Page 1786 – RTO Insider

February 4, 2015June 15, 2023

Prices up One-Third in ISO-NE Capacity Auction

By William Opalka

ISO-NE’s ninth Forward Capacity Auction saw prices increase by about one-third as 1,400 MW of new resources cleared to replace retiring coal plants.

While the RTO exceeded its six-state requirement of 34,189 MW by more than 500 MW, the Southeastern Massachusetts-Rhode Island zone failed to meet its obligation.

Monday’s auction was held to meet demand for the capacity commitment period from June 1, 2018, to May 31, 2019.

A preliminary estimate of the total cost is about $4 billion, compared to the 2014 auction that resulted in a total cost of about $3 billion.

The 24,447 MW of new and existing capacity resources that cleared the auction outside of SEMA/RI will be paid $9.55/kW-month. In FCA 8, most resources cleared at $7.025/kW-month.

The increase was expected. (See ISO-NE Opens FCA 9 amid Expectations of High Prices.)

New Capacity

The auction results included 1,400 MW of new capacity to help make up the shortage of generation created by the announced or pending retirements of more than 3,000 MW. New resources include three power plants — two in Connecticut and one in Southeastern Massachusetts — and 367 MW of new demand-side resources.

The resources include a 725-MW combined-cycle resource in Oxford, Conn., under development by Competitive Power Ventures. Two 45-MW combustion turbines in Wallingford, Conn., and a 195-MW CT in Medway, Mass., also cleared.

The auction started with 5,432 MW of new resources qualified to compete, according to the RTO.

“The capacity market is working as designed. The price signals from last year’s auction helped spur investment in new resources, including more than 1,000 MW of new generating capacity, which will help address the region’s resource shortage and meet peak demand in 2018-2019,” ISO-NE CEO Gordon van Welie said in a statement.

He credited the Pay-for-Performance incentive that rewards the best performing resources — an innovation being used for the first time in FCA 9 — a sloped demand curve, a seven-year price lock-in for new resources and the ability to defer a capacity obligation for one year under extraordinary circumstances.

The region was divided into four zones: Connecticut; Northeast Massachusetts/Greater Boston (NEMA/Boston); Rest of Pool (ROP); and a new zone, Southeast Massachusetts/Rhode Island (SEMA/RI).

Shortfall

In SEMA/RI — home of the 1,517-MW Brayton Point generating station, which is set to close in 2017 — 7,241 MW qualified, falling short of the 7,479 MW needed to meet the zone’s local sourcing requirement.

The shortfall meant the zone was not opened to bidding. Instead, administrative pricing rules were triggered: 353 MW of new resources will receive the auction starting price of $17.73/kW-month, while the 6,888 MW of existing resources will receive $11.08/kW-month, which is based on the net cost to build a new resource.

February 3, 2015June 15, 2023

FERC: PJM Excess Reserve Pricing Proposal Deficient

By Suzanne Herel

The Federal Energy Regulatory Commission issued a deficiency letter last week asking PJM to justify its proposal for pricing reserves in emergencies (ER15-643).

The Jan. 27 letter from FERC’s Office of Energy Market Regulation gave PJM 15 days to respond to a series of questions about the RTO’s effort to reduce uplift and ensure that energy prices better reflect operator actions. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)

The letter questioned PJM’s rationale in valuing extended reserves — reserves procured in addition to primary and synchronized reserves — up to $300/MWh. It also asked PJM how it plans to calculate additional reserve requirements for the day-ahead and real-time markets.

The changes outlined in PJM’s Dec. 17 filing were unanimously approved by the Members Committee on Nov. 21.

“PJM’s proposal merely ensures that the additional reserves already scheduled by PJM’s system operators are included in the updated reserve requirement used by PJM’s market clearing engines,” PJM said. “In this way, PJM will be better able to align market clearing prices with its system operators’ actions, while the total production cost of providing reserves will remain the same.”

The PJM Power Providers (P3) Group and Exelon filed comments in favor of the proposed revisions.

“PJM’s changes will reduce uplift, decrease price suppression and allow for reserves to be priced consistent with market conditions,” P3 said.

The group added, “The broad support for the proposal is an indication of the importance of getting reserve pricing correct and, perhaps more importantly, recognition of the need to procure additional reserves during times of system stress.”

Public Service Electric and Gas and two sister companies offered limited support.

“While a step in the right direction in improving the Tariff provisions concerning shortage pricing, the PJM filing is not a complete solution to achieve PJM’s stated objective — ‘to enhance PJM’s market rules to better capture actions into energy and reserve pricing.’”

PSE&G also said it disagreed “with PJM’s claim that the reliability contribution of primary reserves is necessarily greater than reliability value of ‘extended reserves’ deemed necessary by PJM’s own operators during times of system stress.”

February 3, 2015

FERC Seeks $5M from Maxim Power; Clark Dissents

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.

February 3, 2015May 28, 2025

PPL, Riverstone Accept FERC Mitigation Plan on Talen Spinoff

By Ted Caddell

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.

February 3, 2015June 15, 2023

LaFleur: FERC an ‘Honest Broker;’ Won’t Take Sides on Clean Power Plan

By Michael Brooks

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.”

February 3, 2015

Michigan PSC to MISO: Show Us the Numbers

By Chris O’Malley

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.)

February 3, 2015June 15, 2023

ISO-NE Opens FCA 9 amid Expectations of High Prices

By William Opalka

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).

FERC, which has asked the Supreme Court to reconsider the ruling, rejected the generators’ challenge last month (ER15-257). (See FERC Approves New England Demand Response Integration.)

[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.]

February 3, 2015

MISO Planning Advisory Committee Briefs

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.

February 3, 2015June 15, 2023

FERC Questions NYISO Plan to Terminate Generators’ Interconnection Rights

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.

February 3, 2015June 15, 2023

MISO Reliability Subcommittee Briefs

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 standard was approved by the Federal Energy Regulatory Commission in January 2014. (See FERC OKs Rules on Geomagnetic Disturbances, Frequency Response.)

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.

FERC approved the standard, the first phase of rules to protect the grid from GMDs, in June. (See FERC OKs GMD, Training Standards; Proposes Modeling Rule Change.)

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.

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.