MISO’s proposed three-year forward auction in its retail-choice areas attracted more than 40 comments and protests, with critics calling the proposal costly and ill-conceived.
Executive Director of Market Services Jeff Bladen has said the proposal, which would take effect in the 2018/19 planning year, is designed to provide equally valued capacity from both merchant generators and regulated utilities (ER17-284). The comment period on the FERC filing closed last week; MISO expects a decision from the commission by March. (See MISO Files Forward Capacity Auction Plan with FERC.)
Among critics of the plan are MISO’s Market Monitor, which says the auction, with a sloped demand curve for competitive retail areas, will not accurately represent the marginal value of capacity. “The proposal is highly likely to result in unstable prices that are either too low to retain existing supply that is needed or excessively high, attracting new resources that are not needed,” Monitor David Patton said.
The Brattle Group’s sloped demand curve in red | The Brattle Group
In his protest, Patton included a proposal for a two-stage prompt auction for FERC consideration. Competitive retail supply would still use a sloped demand curve and regulated utilities would use a vertical demand curve.
Premature?
The Illinois Office of Attorney General objected to the bifurcation of the capacity market. “By separating Illinois from the rest of MISO through the use of a three-year forward auction, as opposed to the prompt auction applicable to the remaining 90% of MISO load, Illinois consumers would pay higher prices for capacity,” the office said.
Watchdog group Public Citizen said MISO did not have enough conversations with state lawmakers on their resource adequacy plans before making the filing, which he said will increase the cost to ratepayers. “This whole filing is a solution in search of a problem,” Tyson Slocum, the group’s energy program director, said in an interview. “That’s the whole problem with holding stakeholder meetings, it’s whoever shows up.”
“At a minimum, FERC should suspend issuing an order in this docket until the legislative actions of Illinois and Michigan to address long-term resource adequacy can be independently analyzed and incorporated into this docket,” Public Citizen wrote, referring to Illinois’ financial support for Exelon’s Clinton and Quad Cities nuclear plants and energy legislation approved by Michigan last week. (See Illinois Lawmakers Clear Nuke Subsidy and related story Michigan House Passes Energy Bill, Preserves RPS, 10% Retail Choice Cap.)
‘Blind Faith’
The Coalition of MISO Transmission Customers and the Illinois Industrial Energy Consumers filed a joint protest asking FERC to reject the filing because MISO did not fully include the results of The Brattle Group’s study, which the RTO relied on to justify the forward auction. The filing instead contained a MISO description of the study, demand curve diagrams, presentations made to MISO stakeholders by Brattle and testimony from three Brattle employees.
“The commission should not accept, on blind faith, that the Brattle study appropriately supports MISO’s endeavors,” the groups said. They also challenged Brattle’s analysis as biased. Alliant Energy and others challenged MISO’s reliance on the results of the OMS/MISO survey, which forecasts generation shortfalls in 2018. The company said the survey is not a “complete reflection of the future capacity needs in the MISO region.”
Results of the 2016 MISO-OMS Survey | OMS, MISO
A group of transmission-dependent utilities in the Midwest — Madison Gas and Electric, Missouri Joint Municipal Electric Utility Commission, Midwest Municipal Transmission Group, Missouri River Energy Services and WPPI Energy — argued the proposal is “fraught with inconsistencies, errors and ambiguities” that could cause the provisions of the forward market to bleed into noncompetitive areas. The group asked FERC to reject it.
Interference
Power marketer Direct Energy, which offers competitive natural gas plans for Michigan ratepayers in Consumers Energy and DTE Energy territory, objected to MISO’s Tariff revisions to allow retail-choice states to opt out of capacity provisions via the auction design’s prevailing state compensation mechanism. The company is challenging the filing on the basis it “impermissibly” interferes with wholesale markets.
Ron Carrier, Direct Energy’s director of government and regulatory affairs, said he isn’t sure if the limited amount of participating generation and load from retail choice areas would make the forward auction economic, although he said forward auctions in general “allow some price certainty into the future.”
“Our main concern is the state shouldn’t be granted authority over something FERC should have authority over,” Carrier said.
MISO Transmission Owners said they had no opinion on the filing, but they asked FERC to make sure the RTO does not intrude on state jurisdiction over resource adequacy. They also asked FERC to require MISO to give annual reports that analyze the impact of the forward auction on the entire footprint for the next three years.
The Organization of MISO States also argued for protecting state jurisdiction, but the group took a step further, asking FERC to reaffirm the stance it took in a 2012 order that capacity markets are not necessary in vertically integrated areas (ER11-4081-001). “The [competitive retail solution] should not be viewed as the default means to maintain [resource adequacy] within retail-choice areas. It is imperative that state regulators maintain maximum flexibility and authority over the resource adequacy decisions within their jurisdiction,” OMS wrote.
AUSTIN, Texas — ERCOT celebrated a trio of memorable anniversaries Tuesday by getting part of the band back together for its Annual Membership Meeting.
ERCOT, which became the first ISO in the U.S. 20 years ago, also marked its 15th anniversary as the single control area for the state’s competitive market and the 75th anniversary of the Texas Interconnected System, when the state’s utilities banded together to ship power to the shipyards and refineries on the Gulf Coast during World War II.
“We remain the only independent, state-controlled system operator,” ERCOT CEO Bill Magness told the membership, “and we like it that way.”
To mark the occasion, ERCOT unveiled a historical video and brought back its first Board of Directors chairman, former Oncor president Mike Greene, to introduce one of the primary architects of the state’s electric restructuring bill as the meeting’s guest speaker. Steve Wolens, a retired 12-term Democratic state representative, worked with Republican State Sen. David Sibley to push Senate Bill 7 through the Texas Legislature in 1999 against only four opposing votes.
Greene name-dropped former Texas PUC commissioner and current ERCOT Director Judy Walsh, former FERC and PUC commissioner Pat Wood and others from the past before eventually introducing Wolens.
“My role has been reversed. I’m standing at the microphone, and Steve is in the audience wondering what I’m going to say,” Greene said, before taking a pause. “I’m actually starting to enjoy this.”
“It’s an honor to be back,” said Wolens, pegged by Texas Monthly in 1999 as the “Intellectual Gladiator” for his legislative work. The magazine noted Wolens “produced an electricity deregulation bill that won the support of consumers, environmentalists and utilities.” When the bill passed, Wolens’ colleagues honored him with a standing ovation.
Wolens, who also led a push to reform ethics laws before retiring from the Legislature in 2005, was recently named by Texas House Speaker Joe Straus to serve on the Texas Ethics Commission. His term will last until November 2019.
Recounting SB7’s history, Wolens said “there was no reason to restructure in the 90s,” given Texas had the lowest electric rates in the country. However, the state also had some of the highest bills ($1,064 annually for the average residential customer, he said) and a reserve margin that was predicted to drop below 8% by 2004.
“And here we were in Texas, boasting about the state and boasting about our growth.”
Wolens said the inability to get energy companies to invest and Ohio-based American Electric Power’s announcement that it would acquire Dallas-based Central and South West Corp. in 1997 gave the restructuring legislation a boost.
“We had to bring more certainty, more reliability to the market,” he said. “Our goal was to reduce the risk to private investment and do whatever we could to keep the local companies we had.”
The key to SB7 was its price-to-beat (PTB) measure, Wolens said. The bill required incumbent utilities to take a 6% rate cut and hold that for three years, or until they lost 40% of their previously regulated market share.
This was to discourage what Texas had seen in other restructured markets, Wolens said. “We had seen it all,” he said, referring to trucking, banking and airline deregulation. “Once you deregulate, the incumbent in that particular industry, the powerful player, cuts rates and drives everyone else out of business. The three years allowed new competitors to come in.”
And that’s exactly what happened in the ERCOT market. Wolens noted nearly 200 residential retail electric providers currently operate in the state, offering in his estimation some 2,000 plans to choose from. The ERCOT market will record its lowest average energy prices this year ($24.64/MWh) since the market opened ($25.64/MWh in 2002).
“The PTB was the DNA of the entire bill,” Wolens said.
SB7 and the ensuing $7 billion Competitive Renewable Energy Zone transmission project, which connected windy West Texas with the growing urban population centers to the east, has given the state almost 18,000 MW of installed wind capacity. If the Lone Star State were its own country, it would rank sixth in the world in wind capacity.
The Texas market is so strong, Wolens said, it will survive a future that may include the country’s withdrawal from the Paris Agreement, the loss of wind and solar tax credits and “installing a climate denier” at EPA.
“All those issues aside, it’s not going to make a difference because the market is vibrant,” he said. “It’s exactly what we hoped for in 1999.”
Magness Celebrates ERCOT’s Achievements
Magness listed ERCOT’s 2016 achievements before the luncheon began, including maintaining a reliable system and efficient market, upgrading the Energy Management System, revising the criteria for reliability-must-run studies, completing transmission improvements in the Rio Grande Valley and integrating wind generation.
The ERCOT market generated more than 15,000 MW of wind energy for the first time in 2016, setting a new record of 15,033 MW in November. It also recorded three new marks for wind penetration during the year, topping out at 48.28% of load in March.
Magness credited stakeholders’ collaboration with staff and their forward thinking with making the records possible.
“We’ve always said if we can see it, we can integrate it,” he said. “When we hit 15,000 MW of wind and high penetration levels, people asked, ‘How do you do that? How is that possible?’ It’s possible because in ERCOT, when those things start to happen, we talk about it. That’s the value of thinking ahead while still in real time.”
ERCOT also set a new system peak (71,110 MW on Aug. 11), two monthly demand highs (during a warmer-than-normal September and October) and a new weekend peak (Aug. 7). The ISO’s annual Capacity, Demand and Reserve report released Thursday foresees demand rising to more than 77,000 MW by the summer of 2021. (See related story, ERCOT Sees Increased Load Growth, Shrinking Margins.)
Increasing Demand Boosts Finances
The high demand in the fall means the ISO should go into 2017 — the second year of its two-year spending plan — with net revenues as much as $13 million above budget. Also helping ERCOT’s finances are savings in resource management costs (primarily staffing management and project work), expected to come in $3.9 million under budget, and computer hardware purchases, at $1.9 million under budget.
“We challenged ourselves as a management team to maintaining some flexibility for ourselves, going into [the] second year,” Magness said. “We’re committed to keeping a flat [administrative] fee for at least two years. Keeping that budget discipline is going to be really important in maintaining that. One year in, we feel like we’re in a pretty good place.”
Magness also said ERCOT’s “technology refresh” to update aging computer technology is well underway. The four-year project began in 2015 and is forecast to come in at or under its $48 million budget. Magness said 60% of the contracts are locked in place, with 21% of the hardware already deployed.
Board Passes Transmission Planning Change
The board easily passed the only contested revision request before it, a planning guide change revising the criteria used to determine the need for new transmission projects that faced some pushback at the Technical Advisory Committee earlier this month. (See ERCOT Addresses Transmission Planning Challenges with New Rule.)
Valero Services’ Jack Durland, representing the Industrial Consumer sector, cast the lone dissenting vote. He questioned the planning guide revision request’s (PGRR) “bounded higher of” load forecast methodology, in which ERCOT will compare its load forecast with the summed bus-level forecast for each weather zone, and the need for two additional staffers to work on the planning process.
“Does one size fit all the [ERCOT] regions?” Durland asked. “If it doesn’t, we’ll end up with constraints, specifically in Houston. We’d like to see maybe some backcasting to understand this higher boundary methodology actually does fit most scenarios.”
PGRR042 defines considerations for selecting the most appropriate demand forecast in planning studies and how to model certain generation resources, such as mothballed units or those that can be also be connected outside the ERCOT region, in planning cases. It also describes how to incorporate new generation units in sensitivity analyses when they have interconnection agreements but have not met all the requirements to be included in transmission planning studies.
Warren Lasher, ERCOT’s senior director of system planning, told the board the ISO will “grey box” the PGRR’s language before formally codifying it for 2018. In the meantime, he promised staff would work closely with stakeholders throughout next year “to ensure we have an appropriate mechanism to make sure we have adequate transmission.”
“We have been having discussions with stakeholders about doing backcasts for the forecasts in the planning working groups,” Lasher said, “and we will continue to have those discussions … to make sure that the needs of customers, especially in the Houston region, and other regions of the state are met.”
“I can tell you with confidence that we can move around folks,” Magness said, addressing the staff additions. “Two [full-time employees], we can handle.”
Magness reminded stakeholders that PGRR042 came from a Public Utility Commission of Texas request to re-evaluate ERCOT’s planning process, part of the commission’s approval order for the Houston Import Project, a $590 million initiative due to be completed by summer 2018.
“This planning guide became the vehicle for the analysis,” he said. “Our folks feel comfortable they have sufficient flexibility and options for making sure the change works. It was a successful accommodation … of something we could work with, and we felt like folks in the market could work with, as well.”
New Board, TAC Members Approved
The ERCOT board approved Calpine’s Randy Jones and Source Power & Gas’ John Werner as new members of the board for 2017. The two, who served as alternates last year, will represent the Independent Generator and Independent Retail Electric Provider segments, respectively.
Jones is switching places with E.ON Climate and Renewables’ Kevin Gresham, while Werner replaces Direct Energy’s Read Comstock.
The board has yet to fill the unaffiliated position vacated by Jorge Bermudez, who resigned from the board in October when his pending marriage created a conflict of interest. (See “ERCOT’s Bermudez Resigns from Board Position,” ERCOT Briefs.)
“We were distressed to find out you love someone more than us,” joked Board Chair Craven Crowell, before presenting Bermudez with a resolution honoring his service.
The board also approved the Lower Colorado River Authority’s John Dumas and Golden Spread Electric’s Mike Wise (Cooperatives), SESCO’s David Hastings (Independent Power Marketers) and Direct Energy’s Sandra Morris and Noble Americas Energy Solution’s Clint Sandidge (Independent Retail Electric Providers) as new TAC members.
Ancillary Service Changes, NPRRs Sail Through
The directors unanimously approved “very minimal” changes to the minimum ancillary service requirements, after two years of more substantial changes.
Staff limited its changes to regulation service. It proposed removing the exhaustion rate feedback metric from the regulation-procurement analysis, estimating five-minute net load variability by including solar generation and making annual updates to the 2013 General Electric study’s tables reflecting incremental installed wind generation.
The board also unanimously approved a clean Statement on Standards for Attestation Engagements (SSAE) No. 16 audit report, modifications to forms ensuring the credit worthiness of market participants and five changes to the 2016 list of key performance indicators used to drive organizational performance.
The board consent agenda, which passed unanimously, listed eight nodal protocol revision requests (NPRRs):
NPRR773: Broadens the scope of acceptable letter of credit issuers, allowing electric cooperatives to post letters from the National Rural Utilities Cooperative Finance Corp. with ERCOT.
NPRR783: Revises a requirement for an independent audit to confirm the consistency of ERCOT operations models. The change is to comply with NERC reliability standard MOD-033-1 requiring a documented data-validation process for power flow and dynamic models.
NPRR790: Adds phase angle equipment limitations to real-time monitoring, real-time assessments and operational planning analysis, as required by NERC standards. ERCOT will collect this information through the network operations modeling process.
NPRR791: Clarifies the initial estimated liability (IEL) description to specify that it is based on estimated sales between qualified scheduling entities; restores the IEL for traders (inadvertently omitted from NPRR741) and corrects errors to the minimum-current exposure formula mistakenly overwritten by NPRR743.
NPRR792: Aligns the nodal protocols with NERC’s definition for special protection system (SPS) and uses “remedial action scheme” and “automatic mitigation plan” in place of SPS for consistency purposes, when applicable. The approval resulted in the TAC conducting an email vote on a related nodal operating guide request, NOGRR164, which was approved Thursday, 21-0.
NPRR797: Creates a new report and display for the actual system load by forecast zone, similar to the capability for weather zones.
NPRR801: Revises the physical responsive capability (PRC) calculation to include all load resources and align operating reserve demand curve (ORDC) reserves with the PRC change. It also aligns the ancillary service imbalance settlement with the change to the ORDC reserves.
NPRR803: Removes un-codified language from NPRR439, which was approved four years ago to allow counterparties to increase their credit limit for the day-ahead market’s current day.
The Public Utility Commission of Texas wrapped up its 2016 open meeting schedule Friday by approving a rulemaking on interconnection agreements (IAs) for distributed generation and reports on electric market competition and alternative ratemaking mechanisms.
The distributed generation order allows the end-use DG customer to either be a party to the agreement or the “non-utility” party as the owner of the facility, the facility’s premises or the produced energy (No. 45078). The commissioners said they would have jurisdiction over IAs, but not over “any disputes between an end-use customer and a non-utility signatory to the IA.”
| ERCOT
Chairman Donna Nelson dissented from the order. She had expressed concerns last month over the PUC’s inability to help solar energy customers seeking redress from the commission over potential “bad actors.”
2017 Competition Report
The PUC approved its “2017 Report on the Scope of Competition in Electric Markets in Texas” (No. 45635), accepting Commissioner Ken Anderson’s suggestion that the report repeat previous recommendations to the Texas Legislature calling for:
The repeal of state law establishing natural gas as “the preferential fuel” for electricity generation and creating natural gas energy trading credits. “Because natural gas-fueled facilities have been the most commonly built new generation in Texas for many years and are expected to continue to be, there is no need to establish incentives for natural gas generation,” the report says.
The repeal of state law requiring the installation of 5,880 MW of renewable energy by 2015, a mandate that was met in 2008.
Authorization for the PUC to issue advisory opinions on electric industry issues. “Providing clarification to a company concerning issues such as the purchase of assets or the acquisition of another company could allow it to avoid expensive regulatory proceedings, without impairing the commission’s authority,” the report says.
Authorization for the PUC to use outside consultants, auditors, engineers or attorneys to represent the state before ERCOT, as it is currently permitted to do in FERC proceedings.
| ERCOT
The commission also approved its report on alternative ratemaking mechanisms, which concludes that the current ratemaking system is not “in need of major revision” and that periodic rate proceedings using “streamlined recovery mechanisms” is “an efficient and effective way to ensure that electric rates are just and reasonable” (No. 46046).
The report does suggest the Legislature address concerns about vertically integrated utilities operating outside the ERCOT service area, whose key financial metrics “have lagged in comparison to those of the ERCOT utility companies,” with reported rates of return consistently falling below PUC-authorized levels. The report says the utilities’ returns have been hampered by “regulatory lag” in recovering capital investments.
Both reports will be sent to the Legislature, which convenes Jan. 10.
SPP and MISO continue to study seven potential joint transmission projects across their seam, but much of their focus is now turning to developing the 2017 joint study by next April.
Staff from the two RTOs told their Interregional Planning Stakeholder Advisory Committee on Friday that they have already begun to put together a work plan that includes a study scope, timeline and Tariff and joint operating agreement changes needed to accommodate the study.
RTO staffers met in October at MISO’s Louisiana offices to lay out a high-level framework for the study, which would end in 2019. Staff hope to improve coordination of their regional processes and sharing of regional planning assumptions.
“As we develop our regional plans individually, we would start developing regional candidate projects,” said MISO’s Davey Lopez, advisor of planning coordination and strategy. “Both parties agreed we want to plan for the best value, which may not be the cheapest solution.”
Lopez and his counterpart, SPP Interregional Coordinator Adam Bell, said their boards would be able to evaluate the regional projects and interregional projects on the same timeline, eliminating one of the stakeholder complaints in recent years.
“One of major hurdles we have is the timing of the regional processes,” Bell said. “Both sets of stakeholders will be able to look at regional and interregional plans at the same time, and pick the best project. One is not winning out by virtue of finishing first.”
| MISO-SPP IPSAC
Lopez told the IPSAC that the 2017 study will begin as the 2016 coordinated study process ends, using the latter’s study results as an input. “We’d like to ramp it up in April 2017, hit the ground running and jump right into another study,” he said.
The 2016 analysis has resulted in seven potential projects, primarily in the Dakotas and along the Kansas-Missouri border. Lopez said the list may be reduced further but that it is “good information for the 2017 study.”
Three of the projects would solve market-to-market flowgates, which have resulted in payments from MISO to SPP totaling $2.75 million.
Nine entities have submitted 32 solution ideas to address the project needs posted in October. Several of the solutions were duplicates of, or similar to, others.
Final study results will be shared with the IPSAC during its next meeting, tentatively scheduled for February.
Competitive Tx Process Task Force Suggests Criteria Change
The Competitive Transmission Process Task Force completed its review of the documents to be used by transmission developers bidding on projects through SPP’s Order 1000 competitive process.
Stakeholders determined that the inflation rate (2.5%), discount rate (8%) and operations and maintenance escalation rates should be prescribed by SPP in its solicitation.
Duke Energy’s Bob Burner proposed the group use a “pass-fail” grading system rather than point-scoring for certain qualitative items evaluated by the industry expert panel (IEP).
Staff noted the Tariff language gives the IEP sole discretion in determining how it scores competitive proposals but agreed to recommend to the panel which items should fall into the pass-fail category. Staff will draft a revision request that would remove certain pass-fail items from the solicitation process. Points allotted to the scoring categories would not be impacted.
The task force will meet again Jan. 9, in preparation for the Markets and Operations Policy Committee meeting two weeks later.
Gas-Electric Coordination Report Filed with FERC
SPP on Friday filed with FERC its first informational report on the RTO’s efforts to coordinate gas and electric scheduling practices. Staff shared a draft of the report two weeks ago with the Gas-Electric Coordination Task Force. (See “SPP to Deliver Positive Report to FERC on Gas-Scheduling Practices,” SPP Briefs.)
The report was filed to comply with FERC Order 809, which required RTOs to improve the alignment of their market schedules with those of interstate gas pipelines (RM14-2). SPP’s changes took effect Sept. 30.
SPP Sets New Winter Peak Mark
SPP set a new winter demand peak earlier this month, hitting 37,780 MW at 7:21 a.m. Dec. 9. The mark broke the previous record of 37,412 MW set Jan. 18.
FERC on Thursday declined to grant a solar developer’s petition to enforce the Public Utility Regulatory Policies Act in Montana, where state regulators in June suspended a utility’s tariff for qualifying solar facilities above 100 kW (EL17-5).
As a result, solar developer FLS Energy can sue the Montana PSC or NorthWestern Energy in federal court, if it chooses.
FLS Solar’s Fairmont Solar Farm in Fairmont, NC | FLS Solar
But FERC did find that the Montana Public Service Commission violated PURPA by requiring that qualifying facilities have power purchase agreements and interconnection agreements with utilities to form a legally enforceable obligation.
The Montana PSC voted 3-2 to suspend NorthWestern’s tariff, finding that the avoided cost rate the utility was required to pay QFs was too high. The PSC grandfathered in facilities that had completed their agreements prior to the date of the order, June 16.
In its complaint filed in October, FLS said it had completed PPAs, but not interconnection agreements, for 14 QFs in the state. It accused NorthWestern of slow-walking the interconnection process while it lobbied the PSC for the tariff suspension.
As a result of the suspension, the North Carolina-based company said it stands to lose $750,000, as it would have to negotiate new PPAs with NorthWestern, likely at a lower rate.
Under PURPA, utilities are obligated to purchase electricity from QFs, but each state can determine when a legally enforceable obligation begins, as long it does not conflict with FERC’s regulations.
“We find that, just as requiring a QF to have a utility-executed contract, such as a PPA, in order to have a legally enforceable obligation is inconsistent with PURPA and our regulations, requiring a QF to tender an executed interconnection agreement is equally inconsistent with PURPA and our regulations,” FERC said. “Such a requirement allows the utility to control whether and when a legally enforceable obligation exists — e.g., by delaying the facilities study or by delaying the tendering by the utility to the QF of an executable interconnection agreement.”
FERC’s order did not comment on the merits of the PSC’s suspension itself, which FLS had also requested. The commission last month tossed out the same complaint by solar advocates, saying only QFs can seek PURPA enforcement. (See FERC Rejects Complaint on Montana Solar; 2nd Case Pending.)
In a footnote, however, FERC said, “When a state commission believes that a previously determined avoided cost rate is no longer an accurate measure of a utility’s avoided costs, the appropriate response is not to establish a standard for a legally enforceable obligation that is inconsistent with PURPA and the commission’s regulations under PURPA, but instead to determine a new avoided cost rate that better reflects the utility’s avoided costs.”
“This is a great win for our company and the QF community,” Steven Levitas, vice president of business affairs and general counsel for FLS, said in an interview. “We were confident that the Montana commission’s [legally enforceable obligation] was inconsistent with PURPA.”
Levitas said that the company hopes the PSC will change the standard to comply with PURPA. Otherwise, he said, the company is prepared to take it to court.
FERC did not address FLS’s accusation that NorthWestern violated interconnection procedures, saying that, as a Federal Power Act matter, it was beyond the scope of the complaint.
MISO engineer Adam Solomon told the Planning Subcommittee Dec. 13 that while it is possible to make joint powerflow and economic models, they would not be based on a set of common assumptions. “We think we can make assumptions from both MISO and PJM using separate sensitivities,” Solomon said during a Dec. 13 Planning Subcommittee meeting.
In an April 21 order, FERC directed MISO and PJM to explore with stakeholders the possibility of a joint model that uses identical model assumptions and criteria for regional transmission planning processes (EL13-88).
MISO has maintained that a joint model would be difficult to accomplish, as it studies two, five and 10 years into the future, while PJM studies five, seven and eight years ahead. In addition, MISO uses local balancing areas for dispatch, while PJM uses a single balancing area. PJM also does not forecast generation retirements, while MISO includes forecasted generation retirements in its futures modeling.
The RTOs’ Oct. 25 informational filing to FERC detailed their reasoning as to why a single set of assumptions was infeasible. The RTOs told FERC that “most stakeholders agree with the RTOs’ position that requiring the RTOs to adopt the same assumptions and criteria when conducting regional transmission planning would create significant challenges, including substantial revisions to each RTO’s robust regional planning processes and cost allocation methodologies.”
But Northern Indiana Public Service Co., whose complaint prompted the FERC order, said in comments to MISO that the two RTOs need a joint model because their different study processes lead to projects being categorized inconsistently (e.g., reliability, public policy or economic). “However, tests of NERC reliability thermal or voltage violations have less disparity between RTOs. Reliability models typically have similar topology, base resource modeling and demand assumptions,” the utility said.
In a Nov. 15 filing with FERC, NIPSCO accused the RTOs’ of ignoring the commission’s directives. “The pattern of behavior shown by the RTOs … demonstrates that [they] are committed to interpreting the April 21 order as empowering the RTOs to eliminate the Coordinated System Plan Study for interregional planning, which is plainly contrary to the spirit, if not the letter, of the commission’s orders,” NIPSCO said.
At the Dec. 14 Planning Advisory Committee meeting, Adam McKinnie, chief utility economist for the Missouri Public Service Commission, asked MISO to create a common interregional model before it embarks on more studies, such as the MISO-SPP joint study running through the first quarter of 2017. (See MISO-SPP Study Scope Finalized; Stakeholders Doubtful Projects will Result.)
Ameren said MISO and PJM should use the same base models for system load conditions, such as light load, summer shoulder peak, winter peak and summer peak conditions. Other members, including Great River Energy, ITC Holdings, WPPI Energy and American Transmission Co. said they understood MISO’s reluctance to adopt identical assumptions.
Retirement Risk, Deliverability Measured for MTEP 17
MISO’s deliverability analysis for the 2017 Transmission Expansion Plan will identify transmission constraints and possible violations on a five- and 10-year horizon, MISO engineer Carlos Bandak said.
Bandak said the deliverability analysis will determine whether groups of generators in an area can operate at maximum capability without being “bottled-up.” The information is used in granting or denying network resource interconnection service (NRIS).
After stakeholders expressed concerns that MISO would use historical limits for the deliverability analysis, Bandak reassured stakeholders that the RTO each year produces fresh results and does not test values from previous years, although it will not test above already-granted NRIS levels for existing generators.
Stakeholders argued that MISO might test above the approved NRIS level to a generator’s potential capability.
“We’re not going to use the deliverability study to grant incremental capability. That would be too complicated,” said MISO Director of Planning Jeff Webb, adding that the generator interconnection queue is the arena where owners should go if they want to be granted more generating capability.
“All we’re doing here is making sure that generators continue to be deliverable through their interconnection service. There’s nothing really new or strange here,” Webb said.
MISO also will incorporate a retirement sensitivity analysis in MTEP 17’s annual reliability assessment.
MISO will perform 10-year-out sensitivity analyses for age-based retirements modeled in MTEP 17’s “existing fleet” future. By 2027, all coal units 65 years or older and all gas and oil units 55 years or older will be assumed to have been retired.
In 10 years, the MISO footprint will contain 6.4 GW of at-risk coal generation and 10.7 GW of susceptible natural gas and oil generation. The RTO places the current average age of its coal fleet at 38 years and its natural gas and oil fleet at 22 years.
MISO engineer Anton Salib said the RTO would build models until March and test them through May, with preliminary findings released in June. A full report is expected by September.
Ginger Hodge of Customized Energy Solutions asked if results would be included in the MTEP 17 Market Congestion Planning Study. Salib said the findings may inform the study, but information from a variety of analyses would also be used.
By the end of 2016, MISO expects $2 billion more of MTEP 15’s transmission projects to be in-service. Project candidates for MTEP 17 are to be submitted by Sept. 15, 2017. Solomon said the overall scope of MTEP 17 studies will be completed by the end of this month.
In response to stakeholder feedback on the MTEP 17 scope, MISO told the Dec. 14’s Planning Advisory Committee it would consider removing independent load forecasting from the MTEP process because it is not governed by the RTO’s business practices. Purdue University’s State Utility Forecasting Group currently estimates MISO’s power demand. The PAC could weigh in on the future of the forecasting after the new year.
The Western Energy Imbalance Market featured prominently in two proposals approved by the CAISO Board of Governors during its Dec. 15 meeting.
| Trimark Associates, Inc.
One measure will enable more CAISO market participants to meter their own resource performance data and submit it to the ISO for billing. The measure was proposed largely to help reduce costs for participating in the ISO’s markets, according to a CAISO memo to the board.
“Metering is a significant cost for market participants both in our base market and the Western Energy Imbalance Market,” CAISO CEO Steve Berberich said. “Our goal is to reduce the barriers of entry to [the EIM], and metering is part of that.”
CAISO currently obtains settlement-quality meter data through two different processes, depending on the type of resource. In one process, the ISO directly polls a resource’s meter and performs the validation, estimation and editing procedures necessary to achieve settlement. In the other, a scheduling coordinator is authorized to perform those settlement functions itself and submit the results to the ISO.
The proposal approved by the board extends eligibility for scheduling coordinator metering to certain resources that are currently required to be metered by the ISO.
Eligibility will now be open to energy- or ancillary services-only generators, distributed energy resources operating under a participating generator agreement and “intraties” — links between two utility distribution company service areas that can function as a proxy resource for market purposes.
The change will allow market participants to avoid the costs associated with using a CAISO-approved meter, meter reprogramming, inspection by an authorized inspector and the telecommunications equipment needed for the ISO to poll the data.
Scheduling coordinators applying for self-metering will be required to submit a settlement-quality meter data plan for all resources they represent to ensure accuracy in settlements.
That provision will apply to all new resources entering the market, regardless of resource type. It will also cover any new ISO resources that were previously EIM resources not subject to the requirement.
But the data plan requirement will not apply to scheduling coordinator metered resources already operating in the market.
“Existing market participants will have no additional requirements imposed on them as a result of this proposal,” said Tom Flynn, CAISO manager of infrastructure policy and development.
The measure also creates some uniformity in reporting by requiring all new generators in the ISO or EIM to submit meter data in five- or 15-minute intervals. Under current practice, ISO resources can choose break down their data submission into five-, 15- or 60-minute intervals, while EIM participants are restricted to five-minute reporting.
“For EIM participating generators, this represents a potential cost savings by avoiding the need to reprogram existing meters already capable of submitting meter data in 15-minute intervals,” the ISO said.
Kristine Schmidt, chair of the EIM governing body, expressed appreciation for the ISO’s revised approach to metering.
“This is very important for our EIM entities who have a significant number of meters that would otherwise have to be changed out,” Schmidt said.
“This seems like a win-win all around,” ISO board member Angelina Galiteva said in voting for the proposal. “This one is easy.”
Guidance Document Approved
The board also voted to approve the EIM’s “guidance document,” a set of procedures outlining how ISO staff should interact with EIM representatives and participants. The document sets out the timeframes in which CAISO staff will notify the governing body about ISO initiatives and explains the processes by which governing body members and EIM participants can provide feedback on proposed policy changes that affect the market.
“What the guidance document does is take all those rules — and establishes a process for implementing them,” said Dan Shonkwiler, CAISO general counsel.
Most significantly, the document provides solutions to the overlapping authority between the ISO board and the EIM governing body resulting from the EIM’s delegation of a portion of its authority over Federal Power Act Section 205 filings to the ISO. (See EIM Leaders OK Governance ‘Guidance’ Proposal.)
While the EIM governing body voted earlier this month to approve the guidance document, CAISO’s Tariff requires the board to formally approve any proposals — including those solely affecting the EIM — that alter the Tariff.
“I think this is an important step forward,” board member David Olsen said. “It really helps to clarify the scope of responsibility of the EIM board.”
CARMEL, Ind. — MISO planners approved an expedited project request in northeast Arkansas and are evaluating three others in Michigan, officials told the Planning Advisory Committee last week.
The $3 million Hickman Central project, submitted by Arkansas Electric Cooperative Corp. in October, will include a new substation, a quarter-mile line to connect it to the Dell-Blytheville North 161-kV line and two 161/345-kV transformers, said Edin Habibovic, manager of expansion planning in MISO South.
The Little Rock-based cooperative said the improvements are needed by October 2017 to accommodate about 35 MW of new industrial load. It said getting approval under the 2017 Transmission Expansion Plan in December 2017 would be too late.
MISO recommended that AECC begin work on the project “as needed” to meet the in-service date in less than 10 months and said the project would be formally included in MTEP 17.
The RTO also received three expedited review requests from ITC Holdings’ Michigan Electric Transmission Co. on Nov. 30:
A new 120-kV substation and 2 miles of double circuit 120-kV lines to handle an added 6 to 10 MVA in northern Michigan;
A new 120-kV substation and 0.1 miles of underground cable to serve 5 MW of new DTE Energy load in Detroit; and
A new 138-kV substation to serve 35 MW of new Consumers Energy load near Grand Rapids, Mich.
MISO said it is performing an independent reliability analysis “to determine that the projects [do] not cause any harm to the system.” The RTO plans to schedule a Technical Studies Task Force meeting in January to discuss results, said Senior Manager of Transmission Expansion Planning Thompson Adu.
After seven years in the PAC chair, American Transmission Co.’s Bob McKee has announced he will not seek re-election.
MISO PAC Liaison Jeff Webb called him the “PAC Man” and presented him with a Pac-Man themed blanket. “It is in fact, sadly, game over,” Webb joked.
During his tenure, McKee oversaw MTEPs from 2010 to 2016. In parting words, he encouraged stakeholders to “take stock” and be actively involved in MISO’s planning process.
ITC’s Cynthia Crane will take over next year as chair.
VALLEY FORGE, Pa. — PJM’s proposed timeline for reviewing tie-line requests will need another round of revisions before members are comfortable with endorsing it.
Two clarifications precluded members from bringing it to an endorsement vote at last week’s Planning Committee meeting. The first concern was an implication that the applicant must present their request at a meeting of the System Operations Subcommittee’s transmission owners group (SOS-T) following PJM’s legal and technical review. The second issue was the timeline’s awkward construction, in which it counts down to a FERC filing date and then counts down again to an in-service date.
“We thought it was valuable, but if it’s causing issues, we can remove it,” PJM’s Sue Glatz said. She went on to request an endorsement vote with the understanding that the clarifications will be made.
Stakeholders questioned PJM’s pressure to secure approval despite reservations.
“It’s essential that these documents be clear and concise. I’m not wishing this on anyone, but there is the possibility that some of us might not be around to interpret them,” American Municipal Power’s Ed Tatum said.
| PJM
PJM’s Paul McGlynn countered that the process has been going on for quite some time. “We’ve been at it for four months now,” he said.
Project-Selection Guidelines Criticized as Too Subjective
PJM unveiled guidelines for how it will select market efficiency projects, noting a “bright line” criterion that it must relieve at least one economic (capacity or energy) constraint. Projects also must clear a benefit/cost ratio of 1.25:1 and proposals with estimated costs of more than $50 million will be subject to an independent review.
John Farber of the Delaware Public Service Commission questioned what he called PJM’s “market efficiency at any cost” metrics and asked that it increase its focus on gathering “objective data to move this from a subjective to an objective process” going forward. He said PJM’s analysis is subjective and that cost containment caps are not a “panacea.”
PJM’s Asanga Perera said congestion created by any outages needed to complete a proposed project would be factored into decisions if it’s useful, but that it’s “tough” to include short-term factors and a “one-time thing” like an outage into a 15-year analysis.
“I think what we’re suggesting with some of these slides is that a project without outage congestion might be a better choice,” McGlynn said.
PJM will publish the guidelines, which will be effective for the 2016/17 transmission planning cycle, on the market efficiency web page.
New Forecast Sees Further Load-Growth Reductions
PJM is again reducing its load growth projections due to the economic outlook and increased efficiency.
In its preliminary 2017 forecast, expected summer load for 2020 dropped 2.1% compared to last year’s forecast, while that for 2022 was down 2.9%. The winter 2020/21 forecast dropped 2.6% and 2022/23 was down 3.5%. 2020 was chosen for comparison because it’s the next year for the Base Residual Auction; 2022 is the year used in the Regional Transmission Expansion Plan study.
Analysis Needed to Answer Winter Resource Adequacy PS
Work is being done to assess how well it processes all factors, including how to quantify the operational risks of activities such as transmission outages and generator maintenance.
“Our suggestion is going to be that PJM take the next two or three months to assess internally,” he said.
He expected to have more information for March’s Planning Committee meeting.
‘Immediate Need’ Designations Questioned
At the meeting of the Transmission Expansion Advisory Committee, stakeholders questioned PJM’s determination of “immediate need” for several transmission reliability projects and criticized the decision not to open them to competitive bidding.
In particular, an American Electric Power project in northeastern Indiana raised eyebrows. The company says an outage of its South Butler-Collingwood 345-kV line would result in the loss of more 300 MW of load.
One fix, estimated at $76.5 million, would involve a new 345-kV switching station and a new double-circuit 345-KV line of 17 miles. PJM said it favors an alternative proposal from AEP estimated at $107.7 million because it would also address aging-infrastructure concerns.
PJM’s recommendation rankled some members, who felt the project could have been identified earlier to allow for competitive bidding. Some also questioned including costs for local infrastructure that they said shouldn’t be allocated throughout the RTO.
Five transmission towers along the route are in immediate need of replacement, 79 will need to be addressed within three years and another 22 will need to be fixed soon thereafter, according to AEP’s assessment.
Sharon Segner of LS Power questioned PJM’s findings on two projects it plans to award to Dominion, the incumbent transmission owner, based on immediate need. According to Dominion’s proposal, the projects aren’t slated to be completed until 2021, which is beyond PJM’s definition for an “immediate need” project, Segner said. She suggested opening a 30-day window for competitive transmission developers like her company to propose alternatives.
“Right now, the incumbent transmission owner cannot meet it in three years. Therefore, it would seem to me the right thing to do would be to see if anyone can meet it in the proposal window,” she said.
PJM’s Steve Herling said that would create months of analysis and third-party verification for PJM that would only delay AEP from completing the project.
“We’ve already considered all of these factors, and what we have here is our decision. If you take exception to our decision, you can communicate it to the board,” he said.
PJM staff also pointed out that a recent FERC docket offered stakeholders the opportunity to raise these concerns. The commission’s July order in that case made clear that the definition is based on the date of need, not the in-service date (ER16-736, EL16-96). (See FERC Rejects PJM Cost Allocation on Dominion Project.)
PJM Review of Artificial Island Bid Elements Completed
“There may be benefits to installing the optical ground wire and new relay, but that scope of work would not directly address the operational performance issue,” McGlynn explained.
An OPGW serves as both a ground and a telecommunications link. PJM determined that although high-speed relaying using such wires would improve the clearing times for line faults, some bus-fault clearing times were more limiting. “Since the timing is not improved by the OPGW and line relay changes, they will not improve the stability margin,” PJM said.
One of the preliminary recommendations from PJM’s analysis is to remove the ground wire and relay upgrades from the project scope, McGlynn said.
Stakeholders asked whether, based on the scope changes, PJM plans to re-evaluate submitted proposals, but Herling said that was not possible.
“Realistically, we’re only looking at the finalists … in the context that things have changed. … We’re not going to go back to the most expensive projects that were eliminated,” he said. “We’re still working our way through the cost issues and the constructability issues. … Obviously, we still have a lot of work to do.”
RTOs and ISOs would be required to incorporate fast-start resources into energy and ancillary services pricing under a Notice of Proposed Rulemaking approved by FERC on Thursday (RM17-3).
Kheloussi | FERC
The commission said new rules are required to allow fast-start resources to set LMPs — changes regulators said should reduce uplift and provide more accurate price signals to encourage investments.
“Without some form of fast-start pricing, most fast-start resources are not eligible to set prices even when they are the marginal resource,” Daniel Kheloussi, a staffer in FERC’s Office of Energy Policy and Innovation, said during a presentation at the commission’s monthly meeting. “Further, even when fast-start resources can set prices, they may not be able to recover their commitment costs, such as start-up and no-load costs, through prices. As a result, prices may not reflect the marginal cost of serving load.”
The commission said fast-start resources are unique because they are often dispatched to inflexible minimum or maximum operating limits, making them ineligible to set LMPs. They also are usually committed in real-time.
“As a result, the cost to commit these resources is incurred at roughly the same time the incremental energy costs are incurred, which raises the question of whether the commitment costs should be included in the LMP,” the commission said. “Finally, fast-start resources can arguably respond quickly enough to be considered part of an RTO’s/ISO’s operating reserves even when they have not yet been committed.”
Seeking to build on the RTOs’ best practices, the NOPR would:
Standardize the definition of fast-start resources to include any resource committed by the RTO/ISO that is able to start up within 10 minutes or less, has a minimum run time of one hour or less and that submits economic energy offers to the market. The definition would be technology-agnostic.
Require that an RTO must incorporate the start-up and no-load costs (commitment costs) of a committed resource in energy and operating reserve prices for the resource’s minimum run time.
Require RTOs to relax the resource’s economic minimum operating limit (eco min) when calculating prices — treating it as if it is dispatchable from zero to the economic maximum operating limit (eco max).
Allow offline fast-start resources to set prices under certain system conditions when they are economic and feasible.
Require RTOs to incorporate fast-start pricing in both the day-ahead and real-time markets to support price convergence between the two.
The NOPR is the third issued by the commission since it initiated a proceeding on price formation in RTO/ISO markets in June 2014 (AD14-14). It follows a June order requiring RTOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period (RM15-24). (See FERC Issues 1st RTO Price Formation Reforms.) In November, the commission doubled the “hard” offer cap for day-ahead and real-time markets to $2,000/MWh. (See New FERC Rule Will Double RTO Offer Caps.)
Inflexible
Fast-start resources are often required to be dispatched at their eco min or are block-loaded — in which the eco min equals its eco max.
Because the system may not need all of the resource’s eco min to meet load, other resources must be dispatched down, making them the most economic option to serve the next increment of load. “Therefore, despite the fact that a fast-start resource is essentially marginal, this restriction prevents a fast-start resource dispatched at its economic minimum operating limit from setting the LMP,” the commission said.
Thus, some RTOs have relaxed the resources’ eco min limits, treating them as dispatchable in a pricing algorithm separate from the dispatch algorithm. But while these changes can improve price signals — especially during stressed conditions when the need for fast-start resources is the greatest — the disconnect between prices and dispatch instructions can cause over-generation. Only some RTOs conduct reconciliations between the pricing and dispatch runs to prevent excess generation, FERC said.
RTOs Have Differing Approaches
In comments filed following the commission’s technical workshops on price formation, many stakeholders said they would support changes allowing resources dispatched at their operating limits to set LMP and allowing start-up and no-load costs to affect prices. The Electric Power Supply Association and Western Power Trading Forum said such changes could help address CAISO’s “duck curve” by redistributing excess costs incurred during the middle of the day to the ramping periods.
Region
Fast-Start Resource Definition
No-load costs incorporated in LMPs?
Startup costs incorporated in LMPs?
Set DA prices?
Set RT prices?
Offline prices set LMP?
FERC NOPR
Start-up: within 10 minutes or less. Minimum run time: one hour or less. Other: Submits economic energy offers.
Yes
Yes
Yes
Yes
Yes
CAISO
Start-up: online within two hours or less. Other: can be committed in CAISO’s 15-minute market or short-term unit commitment process.
Yes
No
Yes
Yes
No
ISO-NE
Start-up: 30 minutes or less. Minimum run time: one hour or less. Minimum down time: one hour or less.
Yes (1)
Yes (1)
No
Yes
No
NYISO
Does not apply fast-start pricing to all fast-start resources.(2)(3)
N/A
Yes
Yes
Yes
Yes
PJM
Start-up: two hours or less (fast start CT). Block-loaded resource: eco min = eco max.
No
No
Yes (4)
Yes
No
MISO
Start-up: 10 minutes or less. Minimum run time: one hour or less.(6)
Yes
Yes
Yes
Yes
Yes (5)
SPP
Start-up: 10 minutes or less. Minimum run time: one hour or less. Other: total minimum down time one hour or less. (10)
No (7)
No (8)
Yes (9)
Yes
No
(1) New rules effective March 1, 2017 (ER15-2716).
(2) Uses “hybrid gas turbine pricing logic” and “offline gas turbine pricing logic” for all fast-start block loaded resources in its real-time energy market. Allows all fast-start block loaded resources to set price in its day ahead energy market.
(3) Worked with Market Monitoring Unit and stakeholders on revising its “hybrid gas turbine pricing logic.” In a Dec. 14 FERC filing (ER17-549), the ISO proposed broadening its eligibility criteria to allow all fast-start resources to be eligible to set prices in its real-time energy market.
(4) Yes. But generally limited to certain operational conditions like constraint control.
(5) Yes. Only under reserve or transmission scarcity conditions.
(6) Extended LMP took effect in 2015 (150 FERC ¶ 61,143). Planning to implement ELMP Phase II to apply fast-start pricing to more peaking resources.
(7) No. But does allow inclusion of no-load costs in mitigated energy offer curves for unit commitment.
(8) No. But does allow inclusion of start-up costs in mitigated energy offer curves for the unit commitment.
(9) Yes, if offered into day-ahead market.
(10) Implementing fast-start pricing to commit quick-start resources more efficiently in real-time in Q2 2017.
ERCOT (Not subject to FERC NOPR)
Start-up: 10 minutes or less. No minimum run time requirement (11) (17)
Yes (12)(13)
Yes (13)(14)
Yes (15)
Yes (13)(16)
Yes
(11) Resource is exempted from following instructions for the first five-minute dispatch. Regulation reserves are used to cover missing energy.
(12) Yes. Market participants may include no-load costs in energy offer curves.
(13) Uplift may occur in cases in which the assumptions built into the energy offer curves are not correct and costs are not fully recovered.
(14) Yes. Market participants may include startup costs in energy offer curves.
(15) Yes. Day-ahead market is voluntary. Market participants may include no-load and start-up costs in energy offer curves.
(16) Market participants may include no-load and start-up costs in energy offer curves.
(17) Analyzing the feasibility and benefits of implementing a multi-interval real-time market.
The commenters noted that start-up time requirements for quick-start resources range from 10 minutes in NYISO, MISO and SPP, to 30 minutes in ISO-NE and two hours in PJM and CAISO.
Several stakeholders praised MISO’s extended LMP. The program, implemented in March 2015, is designed to reduce uplift by incorporating all offer costs into market clearing prices. (See MISO Study Undercuts IMM Proposal on Expanding ELMP Pricing.) The RTO is planning to implement ELMP Phase II to apply fast-start pricing to more peaking resources.
NYISO and ISO-NE also received some praise, while Golden Spread Electric Cooperative criticized SPP, saying the RTO’s market design and operator practices fail to reflect fast-start resources’ costs and their value to the system.
NYISO worked with its Market Monitoring Unit and stakeholders on revising its “hybrid gas turbine pricing logic,” resulting in a Dec. 14 FERC filing in which the ISO proposed broadening its eligibility criteria to allow all fast-start resources to be eligible to set prices in its real-time energy market (ER17-549).
ISO-NE will be implementing new rules effective March 1, 2017, to incorporate no-load and start-up costs in LMPs (ER15-2716).
SPP said it will be implementing fast-start pricing to commit quick-start resources more efficiently in real time in the second quarter of 2017.
PJM was criticized by its Independent Market Monitor, which said that relaxing eco mins for price setting is subjective and overrides “fundamental pricing logic,” sometimes increasing total production costs.
The RTO also was criticized for limiting its fast-start definition to combustion turbines and excluding reciprocating engines.
| GE Power Generation
“A natural gas-fired reciprocating engine that has a cold start-up time of only five minutes and has an economic minimum of 50% of its economic maximum is much, much more flexible, and provides significantly more value to the bulk electric power grid, on a per-megawatt-hour basis, than an inflexible block-loaded resource that takes two hours to start,” IMG Midstream and Tangibl said in comments to the commission.
ERCOT, which is not subject to the FERC NOPR, is analyzing the feasibility and benefits of implementing a multi-interval real-time market.
Comments Sought
The commission asked stakeholders to comment on its proposals, including whether they could result in the exercise of market power. “The concentrated ownership of fast-start resources could raise market power concerns that are not addressed in existing RTO/ISO market power mitigation procedures,” FERC said.
The commission also acknowledged that the changes could require complex and expensive software changes. “We seek comment on the required software changes, updates to optimization modeling and parameter inputs, estimated costs and time necessary to implement” the changes, FERC said.
Comments are due 60 days after publication in the Federal Register.
The Little Rock-based cooperative said the improvements are needed by October 2017 to accommodate about 35 MW of new industrial load. It said getting approval under the 2017 Transmission Expansion Plan in December 2017 would be too late.
