Page 1542 – RTO Insider

June 15, 2015June 15, 2023

How PJM Capacity Performance Compares with ISO-NE’s Pay-for-Performance

PJM’s Capacity Performance plan approved by the Federal Energy Regulatory Commission borrows elements from ISO-NE’s Pay-for-Performance program. Below is a summary of some key differences between the two plans followed by the relevant paragraph numbers from the order.

Annual Stop-Loss Limit: PJM’s annual non-performance charge stop-loss limit is equal to 1.5 times the annual net cost of new entry (CONE) rather than the auction clearing price as in ISO-NE. The commission acknowledged that PJM’s stop-loss limit will likely be higher than ISO-NE’s but said it was reasonable. “An important element of PJM’s overall proposal is to put at risk full capacity auction revenues if a resource completely fails to perform during performance assessment hours. Because the proposed annual stop-loss limit is equal to the maximum clearing price allowed by PJM’s Variable Resource Requirement curve, it meets this criterion,” FERC said. “In addition, basing the limit on net CONE ensures that market participants will know their maximum risk exposure in assuming a Capacity Performance commitment and be in a position to formulate their sell offers accordingly.” (¶164)
Trigger for Performance Assessment Hours: PJM will use the declaration of Emergency Actions as the trigger for performance assessment hours. In contrast, ISO-NE’s trigger is a shortage of system 30-minute reserves, system 10-minute reserves or zonal 30-minute reserves. “While PJM’s proposed trigger is more expansive, to include certain warnings and pre-Emergency Actions, we find that PJM’s approach would accurately correspond with conditions and events during which the system is experiencing, or may reasonably expect to experience, a shortage of capacity,” the commission said. “We find that this approach will appropriately trigger performance assessment hours when performance is most critical to the PJM system.” (¶186)
Transition Mechanism: FERC said PJM’s transition mechanisms strike an appropriate balance between procuring too much or too little capacity able to qualify as a Capacity Performance resource. Although the commission approved ISO-NE’s proposal to acquire only its performance product in its next auction, “PJM has demonstrated that a phased-in approach is also just and reasonable,” FERC said. (¶256)
Withholding: The commission rejected the Market Monitor’s suggestion that PJM adopt ISO-NE’s use of resources’ installed capacity values to define required performance. The Monitor said PJM’s reliance on unforced capacity could result in withholding by allowing a supplier with a large portfolio to reduce its available capacity from some of its resources to result in a higher clearing price for the entire portfolio. Such suppliers also could reduce unforced capacity available from some of its resources as a hedge against unexpected outages on other units. The commission said “the likelihood of such a strategy is mitigated by a resource deliberately forgoing considerable energy revenue in the hopes that the withholding strategy and any additional performance payments during Emergency Actions would outweigh the forgone energy revenue.” It said the Monitor should work with PJM to devise an alternative mitigation mechanism if it finds evidence of such strategies. (¶358)
Application of Non-Performance Charges: The commission approved PJM’s proposed application of non-performance charges, although it said it was “more lenient” than that applied by ISO-NE. It noted that the “more significant” of PJM’s proposed revisions regards generator maintenance outages as opposed to planned outages. “We agree with PJM that a generator on a planned outage should not be expected to return to service within a time interval of less than 72 hours. We also find reasonable PJM’s proposal requiring a generator on a planned outage to provide PJM with an estimate of the amount of time it will require to return to service. This requirement presents no significant burden to the resource but will assist PJM in operating its system during tight conditions,” FERC said. (¶496)

June 15, 2015June 15, 2023

SPP Takes on Grid Management in Great Plains

By Ted Caddell

SPP has expanded its electric grid management from eight to 14 states, adding more than 5,000 MW of peak demand and 9,500 miles of transmission lines in the Great Plains.

The move, effective June 1, brings into SPP the Integrated System: the Western Area Power Administration’s Upper Great Plains Region (Western-UGP), based in Billings, Mont.; Basin Electric Power Cooperative in Bismarck, N.D. and the Heartland Consumers Power District in Madison, S.D.

Western-UGP becomes the first federal power agency to join an RTO under the Federal Energy Regulatory Commission’s Order 2000, which encouraged the voluntary formation of independent grid operators.

FERC approved SPP’s incorporation of the Integrated System in November (ER14-2850). While its grid is now under SPP’s control, the region won’t take part in SPP’s markets until October.

SPP COO Carl Monroe said Monday that the integration — which represents an increase of about 10 to 12% increase in peak load — has been seamless so far.

“The way we measure the success of the transition is if we hear no noise about it,” he said. He said it’s been quiet, and SPP is working on the next step of integrating the new organizations into the SPP tariff. He said Western-UGP, Basin Electric and Heartland Consumers are already participating in SPP’s transmission planning process.

Basin Electric has 2.8 million customers and 2,100 miles of transmission lines. Heartland serves 28 municipalities, including Sioux Falls, S.D. Western-UGP covers 378,000 square miles of prairie and farmland. The Integrated System evolved from a 1962 agreement between the Bureau of Reclamation, Basin Electric and 103 cooperative and municipal preference customers in the region. The SPP Board of Directors approved the system’s membership in June 2014.

It marks a significant increase in authority for SPP, which had shrunk after Entergy defected to MISO. The shifting of companies from one RTO to another spurred the need for settlement conferences overseen by FERC. Some issues are still in dispute, including MISO-directed transactions that flow across SPP territory.

The expansion will “enhance our ability to deliver value through transmission,” SPP CEO Nick Brown said. “The Integrated System’s footprint is well connected to SPP’s existing service territory and provides a logical expansion from a network configuration standpoint.”

SPP says the expansion will result in stakeholder net benefits of about $334 million. These include the increased ability to commit and dispatch generation into and out of Nebraska, and the availability of low-priced hydro generation out of Western-UGP.

Monroe thanked the Integrated System’s efforts in easing the transition. “Coordinating the flow of power requires hard work and collaborative planning,” he said. “We look forward to completing the Integrated System’s full membership in SPP this fall, which will provide increased options for buying and selling power.”

June 15, 2015June 15, 2023

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM staff introduced a problem statement at last week’s Operating Committee meeting to address concerns that the RTO is purchasing too much fast-responding “RegD” resources, which is negatively affecting regulation and reliability.

The problem statement calls for a reevaluation of the marginal benefits factor used in the regulation market optimization solution, which appears to over-value the contribution of RegD resources as a substitute for traditional RegA.

“In order for the regulation market to arrange the optimal, least-cost combination of RegA and RegD to meet [area control error] control requirements, the marginal benefits factor function needs to be accurately defined,” according to the problem statement. (See PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation.)

Generators’ Non-Compliance Continues

PJM staff continues to struggle with generators’ non-compliance with training and certification requirements.

While transmission owners generally are in compliance, 10 generators (12%) were non-compliant for certification, and two (3%) were non-compliant for training as of May, PJM’s Glen Boyle told the Operating Committee. Four demand response companies (17%) were non-compliant for training. In addition, four small generation companies (20%) were non-compliant for training.

While non-compliant companies are supposed to submit mitigation plans, many have not, and there are no financial penalties for failing to do so.

Stakeholders suggested PJM identify a compliance officer at each organization with whom to follow up. (See PJM Operating Committee Briefs, “Sought: Ways to Incent Training, Certification Compliance.”)

SPS Removals in PPL

PPL Electric Utilities is removing three special protections schemes (SPS).

Susquehanna Loss of Outlet Scheme: The SPS would trip Susquehanna Unit 2 when two 500-kV outlets were open at the same time. The SPS is no longer needed with the May addition of the Susquehanna-Roseland 500-kV line.
Wescosville T3 SPS: The Wescosville 500/138-kV Transformer T3 would trip when the Alburtis end of the Susquehanna–Wescosville-Alburtis 500-kV line was open. The SPS is no longer needed with the May installation of the Breinigsville 500/138/69-kV substation.
Montour Runback SPS: During construction of the 230-kV line between Lackawanna and Bushkill and on one of the two Susquehanna-Harwood 230-kV lines, certain contingencies could overload the remaining second line. This SPS either reduced the output of Montour Units 1 and 2 or tripped the units to alleviate the overload. The SPS is no longer needed with the rebuilt line between Lackawanna and Bushkill and the Susquehanna-Harwood lines being back in service. It is blocked and will be removed in September.

— Suzanne Herel

June 15, 2015

PJM Transmission Expansion Advisory Committee Briefs

VALLEY FORGE, Pa. — Maryland and Delaware officials are protesting PJM’s proposal to allocate most of the cost of the stability fix at Artificial Island to Delmarva Power & Light ratepayers.

PJM planners expect to present their recommended fix to the Board of Managers on July 27, after a meeting with the board’s Reliability Committee, which is made up of four of the board’s 10 members.

The project has been mired in controversy since planners last summer recommended Public Service Electric & Gas for the job, only to have the Board of Managers reopen the bidding following an outcry from finalists, environmentalists and New Jersey officials. On April 28, planners completed a second review, recommending selection of a proposal by LS Power. Including upgrades by PSE&G and Transource, the project is expected to total more than $200 million. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)

The recommendation has drawn comments and complaints from several losing bidders and the public service commissions of Maryland and Delaware, which objected to the cost allocation. The Delaware Public Advocate and Old Dominion Electric Cooperative also raised objections over the allocation.

Steve Herling, vice president of planning, told the Transmission Expansion Advisory Committee that the allocation is based on the location of the solution, not the problem. In this case, while the stability fix affects nuclear generators located in New Jersey, the project would entail transmission terminating in Red Lion, Del.

In its letter to the board, the Delaware PSC estimates that the AI fix could boost Delmarva’s annual transmission revenue requirements by $30 million over the current $121 million, an increase of almost 25%. Ratepayers of ODEC and the Delaware Municipal Electric Corp. also would be affected.

The Maryland PSC echoed its neighboring state’s concern, saying, “We do not view such a cost allocation as reasonably comparable to the benefits received from the project, which we believe would flow equally to at least New Jersey and Pennsylvania residents. Thus, such an allocation of costs, we believe, is in violation of FERC’s Order 1000 cost allocation principles and directives.”

PJM Holds Firm on its Pratts Decision

PJM planners reaffirmed their recommendation to select Dominion Resources and FirstEnergy to resolve reliability problems near Pratts, Va., despite feedback from several stakeholders questioning their decision. (See Tx Developers Challenge PJM Choice on Pratts Project.)

The feedback was received from three entities that were unsuccessful in vying for the project: Ameren, ITC and LS Power’s Northeast Transmission Development.

“We’ve been pretty consistent in the way we’ve been evaluating all the proposals submitted in a proposal window,” said Paul McGlynn, PJM general manager of system planning, noting that the key factors in PJM’s decision were performance, cost and risk associated with siting, feasibility and cost commitment.

PJM will continue to accept comments regarding the decision until July 13. It plans to make its recommendation to the Board of Managers at its meeting July 27.

— Suzanne Herel

June 15, 2015June 15, 2023

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — A months-long debate over whether to create “historic” capacity rights for some load-serving entities took a twist last week when PJM staff returned with a different proposal angled to achieve the same result.

“This has very little similarity, if any, to the previous approach,” PJM’s Jeff Bastian told the Market Implementation Committee on Wednesday.

PJM has been wrestling with how to help the Illinois Municipal Electric Agency meet its internal resource capacity requirements when it needed to use resources located outside of the Commonwealth Edison locational deliverability area to serve its Naperville, Ill., load. (See PJM Debate over ‘Historic’ Capacity Rights Gets a Face: IMEA.)

After failing to gain traction with skeptical stakeholders, staff veered from the notion of “historic” capacity to recommend a proposal that would apply only to Fixed Resource Requirement (FRR) entities — LSEs permitted to avoid direct participation in the Reliability Pricing Model auctions by meeting their capacity requirements using internally owned resources.

Under a proposal approved by PJM, the Independent Market Monitor and IMEA, the internal capacity requirement would not have an effect unless there was price separation for the relevant LDA.

IMEA will put in its offer after PJM defines the auction parameters. If its LDA has price separation when PJM clears the auction, it will be required to meet the internal requirement for the next auction, avoiding the internal capacity rule for only one auction, Market Monitor Joe Bowring explained.

The changes put IMEA where it was before PJM changed the rules regarding the trigger for the internal capacity requirement.

“Within an LDA that is being modeled separately, for reasons other than [Capacity Emergency Transmission Objective or Capacity Emergency Transmission Limit] threshold test or non-zero locational price adder in past three auctions, the FRR entity would not be subject to an internal minimum requirement until the first year after the LDA actually in an auction — or they could resort back to RPM the following year,” Bastian said.

Stakeholders, however, asked for more information regarding the thought process behind the changes before they considered approval.

Proposals Address Tier 1 Synch Reserve Compensation

Committee members were presented with the first read of three competing proposals addressing the issue of how to compensate Tier 1 synchronized reserves.

Since October 2012, Tier 1 reserves have been compensated at the synch reserve market clearing price (SRMCP) when the non-synch reserve market clearing price (NSRMCP) is greater than $0. While Tier 1 reserves are paid the same as Tier 2, only the latter is subject to penalties for non-performance.

The problem statement the proposals seek to solve asks whether it’s appropriate for such reserves to be credited when they are not responding to a synch reserve event, and if so, how much? (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)

Tier 1 reserves are made up of on-line resources that are able to ramp up from their current output within 10 minutes in response to a synchronized reserve event.

The proposals come from PJM, the Independent Market Monitor and PJM’s Industrial Customer Coalition.

The PJM proposal would retain the status quo of paying Tier 1 reserves the SRMCP when the NSRMCP is greater than zero. The ICC recommends paying the non-synch reserve price in that scenario. The Monitor says Tier 1 resources should not be paid except during a synch reserve event.

PJM’s proposal alone would impose an obligation on Tier 1 resources to respond, with a refund owed for nonperformance.

Independent Market Monitor Joe Bowring said the payments to Tier 1 resources are an unnecessary “windfall” that have totaled up to $15 million in the first quarter of this year alone.

“There’s no reason to pay Tier 1 anything additional than what they’re being paid now,” Bowring said. “That’s fully compensatory for what they’re doing.”

Changes Would Allow Earlier Replacement Transactions

The committee will be asked to vote at its next meeting on manual changes that would allow replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year.

Such replacements would be permitted when the owner of the replaced resource could show the expected final physical position of the resource at the time of the request.

Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project is cancelled or delayed. Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.

Resources replaced would not be able to be recommitted for the delivery year.

— Suzanne Herel

June 15, 2015June 15, 2023

PJM Planning Committee Briefs

VALLEY FORGE, Pa. — PJM will propose a two-tiered fee schedule for proposed transmission projects, officials told the Planning Committee last week.

Instead of asking for $30,000 to study any project costing at least $20 million, it will request that amount only for projects of at least $100 million.

For projects between $20 million and $100 million, PJM will recommend collecting a fee of $5,000.

The $30,000 fee proposal was approved Feb. 26 by the Markets and Reliability and Members committees after the Federal Energy Regulatory Commission rejected as discriminatory a previous plan to apply the charge to all greenfield projects but not upgrades of less than $20 million. (See FERC Rejects Fee on Greenfield Transmission Projects.)

“Because we put this threshold in place, we were going to be collecting for a larger number of projects,” PJM’s Fran Barrett told the committee. “Staff said that we could find ourselves over-collecting.”

The Planning Committee will be asked to approve the proposal, which would be tested over a two-year period, at its next meeting on July 9.

The fee schedule would be applied based on the cost estimates presented by those proposing the projects.

“If it turns out that a lot of people are trying to get around that with [estimates of] $99,999,000 we’ll have to revisit it,” said Steve Herling, vice president of planning.

Task Force Would Create Standards for Order 1000 Projects

A problem statement and issue charge introduced on first read Thursday would create a task force to develop minimum design standards for competitively solicited greenfield projects under FERC Order 1000.

The idea arose from concern that the designated entities for such projects would not be required to follow the design standards of the zonal transmission owner.

“We don’t want this new product to fix one problem but introduce a weak point in the system,” PJM’s Suzanne Glatz said, reflecting stakeholder feedback.

The design standards would apply to transmission lines, substations, and system protection and control design and coordination. They would take into consideration geography and physical and local needs of the project.

The task force would be open to all PJM stakeholders and would report to the Planning Committee.

Still Searching for Ways to Incent Early Project Submissions

The committee endorsed a problem statement and issue charge to find ways to incent customers to submit transmission projects earlier in the queue window.

The issue will be assigned to the Planning Committee, which will have three to six months to identify better incentives to encourage earlier participation. (See PJM to Try Again to Speed Interconnection Filings.)

The imposition of non-refundable fees that escalate later in the queue window have had little effect on changing participants’ behavior, said Dave Egan, manager of interconnection projects.

Meanwhile, those who have done their due diligence in their submittals are being held up by late, deficient entrants, PJM says.

— Suzanne Herel

June 15, 2015June 15, 2023

Duke, ODEC Denied ‘Stranded’ Gas Compensation

By Michael Brooks

The Federal Energy Regulatory Commission last week rejected requests by two PJM generators seeking the recovery of “stranded” natural gas costs incurred during the polar vortex last year.

But the commission also ordered PJM to change its Tariff to allow generators to submit day-ahead offers that vary by hour and to update their offers in real time. PJM is the only RTO that doesn’t allow such variable offers.

Duke Energy (EL14-45) and Old Dominion Electric Cooperative (ER14-2242) both argued that they were owed compensation due to the events of January 2014, when a cold snap sent gas prices soaring. Duke purchased $12.5 million worth of natural gas for its Lee plant in Illinois, only to have it not called on in real time. Similarly, ODEC complained that PJM canceled multiple dispatches that left gas it had purchased for its plants unused.

ODEC also said its plants’ operating costs on Jan. 23, 2014, exceeded what it could recover in the day-ahead market due to the $1,000/MWh offer cap at the time. The co-op asked for an extension of the waiver FERC granted PJM on Jan. 24, which allowed capacity resources to receive make-whole payments if their costs exceeded the offer cap for a limited time.

Duke, which was able to resell some of its gas, sought $9.8 million, while ODEC said it was due nearly $15 million.

Different Arguments, Same Result

While PJM supported the companies receiving one-time waivers, FERC denied both requests, citing its rules against retroactive ratemaking. The commission said that in both cases, ratepayers had not given prior notice that they would be responsible for natural gas-related costs.

Additionally, FERC disagreed with Duke’s assertion that it was due indemnification under section 10.3 of the PJM Tariff, which the company claimed required PJM to hold it harmless for obligations to third parties as a result of directives from the RTO. Duke told FERC that PJM had effectively ordered it to buy gas on Jan. 27, as it was likely Lee would be called upon to maintain reliability.

Although PJM supported the waiver requests, it said it was not permitted to provide Duke relief under the Tariff. “Any extension of section 10.3 to cover the type of loss Duke incurred under the circumstances at issue would read the indemnification provision into a blanket insurance policy for losses of whatever sort, caused by accident, act of God or plain misfortune that a market seller may incur in responding to PJM dispatch,” PJM told FERC in response to Duke’s complaint. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)

FERC agreed with PJM’s interpretation of the section. “The PJM indemnification provision should not be interpreted to guarantee reimbursement of a generator’s losses on gas purchases incurred in meeting its capacity resource obligations in PJM,” the commission said. “Fulfilling its energy market commitments are among the risks the generation capacity resource has assumed … when choosing to participate in the market.”

FERC also disputed Duke’s claim that PJM’s communication with Duke on Jan. 27 constituted a “directive” by the RTO. FERC said that PJM was merely advising that Lee was likely to be dispatched for reliability reasons.

And while PJM’s Independent Market Monitor objected to ODEC receiving compensation for its purchases of gas, it supported the co-op’s request to extend FERC’s waiver by a day in order to receive $2.7 million in make-whole payments. FERC said it saw no difference between the requests.

Offer Flexibility

FERC, however, found that PJM’s Tariff may be unjust and unreasonable because it does not allow generators to submit offers in the day-ahead market that vary hourly or to update their offers in the real-time market. ISO-NE gave its generators that flexibility in December, leaving PJM as the only RTO that does not allow such changes. (See related story, ISO-NE Prices Down Sharply in Q1; Generators Using Offer Flexibility Rule.)

The commission said it expects PJM to implement new rules allowing such changes by Nov. 1 and said refunds would be effective with the order’s publication in the Federal Register. PJM was ordered to report within 30 days on its planned response (EL14-45, EL15-73).

In April, the Markets and Reliability Committee authorized the creation of the Generator Offer Flexibility Senior Task Force to consider how to implement the changes under a problem statement proposed by Calpine, which is seeking $3.3 million in compensation for stranded gas-related costs (ER15-376). (See Bid for Generator Price Flexibility Draws Debate over 10% Adder.) The commission has not ruled on Calpine’s request.

Moeller Dissents

Commissioner Philip Moeller agreed with the majority that PJM’s Tariff was potentially unjust due to the lack of offer flexibility, but he said that he was “troubled” that it was unwilling to grant the companies any relief.

PJM’s “inflexibility contributed to the inability of generation units … to recover legitimate fuel costs,” Moeller said in his dissents to the orders. The companies “acted in good faith to preserve system reliability during a time of extraordinary system stress and deserve appropriate compensation.”

Moeller also said that the majority ignored the companies’ arguments and applied “an overly narrow reading of the prior notice rule and prohibition against retroactive ratemaking to find that ratepayers somehow lacked adequate notice that they would, in fact, be responsible for paying the cost of services provided to them to ensure resource availability during system emergencies.”

The complaints should have at least been set for hearing and settlement judge procedures, he said.

June 15, 2015June 15, 2023

Lake Champlain Cable into New England Progresses

By William Opalka

The second transmission line proposed to bring Canadian hydropower into the Northeast under Lake Champlain has advanced with the release of its draft environmental impact statement.

The New England Clean Power Link, proposed by Transmission Developers Inc.-New England (TDI-NE), is a high voltage, direct current line that would transport 1,000 MW of electricity 154 miles from Quebec to Ludlow, Vt. Ninety-eight miles of the cable would be buried under Lake Champlain, and most of its land-based route would be underground.

The U.S. Department of Energy released the draft on June 3 for the $1.2 billion for the project, which it says should be issued a Presidential Permit, required for the border crossing.

TDI also is planning another 1,200-MW line using a path underneath the lake and through existing rights-of-way to New York City. This project is furthest along the regulatory path, having received its final permits in April. (See Quebec-NYC Tx Line Clears Final Regulatory Hurdle.)

A third high-voltage transmission line proposed to transport Canadian hydropower into the Northeast, Eversource Energy’s Northern Pass in New Hampshire, is expecting its final EIS next month, as its review is taking longer than expected to complete. (See Eversource: Northern Pass Delayed Until ’19; Earnings Up.)

TDI-NE touts the Vermont project as a way to deliver renewable energy from Canada to the ISO-NE market. The company estimates that the regulatory process will take until the end of the year, with construction starting in 2016. The project is expected to be in service by 2019.

TDI-NE still needs permits from Vermont and has yet to announce customers for its electricity.

The release of the draft opens a 60-day comment period that is scheduled to close on Aug. 11.

June 15, 2015

Connecticut Officials at Odds over Plant Clean-up, Merger

By William Opalka

Connecticut environmental officials are at odds with utility regulators over whether the state should seek cleanup of an abandoned power plant as a condition for Iberdrola’s acquisition of UIL Holdings.

Attorney General George Jepsen, the state Department of Energy and Environmental Protection and the City of New Haven see the merger as the best chance to clean up the contaminated site in the city, but the Public Utilities Regulatory Authority doesn’t seem inclined to force the issue.

Spanish conglomerate Iberdrola announced in February it would acquire UIL Holdings, which has electric and gas units in Connecticut and Massachusetts, in a $3 billion cash and stock deal. (See Iberdrola Broadens Northeast Footprint in $3B UIL Deal.)

English Station

The power plant that has emerged as a flashpoint is the English Station, a coal- and oil-fired generator that dates to the 1920s and sits on a man-made island in the Mill River. The plant was shut down by United Illuminating, the electric utility subsidiary of UIL, in 1992 and sold eight years later.

The new owner intended to revive the plant, but environmental problems killed that plan. It was later sold to a real estate developer.

State environmental regulators have closed the site pending an estimated $30 million cleanup of toxins. DEEP’s environmental remediation order for the site — while not yet final — would require UI and the subsequent owners to clean up the site.

In a brief filed June 5, the attorney general said the state should require the merger applicants to place $30 million in an escrow fund to pay for cleanup of the site, with an additional promise that Iberdrola pay any additional costs more than that amount. Jepsen said UIL “bears a significant portion of responsibility” for the contamination.

The utilities and PURA say that the environmental issues are beyond the scope of the merger.

‘Devoid of Evidence’

In a reply filed Friday, the companies rely on a recent PURA order that removed English Station from the merger’s consideration. “The record is devoid of any evidence upon which the authority could base a condition such as that recommended by the AG. As such, the authority should not entertain conditions related to matters it has already decided are beyond the scope of the proceeding and its authority and upon which it has no record evidence to decide,” they wrote.

PURA had said its docket is not the “appropriate forum” on responsibility for the cleanup.

“English Station property is already the subject of pending legal actions in other appropriate forums such as [DEEP] and the U.S. Environmental Protection Agency,” it wrote in a May order.

FERC Approval

Iberdrola USA owns utilities New York State Electric & Gas and Rochester Gas & Electric in New York, Central Maine Power in Maine and significant wind power assets from coast-to-coast.

The Federal Energy Regulatory Commission approved its takeover of UIL on June 2 (EC15-103).

FERC said acquiring an electric utility in Connecticut and gas distribution companies in Massachusetts and Connecticut presented no significant concerns about the combined companies’ market power.

In the PURA docket, however, Jepsen has listed other objections to the takeover, joining the state’s consumer counsel in saying consumer benefits promised by the merging companies are elusive or non-existent.

June 15, 2015

Municipal Eligibility for RTO Adder Questioned by MISO

By Chris O’Malley

MISO and its Transmission Owners sector have raised doubts about the eligibility of some municipal transmission owners that are seeking a 50-basis-point RTO adder, asking the Federal Energy Regulatory Commission for clarification in separate filings.

Last week, MISO filed a limited protest to a compliance filing it submitted last month on behalf of several municipal TOs who requested an adder as an incentive for RTO membership. FERC had ordered MISO to make it clear that only municipals that have turned over functional control of their transmission to MISO, or provide service over non-transferred transmission facilities with MISO acting as agent, may receive the RTO adder. MISO also said that all of the municipals who are seeking the adder fulfill these requirements.

MISO’s protest seeks to clarify that non-integrated facilities for which a TO receives credits under section 30.9 of the MISO Tariff are not eligible for the RTO adder (ER15-1067).

In its protest, the TO sector asked FERC to reject the compliance filing outright, asserting that MISO had not adequately fulfilled the commission’s requirements in its revisions.

“While the Tariff language submitted in the compliance filing appropriately limits the collection of the RTO adder, the compliance filing appears to state that certain municipals that do not meet these requirements but instead only use Attachment O of the MISO Tariff to calculate their revenue requirements for credits under section 30.9 of the MISO Tariff, are eligible to collect the RTO adder,” the TOs said.

MISO filed on behalf of the Municipal Energy Agency of Nebraska, the Central Minnesota Municipal Power Agency, Cedar Falls Utilities and about 15 member cities, boards and agencies.