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November 20, 2024

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NYISO Supports TO Exemptions to BSM Rules

nyisoNYISO last week asked the Federal Energy Regulatory Commission to exempt competitive transmission, including the Champlain Hudson project, from the ISO’s buyer-side mitigation rules.

The ISO and other stakeholders filed comments last week in response to a December complaint by transmission owners, who said NYISO’s market power rules are being misapplied to unsubsidized, competitive projects entering the ISO’s capacity market (EL15-26).

In its response, NYISO essentially asked FERC to order a rule change it was unable to achieve through its stakeholder process, where it was blocked by opposition from generators.

The transmission owners — Consolidated Edison of New York, Orange and Rockland Utilities, New York State Electric and Gas, Rochester Gas and Electric and Central Hudson Gas and Electric — told FERC on Dec. 4 that NYISO should amend its Tariff to include a competitive entry exemption in its BSM rules. The exemption would ensure that projects that did not have contracts with, or receive financial support from, any New York distribution companies, municipalities or the state government are not subject to an offer floor in the ISO’s capacity auctions.

TDI Holdings filed a separate complaint Dec. 16 asking FERC to exempt its high voltage, direct current Champlain Hudson project from the BSM rules after NYISO said it would be subject to the offer floor (EL15-33). The $2.2 billion project would deliver 1,000 MW from the Canadian border to the New York City metropolitan area. TDI said subjecting the project to the offer floor — a minimum clearing price — would jeopardize its commercial viability “because generation supply in Canada may be unwilling to execute transmission service agreements with TDI.”

Supporting TDI’s filing, the transmission owners said the project “emphasizes the need for the commission to grant the [TOs’] competitive entry exemption complaint.” At the same time, the group asked FERC to put off ruling on TDI’s complaint until it ruled on theirs, saying that if it were successful, TDI would not need a project-specific exemption.In their complaints, both the TOs and TDI say they recognize the need for BSM rules in preventing market power.

Buyer-Side Mitigation

NYISO’s rules are similar to PJM’s minimum offer price rule (MOPR).

The rules, approved by FERC in 2013, are intended to prevent state and local governments and large net buyers of capacity — market participants whose load dwarfs the amount of capacity they own — from subsidizing the entry of “uneconomic” generation projects into the capacity market in order to artificially lower prices.

A project is considered economic if its average forecasted price exceeds its net cost of new entry (CONE), or if the annual forecasted revenues in NYISO’s Installed Capacity (ICAP) Spot Market Auction exceed the default net CONE in the project’s locality. The default net CONE is defined as 75% of the net CONE of the reference unit used to determine that locality’s ICAP demand curve.

Uneconomic projects are subjected to the offer floor, defined as the lower of either its net CONE or the default net CONE.

Responses to Complaints

NYISO stakeholders filed comments both in support and in protest to the complaints last week.

In its comments, NYISO said it supported the TOs’ complaint, save for a few minor details. The ISO had proposed a competitive entry exemption last February, but it failed to gain the necessary 58% sector-weighted vote from the Management Committee.

“The NYISO asks that the commission: (i) replace certain proposals in the complaint with alternatives previously advanced by the NYISO in its stakeholder process; and (ii) direct the NYISO to adopt additional Tariff language that will be needed if the competitive entry exemption is to be legally effective and practicably implementable,” the ISO wrote.

It also echoed the TOs’ response to TDI, saying the company should wait until FERC rules on the broader exemption.

NYISO said that BSM rules are intended to prevent uneconomic entry, not protect market participants from competition. The ISO “believes that the BSM rules provide necessary protections to the market and that adding a competitive entry exemption would be entirely consistent with their purpose,” it said.

NYISO’s Market Monitor also supported the exemption, noting that it has proposed such a measure in its past three State of the Market reports.

New York City also voiced its support. “For many years, and in multiple proceedings before the commission and at the NYISO, the city has argued that the NYISO’s buyer-side mitigation rules are overbroad and serve more as a barrier to new entry than a protection against market abuses,” the city said. “Indeed, incumbent generating companies have wielded the mitigation rules as a sword (to strike against potential competitors) and a shield (to block new entry).”

Other stakeholders opposed the rule change.

“At first blush this proposal may seem harmless, but it would in fact create a myriad of new opportunities to artificially suppress capacity pricing in NYISO where out-of-market interference in the markets already is pervasive,” Entergy Nuclear Power Marketing said in its protest to the TO’s complaint.

“While couched in the guise of simply permitting ‘purely private investment’ to risk its own money, review of the proposed Tariff revisions reveals that blanket exemptions would be granted to projects that are not, in fact, purely private. The commission should protect the wholesale NYISO capacity market and reject the complaint.”

The Independent Power Producers of New York said “NYISO’s proposal, which was soundly rejected in the stakeholder process as part of a package of exemptions last year, is fatally flawed.”

The BSM rules were proposed by NYISO as a way of dealing with New York’s ongoing struggles with transmission congestion due to the heavy load imposed by the city. The U.S. Department of Energy has called New York City “an epicenter of transmission congestion.”

This also led to a controversial decision by NYISO to combine its five Lower Hudson River Valley capacity zones into one. The move attracted criticism from ratepayers and attention from the state’s U.S. senators. NYISO, however, claimed vindication when it announced last month that the new zone had led generators to reopen 1,900 MW in shuttered power plants. (See Coal-to-Gas Conversions, New Capacity Zone Ease NYISO Reliability Concerns.)

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Company Briefs

PacilioSourceExelonMichael J. Pacilio, president and chief nuclear officer of Exelon Nuclear, was promoted to executive vice president and chief operating officer of Exelon Generation, the business unit overseeing all of Exelon’s generating stations. Bryan Hanson, Exelon Nuclear COO, will assume Pacilio’s previous roles.

More: PR Newswire

Dynegy Betting on Edwards Station, Commits to Emissions Investments

EdwardsSourceDynegyDynegy said it plans to upgrade pollution controls at the E.D. Edwards coal-fired plant in Bartonville, Ill., rather than shut the 695-MW plant down in response to more stringent emissions standards. It told Illinois officials that the improvements would reduce Edwards’ noxious emissions by 90%.

As part of the agreement reached with state environmental authorities, Dynegy will continue its 10-year practice of burning low-sulfur coal.

Environmental groups were pleased with the news, but they cautioned that the plant would still produce waste. “While Dynegy’s announcement represents one step in addressing one type of coal plant emissions, there are still many harmful pollutants emitted from the coal plant’s stacks and dumped into its ash ponds on a daily basis,” a Sierra Club spokesperson said.

More: JournalStar

Exelon Appealing Valuation of Byron Nuclear Station

Byron Generation Station (Source: Exelon)
Byron Generation Station (Source: Exelon)

Exelon often touts the value of its nuclear generating stations. But not for tax purposes.

For the third straight year, the company is appealing Ogle County’s assessed value of its Byron Generating Station in Illinois. The county’s Supervisor of Assessments puts the value of the nuclear plant at $509 million. Exelon says it should be set at $212.6 million.

The company appealed assessments in 2012 and 2013, but both times the Ogle County Board of Review upheld the valuations — $449 million in 2012 and $509 million in 2013. Exelon’s appeals are still pending before the Illinois Property Tax Appeal Board.

More: Ogle County News

PPL Asks for More Time to Meet Spinoff Conditions

PPL is asking for more time to meet Federal Energy Regulatory Commission conditions to win approval of the spinoff of its generating assets to Talen Energy.

In December, FERC set a series of conditions to increase market competition for the spinoff. PPL told FERC last week that it would be unable to complete the plan by the Jan. 20 deadline and asked for an extension of 10 days. Talen Energy would combine the generating assets of PPL and Riverstone Holdings.

PPL and Riverstone are still determining which plants to divest to meet the FERC conditions. PPL spokesman George Lewis said an extension would not delay completion of the deal.

More: LancasterOnline

JD Power: PSE&G Ranks Highest in Customer Satisfaction Among Large Eastern Utilities

Public Service Electric & Gas topped the list for business customer satisfaction among large Eastern electric utilities, according to the latest survey by J.D. Power.

PSE&G scored 685, above the segment average of 659 for electric business customers. PPL came in at 681, while Exelon’s PECO scored 644, dropping in rankings from fourth to ninth. Pepco Holdings’ Delmarva Power & Light ranked highest among mid-sized utilities. All three of Duke Energy’s utilities — Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida — came in at the bottom of the Southern region rankings.

More: The Philadelphia Inquirer

NRG Concentrating on Solar as Energy Generation Prices Droop

NRG Energy is taking aim at the rooftop solar installation market in the face of declining profits in the conventional power generation industry.

NRG President David Crane said his company wants to move up the charts among domestic solar installers. SolarCity Corp. current ranks first in the U.S., according to GTM Research, and NRG ranks fifth. “We expect to convincingly persuade our investors that NRG has an embedded SolarCity within it,” Crane said.

The company plans to install 250 MW of home solar systems this year, 875 MW by 2017 and 2,400 MW by 2022. Market leader SolarCity installed 520 MW last year. “Everyone is beginning to believe that residential solar is this trillion-dollar market that currently has about 1% market penetration,” Crane said.

More: Bloomberg News

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Falling Oil Prices, Wind Exports Raise Concerns about SPP Transmission Expansion

By Rich Heidorn Jr.

sppDALLAS — SPP members last week approved spending $270 million on transmission improvements over the next five years, but not before stakeholders expressed misgivings about the investment — which comes after the RTO spent $1.8 billion on upgrades in 2014.

Several members of the Markets & Operations Policy Committee complained that the spending was benefitting wind exporters rather than internal loads and that the RTO’s load projections — driven in part by oil and gas producers — might prove too high.

Members also rescinded approval for a controversial project in the Ozarks in the face of falling demand projections and split one project in two, agreeing to consider generation alternatives to a local voltage problem.

Doubts about Load Projections

Burton Crawford of Kansas City Power and Light declined to endorse the 2015 Integrated Transmission Plan 10-year (ITP10) assessment, which was approved by voice vote with some nays and multiple abstentions.

Crawford said the assessment predicts wholesale sales 50% higher than his company’s internal estimates. “We’re a little concerned with the calculations behind this,” he said.

“We’re concerned that the load forecast is way off,” said the Empire District Electric Co.’s Bary Warren, who noted that much of the growth is based on anticipated demand from oil and gas producers. With the continued fall in oil prices, he said, “we need to determine if these projects will be needed.”

“What if oil goes to $20 a barrel and everyone stops drilling? Or there’s more earthquakes in North Texas and that affects fracking?” he added. “Things have changed in the last six months.”

But Jay Caspary, SPP director of research, development and special studies, noted that while spot prices have fallen to $45 a barrel, futures prices remain above $80, suggesting the price drop may be short-lived.

Several speakers also noted the volume of existing wind generators and oil producers that are unable to connect to SPP.

Xcel Energy’s Southwestern Power System (SPS) area in North Texas and eastern New Mexico is showing the worst potential problems in SPP’s reliability studies.

“They’re out there pumping oil. So there’s additional load that we could add to our system if we had the infrastructure in place,” Caspary said.

Caspary said there has been no significant drop in activity in the SPS territory, noting that The Wall Street Journal recently reported that rigs are being redeployed from the Eagle Ford shale zone in south Texas to the Permian Basin, an SPS territory in southeast New Mexico.

Bill Grant of Xcel Energy said there is at least 80 MW of load that wants to be served, including 30 MW of requests that were denied service and 53 MW of distributed generation.

Warren said the near-term prospects will become clearer this spring when oil producers announce their capital spending plans.

Cost Allocation, Modeling Complaints

SPP’s cost allocation and modeling methodology also came under criticism.

“We’re getting allocated these reliability benefits [for improvements] nowhere near our system,” Crawford said.

In abstaining on ITP10, Warren cited concern about how benefits are calculated.

“We need to think about whether there are some fundamental problems with the way we model our system,” commented Richard Ross of American Electric Power.

Jason Atwood of Northeast Texas Electric Cooperative voted against the 2015 Integrated Transmission Plan Near-Term assessment (ITPNT), which was endorsed with several abstentions. “I don’t want my load to pay for transmission to move power outside the footprint,” he said.

Atwood said wind generation in SPP has never exceeded 1,000 MW during the summer peak, “and we’re modeling for 7,000” MW based on transmission service reservations.

Discussing SPP’s strategic initiatives later in the meeting, Michael Desselle, SPP vice president of process integrity and chief administrative officer, said the RTO’s highway/byway cost allocation methodology is “not appropriate” for exports.

Jeff Knottek, of City Utilities of Springfield, Mo., raised a more acute modeling issue, citing the occurrence of transmission load relief procedures on two flowgates between SPP and Associated Electric Cooperative.

“No one can seem to replicate this problem that occurs in real time. We need to dig down and find what the cause of the problem is.”

2015 ITP10

The MOPC approved a portfolio of $273 million in engineering and construction costs for projects based on the ITP10 assessment of a business-as-usual future and one that assumed up to 20% of hydro capacity and conventional generation — including most coal units under 200 MW — would be lost.

It included 166 miles of reliability projects estimated at almost $210 million and 94 miles of economic projects costing almost $70 million.

The MOPC’s approval also recommended the Board of Directors issue Notifications to Construct (NTCs) for 16 projects needed in 2019. These projects’ cost of $142 million was reduced when members amended the plan to split the largest project, totaling $36 million, into two.

The original project would add a new substation with a 345/115-kV transformer on the Hitchland-Finney 345-kV line; a new 1-mile, 115-kV line from the substation to the Walkemeyer 115-kV line; and a second 21-mile, 115-kV line from Walkemeyer to North Liberal.

Members voted to split the project in two based on differences in the needed in-service dates. Some members suggested studying whether converting the 76-MW Cimarron natural gas generator to a synchronous condenser would eliminate the need for the Walkemeyer-North Liberal line.

Other projects exceeding $10 million were an upgrade of the Iatan-Stranger Creek 161-kV line to 345 kV ($16.1 million) and the rebuild of the South Shreveport-Wallace Lake 138-kV line ($10.3 million).

2015 ITPNT

The 2015 ITPNT, which addresses reliability problems through 2020, includes 42 projects totaling $257 million. Eight of the projects also were identified in the 10-year plan.

More than half of the total is slated for New Mexico ($82.1 million) and Kansas ($50.7 million).

The MOPC separately endorsed two Consolidated Balancing Area projects in the 2015 ITPNT: an upgrade of 138-kV terminal equipment at Benton ($480,000) and a rebuild of the Southwestern Station-Carnegie 138-kV line ($13.4 million).

Ozarks Project Cancelled

Members also recommended the Board of Directors withdraw the NTC for the 41-mile Kings River-Shipe Road 345-kV line.

The NTC was issued following the 2007 Ozark Study as one of several 345-kV projects that would create a loop around Northwest Arkansas and extend eastward across northern Arkansas and into southern Missouri.

Southwestern Electric Power Co. opposed the route selected and requested rehearing. The project also was opposed by a citizens group, Save the Ozarks.

Lanny Nickell, SPP vice president of engineering, said a review last year showed a 50% drop in load growth rates in the area critical to the project’s need. There was a 54-MW drop in post-contingency loading on the East Rogers-Avoca 161-kV line, “a fairly large percentage of [the new line’s] capability,” Nickell said.

“We’re not seeing nearly the severity in the number of overloads that we saw the last time,” he said.

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FERC OKs Revised NYISO Credit Policy

The Federal Energy Regulatory Commission has approved changes to NYISO’s credit requirements to protect the ISO from defaults by market participants that under-forecast their loads (ER15-470).

The new rule will require extra collateral from market participants that consistently fail to forecast their load within 90% of their actual meter data. It also prohibits those participants from using unsecured credit.

NYISO bills participants initially based on forecast load, with true-ups four months later, when meter documenting actual load is available to the ISO.

“During periods of increased prices like the 2013/2014 winter cold snaps, if a market participant is under-forecasting, the current credit requirements may not cover the exposure caused by the under-forecasting,” the ISO explained in its filing with the commission. “This potential exposure can grow the longer the market participant under-forecasts and [other] market participants could be exposed to potential bad debt losses as the NYISO may not have sufficient credit support in place to cover this true-up exposure if the market participant ultimately defaults.”

FERC said the new rules will go into effect on Feb. 18, unless NYISO requests a later date.

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ALLETE Buying Minn. Wind Farms from EDF for $10M

alleteMinnesota’s ALLETE Clean Energy will increase its MISO wind portfolio by one-third with a $10 million acquisition from EDF Renewable Energy.

The companies asked the Federal Energy Regulatory Commission last week to approve ALLETE’s acquisition of EDF’s Northern Wind Energy, which owns 97.5 MW of wind capacity in Minnesota (EC15-58).

Northern Wind owns the 85.5-MW Chanarambie wind farm in Murray County, Minn., as well as eight 1.5-MW qualifying facilities in Minnesota: Buffalo Ridge Wind Farm, Moulton Heights Wind Power Project, Muncie Power Partners, North Ridge Wind Farm, Vandy South Project, Viking Wind Farm, Vindy Power Partners and Wilson-West Wind Farm.

All of the facilities being sold have long-term power purchase agreements with Northern States Power (NSP).

They would be acquired by ALLETE’s subsidiary, ACE Mid-West, which owns a 50-MW wind farm in Condon, Ore., and three wind generators in MISO with a combined capacity of about 290 MW.

The applicants requested approval by Feb. 17 to allow them to close the deal by March 1.

They said the deal raises no market power issues. “Ignoring the fact that the capacity from those facilities is fully committed to NSP under a long-term PPA, it would result in ACE and its affiliates controlling 2,991.6 MW, or 1.69%, of the installed capacity in MISO,” they told FERC.

A sister company of Minnesota Power, ALLETE was formed in 2011. It had no wind assets until last year, when it purchased four wind farms in Oregon, Minnesota and Iowa from NRG Energy and AES for a combined $41.9 million.

It also has an option to acquire a 101-MW wind farm in Armenia Mountain, Pa., from AES and plans to build a 107-MW wind farm near Hettinger, N.D., that it will sell to Montana-Dakota Utilities for about $200 million.

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SPP Moves Forward on Change to Generator Mitigation Rules

By Rich Heidorn Jr.

DALLAS — SPP will change the way it calculates offer caps for generators under market mitigation in a “design approach” approved last week by the Markets & Operations Policy Committee. The vote endorsed a proposed two-step transition to a methodology similar to that used by MISO.

The initiative was prompted by the Federal Energy Regulatory Commission’s October 2012 order, which encouraged the RTO to change its mitigation rules, and orders in 2013 and 2014 criticizing the lack of cost details in its Tariff. As stakeholders began examining the issue, said SPP’s Richard Dillon, it became clear “the solution needed to be a lot larger than just variable [operations and maintenance].”

The Board of Directors rejected an earlier proposal in December, directing the MOPC to find a change that would have broader support among members and the RTO’s Market Monitoring Unit.

The initial step would create a process for calculating a default variable operating and maintenance (VOM) component for mitigated offers and add Tariff language regarding the calculation of cost-based rates.

SPP will work towards replacing the term “short run marginal costs” with defined, individual cost components. “We have to get this written down,” Dillon said.

An adder would also be included for “outlier” generators, such as diesels that are seldom run but are necessary on occasion when there is market power.

The interim proposal will include a deadline for filing the long-term solution, which would adapt the methodology used by MISO, which determines its reference levels for mitigation based on accepted offers and market prices, before considering the unit’s costs.

The proposed rule would prevent generators from seeing their cost-based offer caps drop far below the market curves they were paid when operating without mitigation.

SPP staff will present an analysis of the cost impact of the changes at the April MOPC.

Said Dillon: “We want to get this right because, quite honestly, I don’t want to be doing this again in six months.”

Richard Ross of American Electric Power said he was concerned that the changes in the long-term solution “potentially could be very costly.”

“The majority of us could live with the interim solution,” he said.

But Doug Collins of the Omaha Public Power District said he didn’t think the proposed changes went far enough. The costs the Market Monitoring Unit wants to include are “one-tenth of 1% of the costs I want to include,” he said, hyperbolizing for emphasis.

The proposal was approved by voice vote with no opposition and several abstentions. Dillon will write draft language for review by the Mitigated Offer Strike Team and the Markets Working Group before the FERC filing. Dillon estimated it will take about a year to implement the final solution.

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PJM Capacity Release Filings Draw Critics

By Suzanne Herel

pjm
(Click to zoom.)

A pair of requests PJM submitted to the Federal Energy Regulatory Commission to safeguard capacity for the 2015/16 delivery year drew a number of protests last week, many calling the filings premature.

Fearing that it might run short due to retirements of coal-fired generation, PJM asked for a one-time waiver on rules that would otherwise require it to release 2,000 MW of capacity in the Feb. 23 third Incremental Auction for 2015/16 (ER15-738). (See PJM Seeks Waiver on Capacity Release.)

It also proposed revising its Tariff to allow it to enter into capacity agreements made outside the Reliability Pricing Model auctions (ER15-739). FERC granted a request from the PJM Power Providers Group for more time to file comments on the filing, extending the window by six days to Jan. 20.

Dominion Resources, commenting on behalf of Dominion Virginia Power, urged the commission to restrict PJM’s waiver request to the amount necessary to alleviate concerns about winter resource adequacy. “The commission should not grant PJM’s request with respect to any summer capacity because it is unnecessary to sustain the established [installed reserve margin] during the delivery year, and thus would impose unnecessary costs on participating loads.”

Old Dominion Electric Cooperative, a coalition of PJM utilities and the Independent Market Monitor commented in support of the waiver. The Electric Power Supply Association, whose legal challenge of FERC Order 745 has raised questions about the future of demand response, also indicated its support. (See related story, FERC Files EPSA DR Appeal with Supreme Court.)

In its assent, ODEC cited an “atypical confluence of uncertainty caused by the pending EPSA litigation in the face of larger-than-normal retirements due to impending compliance deadlines for new [Environmental Protection Agency] rules.”

The utilities coalition — American Electric Power, Dayton Power and Light, FirstEnergy, East Kentucky Power Cooperative and Buckeye Power — said the waiver would “prevent the abuse of capacity market arbitrage opportunities by demand resources.”

For its part, EPSA commented that the one-time waiver posed fewer market-distorting effects than other approaches to retain capacity.

PJM’s request to revise its Tariff met with more opposition.

ODEC opposed that filing, saying it was “based upon uncertain and premature analysis of reliability which cannot occur before the third Incremental Auction.”

EPSA concurred, noting the request represented “a clear departure from competitive market approaches to ensure reliability for PJM.”

While the Independent Market Monitor showed support for the idea, it cautioned: “The prudence of a particular purchase, and the terms and conditions of any such purchases, should be subject to careful review against defined standards.”

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Sale Would End SSR, Clear Way for WE-Integrys Deal

By Chris O’Malley

presque isleElectric customers in Michigan’s Upper Peninsula would receive a rate cut and Michigan regulators would drop their objections to Wisconsin Energy’s acquisition of Integrys Energy Group under an agreement announced by company officials and Michigan Gov. Rick Snyder last week.

Under the deal, Integrys’ Wisconsin Public Service Corp. and Wisconsin Energy’s We Energies subsidiary would sell their electric distribution assets serving 28,000 U.P. customers to Upper Peninsula Power Co. for an undisclosed price.

The sale also would include We’s 400-MW coal-fired Presque Isle generator, which is operating under a costly system support reliability agreement (SSR) to prevent its retirement. UPPCO said it would “step into” the utilities’ existing rates, except that the SSR would be eliminated, likely in July.

If the deal is approved, it would relieve U.P. ratepayers from the estimated $97 million annual cost of the SSR. UPPCO’s current customers were to pay for nearly 6% of that amount.

The deal would also relieve Wisconsin ratepayers from their share of the Presque Isle SSR costs. Last year the Public Service Commission of Wisconsin complained to the Federal Energy Regulatory Commission that Wisconsin ratepayers would pay a disproportionate share of SSR costs.

FERC agreed and shifted SSR costs more heavily to Michigan (ER14-2860, ER14-2862). Residential ratepayers were furious, saying they could pay up to $150 more a year. U.P. businesses said their annual costs could rise by thousands or millions of dollars.

“This is a critical development for the Upper Peninsula and our entire state,” Snyder said in a press release announcing the sale Tuesday. The announcement cautioned that “all of the agreements have a number of contingencies and will be subject to further discussion and refinement.”

Cliffs to Purchase Presque Isle Power

UPPCO would run Presque Isle, in Marquette, Mich., until 2020, when the Environmental Protection Agency’s proposed carbon rules take effect. Cliffs Natural Resources, whose Empire and Tilden mines make it the largest electricity consumer in the U.P., would purchase “a significant majority” of its power from UPPCO until the retirement, according to the agreement.

Before then, Chicago-based Invenergy plans to build a natural gas-fueled combined heat and power plant on Cliffs’ site that would serve the mines and other local utilities. Invenergy told Crain’s Chicago Business the plant will be between 200 and 280 MW.

Previously, faced with soaring power costs from Presque Isle due to the SSR, Cliffs had lined up an alternative electric supplier.

Integrys Acquisition

Snyder, Michigan Attorney General Bill Schuette, the Michigan Public Service Commission and Cliffs also agreed not to object before FERC to Wisconsin Energy’s acquisition of Integrys.

The $9 billion deal could have been derailed or at least delayed as a result of the SSR dispute.

So roiled were Michigan leaders that the state’s House of Representatives on Nov. 6 passed a resolution calling on FERC to reverse its acceptance of MISO’s cost allocation it said would saddle U.P. residents with 99.5% of Presque Isle’s costs.

The uproar also triggered bipartisan legislation from Michigan lawmakers in Congress that would require FERC to overrule decisions by the North American Electric Reliability Corp. if a review found it resulted in “unjust and unreasonable” rate increases.

One Provider for UP

UPPCO, which serves about 52,000 customers in the U.P., currently owns seven hydroelectric generators and two combustion turbines with total capacity of 80 MW.

Formed in 1947 from the merger of three utilities, UPPCO was later acquired by Integrys, which agreed in January 2014 to sell the company to an infrastructure equity investment fund, Balfour Beatty Infrastructure Partners, for about $300 million.

If the deal announced last week is completed, UPPCO, based in Ishpeming, Mich., would serve a majority of the U.P.

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NIPSCO Blows Back at Wind Farm Complaints

By Chris O’Malley

nipscoNorthern Indiana Public Service Co. last week asked federal regulators to dismiss a complaint by two wind farm operators alleging they were overcharged by the utility for transmission upgrades to reduce congestion-related curtailments.

NIPSCO’s request, filed Jan. 12 with the Federal Energy Regulatory Commission (EL15-34), says the Fowler Ridge and Meadow Lake wind farms are improperly trying to piggyback on a complaint filed last June by E.ON Climate and Renewables North America.

The Indiana utility charged Fowler Ridge, Meadow Lake and seven other wind farms $50.4 million to build transmission upgrades, plus another $35.8 million to operate them over 35 years.

E.ON alleged that a 1.71 multiplier NIPSCO used to calculate operating costs of E.ON’s Pioneer Trail and Settlers Trail wind farms is too high (EL14-66).

On Dec. 8, FERC ruled that the multiplier was unreasonable and instructed E.ON and NIPSCO to enter into settlement proceedings to determine a new rate. Fowler Ridge and Meadow Lake filed their complaint Dec. 23. (See Two More Indiana Wind Farms Join NIPSCO Complaint over Tx Upgrades.)

In its request for dismissal of the Fowler Ridge and Meadow Lake complaint, NIPSCO said the farm operators took no position in the transmission complaint filed by E.ON and now, six months later, seek a refund.

“The complainants’ participation in the E.ON complaint proceeding to date has been that of a bystander, at best,” NIPSCO said.

Different Terms

NIPSCO also said there are differences between the transmission upgrade agreements (TUAs) it struck with the two farms and the one it reached with E.ON.

Fowler Ridge and Meadow Lake paid their initial upgrade costs in a lump sum shortly after the agreement was accepted by FERC, last February, “without any conditions, contingencies or exceptions.”

Conversely, E.ON agreed to make installment payments for the initial upgrade cost amounts, NIPSCO said.

“The commission is barred, via the filed rate doctrine, from retroactively refunding [Fowler Ridge and Meadow Lake] for the rates they already paid in full under the TUA,” the utility argues.

NISPCO also argues that while the two wind farm operators in Indiana have claimed the multiplier results in excessive charges of more than $1 million, they offer no support or justification for how they determined the alleged excess charges.

Congestion at Root

In its complaint, E.ON said its Illinois-based Pioneer Trail and Settlers Trail wind farms, with a combined capacity of 300 MW, lost between $9.8 million and $11.7 million in 2013 when grid operators forced them to curtail output due to congestion.

The 600-MW Fowler Ridge is jointly owned by BP Wind Energy North America and Dominion Resources. The 526-MW Meadow Lake is owned by EDP Renewables North America. The farms make up 73% of Indiana’s total wind capacity, according to the U.S. Department of Energy.

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Ginna Negotiators Given 3 More Weeks to Make Deal

ginnaNegotiators trying to hammer out a contract to keep an upstate New York nuclear power plant financially viable have been given a three-week extension by state regulators.

Constellation Energy Nuclear Group and Rochester Gas & Electric had faced a Jan. 15 deadline to complete talks for a reliability support services agreement (RSSA) that would likely raise rates for customers.

The New York Public Service Commission in November ordered the RSSA in an effort to save the 580-MW Ginna Nuclear Power Plant on Lake Ontario, 20 miles east of Rochester. NYISO and RG&E said the plant is needed until at least 2018 to maintain system reliability in western New York.

Constellation said the plant has lost $100 million over the past three years and would be mothballed without better financial terms. The RSSA would provide electricity to RG&E at a guaranteed price when called upon.

The two companies jointly asked for an extension until Feb. 6.

“Although significant progress has been made, GNPP and RG&E have not yet finalized an agreement that satisfactorily resolves all of these issues,” the petitioners wrote. “A brief extension will permit GNPP and RG&E to continue to work together in an attempt to develop a more considered RSSA that best satisfies the commission’s requirements as well as the needs of GNPP, RG&E and all interested parties.”

While negotiations continued during the original 60-day period, PSC staff requested financial information from the companies. Ginna and RG&E have asked that the commission keep those documents confidential as they contain protected trade information. That has led to complaints from consumer groups who seek more disclosure.

“Despite the potential for major cost increases for the public in the Rochester area, this PSC proceeding has been marked by an unusual lack of information available to the public,” the Alliance for a Green Economy and the Citizens’ Environmental Coalition wrote in a Jan. 13 letter to the commission. “Today we are writing to flag this problem for the commission as an issue of major concern.”