CARMEL, Ind. — MISO has called off a proposal to rely on data from its load-serving entities to compile its own long-term load forecast, stakeholders learned last week.
The RTO will instead continue to use independent load forecasts (ILFs) prepared by Purdue University’s State Utility Forecasting Group but with a twist: It will now order four versions of the forecast, each tailored to one of the futures used to inform MISO’s annual Transmission Expansion Plan.
“After careful consideration of the comments and proposals by stakeholders, MISO will begin to use the independent load forecasts to develop futures-specific load and energy forecasts for MTEP 20 and beyond,” John Lawhorn, MISO senior director of policy and economic studies, told stakeholders at a June 13 Planning Advisory Committee meeting.
Lawhorn said “consistency and clarity, not necessarily increased precision,” prompted the decision, and he stressed that MISO will continue to use LSE forecasts to plan for resource adequacy.
The expanded independent forecast is “for transmission planning purposes only,” Lawhorn said.
“I know we’ve been talking about the ILF for the past five years, with more discussion in the past eight months,” he said.
The change to an LSE-based forecast would have required MISO’s 140-plus LSEs to annually assemble four different 20-year load forecasts to fit with each of the MTEP futures, an unpopular proposition with many stakeholders. (See Advisory Committee Steps up Criticism of MISO Forecast Plan.)
The LSEs themselves were mixed over whether they would be able produce their own 20-year forecasts. An April survey generating responses from one-third of LSEs representing about two-thirds of load showed that LSEs estimated the costs of putting together forecasts would be anywhere from “minimal” to a few hundred thousand dollars, Lawhorn said.
“Costs were all over the map from that perspective, whether they already had a load forecasting group or not,” Lawhorn said in April.
Stakeholders at last week’s meeting asked whether MISO has a plan to monitor its ILFs and compare them with actual loads after the fact.
Lawhorn said although it’s difficult for MISO to line up all variables to compare forecasted load to actual load, Purdue’s own analysis has shown its forecasts “trend well” with actual load in the long term.
Other stakeholders expressed concerns that MISO had no specific plan to hold the ILF to a standard of accuracy.
WPPI Energy’s Steve Leovy said he would have liked MISO to hold more discussion with stakeholders before deciding on the ILF, adding that a single survey of LSEs was inadequate to collect opinions. Organization of MISO States Executive Director Tanya Paslawski said she was likewise concerned about MISO’s short comment period and scant communication about its decision. She noted she would take her concerns to her Board of Directors.
‘Post-capacity’ Planning
MISO said it makes sense for the ILF to be tailored to MTEP futures because energy usage is increasingly driving transmission planning, shifting away from capacity-based planning that relies on an annual system peak. The RTO says it will increasingly experience peaks that can occur during any hour of the year.
“It’s a shift that we’re seeing from a capacity-planning paradigm to an energy-planning paradigm … as we move to more facilities that are small and local. Energy delivery is becoming the driver of a robust transmission system. Moving energy around the system becomes more important as the resource mix changes,” Lawhorn said, pointing to MISO’s 93-GW interconnection queue, which includes 80 GW of potential renewable sources. “This is portending to be a major shift in our system.”
MILFORD, Mass. — ISO-NE forecasts a net installed capacity requirement (ICR) value of 34,000 MW for capacity commitment period 2023/24, a 275-MW increase from the 33,725 used in February’s Forward Capacity Auction 12 for 2021/22, officials told the Planning Advisory Committee on Wednesday.
| ISO-NE
The net ICR is forecast to rise by 200-MW increments each period to 34,800 MW for 2027/28 with capacity margins dropping to 15% from 16.7% for 2021/22.
The forecast uses the same capacity and transmission transfer capability assumptions used to develop ICR values for FCA 12 but with the 2018–2027 Forecast Report of Capacity, Energy, Loads and Transmission (2018 CELT) load forecast. The FCA 12 values were based on the 2017 CELT, system planning engineer Manasa Kotha told the PAC. (See ISO-NE Capacity Prices Hit 5-Year Low.)
The RTO modeled three capacity zones for FCA 12: the Southeast New England (SENE) import-constrained capacity zone comprising Northeast Massachusetts (NEMA)/Boston, Southeast Massachusetts (SEMA) and Rhode Island; the Northern New England (NNE) export-constrained capacity zone comprising Maine, New Hampshire and Vermont; and the Rest-of-Pool capacity zone comprising Connecticut and Western/Central Massachusetts.
Comparisons of the 2018 and 2017 CELT load forecasts show that while overall New England load decreased, load in the SENE sub-areas has increased, as it did last year, Kotha said.
Comparison of 2017 and 2018 Net ICR Forecasts (MW) | ISO-NE
The increase is attributable to the Massachusetts economy continuing to grow faster relative to the other New England states, she said.
As part of its review of ICR assumptions for Operating Procedure No. 4 conditions (action during a capacity deficiency), the RTO has proposed using 700 MW of minimum operating reserves in the ICR model, an increase of 500 MW over the long-term assumption of 200 MW previously used. The new 700-MW assumption will be used in FCA 13 ICR calculations, Kotha said.
Future Locational Reserve Needs
ISO-NE foresees reserve needs in NEMA/Boston to be in the range of 250 to 700 MW for summer 2019 and 250 to 400 MW for winter 2019, Fei Zeng, technical manager for resource adequacy, told the PAC.
The RTO developed future representative operating reserve needs for the current reserve zones in NEMA/Boston, Southwest Connecticut (SWCT) and Greater Connecticut for summer and winter for study period 2018-2022. The actual requirements reported for 2018 are based on historical data of the last two years.
Investment of New England transmission reliability projects by status through 2022 (numbers represent project quantities) | ISO-NE
The forecasts did not consider the impacts of Footprint Power’s new 674-MW combined cycle power plant in Salem, Mass., “which when it goes into service by the end of the year is expected to have an impact on the following year’s calculations,” Zeng said.
Together with upgrades in the greater Boston area, the new Salem Harbor Station will help eliminate the local reserve needs for the study period, Zeng said.
In SWCT, the grid operator expects Competitive Power Ventures’ Towantic Energy Center, which began generating last month, to help reduce local reserve needs to a minimum level for summer 2019. With the assumed addition of Bridgeport Harbor 5, and the SWCT transmission upgrades, forward reserve requirements are expected to be zero for the remainder of the study period. (See related story, CPV: Subsidies — not Gas Shortages — Challenge for New Plants.)
CEII Presentations Describe Aging Infrastructure
The PAC heard five presentations on regional transmission infrastructure, which collectively described the rust in New England’s rustbelt. All five presentations were classified as containing critical energy/electric infrastructure information (CEII).
However, one stakeholder pointed out that much of what the classified material detailed would be visible to any interested commuter in the region. The needed replacements range from vintage control room equipment to brown glass insulators to replacing rusting towers.
Pradip Vijayan, ISO-NE senior engineer for transmission planning, updated the PAC on results from the SWCT 2027 needs assessment, as well as one project related to an older needs assessment for Greater Hartford/Central Connecticut.
Christopher Malone, Avangrid manager for Connecticut transmission planning, presented railroad corridor transmission line asset conditions. Maintenance of century-old catenary structures over the railroad is complicated by railroad control of 22-kV feeder/signal conductors.
Eversource Energy system planning manager Shaun Moran presented on challenges with the infrastructure in Eastern Massachusetts that carries much of the load for Cape Cod.
Kelly Csizmesia presented on behalf of National Grid’s New England Power unit, which operates transmission facilities in every regional state except Connecticut.
Transmission Projects and Asset Condition Update
Jon Breard, ISO-NE associate engineer for transmission planning, presented an update on the Regional System Plan regarding transmission projects and asset conditions, noting that seven new transmission projects totaling $146.8 million have been placed in service since the last update in March.
The RTO estimates about $1.74 billion in active reliability projects are underway now, compared to $1.9 billion in March.
Regarding asset conditions, the RTO reported one new project (the $6.3 million replacement of the Montville 16X transformer in Connecticut), and three projects placed in service since the last update in March, including: the installation of two 40-MVAR reactors on the Scobie 115-kV bus in New Hampshire ($4.7 million); replacement of the Salem Harbor Substation 115-kV oil circuit breaker ($4.6 million); and the 1231/1242 structure replacement project in Massachusetts ($8 million).
MILFORD, Mass. — Only six of 32 interconnection requests studied by ISO-NE in its initial test of its new queue clustering methodology have moved on to the next stage of the process, all of them in western Maine.
The six interconnection requests, totaling 691 MW, will be included in the RTO’s first cluster system impact study (SIS), Al McBride, director of transmission strategy and services, told the Planning Advisory Committee last week.
ISO-NE implemented the clustering methodology to address the queue backlog in Maine, where more than 5,800 MW of proposed resources, mostly wind, want to connect to the grid.
Bingham Wind Project | NovatusEnergy
The process allows for two or more interconnection requests in the same area to be analyzed together and to share costs for required transmission upgrades when none of the requests can interconnect without the use of common new infrastructure rated at 115 kV AC or HVDC.
The first Maine Resource Integration Study (MRIS) concluded that the RTO could connect nine Northern Maine requests totaling 1,118 MW and 23 western Maine requests totaling 777 MW with about $1.83 billion in transmission upgrades. The upgrades included a second 345-kV Coopers Mill-Maine Yankee 392 line — which both clusters required — at a cost of $108 million.
With constraints on the system, “we found ourselves hitting a ceiling of around 1,800 MW” in interconnection requests able to be accommodated, “which is a significant addition to the Maine transmission system,” McBride said.
ISO-NE Maine Study | ISO-NE
Projects had 30 days after posting of the MRIS on March 12 to inform ISO-NE of their intention to move on to the clustered SIS process.
None of the Northern cluster projects — whose upgrades would have totaled $1.36 billion, including the second 392 line — agreed to proceed.
Seven of the 23 western Maine requesters sought to be included in the cluster SIS, but one, for 1,200 MW, was not permitted because it exceeded the capacity of the “cluster-enabling transmission upgrades.” It will be studied separately.
Costs of the upgrades for the western projects, including the second 392 line, were estimated at $575.5 million. The other upgrades include a new 345-kV line from a new substation near Johnson Mountain to the existing 345-kV substation at Larrabee Road.
Second Study Planned
The RTO is planning a second MRIS to evaluate upgrades needed to accommodate an additional 22 interconnection requests, including about 1,350 MW in Somerset and Franklin counties and about 2,300 MW in Aroostook and Penobscot counties.
McBride said the study will consider new HVDC transmission connecting to the southern part of the RTO’s system, connecting either radially to proposed generation or to the existing network.
The RTO asked stakeholders to email feedback on the proposed study scope to PACmatters@iso-ne.com by July 13.
It hopes to complete the study within 12 months.
“We would be very reluctant to study major transmission proposals, from $500 million to $1 billion, that provide only minimal interconnection capability,” McBride said.
Sacramento, Calif. — The California Energy Commission on Wednesday approved $10 million in grants for two microgrid projects, including one that represents a new form of partnership between investor-owned utilities and a community choice aggregator.
The commission in a 4-0 vote approved $5 million apiece in grants for microgrids at California Redwood Coast-Humboldt County Airport and at Santa Rosa Junior College in Sonoma County. The CEC said the airport project enables further research into microgrids and many value streams, including demonstrating the ability for CCAs to work with utilities to maintain reliability, offsetting electricity costs, integrating microgrids into CAISO operations, generating data and producing ancillary benefits at the remote location.
The solar/storage project at the coastal airport will “represent the first multi-customer, front-of-the-meter microgrid with renewable energy generation owned by a CCA and the microgrid circuit owned by an IOU.” Redwood Coast Energy will own the generation while Pacific Gas and Electric will own the distribution circuit, with Schatz Energy Research Center leading the project.
The airport facility consists of two ground-mounted solar PV arrays, one a 250-kW array configured for net energy metering service, and the other a 2-MW, 6-acre array for wholesale power sale. It also features a 2-MW/8-MWh lithium ion battery storage system and will additionally power a U.S. Coast Guard station. It will add resilience to 18 accounts on PG&E’s Janes Creek 1103 distribution circuit and is seen as providing a roadmap for microgrid development, the CEC said.
The Santa Rosa project will be 136,000 square feet of rooftop solar on two existing parking structures and two 1-MW lithium-ion battery systems. Other subcontractors and vendors include the California Center for Sustainable Energy, PXiSE Energy Solutions, WorleyParsons, SunPower, STEM and nine other subcontractors to be announced.
Chairman Robert Weisenmiller on Wednesday said the CEC has been communicating with utilities and the Public Utilities Commission about making microgrids a priority in high fire-risk areas to help maintain resilience and reliability.
“It is time to move more toward the future in this area,” Weisenmiller said.
Commissioner Andrew McAllister said: “I think this is absolutely a valid thing to be doing,” but he called for “realism” as microgrids are developed. “Part of the challenge is to figure out and learn where they are really needed. … The goal isn’t necessarily for the whole distribution grid to be a complete assembly of microgrids.”
The projects were funded through the latest round of solicitations of the Electric Program Investment Charge (EPIC), a retail ratepayer surcharge. (See California Awarding $45 Million for Microgrids.) The program has funded hundreds of projects, approaching $500 million in awards.
The CEC also approved:
Building energy efficiency standards for Marin County that will require all new single-family residences less than 4,000 square feet to be all electric or, if mixed fuel, to reduce energy consumption by 15%, or 20% below the 2016 standards if a PV is included. New low-rise multifamily residential will be required to be all electric or reduce energy consumption by 10%, or 15% if a PV system is included. New high-rise multifamily residential and new nonresidential construction will be required to be all electric or reduce energy consumption by 10%.
A $1.5 million, 1% interest rate loan for energy conservation measures for the city of Weed for city-owned sites.
A $260,000, 1% interest rate loan to San Diego County to install demand-controlled ventilation and more efficient interior and exterior lights at a nursing facility.
CARMEL, Ind. — MISO is seeking stakeholder input as it develops a conceptual study to determine how to incorporate the impact of transmission outages into its economic planning models.
MISO said transmission and generation outages are “a major contributing factor of market price volatility.” While the RTO includes concurrent generation outages in its economic model, it does not model concurrent transmission outages, though it said a 2014 exploratory study showed that transmission outages could increase system congestion by about 66%.
“Transmission outages, planned or forced, can cause redispatch of the generation. They have economic consequences,” it said.
Speaking at a June 12 Planning Subcommittee meeting, MISO adviser Ling Hua said the RTO is gathering information to create modeling options for transmission outages and evaluate their trade-offs. Its study examines transmission outage modeling based on either: historical outages; a Monte Carlo-style simulation based on statistics gathered from historical outage data; a systemwide transmission facility derate of 5 or 10%; or use of still undefined research to establish an adjusted production cost adder in the model.
Using 2016 data on 2,000 planned and forced transmission outage events on 115-kV or above facilities lasting longer than five days, the RTO said it could conservatively model about 1,460 transmission outage events in one 2017 Transmission Expansion Plan future model based on a historical outage modeling method.
Hua also said that while both the derate and adjusted production cost adder can capture the systemwide average impact from transmission outages, they fail to account for locations of transmission outages. The historical and Monte Carlo options are more labor-intensive to put together, he said.
American Transmission Co.’s Chris Hagman thanked MISO for investigating the four approaches for stakeholders and said it was important for the RTO to plan for the impact of transmission outages.
MISO Transmission Planning Engineer Amit Rao asked stakeholders to provide their reactions to the four approaches and additional modeling suggestions by July 9.
New Benefit Metrics
MISO is continuing a discussion on which benefits metrics it should account for regarding new transmission projects, as it prepares a plan to prioritize projects that avoid costly investment or reduce settlement costs on its contract path with SPP. (See Stakeholders Debate MISO Cost Allocation Plan.)
The RTO is proposing that new market efficiency projects (MEPs) that would eliminate the need for proposed MTEP reliability projects to include the value of those reliability projects in their estimated costs. The avoided cost benefit — and cost allocation — would then be spread among pricing zones where the reliability projects would have been built. The RTO plans to review all avoided projects with transmission owners.
But Customized Energy Solutions’ Ginger Hodge said she was worried about transmission owners under- or overstating the planning-level cost estimates that inform the benefit metric. She asked the RTO to conduct a historical analysis comparing TO cost estimates at the MTEP planning phase to actual costs to better determine the average variance between estimates and actuals. Hua said MISO could look into the possibility.
MISO also plans to value MEPs based on their ability to reduce annual payments to SPP for flows above the contract path capacity between MISO Midwest and South, but Hua said eligible MEPs eligible would have to physically connect the two regions. For every megawatt that an MEP increases the MISO contract path, the payment structure in the MISO-SPP agreement will be reduced by $667/MW-month, Hua said. She said the benefit would be calculated as an annuity from the in-service date over a 20-year asset life.
The benefits would be distributed to local resource zones using the load-ratio share cost allocation approach already outlined in the settlement agreement for market settlement costs, Hua said.
Hua asked for stakeholder feedback on the two proposed benefit metrics through July 2. She said the RTO would finalize the new benefit metrics for a Tariff filing in August.
Matching Modeling with Proposed Retirement Process
MISO is working to update its modeling to comply with a new generator retirement process recently filed with FERC.
The new retirement process filed last month proposes to place all generation owners submitting an Attachment Y retirement notice into a catch-all three-year suspension period (ER18-1636). Suspended units would maintain their interconnection rights for the full three years unless they formally decide to retire. After three years without a return to service, the units are presumed retired and MISO dissolves their interconnection rights. (See MISO Readies Retirement Change.)
MISO will update its dispatch assumptions to match the new process by modeling a suspended unit as initially offline for the first three years, but assumed to be participating in dispatch after three years, unless the unit is retired. Patrick Jehring, of the RTO’s expansion planning group, said more than half of generation owners submitting an Attachment Y notice decide to immediately retire.
Jehring said MISO modeling is in “limbo” for those three suspension years, but modeling must assume that suspended units will return to service, based on the Tariff.
He noted that the RTO doesn’t foresee granting conflicting interconnection rights — a concern voiced by some stakeholders in prior meetings — because its interconnection process requires that it conduct a deliverability analysis for proposed generation projects, which would flag any issues.
Generators Miss 1st Pass in Under-frequency Study
| MISO
MISO will complete a NERC-required under-frequency load shedding study by fall, and, at first blush, a few generators have more work ahead to comply with one frequency requirement.
The study is required once every five years, and the RTO last conducted one for MISO Midwest in 2013. The RTO is studying seven under-frequency load-shedding islands in the region.
Anton Salib of the RTO’s expansion planning group said the frequency performance of the seven islands meets most requirements of NERC Standard PRC-006-3, although a few generators might need to take steps to ensure they don’t exceed 1.18 V/Hz per unit for more than two seconds and 1.1 V/Hz per unit for more than 45 seconds at each generator bus.
An initial examination showed that four of the seven islands’ frequency performance exceeded the NERC requirement: Michigan’s Lower Peninsula; “Gateway” in parts of Illinois and Missouri; ATC-A in Wisconsin and part of Michigan’s Upper Peninsula; and Local Resource Zone 1 in the Dakotas, Minnesota, Wisconsin and a small portion of Montana.
Salib said MISO will finish the study and present results in time to meet the October deadline.
Examining 7 Transfers for MTEP 18
MISO has begun a transfer analysis as part of its MTEP 18, due to be revealed in early December.
| MISO
The analysis examines whether the RTO can reliably transfer energy and identifies potential future system weaknesses or limiting transmission facilities under NERC standard FAC-013-2.
Shelly Botkin enjoyed a relatively quiet debut on the Public Utility Commission of Texas last week, sitting through a 15-minute open meeting devoid of any major decisions.
Botkin | AdminMonitor
Appointed to the three-person commission on June 11 by Gov. Greg Abbott and sworn in two days later, the former ERCOT communications and governmental relations director smiled often at friends in the audience and seconded motions for approval. (See ERCOT’s Botkin Named to Texas PUC.)
“With that, your first meeting is over,” PUC Chair DeAnn Walker said to Botkin as she adjourned the June 14 meeting to the room’s applause.
Walker Calls for Attention to Details During Summer
Walker opened the meeting with a plea for normalcy during the summer months, when demand will be high, ERCOT’s reserve margin low and energy prices potentially poised to spike.
Already, the market has seen the collapse of Breeze Energy on May 30, the first retail electric provider (REP) to go out of business since 2014. ERCOT staff told the Board of Directors June 12 that the retailer defaulted on its collateral obligations to the ISO.
Texas PUC commissioners react to applause | AdminMonitor
Mark Ruane, ERCOT’s director of settlements, retail and credit, said that when Breeze “failed to cure that breach,” the ISO began a transition of its nearly 10,000 customers to their providers of last resort: other REPs.
“While I think it went smoothly, I think it could go smoother in the future,” Walker said, thanking Oncor for managing the transition. “They waived all the deposits. I think that was very helpful too.”
ERCOT is holding a workshop June 21 to discuss lessons learned from the Breeze transition.
Texas PUC’s June 14 open meeting | AdminMonitor
“My focus is making sure consumers get to choose who they get to take service from and do it in a timely manner,” Walker said.
PUC to Intervene in FERC Dockets
Following its executive session, the PUC moved to intervene in three dockets currently before FERC:
NextEra Energy Transmission’s request to buy a 30-mile transmission line in East Texas owned by Rayburn Country Electric Cooperative. NextEra plans to transfer functional control of the line to SPP (EC18-97).
Entergy’s waiver request to allow its operating companies to reflect recent tax law changes in MISO’s formula rate templates (ER18-1721).
MISO’s proposed Tariff modifications governing the treatment of generation retirements and suspensions (ER18-1636).
Duke Energy and Old Dominion Electric Cooperative have likely struck out on trying to recoup millions of dollars in “stranded” gas costs they say PJM forced them to incur during the 2014 polar vortex.
Duke and ODEC had argued to FERC that they were owed compensation when PJM ordered them to be ready to run even as the cold snap sent gas prices soaring. Duke purchased $12.5 million worth of natural gas for its Lee plant in Illinois, only to have it not called on in real time. The company was able to resell some of its gas and sought $9.8 million in restitution.
ODEC complained that it was due nearly $15 million because PJM canceled multiple dispatches that left gas it had purchased for its plants unused. It also said its plants’ operating costs on Jan. 23, 2014, exceeded what it could recover in the day-ahead market because of the $1,000/MWh offer cap at the time. The co-op asked the commission to extend to Jan. 23 the waiver FERC granted PJM on Jan. 24, which allowed capacity resources to receive make-whole payments if their costs exceeded the offer cap.
FERC denied the request, saying PJM’s Tariff didn’t allow it and that ODEC’s ratepayers lacked sufficient notice that the approved rate was subject to change. The court upheld FERC’s decision, dismissing ODEC’s arguments that it could charge a market-variable formula rate and that customers received sufficient notice from an announcement PJM posted that it would seek commission approval for certain generators to exceed the rate cap.
“Close, but no cigar,” the court said of the formula rate argument. ODEC failed to identify Tariff provisions specifying such a rate or an instance in which utilities refunded overbillings back to customers, a bidirectional condition that would exist under formula rates. Additionally, “to toss that [$1,000/MWh rate] cap aside after the fact just because it did exactly what a cap is supposed to do — serve as a firm ceiling on market prices — would retroactively rewrite the terms of the filed rate,” the court said.
ODEC’s argument that PJM’s announcement qualified as sufficient notice “fails at every step,” the court said, noting that it wasn’t filed at FERC as required for rate changes.
The court also sided with FERC on Duke’s request, in which the commission concluded that PJM’s conversations with the company did not constitute an order to purchase expensive gas.
| Monitoring Analytics
FERC determined that PJM operators told the generators “to do whatever needed to be done to fulfill its Tariff obligation” but “said nothing about when to purchase natural gas, at what price to purchase the gas, how to bid into the market or to take any action beyond that which Duke is otherwise obligated to take under the Tariff: to purchase natural gas to be prepared to run its units.”
The court conceded that “the record may well be subject to other interpretations,” including those preferred by Duke.
“But our task is not to assess whether Duke’s interpretation of the record is fair,” the court said. “Just the opposite: We must accept FERC’s interpretation unless unsupported by substantial evidence. And Duke has given us no basis for believing that a ‘reasonable mind’ would not find the evidence here ‘adequate to support [FERC’s] conclusion.’”
PJM hopes to reduce its capacity market demand curve by including peak shaving among the variables used to develop its load forecast.
Andrew Gledhill, senior analyst of resource adequacy planning, explained the proposal at a meeting last week of the Summer Only Demand Response Senior Task Force (SODRSTF). It has the potential to reduce reliability requirements — and subsequently the variable resource requirement demand curve — by hundreds of megawatts.
PJM would start by adjusting historical loads back to 1998 through a formula that assumes perfect previous curtailment compliance. The program would be assumed to have been enacted every time a predetermined temperature-humidity index (THI) threshold was reached. THI has a strong correlation with loss-of-load expectation, the RTO said.
Each event would have been six hours from 1 to 7 p.m. on a non-holiday weekday. The events would have occurred any time between May and October, but “we don’t have a lot of high-THI events that occur in May, September and October, so … these are most likely to occur in June, July and August,” which account for the six highest load hours in the RTO, Gledhill said.
Adjusting the Model
The current method identifies the gross load for a delivery year and regresses for the forecast based on variables, including economic, weather and end-use changes.
“But there’s no variable in there for peak shaving,” Gledhill explained, so it would have been included only by reducing the gross load.
| An example from PJM of the potential impact to the VRR curve in ATSI’s transmission zone.
Some stakeholders voiced concerns that requiring commitments to last six hours was a high bar that would reduce offerings into capacity auctions, but others urged them to take a holistic view.
“We have to look at what PJM’s need is, not simply what the easiest program or the most customer-friendly program would be,” GT Power Group’s Dave Pratzon said.
Staff said the six-hour time frame is intentional because it mitigates peak shifting. They noted that the curtailments have already been factored into forecasts. PJM would only be looking for compliance, but these would not be RTO programs.
“The load forecast has already reflected the benefit of reduction of load when THI trigger is hit,” PJM’s Tom Falin said. “The intent of this is to improve the load forecast. … We’ve already assumed a certain amount of behavior, so it has to continue in the future, so the forecast can remain consistent.”
Impact
PJM’s analysis showed that only a percentage of the cumulative peak shaving would impact the load forecast because of the peak simply shifting to another hour. For most transmission zones, the impact shrinks as the amount of shaving increases, staff found. For example, 100% of the megawatts in a 2% shave would impact the forecast in the Penelec zone, but less than 40% of the megawatts in a 10% shave would impact the forecast in East Kentucky Power Cooperative’s zone.
| This graph from PJM shows how much of an impact on the load forecast in different transmission zone varying percentages of peak shaving would have.
It would have even less of an impact on the reliability requirement, though it would still be significant. PJM found that, given a 6% peak shave, the reliability requirement would be reduced by anywhere from 30 to 85% of the shaved megawatts.
MISO last week said it will revise its regional cost-sharing practices for interregional projects with SPP to match its process for PJM seams projects, lowering the voltage threshold to 100 kV and eliminating a minimum cost requirement.
The move is part of MISO’s broader plan to revise cost allocation for market efficiency projects (MEPs) as Entergy’s five-year transition period — which limits cost sharing in MISO South — expires at the end of the year. The plan still includes Tariff changes to eliminate a footprint-wide postage stamp rate for MEPs in favor of more detailed benefit metrics, and to lower the voltage threshold for cost allocation eligibility of internal MEPs from 345 kV to 230 kV.
Unlike interregional MEPs, internal MEPs will still have to meet a $5 million minimum cost threshold, although both project types will still be subject to a 1.25:1 benefit-to-cost requirement. None of the changes extends to MISO’s multi-value project category. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.)
MISO’s current regional cost-sharing rules for SPP interregional projects require at least a 345-kV voltage rating and a $5 million price tag. The new rules will mirror regional rules that FERC ordered for MISO-PJM interregional projects in 2016.
Narrowing the Cost Allocation Gap
MISO Director of Strategy Jesse Moser said that ensuring consistency along the RTO seams was the deciding factor in standardizing the treatment of SPP and PJM projects.
The current proposal will “best align who pays with who benefits,” Moser told RTO Insider.
“Our goal is to get as close to that as we can,” he said. “We’ve long had a concern about what we call the cost allocation gap on our seams.”
Having differing rules for separate RTO neighbors “leaves the door open for uncertainty,” Moser said. “We prefer a clear rule set for any beneficial project that comes out of the” interregional process.
MISO will spend the next two months preparing its overall cost allocation proposal for a FERC filing by the end of September. The RTO is open to holding a summer conference call that would invite stakeholders to offer minor suggestions for clarity, but it does not intend to open the proposal to any substantive change, Moser said.
MISO staff have spoken to SPP officials about the changes, which will not require a revision to the RTOs’ joint operating agreement because they only involve MISO’s regional cost sharing, Moser said. Meanwhile, the RTOs will work this summer on a proposal to similarly relax interregional project criteria in the JOA, which still mandates 345-kV and $5 million minimums. (See MISO, SPP Look to Ease Interregional Project Criteria.)
Moser said there was a “possibility” that FERC could have ordered MISO to lower the SPP thresholds as it did with PJM projects, if the commission had received a complaint.
“Looking at the direction we’ve seen so far, on the PJM seam, that seems like something FERC would support,” Moser said. “We have a pretty firm belief that if this issue was not addressed, it would get put in front of FERC.”
But Moser reiterated that consistency, not the threat of a FERC complaint, drove MISO’s decision.
Transmission Owners: Equal Treatment Unnecessary
But some stakeholders continue to question what would be a discrepancy between the voltage thresholds for MISO MEP projects and interregional projects with SPP. (See MISO Cost Allocation Plan Hits Interregional Differences.)
More than 20 MISO transmission owners joined in written opposition to the 100-kV threshold on interregional projects with SPP. They contend that there are differences between the PJM and SPP seams and that the two “should not receive equal treatment.”
MISO’s seam with SPP is longer and has lower load density than that with PJM, meaning generation can be situated far from load, the TOs have pointed out. Higher-voltage interregional projects are a better fit for those conditions, unlike the MISO-PJM seam where population density makes smaller transmission projects more worthwhile, they argue.
The TOs also note that MISO and PJM have been coordinating along their seam for about 18 years while the relationship with SPP is “less mature,” evolving as SPP integrated the Western Area Power Administration and Basin Electric Power Cooperative transmission systems in late 2015 and MISO integrated its MISO South region in 2013. “Congestion patterns along that seam are not well understood and are subject to change,” the TOs said.
But while acknowledging that the proposal wasn’t “universally liked,” Moser contends that MISO collected sufficient stakeholder feedback on regional cost allocation to move ahead with the plan.
“This has been a fairly long process. We’ve been working on this since 2015. We’re looking at what the new needs might be given our new footprint. … We think we’re putting together a package of reforms that best meets the needs of our footprint,” Moser said.
MISO also plans to conduct a general review of its overall cost allocation design three years after implementation, Moser said. The RTO will examine whether projects built under the new rules have benefits commensurate with cost allocation and examine any past proposed projects that appeared highly beneficial but still couldn’t qualify for cost allocation.
“There’s an understanding that needs will continue to change,” Moser said.
New Local Economic Project Type
MISO last week announced another new wrinkle for its cost allocation plan: a new project type that will be ineligible for regional cost sharing for the sake of clarity.
| MISO
Moser said the new category, “Local Economic Projects,” is meant for projects that demonstrate at least a 1.25:1 economic benefit but are below 230 kV. Such projects would have their costs allocated 100% to their local transmission pricing zone. Currently, these projects fall under an “other” category.
Moser said the category is needed to distinguish small economic transmission projects from small reliability-driven transmission projects. Today, most of MISO’s “other” category of projects are reliability-driven, with few small projects being built for economic reasons, he said.
Competitive Power Ventures, which last week celebrated the opening of its new 805-MW combined cycle gas-fired power plant in Oxford, Conn., would like to build more gas plants. But it said it is wary of subsidized competitors.
The company announced Thursday that is has begun selling power in ISO-NE from its Towantic Energy Center, which uses two GE Power 7HA.01 combined cycle, dual-fuel turbines, one of the most efficient designs in the world, with up to 64% efficiency.
CPV Towantic Energy Center in early May, with construction nearly complete. | CPV
The plant represents the 26th HA unit to go online, GE said. The HA series is air-cooled, which CPV says “saves as much as 90% of the water used by similar” steam-cooled designs. Poor sales of its previous steam-cooled H-class turbines prompted GE to switch to condensed air, which allows for a simpler configuration that is not only more efficient but more economic to construct as well, the company says.
A construction worker looks up at the plant’s air-cooled condenser, the design of which “saves as much as 90% of the water used by similar wet-cooled facilities,” according to CPV. | CPV
The turbines’ efficiency will give Towantic an advantage in ISO-NE’s energy market, said Tom Rumsey, CPV senior vice president of external and regulatory affairs. With no load growth in New England, new plants must be more efficient to be profitable, he said.
The plant officially began generating power May 21, just in time for the June 1 start of the 2018/19 capacity commitment period. CPV sold 750 MW of capacity into ISO-NE’s ninth Forward Capacity Auction in 2015.
It gets its fuel primarily from the Algonquin Gas Transmission pipeline and interconnects to the grid through Eversource Energy’s 115-kV Baldwin Junction-Beacon Falls circuit.
Rumsey said the company expects the plant to be a baseload resource, and it isn’t worried about there being gas shortages for the plant because it can also burn ultra-low-sulfur diesel fuel. In the 2014 polar vortex and this year’s bomb cyclone events, “it wasn’t that you couldn’t get gas. It was that gas was so expensive,” he said.
CPV is concerned, however, about state-subsidized resources disrupting the markets, Rumsey said. The company is looking to build more gas plants in New York, Illinois and New Jersey, all of which have enacted zero-emission credit programs for at-risk nuclear plants. They “represent the biggest challenge to the competitive markets since they began,” Rumsey said.
He cited the brief FERC and the Justice Department filed with the 7th U.S. Circuit Court of Appeals in the challenge over Illinois’ program, which argued that it was not pre-empted by the Federal Power Act under the Constitution’s Supremacy Clause. (See Analyst: FERC Asserts Role in Handling Nuke Subsidies.)
CPV also opposed PJM’s capacity market repricing proposals to address subsidies, instead joining Calpine and Eastern Generation to propose a “clean” minimum offer price rule applicable to all subsidized resources. (See Gas Gens Ask FERC for ‘Clean MOPR’ in PJM.)
“Accommodating these resources is the wrong way to go,” Rumsey said.
Combined with the Department of Energy’s latest plan to bail out uneconomic coal and nuclear plants, “it’s all coming to a head at FERC this year.”
