The Federal Energy Regulatory Commission gave final approval to a North American Electric Reliability Corp. standard on physical security without a provision that would have given FERC and other government agencies the ability to overrule transmission owners’ definition of “critical” facilities.
In its final order (RM14-15), FERC said it dropped the veto proposal in response to criticism that the term “applicable governmental authorities” was too vague, making the standard impractical to enforce. Many also called it redundant, as FERC’s power to enforce NERC reliability standards would already ensure coverage of the most critical facilities.
“We are persuaded by commenters that the [Notice of Proposed Rulemaking] directive would present NERC, as the entity that would have to develop the proposed modification, and the commission, which would have to approve any NERC proposal, with a number of substantial policy issues,” FERC said.
The NOPR said the commission and “other appropriate federal or provincial authorities” should have the ability to add or remove critical facilities. The NOPR was issued under pressure from members of Congress alarmed by the 2013 sabotage of a Pacific Gas and Electric substation. (See FERC: We’ll Have Last Say on Sabotage Rules.)
The reliability standard (CIP-014-1) requires that transmission owners and operators perform risk assessments to identify transmission stations and substations “that, if rendered inoperable or damaged, could result in widespread instability, uncontrolled separation, or cascading within an Interconnection.” Operators of such facilities will be required to conduct an evaluation of the physical threats posed and report on how they are addressing them.
“While the rule does not go as far as some would like, it is still a step in the right direction,” Commissioner Norman Bay said last week. “It’s my hope that registered entities have already begun the process of doing risk assessments and engaging in planning.”
FERC OKs NERC 5-Year Performance Assessment
FERC last week also accepted NERC’s second performance assessment, which the organization is required to file every five years. The commissioners praised NERC for its work in ensuring reliability, but they also said there was room for improvement.
In its order, FERC directed NERC to submit a report on its work to improve the coordination among the regional entities, as well as an analysis of repeat reliability violations by companies.
Chairman Cheryl LaFleur said FERC’s approval of the assessment “reflects the commission’s continued confidence in the work of NERC and the regional entities in strengthening the reliability of the bulk power system. At the same time, it appropriately challenges NERC and the regional entities to further strengthen their efforts.”
The commission also gave preliminary approval to NERC’s revised Real Power Balancing Control Performance Reliability Standard (RM14-10). The standard (BAL-001-2), which applies to balancing authorities and regulation reserve sharing groups, is designed to maintain Interconnection frequency within predefined limits.
Up-to-congestion trading volumes in PJM have dropped by about 85% since September, after the Federal Energy Regulatory Commission said it might make the transactions liable for uplift assessments.
The average volume of cleared up-to-congestion trades had increased 22.5% in the first three quarters of 2014, compared to the first nine months of 2013, according to the Independent Market Monitor’s third-quarter State of the Market report.
But the growth came to a halt Sept. 8, the effective date set by FERC for any uplift assessments.
Market Monitor Joe Bowring told the Members Committee webinar last week that traders appear to have begun limiting their UTC trades to the most profitable paths, as average profits have increased from $0.02 per MW in the two months before Sept. 8 to $0.94 per MW in the two months after.
Before the FERC ruling “you could make money and have a very small margin with large volumes,” Bowring said. Now, he said, traders are shunning less profitable trades that they fear will be net losers if uplift assessments are applied.
FERC ordered a Section 206 proceeding to determine whether PJM is improperly treating UTCs differently than INCs and DECs in the interpretation of a forfeiture rule and in the application of uplift charges. (See UTC Trading Falls Following FERC Order.) FERC has scheduled a technical conference on the issue for Jan. 7.
The Monitor’s quarterly report said the reduction in UTC trading has not resulted in “negative impacts … and there have been some positive impacts.” Day-ahead and real-time binding constraint hours have fallen sharply since Sept. 8.
PJM is planning an effort to identify discrepancies among its governing documents, an initiative prompted by a lawsuit that officials say could have harmed the RTO’s credit rating and increased its insurance costs.
At last week’s Markets and Reliability Committee meeting, General Counsel Vince Duane presented the first read on a problem statement to create a Tariff Harmonization Senior Task Force to review what he called “legal boilerplate” provisions regarding definitions, indemnification, limitation of liability and alternative dispute resolution procedures in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35.
“Sometimes they should be the same; sometimes they should be different,” he said.
Duane said the inconsistencies came to light when counsel examined the documents in connection with a lawsuit brought in 2008 by PPL electrician Marlin Yorty, who was severely burned while working at a substation on the Juniata-Conemaugh 500-kV transmission line.
In October 2013, the Pennsylvania Superior Court ruled that PJM was not responsible for Yorty’s injuries because it was protected by a Federal Energy Regulatory Commission tariff that superseded state law.
“We began looking at the provisions more carefully in the legal department and found inconsistencies and vulnerabilities,” Duane said.
Separately, the MRC approved non-substantive revisions to definitions in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35. The changes are intended to align the documents.
Transmission upgrades of $20 million or more and all “greenfield” transmission proposals will be charged a $30,000 fee under an Operating Agreement revision approved by the Members Committee Thursday.
The proposal by LS Power was approved by an 84% sector-weighted vote after an earlier proposal by the Regional Planning Process Task Force, which would have charged only greenfield projects, fell short of a two-thirds majority. The task force’s proposal was approved by the Markets and Reliability Committee in October. (See PJM Members Approve $30K Fee on ‘Greenfield’ Tx Proposals.)
The result is a victory for LS Power and other nonincumbent transmission developers, who contended it was unfair to charge greenfield projects only.
PJM officials said that upgrades by transmission owners typically did not require the intensive engineering analysis that the fee is intended to pay for. “There is virtually no cost in evaluating these proposals,” said Steve Herling, vice president of planning.
The fee will be re-evaluated after a two-year trial.
ICC to Vote on Rock Island Clean Line at Next Meeting
The Commerce Commission could vote today on the future of a $2 billion direct-current transmission project designed to bring wind energy from the Midwest, including Iowa, into the PJM system.
The 500-mile Rock Island Clean Line would transmit wind energy to a $300 million converter station in Grundy County, where the direct current would be transformed into an alternating current and introduced to the grid. The ICC vote on the project was scheduled for a meeting earlier in the month but was delayed to give commissioners more time to review it. The operators are seeking a certificate of public convenience and necessity.
The project has attracted opposition from landowners along its proposed right-of-way.
Customer Advocate Calls for Rejection of Duke Energy’s $1.9B Grid Upgrade
The Office of Utility Consumer Counselor said Duke Energy hasn’t provided enough details on its proposal to spend $1.9 billion on transmission and distribution upgrades and that the proposal includes items that shouldn’t be billed to ratepayers.
“The information we found in Duke Energy’s filings does not meet the statute’s requirements, while also falling short of the standards established in previous cases involving the approval of other utilities’ plans,” Consumer Counselor David Stippler said. He said items such as vegetation management, a $3 million energy learning center and radio system improvements that are included in Duke’s seven-year plan should not be included in the rate base.
Stippler has recommended that the Utility Regulatory Commission deny the plan, which would result in rate increases of about 1% per year from 2016 through 2022 for Duke’s 800,000 customers in the state.
A Duke spokeswoman said the company has provided hundreds of pages of documentation and that all its proposed expenses are necessary and responsible. “Our electric grid is aging and many components need to be updated and replaced,” she said. “This plan is about modernizing our electric grid and bringing our system into the 21st century.”
State Signals Intent to Deny Exelon’s Conowingo Permit
The state Department of the Environment said it needs more information on Conowingo Dam’s impact on the health of the Chesapeake Bay and said it intends to deny a key approval for the Exelon Generation facility. The DEP has scheduled a Jan. 7 public hearing in advance of a Jan. 31 deadline the state must meet to sign off on the water quality portion of the Federal Energy Regulatory Commission’s overall operating permit.
The Susquehanna River hydro facility has already obtained a one-year extension of its current license, so DEP’s decision does not have an immediate impact on plant operations. If the state continues to withhold the water quality permit, Exelon may have to change how it operates the facility. The company has faced persistent criticism about how much nutrient-rich sediment the dam allows downstream.
Michigan PSC to be First Agency to Use PACE for New Headquarters
The Public Service Commission’s landlord is using Property Assessed Clean Energy (PACE) financing to pay for efficiency improvements at its new headquarters, the first energy agency in the U.S. to use the emerging funding mechanism.
The building’s private owner is using $500,000 in PACE financing for LED lighting, a solar array and HVAC equipment. PACE financing is typically done through a local government agency and the costs are repaid through a property tax assessment, making it easy for building owners to transfer repayment obligations to a new owner. With its headquarters, the commission will repay the costs of the 20-year fixed-rate loan through the project’s energy savings.
“PACE is an innovative way that landlords, tenants and local officials can work together to pursue energy-efficiency projects that would not otherwise take place,” PSC Chairman John Quackenbush said.
BPU Again Denies Fisherman’s Energy Wind Project Due to High Prices
The third time was not the charm for the proposed Fisherman’s Energy wind project off the coast of Atlantic City.
The Board of Public Utilities again denied approval for the 25-MW project, saying that the projected energy price of $199.17 per MW/h was too high and that ratepayers could end up responsible for $19 million if the project fails. The project has been in the works for three years and has gained federal funding, but it hasn’t been able to get BPU approval to go forward.
State Senate President Stephen Sweeney, a Democrat, decried the state’s failure to build a single offshore turbine since New Jersey passed the Offshore Wind Economic Development Act.
“Over three years ago we passed legislation that was meant to make New Jersey the national leader in wind and renewable energy,” Sweeney said in a statement. “It means hundreds, if not thousands, of new jobs for our state in a time of economic uncertainty. But three years later, even though the bill was signed into law, nothing has happened to make this a reality. New Jerseyans have suffered because of this inaction.”
Gov. McCrory Sues Legislature over Coal Ash Commission Makeup
Gov. Pat McCrory, along with two former governors, is suing Senate Leader Phil Berger and House Speaker Thom Tillis over the makeup of the state’s new Coal Ash Management Commission.
The legislature formed the commission after Duke Energy’s massive coal ash spill into the Dan River in February. McCrory, who was a Duke executive before becoming governor, contends that the commission’s makeup — the legislature names six of nine members — violates the separation of powers by giving the legislature control over environmental regulation, a function he says belongs with the executive branch.
“The disagreement among the two branches is not acrimonious, but it is of fundamental importance,” McCrory said. “I have too much respect for North Carolina’s constitution to allow the growing encroachment of the legislative branch into the responsibilities the people of North Carolina have vested in the executive branch.”
Berger and Tillis have said that McCrory could have vetoed the legislation and didn’t.
AEP Ohio’s Energy-Only Auction Results Accepted by PUCO
The Public Utilities Commission has approved the results of AEP Ohio’s energy-only auction, which set the average clearing price of $51.37 per MW/h for 40% of the company’s load from January through May of next year. Five suppliers submitted winning bids during the 14-round auction.
This was the fourth auction, and its results will ultimately determine retail generation service rates through May. The independent auction manager was National Economic Research Associates. Boston Pacific Company monitored the auction. Winning bidder names will be disclosed in 21 days.
A redacted version of the report can be found here.
PENNSYLVANIA
Still Time for Philly Council to Authorize Sale of PGW
It looked like a deal to sell Philadelphia Gas Works to UIL Holdings Corp. for $1.86 billion was dead after the Philadelphia City Council failed to hold hearings on the deal, but efforts to save it are going down to the wire.
A UIL executive breathed life into the proposed sale when he appeared before the council on Nov. 13 and said UIL would consider amended sales terms. Labor leaders are meeting with UIL to address concerns, and Mayor Michael Nutter’s office is continuing to push for the sale. The council could still introduce legislation authorizing the sale at either of its two remaining meetings of the year, Dec. 4 and Dec. 11. The sale agreement expires Dec. 31. Nutter’s office and UIL could also agree to extend the sale agreement if the council doesn’t act in time.
The mayor proposed to privatize the nation’s largest municipal gas utility to pay down its underfunded pension plan and to attract private capital to upgrade the city’s aging natural gas distribution system.
Dominion Customers Could See Bills Increase by 30% by 2025 with EPA Emissions Rules
State lawmakers heard from Dominion Virginia Power that efforts to meet the Environmental Protection Agency’s emissions mandates could increase bills by 30%, or about $400 more a year, for the utility’s customers by 2025.
“In our world, that does not give us a lot of time,” Robert M. Blue, Dominion Virginia Power’s president, told a joint hearing of the House and Senate Commerce and Labor committees last Wednesday. “We need to start acting now. We don’t have the luxury of waiting.” Interim reduction goals need to be met by 2020.
A more optimistic view was offered by Cale Jaffee, director of the state office of the Southern Environmental Law Center. He said Virginia has already met nearly 80% of the carbon reduction goals and that investment in renewable energy sources could take it the rest of the way.
PSC Commissioner Responds to Complaints of Too Much Power
In response to a report complaining that the Public Service Commission had too much power, Chairman Michael Albert said that decreasing the commission’s oversight would be a bad thing for customers.
“Public utilities, whether publicly owned or privately owned, are monopolies,” he said. “The commission fills a special role with respect to public utilities. We are a surrogate for competition that is otherwise lacking in their operations.”
A report commissioned by the West Virginia Rural Water Association and groups representing small public service districts was critical of the commission’s policy of prohibiting public service districts from keeping contingency funds. Albert said the rule is sound because it protects stressed customers from paying utilities to keep a reserve.
PJM should change its rules on pricing and scheduling of interface transactions to reflect changes in system conditions and eliminate the need to schedule physical transactions across seams, the RTO’s Independent Market Monitor says.
The two proposals were among four new recommendations that Monitoring Analytics made in its third-quarter State of the Market report.
(Click to zoom)
The Monitor said PJM and neighboring balancing authorities should develop an optimized joint dispatch that treats their seams like any other constraint under LMP rules.
It also recommended that PJM adjust its weighting procedure to “ensure that the interface prices reflect ongoing changes in system conditions and that loop flows are accounted for on a dynamic basis.” It said PJM should conduct an annual review of the mappings of external balancing authorities to individual interface pricing points to reflect changes to the impact of the external power source on PJM tie lines as a result of system topology changes.
The Monitor also recommended changing the submission deadline for real-time dispatchable transactions from 1200 the day before to three hours before the requested start and that the minimum duration be reduced to 15 minutes from one hour. “These changes would give PJM a more flexible product that could be utilized to meet load in the most economic manner,” the Monitor said.
Offering a different solution on an issue it has discussed before, the Monitor said the amount of tier 1 megawatts paid when the non-synchronized reserve market clearing price goes above zero should be equal to the tier 1 megawatts estimated by the real-time security constrained economic dispatch market solution.
The Monitor has said that its preferred solution is to stop paying tier 1 synchronized reserves the synchronized-reserve market-clearing prices when the non-synchronized price is above zero. Last month, the Market Implementation Committee approved a problem statement proposed by Monitor Joe Bowring to consider changes to the payments.
Map of SPP’s new territory, highlighted in blue (Source: Basin Electric Cooperative)
SPP won federal approval Nov. 10 to add three new members in the Upper Great Plains, a seven-state expansion that restores the RTO’s scope after its loss of Entergy to MISO.
SPP’s footprint shrunk in Arkansas, Louisiana, Mississippi and Texas after Entergy’s defection to MISO. Its territory now shifts north with the Federal Energy Regulatory Commission’s approval (ER14-2850) to add Heartland Consumers Power District, Basin Electric Power Cooperative and the Western Area Power Administration’s Upper Great Plains Region (Western-UGP).
The three new SPP members represent the backbone of the bulk electric system in seven states and consist of about 9,500 miles of transmission lines with more than 3 million customers, increasing SPP by about one-fifth.
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.
“FERC’s substantive approval clears the way for us to continue to work toward [integration]. We expect to take on reliability coordination of the … transmission system in June 2015, with full membership in October 2015,” SPP Chief Operating Officer Carl Monroe said in a statement after FERC’s approval.
Little Rock-based SPP said the expansion will bring stakeholders more than $334 million in net benefits. SPP cites increased ability to commit and dispatch generation that affects flows through and out of Nebraska. It also pointed to the availability of lower-priced generation, including Western-UGP’s excess hydro power.
Concerns Raised
FERC and stakeholders took issue with parts of SPP’s integration plan, however.
The commission rejected SPP’s proposal to revise Schedule 12 of its Tariff, which covers the collection of FERC assessments. FERC noted that the cost of regulating Western-UGP and other federal power marketing agencies is administered in a different manner and that it was concerned about the possibility of a double assessment of FERC charges.
Kansas utility regulators told FERC that the three new members of SPP should be responsible for a “proportionate share” of costs for certain base plan upgrades in service before and after Oct. 1, 2015, because they would benefit from SPP membership and services. Otherwise, Kansas ratepayers would face an unreasonable financial burden when utilities in the state recover those costs from their customers, the Kansas commission argued.
FERC said the Kansas commission “neglects to consider the benefits the rest of the SPP membership will receive” from the three new members’ legacy systems, such as increased grid reliability and congestion management.
A number of consumer groups, transmission operators and state regulators also raised concerns about seams issues, including the potential that some utilities that serve Montana retail customers could be required to pay for transmission service from both SPP and MISO.
FERC said concerns about such pancaked rates were beyond the scope of the proceeding and should be taken up in hearings and settlement judge procedures later.
MISO-SPP Dispute
(Source: SPP)
MISO raised a handful of concerns, including whether FERC’s rulings on the expansion could put it at a disadvantage in its dispute with SPP over their joint operating agreement.
SPP alleges that the JOA was breached after Entergy joined MISO late last year and began transferring electricity over SPP’s lines. MISO said that SPP has billed it for more than $35 million for flows exceeding the limited 1,000-MW physical contract path between MISO Midwest and MISO South. The latter consists mainly of Entergy’s footprint.
MISO sought a confirmation that FERC’s approval of SPP’s proposed cost allocations for Basin Electric’s projects would not prejudice the issue of whether MISO should be held responsible for any charges that could stem from the JOA dispute.
FERC sought to alleviate MISO’s concerns, saying “we confirm that our acceptance of [SPP’s expansion] does not prejudge the outcome of the ongoing hearing and settlement judge procedures.”
Since last April, FERC has convened five settlement conferences between SPP and MISO.
Talks Sour
The tone of the talks soured recently. On Nov. 17, SPP filed a scathing rebuttal opposing a request by MISO for expedited consideration of the JOA dispute, calling it “procedurally improper, unsupported and an impediment to further progress in ongoing settlement negotiations.”
To date, MISO “has not paid a dime for any of the flows it has imposed on SPP’s system,” SPP said.
SPP argues that some of the charges are the result of MISO failing to reserve service under an accepted agreement. “If MISO simply reserved service on an hourly basis it would not be subject to these daily charges,” SPP said.
Hands Full
SPP plans to take on reliability coordination of its three new members starting in June.
SPP said in its most recent annual report that the most significant transmission challenges facing much of its footprint stem from an increase in oil and gas drilling.
“New oil and gas drilling facilities are built faster than they can be captured in SPP’s planning processes and models,” the RTO said. “Additionally, pipeline expansions are proposed for the region that will increase the need for electric transmission facilities to serve the pumping stations.”
The PJM Board of Managers won’t make its Dec. 1 target for filing the RTO’s Capacity Performance proposal with the Federal Energy Regulatory Commission, CEO Terry Boston told members last week.
As a result, PJM will likely post two sets of parameters for the May 2015 capacity auction — one assuming the status quo and one assuming FERC approval of what the board ultimately files.
Boston also said he will recommend that the board’s Section 206 filing not incorporate PJM’s proposal to eliminate demand response as a supply resource. The proposal, outlined in an Oct. 7 white paper, would make load-serving entities responsible for incorporating DR in reduced demand estimates. (See PJM DR Cos. Confident; Reject PJM EPSA Response.)
Boston said PJM should delay changes in its DR rules pending the resolution of a potential Supreme Court review of the D.C. Circuit Court of Appeals’ Electric Power Supply Association ruling voiding federal jurisdiction over DR compensation. “We think the courts and FERC have to do their job,” Boston said. “CP will work either way.”
Boston said the board, which heard from 50 speakers during a four-hour meeting with stakeholder coalitions on Nov. 11, met the day afterward and also conducted a two-hour teleconference with PJM staff last week. The board plans to meet again after Thanksgiving. “The board knows where each coalition stands,” Boston said. “They are weighing all sides of the issue.”
NJ Regulators OK Pass-Through
Meanwhile, the New Jersey Board of Public Utilities decided last week to allow bidders in its February Basic Generation Service auction to pass through “unanticipated” capacity costs approved by FERC.
Retail customers that do not choose alternative suppliers obtain their power through the BGS auctions. In New Jersey, 85% of residential ratepayers and 70% of small commercial customers rely on BGS.
The BPU said it acted because it was unlikely FERC would rule before the next BGS auction in February and it feared potential bidders would decline to participate or include large risk premiums to cover the uncertainty.
BPU President Richard S. Mroz said the action would ensure “the integrity and competiveness” of the auction. “Faced with the uncertainty of federal action on a draft PJM proposal, there was good reason to believe that electric suppliers would either not participate in the upcoming auction or would bid much higher prices to mitigate unknown risks,” he said.
Md. Auction Sees Reduced Participation
The Maryland Public Service Commission blamed uncertainty over the CP proposal for a nearly 50% drop in bidder participation in its Oct. 20 auction for Standard Offer Service, Maryland’s method of supplying customers that do not shop.
The state’s four investor-owned utilities sought 2,184 MW for residential and small and medium commercial customers. The PSC said only five suppliers submitted bids on one or more of the 10 products available in the auction, down from nine in the previous auction.
Only two bidders offered to supply residential and small commercial customers, and only one bidder made offers for several other products.
Pepco (330 MW of combined residential and small commercial customers), Potomac Edison (46 MW of 12-month and 24-month residential supply) and Delmarva Power & Light (122 MW of residential and small commercial) each received only one bid.
Overall, the PSC received bids totaling 1.8 MW for every megawatt it sought, compared with a 3-1 ratio in the previous auction.
“Although the Maryland PSC accepted the bid results and determined that the SOS auction was in line with market conditions, the material reduction in generator interest in bidding in the auction is a cause of great concern,” PSC Chairman W. Kevin Hughes said in a letter to the PJM board.
In testimony to the PSC, Maryland’s bid monitor, Boston Pacific, concluded that “the current level of uncertainty was great enough to keep many bidders from offering for the longer-term residential and [small commercial] products.”
Consolidated Edison of New York has opened a new front in its attempt to persuade federal regulators that it’s been saddled with an unfair share of two transmission upgrades in northern New Jersey.
The company filed a complaint on Nov. 10 with the Federal Energy Regulatory Commission stating its opposition to a cost allocation formula that PJM has devised for the upgrades (EL15-18). Con Ed said it is being overcharged by about $650 million for the projects.
PJM assigned Con Ed $629 million of the costs of a $1.2 billion transmission upgrade to address a short-circuit problem in the Public Service Electric and Gas transmission zone outside New York City. PJM said Con Ed’s responsibility resulted from its use of the “Con Ed-PSEG wheel,” in which Public Service Enterprise Group, PSE&G’s parent company, takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City. PSE&G was allocated $52 million of the cost.
Con Ed was also assigned $51 million of PSEG’s $100 million Sewaren storm-hardening project.
In April, FERC rejected Con Ed’s attempt to avoid paying for the short-circuit project but said it wanted more information on how PJM performed the distribution factor (DFAX) analysis that determined Con Ed’s share of the cost. (See FERC Rejects Con Ed Challenge on Tx Upgrade.)
Con Ed also said PJM’s Tariff requires a review of instances where PJM’s cost allocations will produce “objectively unreasonable” results.
The company said the new complaint will provide a more holistic consideration of the cost allocation than the rate filing that prompted FERC’s earlier order.
“FERC has recognized that parties have a right to challenge previously approved cost allocation methodologies,” Con Ed spokesman Bob McGee said. “As such, Con Edison exercised its rights under the Federal Power Act and challenged the cost allocations themselves, the decisions and actions taken by PJM in producing the cost allocations and the discrete elements of PJM’s Tariff that caused these unjust, unreasonable, unduly discriminatory and preferential results.”
The Federal Energy Regulatory Commission has ordered hearing and settlement procedures on MISO’s proposed cost allocation for the Presque Isle Power Plant, which would cause steep rate increases for residents in Michigan’s Upper Peninsula.
The Nov. 10 ruling (ER14-2860, ER14-2862) comes after a flood of ratepayer and political pushback to MISO’s system support resource agreement (SSR) that blocks Wisconsin Electric Power Co. (WEPCO) from closing the aging and costly generator near Marquette, Mich.
MISO sought the SSR last year after determining that the 400-MW coal-fired plant was needed for reliability of the region’s grid.
Upper Peninsula ratepayers would shoulder the bulk of the estimated $100 million annual cost to keep Presque Isle in operation. Michigan and Wisconsin utility regulators say the cost of keeping the plant in operation is unreasonable. (See Michigan: FERC Favors Transmission in Presque Isle Dispute.)
The Michigan House of Representatives on Nov. 6 passed a resolution calling on FERC to reverse its acceptance of MISO’s cost allocation, which it said would saddle Upper Peninsula residents with 99.5% of the Presque Isle costs. The resolution asks FERC to divide the cost in “a more equitable manner.”
Dozens of cities and towns drafted similar resolutions and filed them with FERC. A number of businesses in the Upper Peninsula complained that their monthly costs would rise by several hundred dollars a month and that they would be forced to cut jobs.
FERC’s files were filled with complaints from residential ratepayers, as well.
“I am a semi-retired elder on a very limited income. Having to pay $30 to $50 more on my electric bill would be an extreme hardship for me and many others like me,” wrote Ruth Pickem, of St. Ignace, Mich.
“If Wisconsin does not have to pay because they do not benefit from the plant, then we should not have to either. We do not benefit from this plant! Close it!” Pickem added.
The uproar over Presque Isle even triggered bipartisan legislation from Michigan lawmakers in Congress, Democratic Sen. Debbie Stabenow and Reps. Dan Benishek (R) and Gary Peters (D).
“The Power Act,” introduced earlier this month, would essentially require FERC to overrule decisions by the North American Electric Reliability Corp. if a review found it resulted in “unjust and unreasonable” rate increases.
The bill’s sponsors said NERC’s intervention “upended” an earlier FERC finding that Upper Peninsula ratepayers should bear only 14% of Presque Isle’s operating costs.
WEPCO has expressed interest in adding new generation in the Upper Peninsula.
Other studies have been conducted into the possibility of building new transmission to the Upper Peninsula, although that would likely cost hundreds of millions of dollars. A combination of both new transmission and generation remains under debate.
A hearing date in the Presque Isle SSR matter has yet to be scheduled.
