Competitive Power Ventures must provide additional information to prove it adequately mitigated market power to continue making market-based sales at its newly opened Towantic Energy Center, FERC ruled Thursday (ER13-343-008, et al.).
FERC’s ruling came in response to CPV’s triennial market power update, which it filed on June 30, 2017, for Towantic, a 785-MW generator in Oxford, Ct., and three other gas-fired plants in CPV’s Northeast region.
CPV Towantic Energy Center in early May, with construction nearly complete. | CPV
The commission’s market-based rate rules require applicants to provide information regarding affiliates and upstream ownership. It considers as affiliates any entity that owns at least 10% of the outstanding voting securities of the applicant.
Two pension funds indirectly own more than 10% of Towantic, but CPV argued that they are only allowed to vote 9% of their shares in an upstream entity. FERC said that doesn’t account for their entire ownership.
“Because the pension funds are included among the stockholders whose votes determine how the votes of the excess shares will be allocated, the sum of votes by the pension funds of their 9% of the shares plus the proportional vote of their excess shares gives the pension funds an effective vote greater than 10%,” the commission said.
It instructed the applicants to update their horizontal and vertical market power analysis with their affiliates’ generation and transmission assets and inputs to electric power production. FERC gave them 30 days to comply.
The other plants are the 725-MW CPV Woodbridge Energy Center in Keasbey, N.J., and the 725-MW CPV St. Charles Energy Center in Waldorf, Md., which were granted MBRA in February 2013 (ER13-342, ER13-343).
[Editor’s Note: An earlier version of this story incorrectly stated that FERC was questioning the ownership of all four CPV plants and that they did not already have MBRA.]
FERC on Thursday identified 13 additional transmission owners it said should change accounting practices that could inflate rates by underestimating tax credits.
The commission ordered a Section 206 proceeding investigating the companies’ use of a double averaging formula to calculate accumulated deferred income taxes (ADIT) (EL18-155, et al.). The utilities include two Ameren subsidiaries, American Transmission Co., GridLiance West Transco, ITC Midwest, Northern States Power, Public Service Company of Colorado, Southern California Edison, TransCanyon DCR, Southwestern Public Service and Virginia Electric and Power Co.
In April, FERC opened a similar investigation of five MISO TOs after rejecting proposed formula rate template revisions that would have applied the two-step averaging methodology in annual true-up calculations of ADIT balances.
The commission signaled it would probe whether the practice makes deferred income tax credits appear lower than they should be, possibly raising rates (ER18-224, EL18-138). The filers were ALLETE, Montana-Dakota Utilities, Northern Indiana Public Service Co., Otter Tail Power and Southern Indiana Gas and Electric Co.
The commission said that the TOs’ practice of averaging the prorated ADIT value for the year with the beginning-of-year ADIT balance “produces a result that is disproportionately skewed towards the beginning-of-year balance.”
“Because most companies tend to continuously make investments in plant[s], which in turn generates ADIT, plant and ADIT balances typically increase throughout the year,” the commission said.
MISO TOs Offer New Formula
On June 4, the five MISO TOs submitted revisions to remove the proposed double averaging and instead apply the IRS’ proration methodology in calculating the annual transmission formula rate true-up.
In last week’s order, FERC suggested that the 13 newly identified utilities would need to similarly revise their rates.
“Upon initial review, the concerns we identify might be addressed by revising respondents’ transmission formula rates to eliminate the use of the two-step averaging methodology to determine ADIT balances,” FERC said. “In particular, respondents could modify their transmission formula rates to apply the first step of the two-step averaging methodology to generate a prorated ADIT value for the year, without taking the second step of averaging the prorated value for the year with the beginning-of-year balance.”
Change of Heart
FERC noted that, in previous proceedings, it had allowed TOs to use the two-step methodology “based on the understanding that this methodology was necessary to comply” with the IRS’ normalization rules, an accounting system the Department of Treasury uses for regulated public utilities to reconcile accelerated depreciation of their public utility assets or investment tax credits with regulatory treatment.
However, FERC said in April that its opinion on the matter has since changed, guided by private letter rulings from the IRS. FERC said it now interprets updated IRS rules to “not require that any averaging convention applied to other elements of rate base also apply to taxpayer’s prorated [ADIT] balance.”
“We conclude that if the IRS’ proration methodology is applied to calculate ADIT balances in forward-looking formula rates — such as the Attachment O formula rate templates of certain MISO TOs — then the additional averaging step need not also be applied in order to comply,” FERC said.
RENSSELAER, N.Y. — NYISO stakeholders last week backed joint proposals by North America Transmission (NAT) and the New York Power Authority to build two 345-kV transmission projects while several losing bidders cried foul.
In an advisory vote, the Business Issues Committee urged the Management Committee on Wednesday to recommend the Board of Directors approve the ISO’s draft AC Transmission Public Policy Transmission Planning Report. Dawei Fan, manager for public policy and interregional planning, said the report contains analysis of seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface and six proposals for the Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface.
NYISO staff analyzed seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface, and six proposals for the Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface. | NY PSC
Advised by consultant Substation Engineering Co. (SECO), ISO staff recommended two 345-kV transmission projects proposed jointly by NAT and NYPA. The BIC voted 76.33% in favor of the report and its recommendations.
Project T027 is a double-circuit 345-kV line from Edic to New Scotland for Segment A. Project T029 for Segment B is a standard 345-kV line from Knickerbocker to Pleasant Valley.
NYISO’s analysis was driven by a December 2015 order by the New York Public Service Commission on “Finding Transmission Needs Driven by Public Policy Requirements.”
T027 had higher costs than other Segment A proposals, but staff determined them warranted by benefits provided by the double-circuit design, including “significant increase in Central East voltage transfer capability, increased production cost savings, and excellent operability and expandability.”
T029 provides similar transfer incremental and production cost savings with the second-lowest cost, and demonstrates excellent operability, staff said. More important, the report said, “T029 poses the lowest siting risk due to the low structure height increase and more than 50% of its new structures with reduced height.”
Staff also said that T027 and T029 would result in cost savings when being built by the same developer simultaneously.
The ISO estimated T027 will cost $577 million to $750 million, the higher figure including a 30% contingency. T029 is estimated at $324 million to $422 million. Staff projected the in-service date for the selected projects in April 2023, “assuming the developer will start the Article VII preparation immediately following the approval of this report by the NYISO board.”
Challenges to Planning Process
Stakeholders abstaining or opposing the motion June 20 included utilities, transmission owners and other developers whose proposals were not selected for recommendation. Several of them submitted comments to the BIC or read statements.
John Borchert, senior director of energy policy and transmission development for Central Hudson Gas & Electric, which abstained, said his company wanted the benefits of improved transmission capability for its service area but was “dissatisfied with the NYISO’s work and its project evaluation.”
He said “the lack of transparency, the way that the aspects of the projects were treated during the evaluation, effectively disqualified projects, and the way that the local TO upgrades were handled during the process have led to frustration and confusion for both those developing projects and for those interconnecting transmission owners.”
Consolidated Edison and its subsidiary Orange and Rockland Utilities voted against the motion, and O&R submitted written comments.
“We don’t feel confident that the recommended selection for Segment B is in the customer’s best interest due to a lack of transparency in the selection process, and deficiencies in evaluation,” said Jane Quin, director of Con Ed’s energy markets policy group. “We are concerned that … NYISO has not considered the full costs associated with the proposed Middletown upgrades, which are local upgrades on the Orange and Rockland system … and could cost as much as 20% of the Segment B project cost.”
The ISO “failed to make clear the technologies and project attributes it would or would not consider, and the reasons for such decisions, and it did not consider stakeholder input on the matter,” Quin said.
Fan responded that the Middletown transformer “is just one of the distinguishing factors for Segment B projects … [for which] the major drivers are the magnitude of the power delivery and the structure design.” He said SECO had included $16 million for the Middletown transformer costs, which it deemed adequate.
Fan said the ISO had already had two meetings with developers and six meetings with the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee to consider comments from stakeholders.
Looking for Fatal Flaws
Zach Smith, NYISO vice president for system and resource planning, noted that “any project recommended for selection does go through our interconnection process … there has been a system impact study that’s been done that’s up at [the Operations Committee] tomorrow for consideration.”
The next step after that is a facilities study, and “what’s key here to our evaluation is to understand whether there are any fatal flaws in our assessment,” Smith said.
Borchert said, “There was no reason why an interconnecting transmission owner should not be consulted if these solutions are talking about equipment that’s going to be installed in their service territory. And the process needs to be done if it’s part of the overall selection and it has an impact on the selection, and it needs to be done prior to the selection being made.”
Carl Patka, the ISO’s assistant general counsel, said, “When we designed the overall planning process, we did not require, and FERC did not approve requiring, a complete interconnection-level analysis for proposed projects. That was proposed during the Order 1000 process, it was proposed during the stakeholder process, and it was rejected. And the reason for that is people did not want to create a barrier to entry and proposal of new projects based upon information that competing developers could not have from the incumbent utility.”
Brian Duncan of NextEra Energy Transmission NY (NEETNY) made a presentation arguing that NYISO was picking winners for a $1 billion project “despite a virtual tie on project benefits” among competing projects, which included NEETNY’s T022 in Segment B.
The ISO “did not provide analysis on cost-contained pricing … and three other project combinations that are virtually identical, provide all the quantifiable and quantitative benefits [and] are within 1 to 5% of the cost estimate using SECO’s numbers,” Duncan said. He also questioned why NYISO made tower height a big issue in its selection when its solicitation made no mention of the factor.
Patka said the PSC order did not mandate the ISO to use cost-contained pricing but required developers to provide two sets of costs, “one based on raw construction costs and one on 80%/20% cost overrun/cost underrun language. … They said they hoped that FERC will adopt cost containment when they address the rate issue, but their words were exactly, ‘The NYISO should evaluate the costs based on raw construction costs.’”
Patka also said that tower heights were considered by NYISO as a risk of project delay and to project completion, as visual impact is a key environmental impact of transmission, and that the ISO had reviewed its analysis with New York Department of Public Service staff.
Duncan also took issue with the concrete pole installation cost estimates, saying that SECO used a metric of dollars per pound on the weight of the pole rather than a more logical figure of total costs, including labor. He also said the ISO’s estimate of 5% in synergy savings on the combined projects by one developer was “overstated.”
“If those issues are addressed, project T022 would be the lowest-cost project by millions of dollars, probably tens of millions of dollars,” Duncan said.
SECO Vice President Joe Allen said he agreed “there would be no synergy” between the two upgrades.
Smith said NYISO could “take that back, but it won’t affect the ranking at all.”
Kathleen Carrigan, New York Transco general counsel, read comments the company jointly submitted with National Grid.
Losing bidders cried foul last week over NYISO’s selection of North America Transmission and the New York Power Authority to build two 345-kV transmission projects to address public policy needs identified by the New York Public Service Commission. | NYISO
The two companies submitted proposal T019 for Segment B, including “a basic controllable series compensation element to preserve the proposed 345-kV transmission line physical designs that the commission deemed the most environmentally and siting friendly in the underlying AC transmission proceedings.”
Carrigan said series compensation technology is widely used across the U.S., and she submitted a study showing no detrimental system impacts from it. NYISO and SECO “considered proposal T019 as too risky due to the inclusion of the series compensation, despite no technical analysis in support of their conclusion,” she said.
Smith said that while the ISO does not oppose the use of series compensation as a technology, it did see potential problems with its application in the National Grid/NY Transco project. In a FAQ document posted with the BIC meeting materials, the ISO cited potential subsynchronous resonance and damage to generators as the major risk of series compensation technology.
Carrigan said NYISO’s own metrics show the National Grid/NY Transco proposal paired with T029 produces consistently better performance results than the ISO’s favored project.
For example, when combined, T027 and T019 increase voltage transfer across Central East by 875 MW and UPNY/SENY by 2,100 MW. “This is a far greater increase than the combination of T027 and T029, which only increases transfer capability along Central East by 825 MW and UPNY/SENY by 1,325,” she told RTO Insider after the meeting.
“Projects T027 + T019 have the highest Central East N-1-1 voltage transfer capability of any studied project combination and far surpass combination T027 and T029 with respect to the incremental UPNY/SENY N-1-1 thermal transfer capability. The baseline 20-year incremental energy produced by projects T027 and T019 nearly doubles that of projects T027 and T029 (40,089 GWh vs. 27,524 GWh); and finally, T027 and T019 produce the highest production cost savings than any other Segment B combination,” Carrigan said.
HOUSTON — While sharing her organization’s report on the state of the ERCOT market in 2017 last week, Potomac Economics’ Beth Garza was naturally asked her forecast of this summer’s energy prices.
“My title is not market predictor. It’s market monitor,” Garza, director of ERCOT’s Independent Market Monitor, reminded her luncheon audience June 21. “I get to watch and opine. I’m sorry to disappoint you.”
Speaking to those gathered at the Gulf Coast Power Association’s lunch in Houston, Garza shared highlights from the State of the Market report. Energy insiders listened attentively as she reviewed 2017 data — and even more so on the rare occasions Garza looked ahead to 2018.
Garza said reserve margins will be tighter this summer than last year, primarily because of the retirement of 4.2 GW of coal generation over the last 12 months. That dropped ERCOT’s planning reserve margin from 18.9% to 9.3% — since increased to 11% — and raised fears of potential shortages during a long, hot summer. (See ERCOT Gains Additional Capacity to Meet Summer Demand.) On Friday, as the system flirted with June’s demand record of 67.8 GW, the ISO still had more than 3.5 GW of operating reserves.
“We had an interesting test of the system in May,” Garza said, referring to the multiple demand records ERCOT set for the month in the face of above-normal temperatures. “But as others have said, a hot May does not necessarily portend a hot summer.”
Statewide temperatures have dropped since then, thanks to recent torrential rains. That has also dampened forward prices, which have settled at about $150/MWh after soaring above $250/MWh in May.
| Potomac Economics
“Is that a reaction to the rain and the temperatures?” Garza asked. “We got through May, but the rest of June has not been severe.”
Garza allowed herself some prognostication in addressing the forward prices.
“I can look at future prices and infer an estimate of how many hours of real-time prices at the 9,000/MWh cap we’ll see,” she said, noting ERCOT saw only 3.5 hours of prices above $1,000/MWh last year. Garza recalled a straw poll of attendees at the recent GCPA spring conference, with expectations of five to 10 hours at the $9,000/MWh cap this year.
“That’s what the future pricing seems to indicate, but that’s based on a $200 price. I haven’t done the math on $150 prices,” Garza said. “If we have 2 GW of wind generation on peak, it’ll be a high-priced day. If we have 10 GW of wind generation on peak, it’ll be a moderately priced day.”
Garza also put in a plug for the addition of real-time co-optimization in the market, one of six recommendations the Monitor has made in each of its last few reports and one of several market improvements being considered by the Public Utility Commission of Texas. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)
“It’s the key missing link in our market,” she said. “Our market is dependent on pricing during significant scarcity intervals. My fear is that as we get to where we see tight reserve margins, the likelihood of scarcity events and high prices increase, because of the ineffective allocation of reserves. If they were allocated differently [through real-time co-optimization], we wouldn’t see those high prices.”
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 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.
INDIANAPOLIS — MISO’s multiyear effort to replace its market platform will likely come in slightly over budget and is at risk of delay because of project snags with vendor General Electric, the RTO’s Board of Directors learned this week.
MISO now expects it will fully migrate to the new modular market platform by 2024, about a year later than it initially projected in 2017. The project’s cost is predicted to increase from $130 million to just under $134 million. (See MISO Makes Case for $130M Market Platform Upgrade.)
The platform replacement was discussed in multiple committee meetings during MISO Board Week.
Todd Ramey, MISO vice president of market system enhancements, said current platform vendor General Electric reported a “significant increase in the work requirement” in early May. Kevin Caringer, executive director of MISO’s IT team, said the RTO recently determined that GE was “too optimistic” in its original timeline, especially concerning estimates on the complex software needed to clear the day-ahead market. He acknowledged that GE got off to a “slow start” in recruiting and hiring staff for the project in 2017 and estimated the company is about five or six months behind schedule.
“We did express our disappointment” in response to GE’s proposed timeline, Caringer said, adding that MISO is working with PJM and ISO-NE to consider a counterproposal to GE’s timeline. The modular platform’s design is being jointly developed with those RTOs, which also use GE-designed platforms. (See MISO Sets Target for Market Platform Upgrade Decision.)
Although MISO executives said the RTO will likely have to adjust timelines for the remainder of the project, they maintain the overall replacement effort remains “generally on target.”
Sunk Costs
A separate third-party vendor was this year expected to deliver a development and testing platform to evaluate new components from GE. MISO now says that plan “is at risk of minor delays beyond July 31 due to vendor negotiations and lead time needed.”
Caringer said he thought MISO could meet its self-imposed 2018 deadline on the testing platform, but he added the RTO “used up a lot of [its timeline] flexibility in negotiations” with the third-party vendor.
Director Baljit Dail pointed out that MISO’s original $130 million budget provides for an additional 20% in contingency funds for unforeseen expenses.
“In the event that things happen — like they’re happening now — we have that buffer,” Dail said.
Director Theresa Wise asked how much in sunk costs MISO would risk if it decided to switch vendors at this point. Executives estimated the RTO has so far spent $2 million to $3 million with GE on developing the platform.
Soon after the question, MISO lawyers said that any discussion on alternative plans should be saved for closed session. Multiple directors responded that they would reserve more specific questions about vendor performance for a closed meeting.
Dail later reported that the board had a robust, nonpublic discussion on GE’s performance.
“General Electric’s woes are being well publicized; they’ve recently dropped out of the Dow Jones. We need to send a strong message to GE and its management because they are critical in this path. … I think we’re all very concerned, and I think we need to send a strong message that they need to step up their game,” Dail said during a June 21 board meeting.
“Could you convey at least one director’s disappointment … in the primary vendor?” Director Thomas Rainwater asked MISO executives during the same meeting.
Board Chairman Michael Curran said the situation was not unlike the adjustments made while developing transmission projects.
“You think you can understand what that vendor can do, you think you have a plan, but once you break ground, shifts may occur. They’re a natural part of the process, and we look forward to you managing it well,” Curran told executives at the end of the week.
MISO reported it is ahead of schedule on at least one aspect of the platform replacement: the hiring of extra staff for the project is occurring earlier than expected.
Caringer explained that the board previously expressed concern that skill shortages might cause delays in hiring technical talent. “While this risk is real, MISO has been able to attract the right skills so far, although this will continue to be a challenge.”
Limited Improvements for Old Platform
MISO reported again that its existing platform and new FERC directives are restricting which market improvements it can undertake.
Executive Director of Market Development Jeff Bladen said about a third of projects under the RTO’s Market Roadmap cannot be implemented because the existing market platform cannot manage the complexity required for the improvements.
However, MISO said it would complete at least two projects on its legacy computer system: 1) the creation of a short capacity reserve market by early 2020 that can deliver reserves within 30 minutes (a Market Roadmap item); and 2) compulsory compliance with FERC Order 841 to create a participation model for energy storage by late 2019.
MISO said other market system-dependent changes on the Market Roadmap will be deferred until the new platform can accommodate them. The deferral includes the plan to create a more sophisticated model that can mimic different combinations of combined cycle units and their dependencies. The project had previously been planned for implementation on the legacy system.
Bladen also explained MISO is not currently planning to implement an integration model for distributed energy resources on the legacy system. He said staff have been in contact with FERC since an April technical conference to explain that the RTO’s footprint doesn’t contain enough growth in DERs to warrant a significant rule change just yet. MISO will be able to transition technology platforms before the need for DER rules emerges, he said.
Dail thanked MISO for the analysis. “This is a very, very complex needle that we’re trying to thread,” he said of undertaking improvements as the platform replacement unfolds.
“It’s almost like there’s a new criteria [for market projects]: impacts to the legacy platform,” Curran said.
MISO President Clair Moeller agreed that it is a balancing act to select market design improvements while not “distracting from the market system enhancement.”
Meeting with Members’ CIOs
MISO has also begun holding biannual nonpublic meetings with member companies’ chief information officers to discuss cybersecurity, NERC critical infrastructure protection and adaptation to the new platform, among other technology issues.
MISO Chief Information Officer Keri Glitch said CIOs and chief information security officers from nine member companies attended a second meeting in St. Paul, Minn., in mid-May.
Glitch said MISO will hold another meeting of the group, now called the CIO/CISO Technology and Security Advisory Council, in St. Louis sometime in November.
