1950: Dunkirk units 1 and 2, each 75-MW simple-steam coal plants, go into operation on Lake Erie, 55 miles southwest of Buffalo, N.Y.
1959-1960: Dunkirk adds units 3 and 4, 185 MW coal-fired, simple-steam units.
1999: NRG Energy acquires Dunkirk from Niagara Mohawk Power. NRG later converts the plant to use low-sulfur Powder River Basin coal and installs controls on mercury and nitrogen oxide emissions.
March 2012: NRG says it will mothball Dunkirk effective Sept. 10, 2012.
August 2012: The New York Public Service Commission approves a reliability support services agreement between NRG and Niagara Mohawk parent National Grid to keep Dunkirk operating to maintain system reliability. National Grid agrees to pay NRG $2.9 million per month for the nine-month period of Sept. 1, 2012, through May 31, 2013, with additional cost adjustments for taxes and coal costs, and credits for capacity market revenues earned by Dunkirk.
May 2013: The PSC approves a new RSSA between NRG and National Grid through May 31, 2015, at a cost of $2.1 million per month, with the same cost adjustments as the original RSSA.
February 2014: The Federal Energy Regulatory Commission accepts and suspends National Grid’s proposed rates to cover the cost of the RSSA. FERC accepts the changes subject to refund and further order, saying it was not convinced the changes were just and reasonable.
June 2014: The PSC approves a $140 million plan to upgrade three Dunkirk units from coal to natural gas, with a capacity of 435 MW. The PSC selected the repowering over a plan to invest up to $76 million in transmission upgrades, which would have addressed reliability concerns and allowed the plant to close. Closing the plant, Chautauqua County’s largest taxpayer, would have reduced the city’s property tax revenues by more than 40%. The repowered plant is expected to pay about $8 million in property taxes annually.
October 2014: The Sierra Club files suit against the PSC over the repowering plan.
January 2015: National Fuel Gas and NRG announce a settlement allowing National Fuel to build a 9.3-mile pipeline to supply Dunkirk. National Fuel and Dunkirk Gas, an NRG affiliate, had originally offered competing pipeline proposals to the PSC.
February 2015: Entergy sues the PSC, alleging it infringed on FERC authority by approving the repowering plan.
March 2015: Niagara Mohawk informs PSC it will exercise its option to extend the RSSA for seven months through Dec. 31, 2015.
September 2015: Projected completion date of Dunkirk repowering.
About 500 organizations will be relieved of some grid reliability regulations and another 200 exempted entirely under the North American Electric Reliability Corp.’s new method for classifying entities under its jurisdiction.
The Federal Energy Regulatory Commission last week approved NERC’s Risk-Based Registration (RBR) initiative, with a few modifications and caveats (RR15-4).
The order approves NERC’s proposals to:
Remove purchasing-selling entities and interchange authorities as functional registration categories. Because these entities’ activities are commercial in nature, their removal poses little or no risk to reliability, NERC said. FERC rejected a proposal to also remove load-serving entities from registration, ordering NERC to provide more information to ensure that there are no reliability gaps.
Raise the threshold for registering entities as distribution providers to those with loads of 75 MW or more, up from 25 MW. NERC also will provide a subset list of reliability standards to distribution providers that are subject to NERC rules solely due to their operation of underfrequency load shedding protection systems. The change is expected to affect about 100 entities, representing less than 1% of load served by NERC-registered distribution providers.
Align five functional registration categories with the 2012 revised definition of the bulk electric system.
Make procedural changes to its registration process, including the introduction of a “materiality” test for registration.
NERC’s Compliance Registry currently lists more than 1,600 organizations responsible for about 4,300 reliability functions under 15 functional entity categories.
The commission said the changes would allow regulators to focus resources on entities with the greatest potential impact on reliability.
NERC said the changes will reduce regulation of about 700 organizations, with about 200 exempt from all NERC rules, and another 500 removed from some registrations while remaining regulated under others. For example, interchange authorities, which verify and communicate interchange schedules, are also registered as either a balancing authority or reliability coordinator.
FERC Chairman Cheryl LaFleur called the changes “another significant step in the evolution” of the mandatory reliability standards ordered by the Energy Policy Act of 2005.
In February, FERC approved NERC’s risk-based approach to reliability compliance monitoring and enforcement, which will reduce the kinds of reliability violations subject to NERC enforcement, with “minimal”-level risk issues subject to less oversight (RR15-2). (See New NERC Enforcement Methods Allow Self-Logging Minor Risk Issues.)
Commissioner Norman Bay said that it is “incumbent on NERC to show that reliability is in fact being enhanced” as a result of the changes.
The Tennessee Valley Authority, releasing its 20-year integrated resource plan, said it anticipates no new major power generation projects after the Watts Bar 2 nuclear facility, which is scheduled to start operations at the end of the year.
According to the plan, TVA predicts slow load growth and says it will be able to replace retiring coal plants with purchased power, energy efficiency or moderate construction plans. It said 26 of its 59 coal-fired plants will retire by the end of next year. There are no plans to restart construction at the Bellefonte Nuclear Power Plant in Alabama, where it has already invested $6 billion.
“We really don’t see an immediate need for any new large baseload capacity beyond what we already have underway,” TVA Vice President Joe Hoagland said.
A fire in a coal bunker last week at Xcel Energy’s Black Dog Generating Station in Burnsville, Minn., injured one worker and forced the evacuation of dozens of others, but operations at the 538-MW plant were unaffected.
The cause of the fire and explosion in the Unit 4 coal bunker is under investigation. The same plant experienced a fire and explosion in 2010 that destroyed 200 feet of the plant’s west wall. Three firefighters were injured in that blaze.
Philip Morris, Dominion Building Largest Solar Facility in Virginia
Dominion Virginia Power and Philip Morris USA are building a 2.4-MW solar plant on the grounds of a Philip Morris facility in suburban Richmond.
The 8,000-panel solar farm will be Virginia’s biggest. Dominion has built and operates 4.8 MW of solar generation in Virginia. It plans to increase solar capacity up to 200 MW by 2020.
PSEG Takes Salem 1 Offline After Missing Repair Deadline
PSEG Nuclear took Salem Unit 1 offline after missing a Nuclear Regulatory Commission-imposed repair deadline.
Workers at the 1,150-MW unit were unable to restart one of five cooling units in the containment area. NRC regulations say if one cooling unit remains inoperable for seven days, the reactor must be shut down.
Salem 1 is the oldest of three units that PSEG Nuclear operates at its site on Artificial Island on the Delaware River in southern New Jersey. The company did not say when the plant would go back into operation.
NextEra Resources has begun to reach out to property owners about its plans to build a $250 million 150-MW wind project in eastern Stark County, N.D.
According to an application filed with the state Public Service Commission, NextEra would spread 87 wind turbines over about 61 square miles. It has secured a 30-year power purchase agreement from Bismarck-based Basin Electric Power Coop. for the output.
AEP Wins Permission to Cut Customers’ Power Remotely
The Public Utilities Commission of Ohio last week granted American Electric Power’s request to remotely disconnect delinquent electricity customers, becoming the first Ohio utility to use its smart meters to shut off service without conducting a home visit.
AEP said it will not apply the policy to some vulnerable customers, including those with mental disabilities or who rely on medical equipment. Customers still will receive several warnings before their power is shut off. Consumer advocates opposed the change, saying it will lead to an increase in disconnections.
The new policy, which applies to 132,000 customers, will go into effect Aug. 1 and last for two years, when AEP will have to reapply.
Williams Gets Green Light for Rock Springs Expansion
Williams has received federal approval to construct and operate a $79.5 million, 11-mile expansion to its Transcontinental Pipeline to deliver gas to Old Dominion Electric Coop.’s new Wildcat Point Generating Facility in Cecil County, Md.
The Rock Springs Expansion Project is expected to provide 192,000 dekatherms daily of firm natural gas transportation service to the power plant.
FirstEnergy Wants to Ship Mansfield’s Ash to Hatfield’s Ferry Plant Site
FirstEnergy wants permission to ship the coal ash from its Bruce Mansfield Plant in Beaver County, Pa., to an existing dump at a closed power station in Greene County to the north.
The Akron company faces a 2016 deadline to close the current landfill that receives Bruce Mansfield’s waste, but its first choice for an alternative, a closed strip mine in neighboring Fayette County, needs a dewatering facility that has not yet received permits. Until the strip mine site is built, FirstEnergy wants to deliver the ash to the Hatfield’s Ferry Power Station site, where the power plant closed in 2013, but its ash landfill still has “several years” of capacity, a company spokeswoman said.
The Department of the Interior on Friday released its long-awaited rules for oil and gas development on federal and tribal lands, which could set a nationwide standard for the controversial practice of hydraulic fracturing.
The new rules require more stringent standards for storage of wastewater produced from fracking and for drilling companies to disclose chemicals used in the hydraulic fracturing process. Exploration companies will also have to provide more information about nearby existing wells, which can inadvertently become pathways for fracking fluids to migrate into groundwater.
“We need to update our regulations to make sure they can keep up with evolving technologies and innovation by industry,” Interior Secretary Sally Jewell said.
While the rules will govern only about a tenth of drilling sites, mostly in Western states, the new regulations set a national standard that might be applied to states where oil and gas regulations are more lenient. “We think this is going to be a template for how the federal government expects the states to regulate water as part of their own oversight of fracking,” said Kevin Book, managing director of energy research firm ClearView Energy Partners.
The oil and gas industry’s supporters criticized the rules as too harsh and said they would increase costs for drillers whose margins already have been depressed by slumping energy prices. “America’s energy boom is one of the best things going for our economy and keeping it going should be one of the federal government’s top priorities,” said House Speaker John Boehner (R-Ohio).
Some environmental groups said the rules weren’t stringent enough. The rules have been in the works since 2012 and took into account 1.5 million public comments.
“There is a lot of fear and public concern, particularly about the safety of groundwater and the impact of these operations,” Jewell said. “We believe these standards are essential.”
The Nuclear Regulatory Commission has given Westinghouse Electric permission to test its small modular reactor design after the company satisfied a safety review that began in 2012.
The NRC issued its Safety Evaluation Report after the company submitted detailed analyses on what would happen in the event of a small loss of coolant accident, or LOCA. Westinghouse said its passive safety systems eliminate the potential for a larger LOCA.
The 225-MW pressurized water reactor’s design is adapted from the company’s larger AP1000 reactor, which received a design certification amendment from the NRC in 2011.
NRC Denies Vermont’s Request to Delay Review of Vermont Yankee Decommission Plan
The Nuclear Regulatory Commission denied a request by Vermont officials to delay a review of the permanent shutdown of the Vermont Yankee nuclear plant.
State officials have expressed concern that Entergy, the plant’s operator, wants to cut emergency preparedness procedures for the plant during decommissioning. The NRC said the state did not file a timely request to delay the review by the Atomic Safety and Licensing Board. The commission said the state could refile its request.
The Nuclear Regulatory Commission plans to spend $2 million to complete a groundwater impact study for the site of the Yucca Mountain nuclear waste storage facility.
The Department of Energy, which is no longer interested in developing the site, decided not to fund the groundwater study. The NRC, which is considering revitalizing the nuclear waste storage project, announced it will fund the study ahead of public sessions scheduled for September.
DOE Buying 5 Million Barrels of Crude to Replace Stock Sold Last Year
The Department of Energy is buying 5 million barrels of crude oil to replace an amount it sold last year out of the U.S. Strategic Petroleum Reserve in a test sale.
The markets are working in the government’s favor, as oil prices have plummeted more than 50% since March 2014, when it sold the oil for an average price of $93.75 a barrel. The average price of sweet crude was about $47.05 a barrel last week.
By law, the department is required to replace any stocks sold within a year. The strategic petroleum reserve, with a total capacity of 727 million barrels, currently stands at about 691 million barrels.
University of Delaware Declines Congressional Request for Funding Info on Climate Denier
Grijalva
The University of Delaware declined a request from the ranking Democrat on the House Committee on Natural Resources to disclose the funding received by David R. Legates, a climate-change skeptic.
U.S. Rep. Raul Grijalva of Arizona demanded to know the sources of funding for Legates, a climatology professor who has co-authored several contrarian studies with Wei-Hock Soon, who received funding from the Southern Co. Legates was the state climatologist until he was fired in 2011, in part for refusing to stop using his title when spreading his skeptical views on climate change.
The university cited academic freedom for declining to provide Legates’ funding sources.
NRC Gives Environmental OK for TVA’s Sequoyah Nuke Plant
The Nuclear Regulatory Commission has approved the environmental assessment required for a 20-year license extension at the Tennessee Valley Authority’s Sequoyah Nuclear Power Plant in Soddy-Daisy, Tenn.
The NRC approved the assessment at the twin-unit plant despite challenges from activists who argued that TVA hasn’t made necessary safety improvements in response to the Fukushima disaster in Japan. “The NRC side-stepped most of the complaints that we raised,” said Louis Zeller, executive director for the Blue Ridge Environmental Defense League.
If the final license extension is approved, TVA would be able to operate both 1,148-MW units until 2041.
WASHINGTON — Chairman Cheryl LaFleur gaveled her final Federal Energy Regulatory Commission open meeting last week, nearing the end of a tumultuous 16-month term.
Cheryl LaFleur comments on her final meeting as FERC chairman as her replacement, Commissioner Norman Bay (right), listens.
LaFleur, who was confirmed to a second, five-year term on the commission in July, is turning over the chairmanship to former FERC Office of Enforcement Director Norman Bay effective April 15.
Bay will assume the chairmanship under an unprecedented deal between the White House, which wanted Bay named chairman immediately, and Senate Republicans, who wanted LaFleur to remain in charge.
While LaFleur won confirmation 90-7, Bay — attacked by some Republicans for his lack of regulatory experience and controversies over his role as Enforcement director — cleared on a 52-45 party-line vote. With the Republicans now in control of both houses of Congress, he will enter the chairmanship without LaFleur’s reservoir of goodwill.
Among the immediate challenges Bay will face is how to handle protesters who have become fixtures at commission meetings. (See Protests Continue — on Camera — at FERC.) He also will be seeking consensus on the commission’s role in ensuring reliability isn’t harmed as a result of federal regulations on carbon dioxide emissions. (See FERC Seeking Its Role on Carbon Rule ‘Safety Valve’.)
LaFleur was appointed acting chairman in late November 2013 to replace Jon Wellinghoff. After LaFleur and Bay were confirmed by the Senate, President Obama removed the “acting” from LaFleur’s title.
At Thursday’s meeting, LaFleur’s fellow commissioners, FERC staffers and audience members celebrated her tenure with a standing ovation. Bay thanked her for what he called her “outstanding leadership.”
“As passionate as she is about Boston area sports teams,” he said of LaFleur, who dons Red Sox and Patriots jerseys at commission meetings when her teams are in the playoffs, “I think she’s even more passionate about the work of FERC.”
In a press conference after the meeting, LaFleur cited the commission’s work on capacity and energy markets, natural gas infrastructure, physical security of the grid and geomagnetic disturbances as among the accomplishments of her tenure in the commission’s center chair.
She also will leave her mark with appointments of new heads for the Office of Energy Market Regulation, the Office of Energy Policy and Innovation and the General Counsel’s office.
“The work of the commission takes place over a long time horizon and so I built on the work of my predecessors,” she said. “And that work will still be ongoing in the new configuration of the commission.”
“From a very personal perspective, I think providing what I hope was steady and sustained leadership to the commission — at a time when it had been through a lot of upheaval during the inspector general investigation and some unexpected things that took place at a time when I didn’t even know my own future — is what … I take most satisfaction from.”
Bay’s ascension to the chairmanship may not be the last of the changes this year on the 11th floor of 888 First St. N.E.
Republican Commissioner Philip Moeller’s term expires June 30. Moeller said earlier this month he would consider a new term but gave no indication that he will be renominated.
“I’m still enjoying it,” he told RTO Insider. “I’ve gotten a lot of encouragement to stick around. But ultimately it’s up to the Senate and president. Stay tuned.”
The Federal Energy Regulatory Commission last week ordered hearing and settlement procedures in a dispute over the costs of keeping NRG Energy’s Dunkirk, N.Y., generating plant online for reliability.
At issue are charges National Grid — whose subsidiary Niagara Mohawk Power serves the region — proposed adding to its transmission service rate to reflect its costs under a reliability support services agreement for the coal-fired generator.
The New York Association of Public Power, Allegheny Electric Cooperative and the Municipal Electric Utilities Association of New York (MEUA) protested the charges as excessive and said they should be shared by other users of the transmission system in western New York, such as New York State Electric and Gas.
Need for Fact Finding
In February 2014, the commission accepted National Grid’s proposed rates subject to refund and further order, saying it was not convinced the changes were just and reasonable.
FERC said last week that it needed to conduct fact finding to make a definitive ruling on the rate changes and underlying RSSA charges. It said a hearing would be conducted if National Grid and the protesters were unable to reach a settlement (ER14-543).
In a related order last week, FERC also denied a separate rehearing request by MEUA, which had challenged the commission’s decision to waive the 60-day prior notice requirement to permit National Grid’s filing to become effective July 1, 2013. The association had also objected to the commission’s decision not to impose a full five-month suspension period (ER14-543-001).
“National Grid’s customers were on notice that RSS-type costs were being incurred and were to begin to be passed through in [transmission service] charges beginning July 1, 2013, even though the exact costs would not be determined until a later time,” FERC wrote.
The orders followed the commission’s decision last month directing NYISO to draft standard rates and cost allocation provisions for reliability-must-run (RMR) services (EL15-37). (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)
Entergy Suit
Meanwhile, a new front opened in the Dunkirk dispute last month when Entergy sued the New York Public Service Commission, alleging it interfered with FERC authority in regulating wholesale electricity markets in June 2014 by approving an agreement between NRG and Niagara Mohawk to repower the plant with natural gas, allowing it to continue operating through 2025 (5:15-CV-230).
“NYPSC issued an order … that will keep the uneconomic Dunkirk generator in the market for a decade (through 2025), propped up by subsidies from a local utility and from a state agency,” Entergy said in the complaint, filed in U.S. District Court for the Northern District of New York.
Dunkirk will receive out-of-market payments of $20.4 million per year from National Grid and a $15 million one-time subsidy from New York state.
Entergy, owner of the 838-MW James A. FitzPatrick nuclear plant in western New York, claims the agreement will suppress capacity auction clearing prices.
FERC last week rejected a similar “price suppression” argument by the Independent Power Producers of New York in a complaint over Dunkirk and a second generator receiving payments under RSSAs. (See related story, NY Generators’ ‘Price Suppression’ Complaint Dismissed.)
Entergy’s complaint raises constitutional challenges similar to those that led federal courts to void actions by regulators in New Jersey and Maryland to incentivize construction of new generation. (See Rebuffed by Courts, CPV Seeks FERC End-Around.)
Trial staff at the Federal Energy Regulatory Commission has recommended approval of a settlement that would reduce transmission owner Niagara Mohawk Power’s return on equity to 10.03% from the current 11.5%.
Niagara Mohawk, a unit of National Grid, reached the agreement with the Municipal Electric Utilities Association of New York, the New York Association of Public Power and the Allegheny Electric Cooperative.
NYISO last week defended its proposed redesign of voltage support compensation, telling the Federal Energy Regulatory Commission it should reject calls by generators for additional inflation adjustments (ER15-1042).
On Feb. 13, NYISO proposed paying voltage support service (VSS) providers $2,592/MVAr for both leading and lagging capability, with annual increases based on the consumer price index (CPI). MVAr is the unit of measurement for reactive power capability.
The current rate is $3,919/MVAr annually based on lagging reactive power capability alone. Although the new rate is lower, the inclusion of both leading and lagging capabilities in the calculation is expected to result in total compensation about equal in the first year to how it has been in past years.
The proposal, the result of more than a year of discussions, won support of almost 80% of stakeholders, including more than half of the generation owners that voted, at the Nov. 20, 2014, Management Committee meeting, the ISO said.
On March 6, however, the Independent Power Producers of New York and Dynegy Marketing and Trade filed separate protests asking FERC to order the ISO to increase the compensation rate to reflect inflation since the existing rate was set in 2002.
IPPNY said it agrees with the ISO in using the CPI to escalate future payments. “If this reasoning serves to justify the use of the CPI to track inflation of costs from this point forward, the commission should apply the same reasoning retroactively to the escalation of costs over the last decade,” the group said.
NYISO said the proposal to include an inflation adjustment in the compensation proposal “was one of the most contentious issues addressed in the stakeholder process.” The ISO’s initial proposal in September 2013 did not include any escalation for past or future inflation. The ISO added a going-forward inflator to its revised proposal to stakeholders in December 2013.
“Although a majority of stakeholders supported increasing the annual VSS compensation rate, they considered, and rejected, a proposal to escalate the proposed starting point for the 2014 VSS compensation rate by applying the annual CPI for each year from 2002 through the present,” the ISO told FERC. “Neither did any NYISO market participant present any evidence during the stakeholder process to indicate that the existing compensation rate, as approved in 2002, was unreasonably low.”
NYISO said it proposed the compensation changes due to the increased need for leading reactive power support. Since 2010, the number of requests for leading reactive power support has increased due to higher off-peak transmission voltages, the ISO said. More than 90% of the ISO’s reactive power support requests since 2010 have been for leading reactive power; before 2010, more than 90% of the requests were for lagging reactive power support.
Generation owners will be exempted from federal open access transmission rules, allowing them to reserve excess capacity on their tie lines for the first five years of operation, under an order approved by regulators last week.
The Federal Energy Regulatory Commission, which has been studying the issue since a 2011 technical conference, said it will grant a blanket waiver from Open Access Transmission Tariff (OATT) requirements for “interconnection customer’s interconnection facilities,” or tie lines (RM14-11).
Under previous policy, a tie line owner must make excess capacity available to third parties unless it can justify its planned future use of the line. The new rule creates a five-year “safe harbor” period during which a tie line owner is assumed to have plans to use the excess capacity on its facilities.
The order eliminates the need for generation owners to seek OATT waivers, a requirement that the commission said created an undue burden. “While the commission has processed scores of requests for transmission tariff waivers in recent years, a third party has requested service, and thus required the interconnection customer to file a tariff, in only four instances total,” commission staff said in a presentation on the new rule.
Third parties seeking to obtain access to tie lines can do so through the procedures applicable to requests for interconnection and transmission service under sections 210, 211 and 212 of the Federal Power Act, which allow tie line owners to negotiate access with third parties.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
A. Manual 11: Energy & Ancillary Services Market Operations — Adds a method for screening of demand bids by load-serving entities. Bids would be limited to the LSE’s calculated zonal peak demand reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. PJM said the need for such limits was illustrated by the default of a retail provider in January 2014. Due to an input error, the company entered a demand bid about 100 times the retailer’s actual load. (See MIC Briefs.)
PJM requires resources to provide symmetrical regulation from their set points.
B. Manual 12: Balancing Operations — Revisions describe the required regulation range, specifying that resources are required to symmetrically provide the total amount of regulation assigned. The changes also detail how performance evaluations are conducted and further define the basepoint around which the resource will be regulating.
3. FTR REVISIONS (9:30-9:45)
Members will be asked to approve non-substantive revisions regarding financial transmission rights. The changes concern clearing deadlines, bilateral trades and Tariff references.
4. ENERGY MARKET UPLIFT SR. TASK FORCE (9:45-10:15)
Members will be asked to endorse revisions to rules regarding treatment of combustion turbine lost opportunity costs and a proposal that uplift be treated as an input to the Regional Transmission Expansion Plan. Under the new CT rules, PJM would use the generator’s energy schedule to calculate opportunity costs except for self-scheduled units, for which the lesser of the available cost- or price-based curves would apply.
5. DEMAND RESPONSE Forecast for Use in RTEP (10:15-10:30)
Members will be asked to OK a proposed change to demand response modeling assumptions used in load deliverability analyses. The new method would use the average of the last three years of committed DR for each zone. (See Change Proposed in PJM Demand Response Modeling.)
6. FERC Order 1000 (10:30-10:45)
Members will be asked to endorse a $30,000 non-refundable fee for studying proposed transmission improvements with estimated costs of $20 million or more. The fee would apply to both greenfield projects and upgrades by incumbent transmission operators. The Federal Energy Regulatory Commission last month rejected an earlier proposal to exempt transmission upgrades from the study fee. (See FERC Rejects Fee on Greenfield Transmission Projects.)
Members Committee
CONSENT AGENDA (1:20-1:25)
B. Members will be asked to approve Tariff and Operating Agreement revisions to implement Coordinated Transaction Scheduling (CTS) with MISO. The objective is to improve interchange scheduling efficiency by aligning energy scheduling with interface prices and adding the option for market participants to schedule energy transactions using an interface bid. (See PJM, MISO Reach Agreement on New Interchange Product.)
ENDORSEMENTS (1:25-1:40)
1. FERC Order 1000: See MRC agenda item #6, above.
