investment portion of the turbogenerator.” The commission also said it did not provide complete information on the reactive service capability of its units, including MISO test reports.
FERC on Thursday granted San Diego Gas & Electric a waiver allowing it to continue the CAISO interconnection study process for its proposed Top Gun Energy Storage project without having to post financial security to itself.
In its June 21 order (ER18-1360), the commission said it found that SDG&E acted in good faith, that the waiver request was of limited scope and addressed a concrete problem, and that granting it would have no undesirable consequences.
Energy storage | SDG&E
Because the utility is both the primary transmission owner (PTO) and the interconnection customer, the commission found it unnecessary for it to post financial security to protect itself from the risk of the project being abandoned after associated network upgrades have been undertaken.
For SDG&E to perform accounting entries to move money from one intracompany account to another intracompany account “in this case serves no useful purpose,” the commission said.
FERC on Thursday granted PacifiCorp a stay on the commission’s March 15 order regarding an application to partially transfer the company’s license for its Klamath Hydroelectric Project to the Klamath River Renewal Corp. (Project Nos. 2082-065, 14803-002).
The 169-MW Klamath project (No. 2082) is located in Oregon and California and includes federal lands administered by the U.S. Bureau of Reclamation and U.S. Bureau of Land Management. The project consists of eight developments, seven with hydroelectric generation.
Klamath River Project John C Boyle Dam
In September 2016, PacifiCorp and the Renewal Corp. proposed that the existing license for the project be amended to remove four developments and place them into a new license for the Lower Klamath Project (No. 14803), to be held by the Renewal Corp.
The application was made in accordance with the Klamath Hydroelectric Settlement Agreement, signed in 2010 and resigned in 2016 by all concerned parties, including the Yurok and Karuk Tribes, to resolve disputes over PacifiCorp’s efforts to relicense Klamath.
The Renewal Corp. also filed an application to surrender the Lower Klamath Project license and physically remove those four developments from the river, contingent on the commission’s approval of the amendment and transfer application.
‘Duplicative and Wasteful Work’
In its March 15 order, the commission found that “transferring a project to a newly formed entity for the sole purpose of decommissioning and dam removal raises unique public interest concerns, specifically whether the transferee — the Renewal Corp. — will have the legal, technical and financial capacity to safely remove project facilities and adequately protect project lands.”
The commission thus “authorized only the administrative amendment of the license for the Klamath project, effective as of the day the order was issued, such that PacifiCorp would remain the licensee for both the Klamath project and the Lower Klamath Project until we receive certain additional information.”
In its motion for a stay, PacifiCorp stated that compliance measures associated with dividing the Klamath project into two separate licenses could exceed $3.1 million.
PacifiCorp argued that requiring it to complete the license amendment compliance “would result in duplicative and wasteful work” in the event the license transfer is subsequently approved and the Renewal Corp. is required to undertake the same tasks. Alternatively, PacifiCorp stated that the measures would serve no purpose and may later need to be reversed in the event the transfer is not approved.
FERC stayed the order pending its ultimate ruling on the license transfer. “PacifiCorp’s arguments demonstrate that justice requires a stay,” the commission’s June 21 order said.
The commission also dismissed PacifiCorp’s alternative request for rehearing as moot.
The board voted unanimously to appoint Currie at its June 21 meeting after discussing her credentials and nomination in closed session a day earlier. As a rule, MISO considers all personnel-related matters to be confidential.
Currie is the second woman and first African-American woman to chair MISO’s board since it was established in 1998. Former Director Judy Walsh was the first woman to chair the board during her tenure from January 2016 to December 2017.
“I hope that I will perform in a manner that will bring continued pride in the MISO community,” Currie said upon accepting the position during a June 21 board meeting.
“I will be immediately instructing you on the Philadelphia sense of humor, and you can have my watch,” Curran joked.
Currie is one of three directors whose three-year term concludes at the end of this year. Along with Mark Johnson, she will be up for re-election for a second term. Curran will reach MISO’s three, three-year term limit at the end of 2018 and is not able to seek re-election.
Director Baljit Dail reported that the RTO’s Nominating Committee will begin vetting and interviewing candidates for the board starting in August.
MISO Expects Year-end Budget Overrun
MISO expects to end the year about 1% over its operating budget, the board heard. Chief Financial Officer Melissa Brown said the RTO is forecasting $267 million in spending this year, about $2 million more than its total budget.
Brown said the overrun would stem from spending on computer maintenance and reclassifying some outlays from its capital budget to its operating budget. MISO also expects to spend just $25.6 million of its $29.6 million capital budget by the end of 2018.
Year to date, MISO has spent $108 million of its $109 million operating budget and $11.4 million of its $15 million capital expense budget. Brown attributed the underspending mainly to delayed investment timing in the operating budget and delayed and decreased technology spending in the capital budget.
New York officials on Thursday outlined how the state plans to add 1,500 MW of energy storage by 2025, a target set by Gov. Andrew Cuomo in January.
Lt. Gov. Kathy Hochul, who announced the release of the Energy Storage Roadmap in Queens, said it “represents the next crucial step forward to tackle climate change and further develop our clean energy economy.”
“Clean energy is the future of our planet, and New York will continue to lead the nation in this technology to fight climate change and conserve resources for generations to come,” Cuomo added in a statement.
In his annual State of the State address in January, Cuomo directed the NY Green Bank to invest $200 million to meet the 1,500-MW target — equal to the demand of one-fifth of New York homes. Cuomo also directed the New York State Energy Research and Development Authority to invest at least $60 million in storage demonstration projects and efforts to reduce barriers to deploying energy storage, including permitting, customer acquisition, interconnection and financing costs. (See Cuomo Pushes Clean Energy in Annual Address.)
A scenario, informed by project economics and market sizing estimates, shows customer‐sited, distribution system and bulk system storage each reaching 500 MW by 2025. | NYSERDA
Developed by NYSERDA and the Public Service Commission, the Roadmap groups storage deployment into three market segments — customer‐sited, distribution system and bulk system — based on where the storage is located and the needs it serves. In bulk system deployments, energy storage can be a firming resource when paired with large‐scale intermittent renewables, can replace or complement peaker plants, and potentially defer transmission investment.
The Roadmap recommends providing $350 million in statewide market acceleration incentives to fast-track the adoption of advanced storage systems for customer sites or on the distribution or bulk electric systems.
The state has approximately 60 MW of advanced energy storage capacity deployed now, with another 500 MW being planned to add to the existing 1,400 MW of traditional pumped hydro storage.
The New York Power Authority is working on several energy storage projects to demonstrate the value of the technology, including work on multiple projects with the State University of New York. The SUNY New Paltz campus, for example, this spring completed a solar energy and battery storage system, and state officials plan a similar system at the SUNY Delhi campus.
Chart shows peak and off‐peak E Values. E Value is defined as the higher of the the social cost of carbon or Tier 1 renewable energy certificates under the Clean Energy Standard, net of expected Regional Greenhouse Gas Initiative allowance values. | NYSERDA
New York will also add incentives for energy storage to NYSERDA’s successful NY-Sun initiative and plans regulatory changes to utility rates, utility solicitations and carbon values to reflect the system benefits and values of storage projects.
The state also will consider recommending modifications to wholesale market rules to enable storage participation, including allowing storage to meet both electric distribution system and wholesale system needs to provide greater value for ratepayers, NYSERDA said.
NY Green Bank has released a Request for Information to solicit interest from project developers for its $200 million investment.
The Roadmap begins the public input phase of the PSC’s storage proceeding, which will include multiple technical conferences to allow for feedback on recommendations and approaches identified (18-E-0130). Public comments on the Roadmap can be submitted via the Department of Public Service’s website.
INDIANAPOLIS — MISO could ensure sufficient energy supply by improving demand response rules, devising a storage participation model and better coordinating outages, among other efforts, Advisory Committee members said last week during a “hot topic” discussion on resource adequacy at the RTO’s Board Week.
The RTO has declared 12 maximum generation events since June 2016 — nine of which occurred in winter and shoulder-season months. That represents a sharp increase from the past pattern of one event “about every two years or once a year,” said MISO Chief Customer Officer Todd Hillman, who moderated the discussion during a June 20 Advisory Committee meeting.
Hillman said the RTO is looking to abandon the standard that it has adequate resources on hand if it can reliably serve load during the one summertime peak hour of the year “when air conditioners run hard.”
Vistra Energy’s Mark Volpe, of the Independent Power Producers sector, said he wasn’t certain how much of MISO’s 12 GW of DR will respond to dispatch signals during maximum generation events. A MISO report last month showed that load-modifying resources underperformed during a mid-January emergency, and the RTO has signaled it will reconsider its rules for LMR participation. (See “LMR Performance in January,” MISO Mulls Additional Emergency Communication.) In 2017, 9% of the capacity load-serving entities committed to the forecasted summer peak consisted of emergency-only resources, MISO has said.
“I think we agree that LMRs have value, and a lot of these processes were designed before MISO was in existence,” said WEC Energy Group’s Chris Plante, representative of the Transmission-Dependent Utilities sector. “Right now, we have an annual resource adequacy construct. … Do we need to look at a more granular resource adequacy construct to respect the temporal nature of LMRs?” he asked.
Representing MISO’s End-User Customers sector, Kevin Murray of the Coalition of Midwest Transmission Customers said the RTO should switch from negative to positive reinforcement for DR performance.
“If MISO is getting to the point where it thinks its current Tariff structure is not blending well with operational needs, well, it needs to look at positive rewards,” Murray said.
MISO could employ a practice where resources agree to voluntarily remove load from the system when prices reach a certain level. He also said the RTO could improve its communication with state commissioners on resource adequacy efforts.
“You’re not going to change behavior until MISO communicates what it needs,” Murray said of LMR performance.
Madison Gas and Electric’s Megan Wisersky said LMRs were originally designed to address capacity emergencies but are now being called on to solve transmission emergencies.
“You have LMRs that have to be available at 2 a.m. on a Sunday now,” Wisersky said. “You’re asking them to do something they weren’t designed to do.”
She also criticized the MISO Communications System — where LMRs report their emergency availability — for being “hard to use” and inflexible.
Hillman asked where distributed energy resources fit into efforts to manage load in tight capacity conditions.
Murray said he saw a place for DERs in controlling load. “How many Nest thermostats does it take to offset a 1,000-MW gas unit?” Murray asked rhetorically. “It’s a crop that’s ready to harvest. It just needs the pickers.”
Great Plains Institute Policy Associate Matt Prorok, the Environmental sector representative, said he agreed DERs could unlock value by “shaving loads, shifting loads and shimmying loads.”
More Outage Control?
Hillman pivoted the discussion.
“OK, increasing outages,” he said. “What do we do?”
Multiple committee members said MISO should discount outages from capacity performance.
“Don’t we do that already?” Hillman asked, referencing the three years of generation data MISO uses to produce unit-specific forced outage rates.
Plante suggested MISO include in the rate planned and maintenance outages, in addition to unplanned outages.
Stakeholders also repeated a longstanding suggestion that MISO give itself a stronger role in outage coordination, perhaps with the authority to approve outages.
But Michigan Public Service Commission Chairman Sally Talberg said the Organization of MISO States does not support the RTO having authority over outage scheduling.
MISO Director Phyllis Currie asked if generation and transmission owners were communicating enough about the conditions of their resources to the RTO so it can better predict when and where outages will occur.
“Generation doesn’t take outages because they want to be out. They take outages because they want to be on,” Murray said. PJM provides more forward-looking information about resource need than MISO, he said, noting that last week the Mid-Atlantic grid operator issued a hot-weather alert for its footprint with a request that asset owners wrap up outages early, if feasible.
“We didn’t see a similar hot-weather notice” in MISO until two days later, Murray said. He added the notice was another example of the positive reinforcement he advocates: Generation owners could reap higher prices if they come online in a hot-weather, high-demand situation.
Wisersky agreed that MISO should communicate when it most needs equipment to return online.
Energy Storage
OMS President and Arkansas Public Service Commission Chair Ted Thomas said storage can help address resource availability issues.
“Storage is crazy flexible. It’s the most flexible thing I’ve seen,” Thomas said.
However, he thinks MISO and regulators should create rules to ensure storage has a monetary value in the market.
“FERC can’t do it all in wholesale, and we can’t do it all in retail,” Thomas said of creating compensation rules. “Who is going to do the aggregation? These questions are really complex.”
LS Power’s Pat Hayes, of the Competitive Transmission Developers sector, said a storage asset in MISO cannot currently generate enough revenue as a standalone resource. He said it should find ways to value storage resources as both a transmission facility and generation asset.
MISO is currently examining how storage resources can function as reliability transmission projects in its annual Transmission Expansion Plan. It is also considering permitting storage resources to bypass the interconnection queue when the resources will be used exclusively as a transmission asset.
‘One Thing’
“If there’s one thing MISO could be working on, what would it be?” Hillman asked, pointing at Advisory Committee members around the panel.
“Creating flexibility for the future — getting all resources on a level playing field. I can’t minimize how difficult that is, but clearly the evolving future requires it,” said Alcoa’s DeWayne Todd.
“Challenge MISO’s current planning assumptions to see if they reflect reality,” Exelon’s David Bloom responded.
“We need to take a hard look at policy associated with resource adequacy,” Plante said.
“Enabling competition among all resources,” Prorok added.
