Minnesota’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.
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.
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.”
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.”
Electric 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.
Northern 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.
Negotiators 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.”
New York utilities have proposed revised transmission upgrades that would add 1,000 MW of capacity to relieve congestion in the Hudson Valley without obtaining new rights of way.
The proposals conform to a recent order by the New York Public Service Commission to use existing rights of way or other utility property to replace aging infrastructure and upgrade older technologies.
The Dec. 14 order (13-M-0457) directed the utilities to revise their previous applications to improve the transmission corridors, with an emphasis on minimizing the visual impact of the lines. The PSC said it was responding to more than 2,000 public comments, many of which opposed the use of new rights of way.
National Grid, Central Hudson Gas & Electric and New York State Electric and Gas filed their revised plans Jan. 7. They, along with an affiliate of Consolidated Edison and Orange and Rockland Utilities, are part of a new organization, New York Transco, which will develop and own the projects once approved by regulators.
The PSC opened the proceeding in November 2012 to press for upgrades to relieve transmission congestion in some areas of upstate New York, particularly interconnections that move power from central New York to within the Hudson Valley. Transmission congestion also prompted the creation of a new capacity zone in areas north of New York City, raising prices for customers in the Lower Hudson Valley.
The utilities filed their original plans in October 2013.
Nine Options
In addition to a modified version of their original proposed project, the utilities’ new filing lists eight alternatives created to address choke points between upstate New York and southeastern New York and other congested transmission lines within the Hudson Valley region. There are four UPNY/SENY Interface alternatives and four UPNY/SENY & Central-East Composite alternatives.
Seven of the nine proposals meet the objective of adding 1,000 MW of capacity to the Hudson Valley region.
The UPNY/SENY alternatives cost less because they address only transfer points at the interface. They range from an estimated $102.5 million to $525 million.
The four composite alternatives are more costly, as they provide system benefits by replacing aging transmission infrastructure. They range in estimated cost from $764 million to nearly $1.19 billion.
The PSC said it will evaluate each of the proposals and determine which ones meet its criteria; not all will be built.
All of the proposed projects would begin construction by 2017 or 2018, with completion of all of the work by the end of 2020.
Concerns over Cost Overruns
On Jan. 15, the transmission owners filed a petition asking the PSC to clarify that current cost estimates are not binding.
In the December order, the PSC said staff recommendations for a risk-sharing approach are “generally consistent with FERC precedent” and that “this approach will ultimately be subject to FERC’s approval.”
The TOs said the PSC’s approach may not conform to FERC policy, putting them and other developers “in a precarious and untenable position.”
“Accordingly, the NYPSC should clarify that it is not mandating that developers adhere to any specific cost estimate or risk sharing mechanism but rather will consider any risk sharing proposal submitted as part of project proposals along with all other factors in determining the best project to meet the public interest.”
A subsidiary of Sumitomo Corp. was temporarily suspended from the New England wholesale energy market this month due to a default on its financial obligations.
Pacific Summit Energy, which trades electricity, natural gas and crude oil from offices in Newport Beach, Calif., and The Woodlands, Texas, was suspended on Jan. 5 by ISO-NE. The grid operator notified the Federal Energy Regulatory Commission by letter on Jan. 12.
“Pacific Summit has cured the default and the company is currently meeting all of its obligations under the ISO New England Tariff,” ISO-NE Spokeswoman Marcia Blomberg said Friday.
Declining to discuss specifics of the case, Blomberg added: “In general, suspensions are a result of a participant not maintaining a minimum amount of collateral and/or not complying with other financial assurance and billing requirements.”
She also declined to say when PSE was returned to good standing.
Blomberg said there is no requirement for notification to FERC when a suspension is lifted.
PSE, created by Japanese conglomerate Sumitomo in 2012, did not return calls seeking comment.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
A. Manual 03A: Energy Management System (EMS) Model Updates and Quality Assurance (QA) — Includes updates and formatting changes to improve consistency and readability; new table added for important links.
C. Manual 18: PJM Capacity Market – Updated to reflect revisions recently approved by the Federal Energy Regulatory Commission to the shape of the Variable Resource Requirement Curve, gross cost of new entry values, and the Net Energy & Ancillary Services Revenue Offset methodology. (See PJM Board Orders Filing on Capacity Parameter Changes.)
D. Regional Transmission and Energy Scheduling Practices document — Changes made to comply with FERC Order 676H and North American Energy Standards Board standards. PJM is primarily impacted by FERC requirements for “Service Across Multiple Transmission Systems” (SAMTS). (See FERC Proposes Revised Communication, Business Rules.)
Members Committee
2. CONSENT AGENDA (11:05-11:10)
B. Tariff and Operating Agreement (OA) revisions developed by the Demand Response Subcommittee to change the way PJM measures and verifies residential demand response.
The revisions allow statistical sampling and clarify rules for all residential customers. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25.)
C. Tariff revisions to remove seller credit, a form of unsecured credit, from the credit policy, which RTO officials say is no longer necessary.
D. Tariff and OA revisions related to data availability for the bus distribution factors for zonal and residual metered load aggregates utilized by the day-ahead energy market. In the event technical limitations restrict PJM’s ability to obtain the load distribution factors from the 0800 snapshot one week prior to the operating day or if the data is unavailable, the load distribution factors from the most recently available day of the week that the operating day falls on will be used. (See “Tariff Revisions to Metered Load Aggregates” in Markets and Reliability Committee Briefs, Dec. 22.)
Illinois legislative leaders haven’t decided on their next move following a report that offered options for improving the finances of Exelon’s nuclear power plants.
“The report just came out. We’re still examining it,” Steve Brown, spokesman for House Speaker Michael Madigan, said Friday. Madigan, a Democrat, introduced Resolution 1146, which passed with bipartisan support last spring, asking state agencies to investigate “potential market-based solutions to guard against premature closure of at-risk nuclear plants and associated consequences.”
The resulting 269-page report, released Jan. 8, advised legislators that they could keep the status quo; establish a cap-and-trade program with other states; tax fossil fuel-burning generators; adopt a low-carbon portfolio standard; or embrace a sustainable power planning standard. (See Illinois Considering Carbon Tax, Cap-and-Trade to Save Exelon Nukes.)
All of the options are likely to result in higher power prices for consumers.
Asked whether there would be meetings or public hearings, Brown said, “I don’t know if any of that has been decided yet.”
Brown said the recent turnover in the state’s executive branch will play a part in what happens next. Republican Gov. Bruce Rauner took office last week, replacing Democrat Pat Quinn.
“I’d say later rather than sooner regarding the timetable,” Brown said, adding that it was premature to say which of the five options will gain traction.
“I have not heard any discussion suggesting that there’s a consensus around any of the different ideas,” he said. “It’s an important issue and will take some time to sort out.”
Likewise, the office of House Republican Leader Jim Durkin, who co-sponsored the resolution, offered no timetable for a response to the report.
Exelon has said that its nuclear generating stations in Byron, Clinton and Quad Cities are unprofitable in the current market and that government subsidies and tax credits afforded the wind and renewable energy sectors have created an unfair market advantage for its competitors.
The nuclear power giant argues that its stations should get credit for producing carbon-free electricity.
While Exelon lauded the report as validating its view, others interpreted it differently.
“These reports clearly demonstrate that the economic situation for multiple nuclear facilities is much more manageable than originally thought. The report also finds that the retirements of the Illinois nuclear fleet will not cause reliability problems with the state’s electric supply, except under extreme scenarios never before seen in U.S. energy markets, including PJM,” said David Gaier, spokesman for NRG Energy.
Gaier said the best course of action would be to keep the status quo. “Allowing the market to work, which means no ‘subsidy legislation,’ will save ratepayers more than $120 million per year,” he said.
Much of the Illinois report addresses the potential costs to the state if the plants are retired, which would result in the loss of jobs and tax revenue and the possibility of having to burn more fossil fuels to replace the lost generation.
It was produced by the Illinois Commerce Commission, the Illinois Power Agency, the Illinois Environmental Protection Agency and the Illinois Department of Commerce and Economic Opportunity.
Minnesota’s ALLETE Clean Energy will increase its MISO wind portfolio by one-third with a $10 million acquisition from EDF Renewable Energy.
