The Federal Energy Regulatory Commission issued an order to show cause against Maxim Power yesterday, telling the Canadian independent power producer to explain why it shouldn’t have to pay a $5 million fine for allegedly misrepresenting the output of three of its generators in ISO-NE (IN15-4).
FERC says that in July and August of 2010, when asked about the company’s offers on the day-ahead market, Maxim employee Kyle Mitton told ISO-NE’s Market Monitor that the generators were unable to procure gas, so it was forced to burn more expensive oil.
FERC says, however, that Maxim purchased large quantities of gas before submitting its offers at the price of oil the same day. FERC assessed Mitton a $50,000 proposed penalty separately from the company.
FERC’s Office of Enforcement issued a Notice of Alleged Violations in November. (See FERC Staff Accuses Maxim Power of Cheating ISO-NE.) The notice included two other alleged schemes by Maxim: gaming ISO-NE market mitigation rules in 2012 to 2013, and boosting its generators’ outputs during testing using “extraordinary measures” in order to collect inflated capacity payments from 2010 to 2013. The order to show cause does not mention these allegations.
Commissioner Tony Clark dissented, saying he did not think the Enforcement staff report and Maxim’s responses justified the order. “Nonetheless, in the next phase of the proceeding, both FERC Enforcement staff and the respondents will have an opportunity to more fully develop the record,” he wrote. “As such, I make no prejudgment as to the final disposition of this case.”
Commissioner Norman Bay, who headed the Office of Enforcement during most of the investigation, did not participate in the decision.
PPL and Riverstone Holdings have agreed to satisfy market power concerns over the spinoff of their generation by making only cost-based offers for the more than 650 MW that their new company will keep in eastern PJM.
The use of cost-based offers was one of two mitigation options the Federal Energy Regulatory Commission said it would accept in its conditional approval of the companies’ plan to combine their generation assets into a new company, Talen Energy.
The mitigation is intended to address market power concerns in PJM’s 5004/5005 submarket in eastern Pennsylvania, New Jersey and Maryland. (See FERC Gives Conditional OK to Talen Energy.)
The companies revealed their response to FERC’s options in a Jan. 27 informational filing (EC14-112).
“After full evaluation, both parties believe the enhanced mitigation will not have a materially different impact on the future operating results of Talen Energy than the original proposal,” the company said in a news release.
In their application, the companies proposed two mitigation packages. One involved divestiture of six Riverstone plants and one PPL plant in New Jersey and Pennsylvania — all combined-cycle plants — for a total of 1,315 MW. The second involved the same six Riverstone plants, plus a 399-MW coal-fired plant in Maryland and two PPL hydro plants in Pennsylvania, for a total of 1,346 MW.
FERC’s Dec. 18 order said the companies would have to sell all of the plants in the two options — totaling about 2,000 MW — or limit energy and regulation market offers for the approximately 650 MW Talen would retain under either package to cost-based rates.
The companies said they would not decide on which of the sets of power plants they will sell until the closing of the PPL-Riverstone spinoff, which is expected in the second quarter of this year. Post-divestiture, Talen will be the seventh-largest generation owner in PJM.
“We have 12 months from the closing date to announce the divestitures, and they may take somewhat longer than that to close on those,” PPL spokesman George Lewis said Thursday.
The companies said that no company with more than 10% of PJM’s summer installed capacity would be permitted to bid for the plants. That would leave out Public Service Enterprise Group, Exelon and NRG Energy.
Talen Energy will own almost 14,000 MW of capacity — about 11,000 MW in PJM — after the divestitures.
In addition to the plant sales and cost-based offers, FERC also required Talen to offer into PJM markets the same plants and output as PPL did, prohibiting it from holding back generation to drive prices up.
The deal still needs approvals from the U.S. Department of Justice, the Nuclear Regulatory Commission and the Pennsylvania Public Utility Commission.
Failed Data Center Project on Hook for $1.4 Million, Court Rules
The Data Centers LLC must pay three consultants $1.4 million in fees and interest related to the company’s failed bid last year to build a power plant and data center on University of Delaware property, according to a recent Superior Court ruling.
The university rejected the project after community opposition arose. The Data Centers recently said it was eyeing a similar project in the greater Baltimore area.
Clean Line Unveils Proposed Routes in Series of Public Meetings
Clean Line Energy, which wants to build a 750-mile overhead direct-current transmission line from Kansas to Indiana, is holding a series of public meetings on the project.
The Grain Belt Express, designed to bring wind power from west to east through Missouri and Illinois, is similar to the company’s Rock Island Line, which will run through northern Illinois. The Rock Island Line has already gained the approval of the Illinois Commerce Commission. Clean Line said it hopes to get ICC approval for the Grain Belt Line this year.
IURC Approves Vectren’s Emissions Plan for SW Indiana Coal Plants
The Utility Regulatory Commission has approved a plan by Vectren Energy Delivery of Indiana to install new emissions controls on its plants in the southwestern part of the state. Vectren plans to spend $70 million to $90 million on the project and to defer recovery of the costs until 2020.
“With today’s ruling, we can avoid an immediate impact to our customers’ electric bills yet still fulfill our obligation to comply with these additional, federally imposed environmental requirements,” said Carl Chapman, Vectren’s chairman, president and CEO.
MoCo Wants Opening of Pepco Lands as Condition of Approving Exelon Deal
The Montgomery County Council urged the state Public Service Commission to require Pepco Holdings Inc. to provide recreational access to its transmission rights of way as a condition of approving the utility’s pending $6.8 billion acquisition by Exelon.
The council’s resolution, the latest in a series of conditions set by various groups on the merger, would force Pepco to allow hikers to access trails crossing the utility’s transmission easements. County Planning Chairman Casey Anderson said there are laws already in place to insulate utilities from liability for recreational use of their land. He said talks with Pepco officials in the past have not been productive.
“It’s frustrating that we have generally tried to be cooperative with Pepco in the past in giving them the access they need to provide utility service, but they are not seeming to be inclined to reciprocate by giving us access when we need it,” he said.
State Faces Barriers to Fulfilling Renewable Energy Potential
A weak renewable energy portfolio standard and a lack of incentive to adopt new technology is blocking the state from reaching its full renewable energy potential, according to a recent report by the Institute for Energy Innovation.
The report noted that state lawmakers declined to adopt a standard that would require utilities to get 25% of their electricity from renewables by 2025. The current goal is 10% by the end of this year.
Hundreds Attend PSC’s Rate Hike Hearing for Ameren Missouri
Hundreds turned out last week for a Public Service Commission meeting to debate Ameren Missouri’s 10% rate increase request, its sixth since 2007.
Ameren said it needs the increase to help it meet oncoming federal emissions standards. If approved, Ameren will have raised rates by 57% in seven years, according to the Fair Energy Rate Action Fund.
Loup Public Power District has approved the purchase of electricity from a new wind farm, its first wind energy purchase.
The 19,000-customer district currently obtains its electricity from nuclear, hydro and fossil sources. Last week, it added wind generation from Bluestem Energy Solutions. Bluestem’s wind farm, when completed, will have four turbines, each capable of generating 1.7 MW.
Although wind will provide only about 2% of the district’s needs, “it gives us a chance to show that we’re doing a little something for the environment in addition to the hydroelectric power,” Loup president Neal Suess said.
Bills Aimed at Pushing Offshore Wind Power Pass Senate Panel
The state Senate Environment and Energy Committee last week approved two bills that could break a Board of Public Utilities logjam over offshore wind farms.
One bill would require the BPU to approve any qualified wind energy project and relax the current requirement for projects to submit cost-benefit analyses. The second would urge the BPU to finalize regulations needed to implement the “Offshore Wind Economic Development Act,” enacted in 2010.
The BPU has repeatedly denied approval to a pilot project to build turbines near Atlantic City, saying it would be too costly for electricity customers.
State Official Puts Brakes on $2 Billion SunZia Tx Line
State Land Commissioner Aubrey Dunn put a 60-day suspension on construction of a $2 billion SunZia Southwest Transmission Project to allow her office time to review the transmission line, which would deliver electricity generated from renewable sources in New Mexico and Arizona to western markets.
“Eighty-nine miles — nearly 30% — of the proposed transmission line will cross state trust land,” Dunn said in a news release. “The suspension will allow our office time to ensure all necessary agreements are in place to protect state trust land and ensure state beneficiaries are receiving fair consideration by SunZia.”
The company said it will work with Dunn’s office to address any concerns.
New Subpoenas Come to Light in Fed Investigation of Duke Spill
A Federal grand jury is investigating last year’s coal ash spill from Duke Energy’s Dan River plant, apparently to determine if the discharge of 39,000 tons of coal ash involved any criminal violations.
A newly unveiled federal subpoena of the state Utilities Commission sought communications between the commission and “Duke Energy or its employees, agents or consultants” regarding engineering reviews of the Dan River ash ponds. Investigators also sought all communication between the commission and state environmental regulators about periodic ash inspections.
“An official criminal investigation of a suspected felony is being conducted by an agency of the United States and a federal grand jury,” Assistant U.S. Attorney Banumathi Rangarajan wrote in a cover letter accompanying the June 24 subpoena. The subpoena was disclosed as a result of a public records request by the News & Record.
The Public Service Commission approved projects totaling $2.7 billion in 2014, up from about $1 billion the year before. The projects included transmission lines, power generating stations and pipelines, the commission said.
Ohio Edison Area Gets $690 Million in Transmission, Distribution Improvements
FirstEnergy says it invested nearly $690 million in transmission and distribution improvements last year in Ohio Edison territory, allowing it to exceed reliability standards set by the Public Utilities Commission.
More than $581 million was spent on new transmission projects, the company said, including a new 100-mile, 345kV line from the Bruce Mansfield plant to northeast Ohio.
Gov. Corbett’s Energy Advisor Leaves for Gas Industry Job
Henderson
Patrick Henderson, former Gov. Tom Corbett’s energy executive, has become a lobbyist for the Marcellus Shale Coalition, an industry trade group.
Henderson confirmed that he will be the MSC’s next director of regulatory affairs. MSC President Dave Spigelmyer praised Henderson’s “deep understanding of energy-related regulatory and legislative issues.”
But Barry Kauffman of Common Cause PA said Henderson’s move to represent the industry “elevates cynicism about how government operates.” Sierra Club representative Joanne Kilgour was even more blunt: “We always suspected he was working for the interests of polluters rather than the people of Pennsylvania,” she said. “Now he just has the title to prove it.”
PSC Will Allow TransCanada to Argue to Use 2010 Permit for Keystone
The Public Service Commission ruled that it will allow TransCanada to try and convince the panel why a 2010 construction permit issued for the Keystone XL pipeline should still be valid.
The Yankton Sioux Tribe and the Rosebud Sioux Tribe, backed by other tribal and landowner organizations, wanted the commission to dismiss TransCanada’s application. Their central argument was that 30 changes identified by TransCanada require a new permitting process. The PSC, by a vote of 3-0, denied the tribes’ requests.
Lawmakers Debate Impact of EPA Emissions Plans on State
Wisconsin could spend as much as $13 billion to comply with new Environmental Protection Agency emissions mandates, according to Ellen Nowak, a member of the Public Service Commission.
Nowak, one of several speakers at a joint committee hearing in Madison last week, said the new emissions rules could hurt Wisconsin because of the state’s heavy reliance on coal-fired power plants. Others said they felt the mandates are being unfairly thrust on the state. “What we have here is an unfunded mandate from the federal government, the Obama administration,” state Sen. Rick Gudex (R-Fond du Lac) said.
But Keith Reopelle, of the environmental group Clean Wisconsin, was more upbeat. He said current renewable requirements, as well as energy efficiency programs, leave Wisconsin well positioned to meet the new rules.
The Federal Energy Regulatory Commission will have a vital role in implementing the Environmental Protection Agency’s proposed carbon emission rules but won’t take sides in ideological debates over the regulations, Chairman Cheryl LaFleur said last week.
“People both for and against the Clean Power Plan are looking to us to publicly validate their views,” LaFleur said during a National Press Club luncheon. “I’ve taken a pretty firm line that I don’t think that’s FERC’s role. FERC is not an environmental regulator. … But make no mistake, I think FERC will have an essential role to play as the Clean Power Plan and our response to climate change is implemented.”
LaFleur said state-by-state compliance with the regulations would be more complicated than a regional approach. Dispatching power based on a state’s portfolio needs, rather than the current least-cost model, would require FERC to change the way RTOs work to support the state plans, she said. “I think it’s going to be a lot more than tinkering around the edges.”
She called a regional approach “the obvious solution,” noting that the EPA gave “extra credit” for regional cooperation. LaFleur highlighted the success of the Regional Greenhouse Gas Initiative but said that FERC will still have to work with states and RTOs to come to agreements and compromises about goals, saying the commission needed to be “an honest broker for discussion.”
“This is the kind of hard, boring, unsexy, technical, dirt-under-the-fingernails work that FERC does,” she said. “… We work on the unsexy underbelly of every energy issue.”
Under pressure from the new Republican majority in Congress, FERC has scheduled four technical conferences in February and March on the reliability impact of the EPA regulations. LaFleur said more sessions will probably be added due to the number of stakeholders who have asked to speak. The first conference will be held Feb. 19 at FERC headquarters.
Asked whether she was disappointed Congress hadn’t passed new major energy legislation recently, she said she doesn’t worry about what those on the Hill are doing or not doing.
“I live by the rules they’ve given us,” she said. “If they pass new legislation, I’ll live by that.”
The Michigan Public Service Commission wants federal regulators to force MISO to turn over a study used to identify areas that require the operation of system support resources (SSR) in the state’s Upper Peninsula.
The load-shed study is “essential” to determining whether MISO’s analysis accurately identifies the local balancing authorities (LBA) that require the SSR units and — if not — how it should be modified to do so, the Michigan PSC said in a filing to the Federal Energy Regulatory Commission (ER14-2952).
In 2014, the Wisconsin Public Service Commission complained to FERC that Wisconsin ratepayers would pay a disproportionate share of SSR costs (ER14-2860, ER14-2862). FERC agreed, and MISO responded in September with revised rate schedules that shifted the costs of the Presque Isle, White Pine and Escanaba SSR units more heavily to Michigan.
Michigan regulators are protesting MISO’s allocation of SSR costs on the basis of the reduced LBA boundaries created by Wisconsin Electric Power Co. (WEPCo) as a result of Wisconsin’s challenge.
Michigan has argued that WEPCo’s LBA boundary changes “produce an unduly discriminatory and disproportionate allocation” of SSR costs.
As examples it cited Cloverland Electric Cooperative, whose SSR costs are estimated to rise by 800%, from $2.6 million to $21.9 million, and WEPCo’s load in the Michigan U.P., which the PSC says will increase by 1,000%, from $7 million to $70 million.
The Michigan PSC said it wants FERC to reject the use of WEPCo’s modified LBA boundaries to assign cost responsibility.
With the study data in hand, the PSC said, it could not only demonstrate the inaccuracy of MISO’s “optimal” load-shed study in identifying the load-serving entities that require SSR units, but also demonstrate the larger area of LSE loads that benefit from operation of the units at issue.
MISO’s Dec. 17 response to a FERC deficiency notice described the load-shed study as based on “optimal contingents” designed to “minimize” the volume of load identified as needing the SSR unit. “MISO admits that the impact area identified in the load-shed study ‘is not an all-inclusive identification of load that can reasonably be expected to benefit under every circumstance,’” the Michigan PSC wrote.
After reviewing the response, the PSC said it asked MISO for a copy of the unredacted load-shed study. MISO refused, the PSC said, saying it was only available to MISO staff and transmission owners.
“The Michigan PSC has reason to believe that the ‘optimal’ load-shed study does not accurately identify load that requires operation of the SSR units,” the PSC said. “For this reason, the Michigan PSC desires to conduct alternate studies that are designed to identify loads that require operation of the SSR units under more realistic conditions.”
Presque Isle Deal
Regardless of how the PSC’s request plays out at FERC, Michigan ratepayers may get some relief as a result of Upper Peninsula Power Co.’s agreement to purchase Wisconsin Energy’s Presque Isle generator. UPPCO said last month it would “step into” the existing rates but eliminate the SSR agreement, relieving U.P. ratepayers of its $97 million annual cost. (See Sale Would End SSR, Clear Way for WE-Integrys Deal.)
ISO-NE opened its ninth Forward Capacity Auction yesterday amid expectations of high prices as the region deals with plant retirements and tight natural gas supplies due to inadequate infrastructure. Results from the auction are expected this week or next.
Last year, for the first time, the auction failed to clear as much capacity as ISO-NE sought, falling 143 MW short of the 33,855-MW requirement. ISO-NE is seeking more than 34,000 MW for delivery year 2018/19, 334 MW more than last year’s requirement.
Revenues from FCA 8 totaled $3.05 billion, a 72% jump from 2009’s previous high of $1.77 billion and nearly triple 2013’s $1.06 billion.
FCA 9 the Peak for Prices?
Analysts for UBS Securities released a report yesterday predicting prices will rise higher in this week’s auction, perhaps reaching $11 to $15/kW-month in southeastern Massachusetts and Rhode Island.
The analysts said prices could be limited by new entrants within the RTO or a rebound in transmission imports following a reduction last year.
In either event, they predict new plant construction and possible expansions at existing sites in the constrained Massachusetts market could send prices crashing in FCA 10 next year. “We suspect this is the top of the market for this region, with prices reaching their highs — pushing down prices for future years,” they wrote.
Christopher Tumure, an analyst at JP Morgan, said yesterday the he expects “a bit of an uptick” in prices.
“On the supply side, much of the new generation has already been bid into recent auctions, so we don’t see much change there. On the demand side, there’s about a 300-MW increase year-over-year.”
Two new developments may partially offset each other, he said.
“One of the changes this year is the Pay-for-Performance [program], which may increase prices as it affects the bidding behavior. Another change is the switch to the sloped demand curve instead of a vertical, and that’s not necessarily a good thing for prices.”
NRG Sees Gains
Last month, NRG executives told the company’s annual investors meeting that they expect $1.445 billion in 2018/19 capacity revenue from ISO-NE and PJM, a $565 million increase over 2017/18.
Since FCA 8, the region has lost the Salem Harbor Generating Station in Massachusetts and the Vermont Yankee nuclear plant to retirement. Also unavailable in FCA 9 will be the Brayton Point Generating Station in Massachusetts, which is set to close in 2017. In a recent media briefing, ISO-NE CEO Gordon van Welie said New England will lose about 3,500 MW of generating resources over the next few years.
ISO-NE’s informational filing for 2018/19, which the Federal Energy Regulatory Commission accepted Jan. 16, shows an installed capacity requirement of 35,142 MW (ER15-328). After accounting for 953 MW of Hydro Quebec Interconnection Capability Credits, the RTO seeks to procure 34,189 MW.
Qualified to compete in the auction are 41,102 MW — 8,547 MW of new resources and 32,555 MW of existing resources.
ISO-NE will model four capacity zones in FCA 9:
Southeastern Massachusetts/Rhode Island (SEMA/RI);
Connecticut;
Northeastern Massachusetts/Boston (NEMA/Boston); and
Rest of Pool (Maine, Western/Central Massachusetts, New Hampshire and Vermont).
ISO-NE determined that SEMA/RI will be modeled as import-constrained in this year’s auction, in addition to Connecticut and NEMA/Boston, which were both modeled as import-constrained last year.
SEMA/RI wasn’t modeled last year, when the four zones were Maine (export-constrained), NEMA/Boston (import-constrained), Connecticut (import-constrained), and Rest-of-Pool.
This year will be the first auction in which ISO-NE will adopt a sloped demand curve, as is used in PJM. FERC ordered the change, which is intended to reduce price volatility, following the shortfall in FCA 8.
Demand Response is In
The New England Power Generators Association had asked FERC to disqualify demand response from participation, citing the D.C. Circuit Court of Appeals ruling voiding FERC’s jurisdiction over DR pricing in the energy markets (Electric Power Supply Association v. Federal Energy Regulatory Commission).
[EDITOR’S NOTE: An earlier version of this story incorrectly said that SEMA/RI was modeled as an import-constrained zone in FCA 8. SEMA/RI was not modeled in last year’s auction.]
CARMEL, IND. — Planning Advisory Committee members had plenty of questions last week as MISO officials presented their proposed scenarios for the 2016 Transmission Expansion Plan.
Stakeholders questioned fuel and generation price forecasts and assumptions about future penetration of renewable resources and the role of energy efficiency.
A stakeholder for EDF Renewable Energy questioned the assumptions on the costs of installing new wind capacity, challenging data from Lazard and the Energy Information Administration’s Annual Energy Outlook that estimated current capital costs at $1,800 to about $2,000/kW.
“These costs seem extremely high,” he said. The real cost “is probably close to half these values.”
Jason Schmidt of Xcel Energy questioned why MISO planned to eliminate a future scenario that assumes an increase in state renewable portfolio standards. The proposed base case assumes only enough wind, solar and energy efficiency to meet state standards. “We just submitted a resource plan in which we doubled our wind [capacity] and achieve 10% solar by 2030,” Schmidt said.
Sean Brady, of wind trade group Wind on the Wires, said he shares Xcel’s concern about modeling of renewables. “It’s a departure from what we’ve done in the past,” he said.
MISO’s David Van Beek said “there wasn’t a lot of support” among stakeholders for significantly higher targets, particularly in MISO South, where Louisiana, Mississippi and Arkansas have no RPS.
MISO officials agreed to seek additional information from Bentek about the assumptions in its gas price forecasts.
Members also debated how to model age-related coal retirements.
The baseline assumes 12 GW of coal retirements by 2016 due to the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS), with another 14 to 20 GW resulting from the Clean Power Plan, depending on regional or sub-regional compliance.
Including the projected 3 to 12 GW of age-related coal retirements leaves all non-business-as-usual futures with high retirements. If age-related retirements are excluded “more balanced retirements can be studied,” MISO said.
Feedback on MISO’s proposed assumptions is due Feb. 11. The RTO will present its final proposals for assumptions and scenarios at the Feb. 18 PAC. The committee will take an advisory vote on the proposal via email or on a conference call after the 18th.
Order 1000 Interregional Compliance Filing
MISO said it expects to make a joint compliance filing with PJM in response to the Federal Energy Regulatory Commission’s December order finding that they only partially complied with the requirements of Order 1000.
The commission ordered the RTOs to modify their cost allocation method for cross-border transmission projects and develop identical language in their Tariffs to describe their interregional transmission coordination procedures (ER13-1944). (See FERC Begins ‘Next Step’ on Order 1000: Interregional Filings.)
At the Regional Expansion Criteria and Benefits Task Force meeting Jan. 29, there was agreement that MISO will have joint stakeholder meetings with PJM to discuss the filing, MISO’s Jesse Moser said.
First Interconnection Request for Battery Storage
Xcel Energy’s Randall Oye, chair of the Interconnection Process Task Force, told PAC members that MISO has received its first interconnection request for battery storage and will work with stakeholders to develop a process for analyzing such requests.
In a meeting of the task force last month, Oye gave a briefing on how California is processing storage interconnections. CAISO received more than 2,000 MW of storage applications in its April 2014 study cycle in response to California law requiring 1,325 MW of storage in service by 2024, according to Oye’s presentation.
Change to Transmission Developer Prequalification Deadline
MISO has changed the deadline for transmission developers to provide the RTO audited financial statements as part of the prequalification process for Order 1000 competitions. The date was changed to May 31 from March 31 after some companies said the March date was too early based on their annual accounting schedules.
Two of Astoria Generating Station’s five units were placed in mothball status in 2012, reducing its capacity from 1,335 MW to 957 MW.
The Federal Energy Regulatory Commission said it has more questions for NYISO before considering proposed revisions to its rules for retired and mothballed generators.
FERC last week sent NYISO a deficiency letter (ER14-2518) listing questions about the ISO’s July 2014 proposal, which would allow it to terminate a generator’s eligibility to participate in the Installed Capacity (ICAP) market after six months in a forced outage if repairs have not been started.
The proposal also would add Tariff definitions of the terms “mothball outage” and “retired.”
The Independent Power Producers of New York supported the six-month rule for participating in the ICAP market. However, it said FERC should reject a requirement that generators on outage respond to reliability needs by returning to service or making their interconnection points available. The association said the requirement would deny generators rights they earned in interconnection agreements with transmission owners.
Responding to the objections, NYISO said in September that “Any modification to, or termination of, an existing interconnection agreement … will continue to be subject to the terms and conditions of the underlying agreements.”
On Jan. 29, FERC’s Office of Energy Market Regulation gave the ISO 14 days to reply to additional questions, including whether it intends to apply its definition of “retired” generators to those with existing interconnection agreements. FERC also asked whether the ISO could unilaterally terminate the interconnection agreements of units in retired status.
Scorecard of frequency response performance for generators in the MISO footprint. Scores of five and above are “problematic,” MISO says. (Click to zoom.)
CARMEL, IND. — MISO has begun collecting data from local balancing authorities in preparation for the North American Electric Reliability Corp.’s new frequency response standard (BAL-003-1).
NERC’s rule is intended to ensure sufficient frequency response from balancing authorities to control interconnection frequency. It also sets consistent methods for measuring frequency response and determining frequency bias settings.
The “generator scorecards” that LBAs are completing cover the period Dec. 1, 2013, through Oct. 31, 2014. MISO’s Terry Bilke presented the results to date to the Reliability Subcommittee, including a histogram showing generator results on a scale of zero to seven. (See chart.) “Anything five and above is problematic,” he said.
Bilke said MISO will work with LBAs and generators to boost governor response where necessary.
The frequency bias setting requirement takes effect April 1. By April 1, 2016, balancing authorities will be required to achieve an annual frequency response measure (FRM) “equal to or more negative” than its frequency response obligation.
Operations Working Group Charter, Management Plan OK’d
Members endorsed the 2015 charter and management plan for the Operations Working Group. There were no substantive changes from 2014, according to chair Ray McCausland of Ameren.
MISO Readies for GMD Rule
Alliant’s Will Behnke, chair of the Emergency Preparedness / Power System Restoration Working Group, briefed members on MISO’s preparation for NERC’s Geomagnetic Disturbance Operations Standard (EOP-010-1), which takes effect April 1.
“We’re ready,” Behnke said.
The standard requires Reliability Coordinators to review the geomagnetic disturbance (GMD) operating procedures or processes of transmission operators (TOPs) within their areas to mitigate the effect of GMDs on the grid.
TOPs must submit a worksheet to MISO 30 days before their GMD operating procedure becomes effective or is revised.
Performance on Real-Time Operations Drills Improving
Local balancing authorities and market participants have improved their performance on monthly drills of real-time operations processes, with more than 80% successfully completing them, MISO’s Danielle Logsdon told members.
Logsdon said that is a marked improvement from the prior success rate of 60%. Performance on the XML drill is “close to 100%,” Logsdon said.
Distributed ICCP Project Extended
MISO said it doesn’t expect to complete its distributed ICCP project until the first quarter of 2016.
MISO’s Arijit Bhowmik told members the RTO expects to complete migration of 70% of the internal links to the new systems by the end of this year. The project, announced last year, was originally scheduled to be complete this August.
MISO’s 2015 Summer Coordinated Seasonal Transmission Assessment will add voltage stability analyses of the Amite South HV Interface and imports in Southwest Michigan in addition to those previously done on the Minnesota Wisconsin Export Interface (MWEX), DSG HV Interface and MISO South’s Western Critical Interface.
ICCP (Inter-Control Center Communications Protocol) is MISO’s real-time data source, providing visibility into the grid and allowing four-second dispatch of generation. The project will spread members across multiple ICCP nodes, reducing the impact of a single failure.
Summer Seasonal Assessment Takes a Closer Look at Louisiana
The 2015 Summer Coordinated Seasonal Transmission Assessment will include a reactive reserves analysis of the Baton Rouge area for the first time, MISO’s Scott Goodwin told members.
Also new will be a voltage stability analysis for the Amite South HV Interface and Southwest Michigan imports.
The CSA is intended to inform operators of potential marginal system conditions expected during the upcoming summer peak and evaluate various stressed conditions, including second contingencies.
The analysis will begin this month, with a draft report posted for review April 24 and the final report expected May 29.
CARMEL, IND. — MISO transmission developers cried foul last week over Entergy’s proposed $187 million transmission upgrade near Lake Charles, La., saying the company’s request for expedited approval is denying them a chance to compete for the project.
Entergy Gulf States Louisiana filed the request with MISO on Dec. 15, saying it was in response to a system need identified on Dec. 1.
The company asked that the request be treated as an out-of-cycle project and not as part of the normal MISO Transmission Expansion Planning (MTEP) process. “Due to major industrial expansion projects ongoing in the Lake Charles area and the aggressive timeline to complete the project by summer of 2018, this project needs to be started in the first half of 2015,” it said.
The project, which the company described in a Jan. 8 press release as “one of the largest single transmission projects in Entergy’s history,” includes two new substations, expansion of a third and 25 miles of 500-kV and 230-kV transmission.
“It’s not the largest [out-of-cycle project] we’ve ever received, but it’s substantial,” said Jeff Webb, MISO director of planning, in presenting the project to the Planning Advisory Committee on Wednesday.
Under the Transmission Planning Business Practice Manual, out-of-cycle projects are limited to reliability projects that address a need identified after the project submittal cutoff date of the prior annual MTEP cycle, with a required need date within three years of the request date and expected in-service date within four years.
Webb said the cost of the project would be allocated to the Entergy pricing zone and built by Entergy — not opened to the competitive selection process ordered by the Federal Energy Regulatory Commission in Order 1000.
“If you wait long enough, everything becomes a reliability project,” said George Dawe, vice president of Duke American Transmission. “In my mind it doesn’t meet at least one, and maybe two, of those criteria. … They’re saying that sometime after September this load materialized.”
“We think it meets the requirements,” responded Webb, noting the requested June 2018 in-service date. “It seems rational. We have no knowledge of when Entergy may or may not have known.”
Webb’s defense did not end the debate. Dawe was joined by others also expressing skepticism. Discussion of the project — scheduled for 10 minutes on the agenda — stretched on for about 45 minutes.
Sharon Segner of LS Power requested MISO evaluate the project to see “whether there are benefits to this line outside of Entergy’s footprint and whether it goes to the competitive bid process.” Those are the questions, she said, that would be the subject of a potential challenge before FERC.
Webb said such an evaluation would take too much time to meet Entergy’s schedule.
Entergy’s press release indicated the project would have benefits beyond reliability: “In addition to enhancing reliability, operational flexibility and helping meet the increased demand in the region, the project will also improve access to lower cost generation in the [MISO] market, potentially reducing costs for all customers in the area.”
Kipp Fox of AEP Transource questioned how the load “mysteriously appeared between Module E submissions” — interim resource adequacy plans each load-serving entity is required to provide MISO annually.
“You should have some governance rules,” he added.
Webb insisted Entergy’s claim was “believable.”
“It’s kind of like generator interconnections. Lots of people talk about generator interconnections. [Utilities] don’t start planning and building until you have a commitment.”
Tia Elliott, director of regulatory affairs at NRG Energy, noted that Entergy had won approval of an out-of-cycle project in Lake Charles a year ago. “Here we are a year later and we see another request for load growth in the Lake Charles area,” she said, noting that the total cost of the two projects exceeds $200 million.
Entergy submitted the earlier request Dec. 19, 2013, saying it was needed to respond to a signed contract it received about two weeks earlier for new block load additions in the Lake Charles area. The request proposed construction of a substation and a transformer upgrade. The company said the facilities, estimated to cost $37.7 million, were needed by summer 2015.
Webb said there is a tension between emergent reliability needs and the competitive developer selection process under Order 1000, which can take 12 months or longer.
Subjected to the competitive process “this project wouldn’t have a developer for a year and a half from now and it has to be in service in June 2018,” he said. “There’s not enough time.”
Webb also said MISO is “sensitive … to the possibility of gaming that [our-of-cycle] process.” He invited stakeholders to provide “specific suggestions on how we can meet those two competing issues” through rule changes.
No one from Entergy spoke during the discussion. In a statement today, Entergy said the project meets all four of MISO’s criteria for out-of-cycle projects. The filing “is the appropriate process for this project given the unprecedented growth occurring and the limited time to install the facilities needed,” it said.
“We look forward to participating in the stakeholder process and we fully expect MISO to approve the [project] as a baseline reliability project needed to support the unprecedented economic development occurring in this region.”
Tom Mielnik, manager of electric system planning at MidAmerican Energy, said the out-of-cycle process is necessary.
“Customers like to make the decision at the last minute and then they want the utility to act expeditiously,” he said. “This is a real issue and a need for out-of-cycle projects.” He added that customers “typically” insist that utilities keep their potential interest confidential as they weigh several different sites for potential expansions.
The project will be discussed in detail at a Feb. 11 meeting of the South Technical Study Task Force in New Orleans. The project will also be considered by the System Planning Committee of the Board of Directors, which Webb said could recommend it to the full board as soon as April.
