Page 1378 – RTO Insider

November 23, 2016

Trump: ‘Open Mind’ on Climate Change

By Rich Heidorn Jr.

President-elect Donald Trump said Tuesday he has an “open mind” on humans’ role in global warming, appearing to soften his campaign pledge to withdraw the U.S. from the Paris Agreement.

Trump made his comments in an interview with editors and reporters of The New York Times.

Asked by columnist Thomas Friedman if he would “take America out of the world’s lead of confronting climate change,” Trump responded that he is “looking at it very closely,” adding “I have an open mind to it.”

“I absolutely have an open mind. I will tell you this: Clean air is vitally important. Clean water, crystal clean water is vitally important. Safety is vitally important,” Trump said.

Editorial page editor James Bennet asked, “When you say an open mind, you mean you’re just not sure whether human activity causes climate change? Do you think human activity is or isn’t connected?”

Trump responded: “I think right now … well, I think there is some connectivity. There is some, something. It depends on how much. It also depends on how much it’s going to cost our companies. You have to understand, our companies are noncompetitive right now.”

donald trump climate change — Methane flaring | *Bureau of Land Management*

White House correspondent Michael Shear followed up with a question about the potential of foreign leaders to impose tariffs on American goods to offset the carbon that the U.S. had pledged to reduce.

“I think that countries will not do that to us,” Trump responded. “I don’t think if they’re run by a person that understands leadership and negotiation, they’re in no position to do that to us, no matter what I do. They’re in no position to do that to us, and that won’t happen, but I’m going to take a look at it. A very serious look. I want to also see how much this is costing, you know, what’s the cost to it, and I’ll be talking to you folks in the not too distant future about it, having to do with what just took place.”

Trump did not specifically mention EPA’s Clean Power Plan, which he has vowed to block. Still, his moderate tone was a marked contrast to his previous bombast on global warming.

In a 2012 tweet, he called climate change a hoax created “by the Chinese in order to make U.S. manufacturing noncompetitive.” During the campaign, he said he would “cancel” the U.S.’s involvement in the Paris Agreement, which aims to limit global warming to 1.5 degrees Celsius above preindustrial levels. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)

But in a video released Monday, Trump also made clear that he will steer a different course than President Obama on energy policy, renewing his promise to “cancel job-killing restrictions on the production of American energy, including shale energy and clean coal.”

Trump and the Republican Congress could use the Congressional Review Act to cancel some of the Obama administration’s most recent regulations, including a Nov. 15 Interior Department rule requiring oil and gas producers to use “currently available technologies and processes” to cut methane flaring in half at oil and gas wells on federal and Native American lands.

The act allows an incoming Congress to reject regulations finalized within 60 days of the end of either the House’s or Senate’s sessions.

The Congressional Research Service has concluded the act would apply to regulations finalized after May 30, if Congress holds no more sessions this year, The Washington Post reported Wednesday.

In contrast, an EPA regulation intended to reduce methane gas leaks was finalized on May 12, making it likely exempt from being reversed under the act, the Post reported. EPA said the rule, designed to reduce methane emissions from new or modified oil and gas wells, will prevent 11 million metric tons of carbon dioxide equivalent emissions by 2025.

Posted on November 22, 2016
Public Advocacy Group Files FERC Complaint over PJM Rate Increase

By Rory D. Sweeney

A consumer advocacy group filed a complaint with FERC on Monday saying PJM’s recent rate-increase request is “unprecedented” and failed to consider mitigating costs by limiting employees’ pay increases (ER17-249).

Public Citizen’s Energy Program, based in D.C., filed the complaint in response to a member fee increase that PJM stakeholders approved in October. (See “Members Committee Endorses Revised Fee Hike,” PJM Markets and Reliability and Members Committees Briefs.)

It asks FERC to deny the rate filing “until PJM offers options on controlling certain expenses.”

The complaint argues that the largest factor necessitating the increase is accommodating PJM’s projected 4.8% average annual growth rate in the financial compensation paid to PJM employees over the next eight years.

“PJM already commands premium salaries paid to its employees, particularly to its top executives,” the complaint contends. “For many of Public Citizen’s members, it remains a tough economy. There aren’t many industries or companies within PJM’s service territory that are projecting a 4.8% annual growth rate for employee financial compensation over the next eight years.”

| PJM

“The impact on consumers of PJM’s proposed administrative rate revisions is 7 cents a month, phased in over eight years,” PJM spokesperson Paula DuPont said in an emailed statement. “Consumer advocates representing the PJM region support our proposal and were involved throughout its development. The proposal was unanimously approved by members.”

Public Citizen argues that neither PJM nor its stakeholders — which include state consumer advocates — “ever formally considered dampening growth in employee compensation as a measure to mitigate the rate hike.”

West Virginia Consumer Advocate Jacqueline Lake Roberts defended PJM’s request in a response to the complaint, also filed Monday. Consumer advocates are “active participants” in PJM’s stakeholder process and aren’t treated differently than other members, Roberts wrote in the response.

“As the steward of consumer interests, [Roberts ] takes rates and proposed increases very seriously,” the response reads. “[Roberts] believes that the stated rate as filed will ensure that consumers continue to benefit from these services. For these reasons, [Roberts] submits that the allegations of Public Citizen are erroneous.”

A representative of the Pennsylvania Office of Consumer Advocate was on PJM’s Finance Committee, Roberts noted, and the committee considered several proposals before unanimously endorsing the one filed with FERC — however, all of them assumed cost increases that necessitated rate increases.

While Public Citizen’s complaint said PJM employees “deserve praise and respect for administrating duties on behalf of FERC under the Federal Power Act,” it also noted that PJM’s audited financial reports indicate employee financial compensation grew from more than $98 million in 2011 to more than $124 million in 2015, for an average annual growth rate of 6.1%. Over this five-year period, employee compensation grew from 35.6% of total PJM expenses in 2011 to 37.4% in 2015.

PJM’s request doesn’t detail other “concerning” expenses, the complaint says, such as payments to outside political lobbying organizations and “expensive social events available to select PJM members.”

Public Citizen says it has tried to become a voting PJM stakeholder, but it can’t afford the RTO’s $2,500 annual membership fee.

“It’s certainly easier to balance budgets if you can tap into a pile of someone else’s money to close the gap,” Tyson Slocum, Public Citizen’s Energy Program director, said in an emailed statement.

“The right thing to do would be for PJM to shrink its out-of-control growth in executive pay,” he said. “FERC should not allow PJM to pay for excessive executive compensation through an unprecedented hike in electric rates paid by household consumers. PJM must learn fiscal discipline and recognize that its salary structure is bloated.”

Posted on November 22, 2016
New FERC Rule Will Double RTO Offer Caps

By Robert Mullin

With winter looming, FERC last week adopted a rule that would double the “hard” offer cap for day-ahead and real-time markets to $2,000/MWh in every RTO and ISO.

Order 831 was a response to the 2013-2014 polar vortex, which caused natural gas price spikes that left some generators in the Northeast complaining they were unable to recover their costs (RM16-5).

The commission also noted that the $1,000/MWh offer caps effective in most RTOs could suppress LMPs below the marginal cost of production “given that recent history demonstrates that resource short-run marginal costs can exceed” that cap.

“We find that the currently effective offer caps may prevent a resource from recovering its short-run marginal costs, which could result in that resource operating at a loss,” the commission said in its decision to adopt the rule.

| © mg154 / 123RF Stock Photo

FERC last year approved a PJM measure to increase its offer cap to $2,000/MWh after RTO stakeholders voted overwhelmingly to approve the move. (See PJM Members OK 2,000/MWh Energy Market Offer Cap.)

The commission’s revised offer cap rule sets out three requirements:

Incremental energy offers must be capped at the higher of $1,000/MWh or a resource’s cost-based energy offer, with $2,000/MWh being the maximum bid.

An RTO must verify the costs underlying a resource’s bid above $1,000/MWh before that offer can be used to calculate the market-clearing LMP.

All resources — regardless of type — will be eligible to submit cost-based incremental energy offers in excess of $1,000/MWh.

The final rule modifies FERC staff’s original proposal, which would have converted the current $1,000/MWh cap into a “soft” cap — without implementing a new hard cap. (See FERC Proposes Uniform Offer Caps Across RTOs.)

The commission said the absence of a hard cap could be problematic for RTOs and their market monitors, who might have only “imperfect information” ahead of the market clearing process to verify the short-run marginal costs for resources bidding above $1,000/MWh.

“While a hard cap may diminish the ability to fully address the shortcomings of current offer caps identified above in all circumstances, we find that, on balance, a hard cap is necessary to reasonably limit the adverse impact that any imperfect information during the verification process could have on LMPs,” the commission said.

Opposing the rule was CAISO, which said that the current $1,000/MWh ceiling far exceeds the highest cost-justified offer from any ISO resource. CAISO further contended that any natural gas-driven price spikes would be too infrequent and short-lived to warrant a change. ISO-NE said it saw no need to increase the cap, but it didn’t contest the rule change.

Market monitors for ISO-NE and SPP also protested, arguing that new sources of gas supply have provided sufficient stability in fuel prices in recent years.

The commission dismissed those contentions, pointing out that three RTOs — PJM, MISO and NYISO — had made previous filings to temporarily waive or change the level of their offer caps.

“The waiver requests and high natural gas costs experienced during the polar vortex, which could have caused some resources to experience costs above $1,000/MWh, demonstrate that the deficiencies of current offer caps, in particular the $1,000/MWh offer cap, are concrete rather than hypothetical.”

In its Nov. 17 presentation to the commission explaining the rule, FERC staff made the case for applying the change to all organized markets.

“Adopting the same offer cap structure in each RTO and ISO would avoid seams issues that could arise if offer caps differ materially across markets,” staff said.

The new rule will be effective 75 days after publication in the Federal Register.

Posted on November 22, 2016
Appeals Court Ruling for Bondholders Clouds EFH Reorganization

By Tom Kleckner

A U.S. appeals court last week ruled Energy Future Holdings must pay hundreds of millions of dollars to certain bondholders, adding a cloud of uncertainty to the bankrupt company’s attempts to emerge from Chapter 11 protection.

Lamar Plant | Luminant

On Thursday, the 3^rd Circuit Court of Appeals in Philadelphia reversed lower court decisions and directed EFH to pay holders of the company’s first-lien and second-lien notes. The bondholders had argued that by repaying its debt early in the bankruptcy proceeding, EFH owed them prepayment premiums — or make-whole payments — of $431 million and $351 million, respectively. The payments don’t include several years of interest.

The decision affects $6.2 billion in debts that were refinanced after EFH declared bankruptcy in 2014. The company has said that disallowing the make-whole claims is a condition of its reorganization and that the added litigation would reduce the funds available to other creditors.

The U.S. Bankruptcy Court in Delaware, which has jurisdiction over the case, is to begin hearings to consider confirming the Texas company’s reorganization Dec. 1.

EFH’s reorganization plan hinges partly on the sale of its Oncor wires business to Florida-based NextEra Energy for $18.4 billion. NextEra and Oncor filed for approval of the sale with the Public Utility Commission of Texas on Oct. 31. (See NextEra Energy Talks Up its Oncor Acquisition.)

It’s unclear whether the additional debt would affect NextEra’s acquisition of Oncor, which relies on eliminating debt and replacing it with equity.

EFH has already spun off its Luminant and TXU Energy businesses into a standalone company, since rebranded as Vistra Energy. (See Luminant, TXU Energy Emerge from Bankruptcy.)

Vistra Energy and NextEra both declined requests for comment by RTO Insider on the court’s ruling and its potential effect on the Oncor acquisition.

Meanwhile, NextEra and Oncor are plunging ahead with their merger application in Texas.

Friday, the state’s Public Utility Commission filed an order finding their application to be sufficient (Docket 46238) and an administrative law judge affirmed hearings before the PUC will begin Feb. 21.

The ALJ also granted all motions to intervene in the case. Those intervening include the Texas Office of Public Utility Counsel, NRG Texas, TXU Energy, Local 69 of the International Brotherhood of Electrical Workers, Texas Industrial Energy Consumers and a group of cities currently served by Oncor.

PUC staff has requested Oncor address a set of questions focused on the utility’s rating agency reports, its five-year capital plan and the tax status of the EFH spin-off.

Posted on November 22, 2016
FERC Rejects Entergy Attempt to End PPA with Goodyear Plant

By Tom Kleckner

FERC last week rejected Entergy Texas’ attempt to terminate a power purchase agreement with qualifying facilities at Goodyear Tire & Rubber’s Beaumont chemical plant (EL16-105).

Goodyear filed a complaint with the commission in August, alleging that Entergy Texas’ plan to terminate its PPA with the tire company’s QFs in Southeast Texas violated the utility’s obligation to purchase energy and capacity in accordance with the Public Utility Regulatory Policies Act of 1978.

Goodyear’s Beaumont Chemical Plant | Goodyear

Entergy contended it had the right to cancel the PPA based on FERC’s January order that terminated the utility’s obligation to purchase from QFs larger than 20 MW in MISO. (See FERC: Entergy not Required to Buy from Large QFs.)

Goodyear’s Beaumont/West QF was self-certified in 1987 with a net capacity of 13 MW. Its Beaumont/East QF was self-certified in 1999 with a net capacity of 18.8 MW.

Entergy argued that the two QFs should be considered as one. It noted that the QFs are located less than a half-mile apart on the same site and that their energy “is commingled behind the meter.”

Goodyear contended that because it had self-certified two cogeneration plants each smaller than 20 MW, the January order did not affect Entergy’s obligation.

The commission agreed. It said its January order concluded that “a QF’s size for purposes of being relieved of the mandatory purchase obligation is determined by its certified size.”

The commission’s January order was based on a 2006 ruling, which said that QFs with net capacity above 20 MW were presumed to have “nondiscriminatory access” to wholesale markets in RTOs such as MISO.

Posted on November 22, 2016
MISO, PJM Move Forward on TMEPs; 6 Projects Planned

By Amanda Durish Cook

CARMEL, Ind. — MISO and PJM are close to implementing a targeted market efficiency project (TMEP) type and poised to approve six such projects with cross-regional benefits.

Moser | © RTO Insider

During the Nov. 15 MISO and PJM Joint and Common Market meeting, Jesse Moser, MISO manager of infrastructure studies, said the RTOs must make a FERC filing to change their joint operating agreement in addition to individual filings on how they plan to handle cost allocation.

Moser said the RTOs prefer making the necessary three filings simultaneously, but they would file standalone JOA changes before the end of the year if certain regional cost allocation details are not finalized in time.

“We’re happy to see this move forward,” Moser said.

The two RTO’s staff say the final six projects are expected to cost about $17.25 million and deliver $111.6 million in reduced congestion on market-to-market flowgates, an average 6.5:1 benefit-to-cost ratio.

The RTOs examined 50 market-to-market flowgates and produced the final six from a pool of 13 potential upgrades. The final six exclude the previously recommended Klondike-Purdue 138-kV project in north-central Indiana, which did not advance because of the discovery that the congestion the project was designed to relieve was outage-driven. (See 7 Sites Eyed for MISO-PJM Targeted Market Efficiency Projects.) “These are meant to be lower cost projects … that have near-term economic benefits,” Moser explained.

MISO to Seek Bifurcated Cost Allocation

Solomon | © RTO Insider

At a Nov. 17 conference call of MISO’s Regional Expansion Criteria and Benefits Working Group, transmission engineer Adam Solomon said the RTO will pursue a bifurcated cost allocation for the TMEPs. MISO proposes to assign cost to a local transmission pricing zone when the constraint is on the transmission of one or more transmission owners. For constraints wholly within PJM, MISO is seeking a postage stamp allocation for all of the MISO North region.

Solomon said MISO decided on a postage stamp for projects within PJM because all local transmission pricing zones would gain from lowered congestion.

PJM officials did not discuss their cost allocation plans at the meeting. Spokeswoman Paula DuPont said the regional cost allocation is being developed by PJM’s Transmission Owners Agreement-Administrative Committee.

The two-option proposal would apply to both RTO’s current batch of TMEPs. “We’re certainly open to looking at it in the future if we can get a better cost allocation,” Solomon said.

Shelly-Ann Maye, representing Midwest Power Transmission Arkansas, said she didn’t understand why a postage stamp allocation could be justified when local beneficiaries in MISO could be identified.

“These projects are avoiding future congestion in MISO, and that congestion gets pretty well spread out in the footprint,” Solomon explained.

Of the six TMEPs currently being considered, the Marysville-Tangy 345-kV project in central Ohio is the only project that would qualify for the postage stamp allocation, as it is located wholly within PJM, Solomon said.

| MISO

Solomon also said the cost allocation rules will only apply to the PJM-MISO seam. MISO staff said they plan to collect more SPP day-ahead market-to-market information and expect to begin discussions with SPP on a similar project type.

“Having this cost allocation spelled out in the JOA and Tariff, I think, will help these projects go through and we can get the benefit of those projects we’re forecasting,” Solomon said.

Wisconsin Public Service’s Chris Plante said his utility was hoping for 50% local pricing zone allocation and 50% postage stamp allocation for all TMEPs.

“We think this is the best proposal that we have at this point with stakeholder feedback considered,” Solomon said.

Retirement Coordination

Neil Shah, MISO adviser of seams administration, also said that both RTOs are planning to file a generator retirement coordination process with FERC by Dec. 15. Shah said the final language was largely unchanged from what was proposed last month. (See MISO Outlines Retirement Coordination with PJM.)

Posted on November 22, 2016
Sandoval: Nuke Shutdown, Auto-DR Aided Aliso Canyon Response

By Robert Mullin

LA QUINTA, Calif. — While the loss of the San Onofre nuclear plant complicated California’s response to the closure of the Aliso Canyon natural gas storage facility last year, planners did benefit from actions taken in the wake of the plant’s 2013 shuttering, according to California Public Utilities Commissioner Catherine Sandoval.

Sandoval | © RTO Insider

“All of that work helped us to better withstand Aliso Canyon when the number one source of natural gas was no longer available,” Sandoval told an audience at the National Association of Regulatory Utility Commissioners’ 128th Annual Meeting.

In response to the shutdown of San Onofre — the largest generator in the state’s most populous area — officials ordered transmission upgrades, installation of synchronous condensers to facilitate the flow of electricity into the Los Angeles area and “a variety of things to help keep the system up and running electrically,” Sandoval said.

The loss of Aliso Canyon prompted the CPUC to authorize additional measures to shore up the region’s grid, including accelerated deployment of energy storage and expedited interconnection procedures. The state also stepped up implementation of demand response to shave summer electricity — and, by extension, natural gas — demand.

“This isn’t your father’s demand response; this is auto-DR,” Sandoval said. Among the most successful auto-DR programs: air-conditioner cycling, which allowed utility customers to select from a range of potential curtailments of their cooling units during periods of high electricity demand.

Aliso Canyon | California Governor’s Office of Emergency Services

The program yielded 300 MW in DR, Sandoval said. “That’s a peaker plant. So we were able to get a negawatt peaker through auto-DR,” Sandoval said.

Southern California weathered the summer without incident on either the gas or electricity system. Now planners are turning their attention to winter, when heating requirements create a second peak for gas demand not driven by electricity generation. (See CAISO Seeks to Extend Aliso Canyon Gas Rules Through Winter.)

While Aliso Canyon owner Southern California Gas has been testing the storage facility for leaks, the CPUC still hasn’t authorized reopening. No set timetable has been established for bringing the facility back online.

“We really have to come up with new messages [for consumers] that are actually well-tailored to the winter side,” Sandoval said. “We have to think about what sorts of programs can we adopt to really ensure that there’s gas sufficiency so that we don’t run into problems, especially if we’re not able to bring Aliso back online.”

Posted on November 22, 2016
PJM, NYISO Still Seeking Spot-in Tx Solution

By Rory D. Sweeney

NYISO and PJM are finding that coordinating transmission across their border is not simple.

After an effort to make it easier for traders to schedule imports from New York failed at the Nov. 2 Market Implementation Committee meeting, stakeholders will resume efforts at a special MIC meeting Dec. 21.

Vitol’s Joe Wadsworth, who has championed efforts to streamline the process for several years, won stakeholder approval in April for a problem statement seeking ways to improve the method of reserving PJM spot-in (non-firm) transmission for energy imports scheduled day-ahead from NYISO. Spot-in service is free but limited and allocated on a first-come, first-served basis.

Additionally, the deadlines for requesting the service from PJM and learning the results of NYISO’s day-ahead energy auction are staggered such that participants looking to import power must reserve spot-in capacity from PJM before knowing how much they’ll need. PJM requests must be made at 9 a.m. to have any hope of success, yet the results of NYISO’s day-ahead market usually aren’t available until after 9:30 a.m.

| Josef Kubes / 123RF Stock Photo

This creates the risk that “there may not be enough spot-in service available for participants who received a cleared day-ahead schedule to import power into PJM,” the problem statement reads, which leaves them “scrambling” to find service. Failure to obtain transmission results in the import being curtailed, which “can create imbalances that must be settled against real-time prices.”

Armed with the problem statement, Wadsworth, PJM and NYISO began discussing potential solutions. NYISO, concerned about those potential imbalances creating costs for its members, proposed a market-based solution that would allocate the costs to PJM’s members.

Wadsworth also favored a market-based solution, but PJM decided, after researching potential solutions, that it would be a much more difficult implementation than the RTO preferred. As a compromise, Wadsworth and PJM developed a proposal that they thought addressed the problem without being overly complex: delay the earliest request for spot-in service from 9 a.m. to 10 a.m. so participants will know how much they need before they request it.

Wadsworth and PJM’s Chris Pacella presented the idea at the Nov. 2 MIC meeting.

“Maybe this is the simple change that eliminates all those risks,” Wadsworth said. (See “NYISO to be Consulted on Changing Spot-in Service Allocation Methods,” PJM Market Implementation Committee Briefs.)

Problem solved!

Software Changes

Except there was one catch: Pacella explained that PJM can make a deadline change for all imports, but that limiting the change to just NYISO would require time-consuming software changes.

PJM Independent Market Monitor Joe Bowring took issue with making a global change, saying it’s not consistent with the problem statement. When the issue first came up, he said, he attempted to argue that it should apply to all RTO interfaces, not just NYISO, but was “told explicitly” that was out of the problem statement’s scope. He said the correct procedural step would be to amend the problem statement to include all RTO seams.

Dan Griffiths, of the Consumer Advocates of the PJM States, agreed. “I’m kind of indifferent to the outcome, but I’d like to see this addressed properly,” he said.

PJM’s Mike Bryson cautioned against the global approach, saying it would create operational problems. “The all-borders issue causes me great concern,” he said.

Wadsworth agreed, saying he preferred to limit the scope of the deadline change to just the NYISO seam. “I think we need to think through all the consequences,” he said.

Other stakeholders, however, wanted to get to the bottom of NYISO’s concerns. “I’d like a better explanation of the mechanics of what it is that NYISO thinks is increasing the costs,” said Roy Shanker of H.Q. Energy Services. “This summary just doesn’t make sense to me. … You may or may not want to pick a fight, but I feel like everybody on both sides should know what’s going on.”

“In these preliminary stages, we’re beholden to New York’s stance,” Pacella said. He later acknowledged, however, that there is precedent for a market-based solution with the cross-seam transmission agreement in place between NYISO and ISO-NE.

An MIC vote on amending the problem statement, which was motioned by Bob O’Connell of PPGI Fund A/B Development and seconded by Jung Suh of Noble Americas, was tabled until the committee’s next meeting on Dec. 14. However, it likely won’t receive much discussion there because of the MIC special session on Dec. 21. It is scheduled from 1 to 3 p.m. at PJM’s Conference & Training Center in Valley Forge.

Posted on November 22, 2016
Minn. City Granted FERC Standards of Conduct Waiver

FERC last week granted Rochester, Minn., a waiver of its Standards of Conduct, finding that the city qualifies as a small public utility.

The commission’s Nov. 17 ruling said the waiver will remain in effect “unless and until the commission takes action on a complaint by an entity that Rochester has unfairly used its access to information to unfairly benefit itself or its affiliates” (TS15-3).

Zumbro Hydro Dam | Rochester Public Utilities

The southeastern Minnesota city sought the waiver in September 2015, claiming it met the definition of a non-jurisdictional utility. Jurisdictional transmission providers are subject to the Standards of Conduct, which require transmission function and marketing function employees to operate independently of each other and prohibit sharing nonpublic transmission information with marketing employees.

Without a waiver, Rochester said it would indirectly be subjected to the standards based on the commission’s reciprocity rules, which ensure nonpublic utilities’ access to transmission service from public utilities. The city pointed out it transferred operational control of its transmission to MISO in late 2014; the waiver requires that utilities own, operate or control “only limited and discrete transmission facilities.”

Rochester’s municipal utility serves about 50,000 customers, mostly with power purchased from the Southern Minnesota Municipal Power Agency. It owns and operates about 86 MW of generation, 42 miles of transmission and 793 miles of distribution. Early this year, Rochester officials announced that the public utility would begin building a new 47-MW natural gas plant in 2017. The utility has proposed a 3.7% rate increase in 2017.

— Amanda Durish Cook

Posted on November 22, 2016
BGE Reaches Settlement with MISO Members in Congestion Dispute

Baltimore Gas and Electric will pay $170,530 to MISO members to end a dispute over cross-system congestion costs under a settlement approved by FERC last week.

FERC’s Nov. 17 order settles a dispute between BGE and almost 30 MISO utilities relating to the cross-system congestion costs known as Seams Elimination Charge/Cost Adjustments/Assignments (SECA). FERC said the uncontested agreement represents “a final settlement of all SECA obligations.”

| Baltimore Gas & Electric

The settlement directs BGE to pay members of the RTO $344,665 and for the RTO to collect $174,135 from its members for BGE, for a net payment by BGE of $170,530. The approval closes out dockets ER05-6-124, EL04-135-126, EL02-111-145 and EL03-212-140.

The SECA cases originated from a 2002 FERC decision allowing American Electric Power, Commonwealth Edison and Dayton Power and Light to move from MISO to PJM. The move created areas in the RTO that were cut off from the rest of the footprint and led to rate pancaking and the eventual elimination of regional through-and-out rates.

FERC approved the 16-month SECA transitional payment mechanism for 2004-2006 and upheld SECA use in 2010, but it said SECA rates recovered from MISO and PJM transmission customers were subject to refund by MISO and PJM transmission owners. The 2010 decision imposed additional SECA liabilities on BGE. MISO laid out SECA amounts in 2013, charging BGE and about 15 other PJM load-serving entities a combined $4 million in SECA charges.

— Amanda Durish Cook

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