Company Briefs

Duke Energy Carolinas reached a settlement with stakeholders on a revised energy efficiency plan that will add programs for multifamily housing and commercial customers.

The agreement with the Environmental Defense Fund and the North Carolina Utilities Commission’s consumer advocates includes a $400,000 bonus if the company increases energy savings by more than 1% in any year.

Under the old program, Duke recovered the costs of the energy savings program as though they were an investment in a power plant. The new plan will use a shared-savings mechanism similar to that used by Dominion North Carolina Power and Duke Energy Progress.

The new offerings will be available in January if the commission, which held a hearing on the proposal Aug. 19, approves.

More: The Charlotte Observer, Charlotte Business Journal

Duke Energy Purchases San Francisco Solar Plant

Duke Energy Renewables has acquired the 4.5 MW Sunset Reservoir Solar Power Project from developer Recurrent Energy. The system’s almost 24,000 solar panels, mounted above the Sunset Reservoir, provides power for municipal facilities through a 25-year power purchase agreement with the San Francisco Public Utilities Commission (SFPUC).

More: Renewable Energy Focus

NRC Meets with Duke on Nuclear Plant Incident

The U.S. Nuclear Regulatory Commission met with Duke Energy Aug. 19 to discuss an October 2012 incident in which the failure of radiator fan belts caused a shutdown of the Robinson nuclear plant’s shutdown diesel generator.

An NRC spokesman said the poorly maintained fan belts could have meant the generator was not available during a loss of offsite power at the plant in Hartsville, S.C. The agency said it will announce any penalties over the incident at a later time.

More: Associated Press

Damage Suit Reinstated vs. NRG Coal Plant

NRG Energy Inc. must defend a lawsuit claiming that ash and contaminants from its coal-fired power plant in Springdale, Pa., damaged nearby properties, an appeals court ruled. The U.S. Appeals Court in Philadelphia reversed a lower-court decision dismissing the suit, rejecting NRG’s claims that the federal Clean Air Act pre-empts state law claims by property owners.

The residents claim that odors produced by the plant, 18 miles northeast of Pittsburgh, made them “prisoners in their own homes” while ash and unburned byproducts settled on their properties.

More: Bloomberg

Covanta Acquires NJ Waste to Energy Plant

Covanta Waste to Energy Facility in Camden, NJ (Source: Covanta Energy) — (Source: Covanta Energy)

Covanta Holding Corp. announced Aug. 19 it has purchased a 21 MW waste to energy plant in Camden, N.J. from a subsidiary of Foster Wheeler AG. The acquisition increased Covanta’s holdings in PJM to 15 generators totaling about 569 MW.

More: Covanta Holding Corp.

August 27, 2013

FirstEnergy Issues Coal Plant Layoff Notices as PJM Seeks Delay

FirstEnergy Corp. has begun sending layoff notices to workers at two Southwestern Pennsylvania coal-fired generating plants even as PJM notified the company it won’t complete transmission upgrades in time for the plants’ scheduled Oct. 9 shutdowns.

Mitchell Power Plant (Source: FirstEnergy)

FirstEnergy expects to lay off about 380 workers as a result of the closing the 370 MW Mitchell Power Station and 1,710 MW Hatfield’s Ferry Power Station.

However, PJM asked the company in early August to postpone the shutdown, saying it needed more time to complete transmission upgrades needed to maintain reliability in the plants’ absence.

“We are reviewing their request and will be responding to it,” First Energy spokeswoman Stephanie Thornton told RTO Insider last week. “That’s all I can say at this point.”

PJM’s Tariff requires generators to provide at least 90 days’ notice of plant closings to allow the RTO time to evaluate reliability impacts.

Generators that delay shutdowns for reliability reasons are entitled to compensation to recover operating costs. But the Tariff does not give PJM the power to block a plant shutdown.

PJM spokeswoman Paula DuPont-Kidd said PJM will provide details on the upgrades needed when it completes its review.

Hatfield's Ferry Power Plant (Source: FirstEnergy) — Hatfield’s Ferry Power Plant (Source: FirstEnergy)

FirstEnergy President and CEO Anthony Alexander told analysts on an Aug. 6 earnings call that neither plant cleared the last PJM capacity auction and that some of the individual units hadn’t cleared the auctions for several years. Alexander said the plant closings, which were hastened by environmental regulations, are part of a company-wide cost-cutting plan, which includes an additional 250 layoffs and reductions in medical and other benefits.

FirstEnergy said the two plants represented 10% of its generating capacity but about 30% of its cost to comply with the EPA’s mercury and air toxics standards (MATS). The closure will reduce FirstEnergy’s MATS compliance costs to $650 million from $925 million.

PJM asked FirstEnergy last year to continue operating three Ohio coal-fired power plants slated for closure, the Ashtabula, Lake Shore and Eastlake plants. The company agreed to keep those plants running until early 2015 under “reliability must-run” rules while it installs new transmission lines to maintain reliability.

August 27, 2013

Settlement on FE Coal Plant Still a Bad Deal: Consumer Group

FirstEnergy Corp. reached a settlement last week in a controversial bid to shift a coal-fired generator from its unregulated subsidiary to regulated utility Monongahela Power, but a consumer group says the reduced price is still a bad deal for ratepayers.

Harrison Power Plant (Source: FirstEnergy)

Under the settlement, Mon Power ratepayers would pay Allegheny Energy Supply Company about $800 million for the 80% of the 1,984 MW Harrison plant it doesn’t already own, a reduction from AE’s original asking price of $1.1 billion. The revised deal was signed by the staff of the West Virginia Public Service Commission, the Consumer Advocate Division, the West Virginia Energy Users Group and several trade unions.

FirstEnergy said the deal will provide rate stability by shielding Mon Power customers from “unpredictable spot market prices.” Residential customers would receive a 1.5% rate cut, the company said.

But the West Virginia Citizen Action Group filed a challenge to the settlement Friday, saying the purchase price is still far more than the $554 million value that Allegheny Energy assigned to Harrison before the company’s acquisition by FE in 2011. The acquisition also would leave Mon Power dependent on Harrison and a second coal generator — the 1,107 MW Fort Martin station, which was built five years before Harrison — for 90% of its power.

“West Virginia rate payers will be stuck with obsolete, highly expensive coal-fired electricity long after the market has moved on, thereby locking an already burdened industrial base into the least competitive fuel source on the planet,” CAG’s attorney wrote. The group said it would be cheaper and less risky for ratepayers to purchase power from the PJM market. (See: Natural Gas Group Seeks Voice in West Virginia Coal Plant Acquisition)

On July 31, Virginia regulators cited a lack of fuel diversity for rejecting AEP’s request to transfer a coal-fired plant from an unregulated subsidiary to its Appalachian Power utility.

Byron Harris, director of the West Virginia state Consumer Advocate, acknowledged that the FirstEnergy settlement did not give his office all that it sought. “Any settlement is by its nature a compromise,” he told The State Journal. “There are what we believe are benefits in the settlement.”

The West Virginia commission yesterday ordered parties in the case to agree by Thursday on a hearing date to review the settlement.

More: StopPATH WV, Daily Mail

August 27, 2013

PJM MRC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee Thursday. (There is no Members Committee meeting this month.) 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.

2. PJM Manuals (9:10-9:25)

A. Manual 28: Operating Agreement Accounting

Reason for change: Incorporating changes to lost opportunity cost compensation as approved by FERC.

Impacts:

Changes sections 5.2.6 and 5.2.8 (Operating Reserve & Reactive Services Lost Opportunity Cost Credits) to limit lost opportunity cost compensation to the lesser of a unit’s economic maximum or maximum facility output as approved in FERC Docket ER13-1200.
Section 7.2 (Shortage Pricing) amended to incorporate calculation details for non-synchronized reserve market lost opportunity costs.
Modifies section 5.3 (Operating Reserve) to correct errors and provide clarifications on exempting deviations during shortage conditions and revisions for associating interfaces to the East or West BOR regions.
Modifies sections: 5.2.3 to incorporate details of Lost Opportunity Cost Credit for Synchronous Condensing; 5.2.6 (Wind Lost Opportunity Cost) to align language with Tariff; 17.3 (Allocation of Annual and Monthly FTR Auction Revenues) to correct section reference.

PJM contact: Stan Williams

B. Manual 14B: PJM Region Transmission Planning Process

Reason for changes: Updates to reflect changes from FERC Order 1000, switch to two-year planning cycle and revised benefit/cost test for Market Efficiency projects.

Impact:

Separates Reliability and Market Efficiency into subsections
Adds a new section (2.1.2) to explain two-year planning cycle on Market Efficiency projects.
Changes to reflect Order 1000.
Changes energy market benefit calculation component of benefit/cost ratio for Market Efficiency projects eligible for regional cost allocation. The change in total energy production cost and change in load energy payments (previously weighted .70/.30) will be equally weighted.

PJM contact: Tim Horger

3. CETL Stability– Easily Resolved Constraints (9:25-9:45)

Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal MRC will be asked to endorse.

Impact: Before posting the planning parameters for each Base Residual Auction, PJM staff would be required to identify Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective. Upgrades that raise the ratio above 115% would be added to the RTEP if they:

Cost less than $5 million;
Can be completed within 36 months or prior to June 1 of the Delivery Year; and
Does not duplicate customer-funded upgrades already in the transmission queue (e.g., one whose cost is assigned to an interconnection customer).

4. Parameter limited schedules (pls) revisions (9:45-10:00)

PJM will add new processes for generators seeking exemptions from operating parameters under changes endorsed by the Market Implementation Committee Aug. 7.

Reason for change: PJM’s generation parameters set defaults for different types and sizes of generators. The parameters cover minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.

Impact: The proposed change would create three types of exemptions:

Temporary Exception: A one-time exception of 30 days or less.
Period Exception: An exception lasting for at least 31 days but no more than one year during the 12 months between June 1 and May 31.
Persistent Exception: An exception lasting for at least one year.

The changes will require revisions to Attachment K of the OATT, Schedule 1 of the Operating Agreement and section 2.3.4 of Manual 11: Energy & Ancillary Services Market Operations.

Assuming FERC approval, the changes will be effective Oct. 1.

PJM contact: Jacqui Hugee

5. Stakeholder Process on Triennial CONE Review (10:00-10:15)

MRC members will be asked to consider changes to the Cost of New Entry (CONE) triennial review process. CONE values are used in PJM’s Reliability Price Model (RPM) to obtain capacity resources.

Reason for problem statement: PJM and members agreed to explore changes in the review process in a settlement approved by the Federal Energy Regulatory Commission in January (Docket No. ER12-513).

Impact of problem statement: The inquiry will assess the use of the Handy-Whitman Index of public utility construction costs for adjusting CONE and other potential changes.

PJM is required to file Tariff changes with FERC in time for the 2014 triennial review or a status report if stakeholders are unable to reach consensus on changes.

PJM contact: Paul Sotkiewicz

August 27, 2013

Market Monitor’s Recommendations

Below are the new recommendations included in the Market Monitor’s State of the Market report for the first half of 2013.

HIGH PRIORITY

Addresses a market design issue that creates significant market inefficiencies and/or long lasting negative market effects.

Operating Reserve — Reexamine allocation of operating reserve charges to participants to ensure payment by all whose market actions result in the incurrence of such charges:
- Eliminate the use of internal bilateral transactions (IBTs) in the calculation of deviations used to allocate balancing operating reserve charges.
- Reallocate the operating reserve credits paid to units supporting the Con Edison – PSEG wheeling contracts.
FTRs — Fix the Financial Transmission Rights overallocation issue:
- Eliminate cross geographic subsidies.
- Improve transmission outage modeling in the FTR auction models.
- Reduce FTR sales on paths with persistent underfunding including clear rules for what defines persistent underfunding and how the reduction will be applied.

MEDIUM PRIORITY

Addresses a market design issue that creates intermediate market inefficiencies and/or near term negative market effects.

Ancillary Services — Remove the distinction between Tier 1 and Tier 2 synchronized reserve, remove the ability to offer MW of synchronized reserve capability, remove the ability to make reserve unavailable, and automatically dispatch primary reserve co-optimized with energy. In the interim, enforce a must-offer requirement for synchronized reserve based on physical capability and increase penalties for non-compliance during spinning events.

LOW PRIORITY

Addresses a market design issue that creates smaller market inefficiencies and/or more limited market effects.

Energy Market — When generator is offline, treat as load (not negative generation) the energy drawn from PJM by those generators for calculating average hourly real-time and day-ahead load.
Demand Response — Load management resources whose load drop method is designated as “Other” should explicitly record the method of load drop.

August 13, 2013

TOs Flex Muscles, Reject Retailer’s Nodal Pricing Bid

Transmission owners flexed their muscles Wednesday, uniting to block proposals that would allow network load customers more frequent opportunities to switch to nodal pricing.

Two proposals by retail marketer Direct Energy to allow a limited number of such switches monthly were rejected by the Market Implementation Committee after utility representatives said the changes would create administrative problems for their electric distribution companies (EDCs).

David Scarpignato, head of PJM regulatory affairs for Direct Energy, said the changes would allow retail marketers to offer more innovative products. He said it would not have significant impact on EDCs or other market participants because it would cap switches at to 5% of the EDC network service peak load. (MIC Considers Loosening Rules on Zonal-Nodal Price Switching)

“This lines up the retail market to the wholesale market better,” he said. “For people who say they support competition, put your money where your mouth is.”

“The existing rules were well-vetted and balanced,” countered Scott Razze, manager of interconnection & arrangements for Pepco Holdings Inc. “Couching this as a minor change is a disservice.”

Few Make the Switch

The Members Committee in 2005 unanimously endorsed a Tariff change allowing the switch to nodal pricing. But after more than seven years under the new rules, all but 15% of PJM load is still using zonal pricing.

The rules give customers one chance a year to switch to nodal pricing, effective June 1 in alignment with the planning year. Customers must provide notice of their intention to switch by October or January depending on type of service.

Scarpignato said the annual window for switching has limited retail marketers’ ability to provide innovative products such as price responsive demand, which he said is most attractive to those with nodal pricing. If a customer’s current contract expires in April, it may not start shopping for a new provider until February, Scarpignato said. But the customer could not make the switch to nodal pricing until the following June — more than a year later.

Opponents of the Direct Energy’s proposal said they were concerned that remaining zonal customers could see their costs increase with a defection of others in their Energy Settlement Area to nodal pricing.

Others cited the impact of intra-year switches on the values of Financial Transmission Rights and Auction Revenue Rights. “That’s really what [the opposition to Direct’s proposal] is all about,” said Marji Philips, ISO services director for Hess Corp.

FTR Windfall

PJM expressed similar concern in explaining to the Federal Energy Regulatory Commission why stakeholders limited switches to once a year. “It is readily apparent that where the zonal price is higher than the price that would be associated with the customer’s specific bus distribution, FTRs initially allocated to hedge the customer’s congestion based on a zonal definition of its load will provide a windfall to that customer,” PJM said.

The merits of the issue became tangled with a parliamentary question when John Horstmann, director of RTO Affairs for Dayton Power and Light, asked for a poll on support for the current rules before a vote on Direct’s proposals.

A Bias Toward Change

John Brodbeck, director of regulatory affairs for Pepco, also called for the status quo poll. “We believe [the PJM issue process] has a bias toward change and a bias toward rapid change,” he said.

After originally promising a poll after a vote on Direct’s proposal, MIC Chairwoman Adrien Ford deferred a decision on Horstmann’s request to give her time to consult PJM rules. “Whatever we do today,” she noted, “could set precedent.”

Ford ultimately ruled that the poll would be taken first. The overwhelming support for the status quo — which was supported by a 98-38 (72%) vote — made the subsequent vote on Scarpignato’s proposals a formality.

Both proposals would have limited intra-year switches to 5% of the EDC network service peak load. As under current rules, customers would be barred from switching from nodal back to zonal without FERC approval.

Direct’s first proposal, which would have further limited switches to five per month per EDC, received less than 35% support. A second option, which would have set the monthly limit at 50 per EDC, won only 28% support.

Those supporting either of Direct’s proposals included retailers, demand response provider EnerNoc, the North Carolina Electric Membership Corp., industrial energy users, the New Jersey Public Power Association and Citigroup Energy, Inc.

Utilities (registered as transmission owners and generators) voted overwhelmingly in opposition.

Not the Last Word

The defeat at the MIC — where some individual TOs hold as many 15 votes — is not the final word.

Scarpignato can bring the proposal before the Markets and Reliability Committee, where a sector-weighted vote would limit the strength of the transmission owners to 20%.

August 13, 2013

Focus on AEP Transformer, Prices in Heat Wave Review

An overworked transformer and the mobilization of demand response were the focus last week as members and PJM staff continued to discuss the mid-July heat wave.

PJM officials gave lengthy briefings to the Operating and Market Implementation committees, explaining their decisions to relieve an overload on the AEP transformer in the west and their mobilization of demand response in the PECO and PPL zones in the east.

The RTO said it will create a “Frequently Asked Questions” report to address the many issues raised by its response to the six-day heat wave, which resulted in the fourth-highest peak demand in PJM history on July 18. “We intend to kind of shake the tree” for lessons learned, said Mike Bryson, executive director of system operations.

Among the issues to be reviewed will be interchange volatility, demand response flexibility (lead time, minimum run time, offer price), the quality of generator data and the creation of localized interfaces.

LMP Comparison - July 18, 2013 (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

Several members asked why demand response set real time prices in FirstEnergy’s ATSI control zone July 18 — peaking at about $1,800 — but not in the PECO and PPL zones, where DR also was mobilized. RTO prices hit $465 at 2 p.m. but plummeted to $52 at 3 p.m. before returning to more than $200 between 4 and 6 p.m. (See Imports, Not DR, Caused Heat Wave Price Crash.)

Jason Barker, wholesale market development director for Exelon, said the heat wave highlighted the need for a reserve product that allows the conservative operations employed by PJM dispatchers to be reflected in prices. “It blows our mind that we’re seeing $52 prices when you have gigawatts [of demand response and peakers dispatched] with prices much higher,” he said.

AEP/ATSI

ATSI - South Canton #3 Transformer Timeline Combined for July 18, 2013 (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

AEP’s formerly anonymous South Canton #3 transformer became an unexpected constraint on July 18 although the problem hadn’t been foreseen in PJM’s day-ahead projections, PJM officials said.

The high loads became acute at the transformer because of an unplanned outage of more than 1,500 MW of generation east of the transformer. “If that [generation] had been on line we wouldn’t have had this problem,” said PJM’s Chris Pilong.

Load on the transformer increased steadily from 9 a.m., briefly exceeding its “Normal Limit” of about 1,900 MVA at about 1 p.m.

PJM officials called on demand response in the neighboring ATSI control zone to maintain flows through the transformer. “It was the biggest bang for your buck,” Pilong said.

Operators also created a temporary interface in the ATSI zone (see map) so that the region had a single LMP reflecting the DR prices.

“It was creating a constraint that accurately reflected the actions the operators took,” explained Adam Keech, director of wholesale market operations.

ATSI Interface Map: July 18, 2013 (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

“The idea is to represent the physical reality that operators were dealing with,” said Stu Bresler, PJM vice president of market operations.

Keech said he wasn’t certain PJM had manual language covering “on the fly” creation of a localized interface. “I’m not sure if we’ve done this before,” he said.

DR Call

While it was the need to unload a constraint that led to the call for DR in the west, it was capacity limits across the system that led to the call for 1,000 MW of DR in PECO & PPL, officials said.

PJM must call for all DR in a zone because its rules don’t allow a call for fractional contributions from zones. “Because it was 1,000 MW we needed we chose PECO and PPL,” Bryson said. “If we needed more we would have called additional zones.”

The Pepco zone was rejected for a DR call because of a water main break in the Washington D.C. suburb of Prince George’s County that threatened to leave thousands without water for days.

If they had to call on demand response again on Friday, Pilong said “we most likely would have looked at different zones from PPL and PECO” because of the annual limits on DR calls for individual providers.

Officials said they expected DR to set energy prices across the entire RTO at their maximum of $1,800. The assumption proved wrong because of an unexpected influx of imports.

RTO LMPs hit $465 at 2 p.m. then plunged to $52 at 3 p.m. before returning to more than $200 between 4 and 6 p.m. The fall in prices came as net interchange jumped from less than 4,700 MW to nearly 7,700 MW.

When the imports arrived, PJM operators unloaded generation that was more expensive.

Keech said 2:40 p.m. to 4:40 p.m. was the minimum run time for demand response. From 4:40 p.m. to 5 p.m., he said, operators discussed whether to release DR. “We decided we didn’t need DR. We didn’t want $1,800 prices.”

August 13, 2013

PJM Proposes Streamlined DR Registration

Members Wednesday heard three proposals for streamlining the time consuming and error prone demand response registration process.

Current rules require Curtailment Service Providers to submit customer names to both the Electric Distribution Company and Load Serving Entity. The EDC and LSE have 10 days to approve or deny the registration. If either rejects the application — for example because they were mistakenly associated with the customer — the process has to begin from the start.

PJM presented the Market Implementation Committee with proposed improvements from the Demand Response Subcommittee, which reached consensus on changes for emergency registrations but split over three options for changing economic registrations.

All three proposals remove the LSE from the Relevant Electric Retail Regulation Authority (RERRA) review process and eliminate LSE review of economic registrations for contractual obligations. (PJM said there has never been a denial because of contractual obligations.) All three also continue the EDCs’ review for economic registrations.

Option 2A, which received the most support within the subcommittee, would remove the LSE from economic registration review process.

Option 2B, which would simplify the LSE role and remove the requirement that they approve the registration also had substantial support.

The final option, 2C, which would keep the LSE role only for Day-Ahead registration review, was the least popular.

Negative Dec

Although Option 2A received the most support within the subcommittee, PJM and others were concerned about its handling of negative decs.

Currently, if a customer registers for economic DR and participates in the Day-Ahead market, PJM places a negative dec on behalf of the LSE for any cleared bids to offset the LSE’s demand bid. PJM would no longer place the negative dec under Option 2A.

PJM’s Andrea Yeaton, who presented the issue to the committee, said eliminating the negative dec can make it difficult for PJM to clear the market.

Jung Suh, of Noble Americas Energy Solutions, LLC, said the negative dec also is important to LSEs. “It protects us from financial harm,” he said.

The issue will be brought to a vote at the next MIC meeting.

August 13, 2013

MIC Corrects Omission in Replacement Capacity Inquiry

The Market Implementation Committee Wednesday revised an issue charge it approved in March, adding a work activity inadvertently omitted from the original.

MIC agreed March 6 to consider changing the rules of the PJM capacity market to eliminate arbitrage opportunities between the Base Residual and Incremental capacity auctions. (MIC to Investigate Arbitrage in Capacity Market)

The issue charge brought to a vote mistakenly omitted a friendly amendment from Dave Mabry, energy management specialist for McNees, Wallace, & Nurick LLC, to include “capacity market costs” in the work activities.

The amended issue charge was approved without opposition.

August 13, 2013

MIC OKs New Process for Exceptions to Generator Parameters

PJM will add new processes for generators seeking exemptions from operating parameters under changes endorsed by the Market Implementation Committee Wednesday.

PJM’s generation parameters set defaults for different types and sizes of generators. The parameters cover minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.

The proposed change, the result of a year-long effort between PJM and the Market Monitor, would create three types of exemptions:

Temporary Exception: A one-time exception of 30 days or less.
Period Exception: An exception lasting for at least 31 days but no more than one year during the 12 months between June 1 and May 31.
Persistent Exception: An exception lasting for at least one year.

The changes will require revisions to Attachment K of the OATT, Schedule 1 of the Operating Agreement and section 2.3.4 of Manual 11: Energy & Ancillary Services Market Operations.

The Markets and Reliability Committee will be asked to endorse the changes at its next meeting. Assuming FERC approval, the changes will be effective Oct. 1.