State Briefs

State Holds Delayed Hearing on PSEG New Nuke Plans

The state’s Congressional delegation arranged for a public comment session on a possible new reactor at Public Service Enterprise Group’s Artificial Island site in New Jersey after lawmakers realized that only Garden State residents had been given the opportunity to talk. A session was held Thursday in Middletown to let residents speak out about the Nuclear Regulatory Commission’s draft environmental impact review. Although PSEG has not made firm plans for a new reactor at the site – home of the Salem and Hope Creek reactors – it is pursuing NRC site approval.

Richard Cathcart, manager of Delaware City and a former state representative, said he supports construction of a new reactor on the Artificial Island site across the state line. “We know that the construction workforce could grow to over 4,000 jobs, many of which could go to Delawareans,” he said, noting that he was speaking as a private citizen. “And we know new construction could bring a much-needed and major boost to the economy.”

But environmentalists question how an early site approval can be given when PSEG hasn’t even determined what type of reactor design it would deploy.

More: The News Journal

DISTRICT OF COLUMBIA

New Office of Consumer Services Chief Named by Public Service Commission

The Public Service Commission appointed a program analyst as the interim Director of the Office of Consumer Services.

Susan Nelson, who started as an analyst in the PSC’s Office of Technical and Regulatory Analysis in May, was elevated to fill the position after Linda Jordan retired earlier this month. The Office of Consumer Services handles consumer complaints and inquiries and operates outreach programs. Nelson held numerous customer care and billing positions in the telecommunications industry before joining the PSC.

More: PSC

ILLINOIS

Grand Prairie Gateway Wins ICC Approval

The Commerce Commission approved Commonwealth Edison’s Grand Prairie Gateway Project, a 70-mile transmission line running across four Illinois counties. Construction of the $251 million project is scheduled to begin next year and be completed in 2017.

The 345-kV line “would allow greater access to renewable energy west of Illinois, which should enhance competition in the electricity markets,” a commission news release said. Terence Donnelly, ComEd executive vice president, said the line will relieve congestion that impedes the flow of low-cost energy, and reduce costs for delivering energy to customers.

The line would start from a substation near Byron Nuclear Generation Station and continue to a substation near Wayne. Byron is owned by ComEd’s parent company, Exelon.

More: Kane County Chronicle

INDIANA

Vectren Customers See Big Spike in Energy Bills

Droves of Vectren customers have applied for energy assistance after many complained about dramatically higher bills to make up for underpayments in previous months.

The Utility Regulatory Commission is monitoring Vectren’s action plan after hundreds of customers complained. Vectren officials say that the problem stems from inaccurately estimated bills. The company has been swamped with requests to meet with customer service representatives, and community service organizations say they’re experiencing record numbers of requests for emergency energy subsidies.

A single mother of three children said her Vectren bill was around $11 for three straight months then jumped to more than $700.

More: WTVW

KENTUCKY

LG&E/KU Adjusts Generation Construction Plans

Louisville Gas & Electric and Kentucky Utilities updated plans with the Public Service Commission, telling the PSC they will need to build between 368 MW and 737 MW of natural gas generation starting in 2020. The PPL subsidiaries filed the updated resource assessment report with the PSC last week.

The companies said they plan to retire two units at the E.W. Brown coal-fired plant and still plan to go forward with a 10-MW solar project on the plant site. Uncertainty about the effect of the recent Environmental Protection Agency emissions rules make it difficult to be more specific, the utilities said. Further load growth studies could force them to consider building more natural gas-fired generation before 2020.

More: UtilityDive

MARYLAND

PSC Holding Public Sessions on BGE’s Rate Increases

Baltimore Gas and Electric is asking for its fourth rate hike in four years. The Public Service Commission has scheduled several public hearings.

The company wants to raise distribution charges to both gas and electric customers by about $15 a month. BGE says it needs the increase to pay for infrastructure upgrades. If approved, the rates would go in effect in January.

More: The Baltimore Sun

MICHIGAN

Senators Ask Feds to Delay We Energies Rate Hike

Sens. Carl Levin and Debbie Stabenow have asked the Federal Energy Regulatory Commission to reconsider its decision to force We Energies customers in the state to absorb a $97 million rate increase to pay for the company’s power plant in Marquette.

We Energies wanted to shut its Presque Isle Power Plant after its largest industrial companies switched to another provider. But MISO determined the plant was crucial to system reliability and ordered that it stay in operation. The Wisconsin Public Service Commission later ruled that a large number of Wisconsin customers should be freed from paying the plant’s costs, shifting the bill to Michigan customers. FERC upheld its ruling.

Levin and Stabenow said the rate impact on customers in the Upper Peninsula is unjustified.

More: WTAQ

NEW JERSEY

Report: Utilities Need to Give BPU More Storm Info

The Board of Public Utilities needs more information on storm responses to determine how to best improve resiliency, according to a consultant’s report.

The report, prepared by GE Energy Consulting, says the state fails to get enough information before and during storms to help it determine the most cost-effective solutions.

It also called on utilities to harden portions of the grid, especially substations. During Superstorm Sandy, 40% of Public Service Electric & Gas substations were shut down by flooding. Since then, the company has started a program to raise substations above the 100-year flood zones or to protect them with walls.

More: NJSpotlight

Utilities Spent $1.25B on Storms in 2011 and 2012, Study Shows

The Board of Public Utilities said utilities in the state spent $1.25 billion to restore and repair systems after the storms of 2011 and 2012, including Superstorm Sandy. The tally was part of the board’s review of storm costs to determine what should be recovered from ratepayers.

The board approved a New Jersey Natural Gas request to recover $48.7 million, including the costs to replace sections of natural gas distribution mains washed away by Sandy. Jersey Central Power & Light said it spent $736.1 million in storm costs. Public Service Electric & Gas said it spent $366.3 million. Atlantic City Electric put its costs at $70 million.

ACE has already received permission to increase rates to cover its costs. JCP&L has a request pending. PSE&G hasn’t asked to raise rates.

More: Asbury Park Press

NORTH CAROLINA

Duke Won’t Charge Customers for Corporate Taxes it Doesn’t Pay

Duke Energy said it will not charge customers $19 million for corporate income taxes that it doesn’t actually have to pay, even though the Utilities Commission approved the practice.

The NCUC ruled earlier this month that utilities can continue to charge customers a 6.9% tax, even though the state legislature recently cut the corporate tax from 6.9% to 5%. Duke said it could have extracted $19 million a year more from Duke Energy Carolinas and Duke Energy Progress customers under the ruling.

“Duke Energy supports the NCUC’s Oct. 9 decision that explains the state of the law in North Carolina,” Duke said. “However, in this case, we have already reduced rates to reflect the decrease in corporate income taxes.”

The ruling gave utilities the option to adjust rates and set an Oct. 24 deadline for them to decide. Republican commission members said the over-collections are negligible for individual bills, but the Democrats said the state’s four utilities would generate an additional $21 million a year.

More: The News & Observer

OHIO

PUCO Drops In-State Renewables Requirement

Utilities in the state no longer have to find in-state sources for half of their renewable energy supply, the Public Utilities Commission ruled.

While making it easier for companies to reach renewable targets, the decision is another blow to the state’s solar industry, which is already feeling a downturn after legislators froze renewable targets earlier this year. “Pure financial projects are on hold right now,” said Geoff Greenfield, president of Third Sun Solar.

More: Columbus Business First

PENNSYLVANIA

PUC Eyes Extension of Utility-Based Energy-Efficiency Conservation

The Public Utility Commission opened a study to consider extending state-directed energy-efficiency and conservation targets for utilities beyond 2016.

The current programs, authorized by a 2008 law called Act 129, set targets for reductions in consumption and peak demand. The targets expire in May 2016. The law requires the PUC to re-evaluate the costs and benefits of energy-efficiency and conservation programs every five years and to consider extending the goals.

More: PUC

EDCs to Provide Customers Look at What Info is Given to Suppliers

The Public Utility Commission directed the state’s electric utilities to reach out to customers every three years to give them the opportunity to review the marketing information being provided to third-party electric generation suppliers. The information includes historic usage and customer addresses.

The PUC’s order directs electric distribution companies to allow customers to access the information and to restrict it if they want. The commission’s action calls on all distribution companies to remind customers of their right to access the information.

More: PUC

PUC’s Audit of PECO Shows Possible Millions in Savings

A Public Utility Commission audit of PECO’s management and operations suggested ways the company could save up to $5.7 million a year and up to $3.1 million in one-time savings. The commission’s Bureau of Audits report was made public by a 5-0 vote of the commission.

The report provided 28 recommendations for the company to improve performance and save money, including reducing non-storm response overtime, improving the mapping of its natural gas lines to cut down on gas line hits and improving oversight of contractors. PECO has agreed to implement all of the recommendations by the first quarter of 2017.

More: The Philadelphia Inquirer; PUC

VIRGINIA

Appalachian Power Files for 6 Energy-Efficiency Plans

Appalachian Power has filed with the State Corporation Commission for approval for four residential energy-efficiency programs and two programs for commercial and industrial customers.

The residential programs include home energy assessments, incentives for customers to give up second refrigerators or freezers, new construction energy-efficiency standards and retail rebates for high-efficiency lighting and appliances. The C&I plans provide incentives for high-efficiency lighting and heating and cooling equipment, and rebates for larger energy-efficiency projects.

The programs are designed to help the company reach mandated energy reduction targets.

More: Bluefield Daily Telegraph

WEST VIRGINIA

Possible to Meet EPA Standards with Mix of Methods, Report Says

The state could meet the Environmental Protection Agency’s proposed carbon emissions standards with a combination of more renewable generation, power plant modification and energy-efficiency programs, according to a report released last week.

The report identified several areas necessary to meet the targets, including modifying existing power plants; dispatching low-emitting plants first; increasing renewable energy generation; expanding energy-efficiency programs; and building lower-emitting, natural gas-fired plants to take advantage of the state’s shale gas production. The report was prepared by the West Virginia University College of Law’s Center for Energy and Sustainable Development, the Morgantown-based consulting firm Downstream Strategies and the Appalachian Stewardship Foundation.

Given the available options, the report said the state can develop a plan to meet its emission targets while also enhancing social, economic and environmental benefits.

More: The Charleston Gazette

October 27, 2014

MRC/MC Preview

The contentious $1,000/MWh energy offer cap is likely to be the subject of some of the most vigorous debate at Thursday’s Markets and Reliability and Members committees meetings.

The MRC deadlocked over the issue Sept. 18 with none of three proposals to lift the cap winning a two-thirds majority. (See Members Deadlock on Change to $1,000 Offer Cap.)

An Oct. 10 task force meeting failed to bridge the gap between generators and load interests. As a result, PJM will ask the MRC to sunset the task force. (MRC agenda item # 3.)

Meanwhile, despite the lack of consensus, Bob O’Connell of J.P. Morgan Ventures Energy will attempt to win MC approval to effectively eliminate the cap from the Operating Agreement as of June 1, 2015. (MC agenda item #4.)

O’Connell’s proposal also suggests that cost-based offers below $2,250/MWh – equivalent to a 15,000 Btu/kWh generator burning gas purchased at $150/Btu -– be allowed to set LMPs. Cost-based offers above $2,250 would be reimbursed through uplift and not set the clearing price. Price-based offers would be permitted to equal cost-based offers when the latter is more than $1,000/MWh.

At the April MRC meeting, O’Connell said that if stakeholders refused to approve a problem statement considering changes to the cap, as few as five members could create a user group to push for the change “through an alternative stakeholder process that may disenfranchise certain members.” (See Effort to Lift Offer Cap Advances After Debate.)

Below is a summary of the other issues scheduled to be brought to a vote at the MRC and MC meetings. 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:

Revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 28: Operating Agreement Accounting that will set the default Tier 1 synchronized reserves estimates to zero MW for nuclear, wind, solar, batteries and hydro generators. The change means those resources will not receive compensation unless they actually produce during a spinning event.
Changes to Manual 1 to comply with a revised reliability standard given preliminary approval by the Federal Energy Regulatory Commission last month. COM-002-4 (Operating Personnel Communications Protocols) requires the use of a three-part communications process when issuing operating instructions. (See FERC Backs NERC, NAESB Standards.)
Revisions to Manual 14A: Generation and Transmission Interconnection Process that create a pre-application process for new and existing generation resource additions of 20 MW or less in compliance with FERC Order 792. Potential interconnection customers will have to submit a formal written request and a $300 processing fee. PJM is requesting these changes be effective beginning Nov. 1. (See PC Starts Work on Small Generator Interconnection Changes.)
Revisions to Manual 19: Load Forecasting and Analysis clarifying process for adjusting load forecasts due to significant load changes. The changes, which do not reflect any change in the procedures, were endorsed by the Planning Committee Sept. 2.
Conforming changes to Manual 18: PJM Capacity Market in response to members’ requests for details of the process for requesting and cancelling demand response maintenance outages and a FERC order allowing Annual, Extended and Limited products for DR (ER11-2288). The changes detail what qualifies for the maintenance outage, timeframes for the notification window, length of outage, extensions, cancellations, impacts to compliance calculations and resource testing.

3. Cap Review Senior Task Force (CRSTF) (9:30-9:50)

The committee will be asked to approve sunsetting the task force. (See above.)

4. Energy / Reserve Pricing & Interchange Volatility update (9:50-10:20)

Members will vote on whether to approve new rules to reduce uplift and ensure energy prices better reflect operator actions. The changes would increase synchronized and primary reserve requirements under emergency conditions when additional intraday resources are scheduled. The committee also will be asked to approve limits on interchange during emergency conditions. The limit would be used when operators have made firm resource commitments and anticipated interchange schedules are sufficient to meet projected load for the hour. The changes were approved last month by the Market Implementation Committee. (See MIC Briefs.)

5. Transmission Owner (TO) Data Feed (10:20-10:30)

Members will be asked to approve Operating Agreement and manual changes to make it easier for transmission owners to access real-time generator data. The changes are intended to improve situational awareness and emergency response. The Operating Agreement would be revised to include a universal non-disclosure agreement, eliminating the need for a separate data confidentiality agreement. Transmission owners will be able to obtain data from generators in their zone without justification. For generators outside its zone, the TO must confirm that the plant is in the current TO energy management system (EMS) model or will be included in an expanded model. The changes were approved by the Operating Committee last month.

6. Cold Weather Resource Improvement (10:30-10:45)

Members will be asked to approve rules for voluntary winter testing of seldom-used generators. The tests would be limited to generators that haven’t run in the prior eight weeks and days when temperatures are below 35 degrees Fahrenheit. (See Winter Testing Could Cost $15.9M.) The Operating Committee approved the changes earlier this month.

7. 2014 IRM STUDY RESULTS (10:45-11:00)

Members will be asked to approve a recommendation to leave PJM’s Installed Reserve Margin at 15.7% for planning year 2018/19, unchanged from 2017/18. The Planning Committee approved the recommendation earlier this month. (See Planning Committee Briefs.)

8. Reactive Supply and Voltage Control Service from Deactivating Resources (11:00-11:15)

The MRC will be asked to approve on first read a proposed problem statement and issue charge seeking to prevent generation fleet owners from collecting payments for reactive power and voltage control service from generators that are no longer running.

9. Manual 29 Revisions – Billing Adjustments (11:15-11:30)

The committee will be asked to approve a proposed problem statement and issue charge on first read regarding revisions to Manual 29: Billing, regarding treatment of underpayments of miscellaneous items or special adjustments. The changes are intended to prevent cost shifting when miscellaneous items or special adjustments are underpaid.

10. Regional Planning Process Senior Task Force (RPPTF) – Window Proposal Fee (11:30-11:45)

Members will consider a proposal by the RPPTF to charge a nonrefundable $30,000 fee for “greenfield” transmission proposals submitted during project proposal windows as a result of FERC Order 1000.

Members Committee

2. CONSENT AGENDA (1:20-1:25)

The MC will be asked to endorse revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described. There is no change in PJM’s calculations, which have been correctly using mileage as it is defined by PJM.
Members will consider revising its conflict of interest policy to reflect the increasing number of consumer product companies, manufacturers and technology companies becoming involved in the electric industry. (See PJM Revising Policy on Prohibited Investments.)

3. Nominating Committee (1:25-1:30)

The MC will elect members of the 2015 Nominating Committee.

4. Energy Market Offer Price Cap (1:30-2:00)

Bob O’Connell of J.P. Morgan Ventures Energy will attempt to win approval for Tariff and Operating Agreement revisions eliminating the $1,000/MWh energy market offer price cap effective June 1, 2015. (See above.)

October 27, 2014

FERC Removes 10% Adder from Generators’ Make-Whole Payments

By Michael Brooks

The Federal Energy Regulatory Commission said Tuesday that PJM should not have included a 10% adder in its calculation of make-whole payments to generators whose costs exceeded the $1,000/MWh offer cap last winter.

FERC granted a rehearing request to PJM’s Independent Market Monitor, agreeing that including the adder — typically included in cost-based offers to account for the uncertainty of calculating operating costs for combustion turbines under changing ambient conditions — was a mistake.

FERC said that the generators subject to their Jan. 24 waiver of the offer cap would still “receive make-whole payments by documenting the cost and volumes of natural gas needed to generate electricity.”

But the commission said that because the generators’ actual costs are now known, including an adder meant to cover uncertainty was inappropriate.

“This type of ex post determination does not contain any inherent uncertainty that would warrant an adder whose purpose in ex ante offers is solely to enable resources to recover uncertain or difficult-to-quantify costs,” FERC said.

The Monitor had argued in a March report that the adder portion was “not an actual cost and the generation owners did not pay it.” (See Stakeholders Preview Offer-Cap Debate.)

Denied

In its rehearing request, the Monitor also argued that non-capacity natural gas-fired generation resources should receive relief so as not to deter them from participating with PJM. FERC, however, disagreed.

“PJM’s filing requested a temporary waiver only for generation capacity resources and, therefore, we will not extend the waiver to other generators,” FERC said. “Further, no party in this proceeding has presented evidence that natural gas-fired generators other than generation capacity resources had documented costs above the market-clearing price.”

FERC also denied requests for rehearing from the Maryland Public Service Commission and the PJM Industrial Customer Coalition.

The coalition said customers shouldn’t be forced to pay higher prices due to generators’ decisions not to hedge against price spikes in the natural gas market. The coalition also said the waiver should have been limited in scope to specific PJM zones rather than the entire footprint.

FERC countered that the events of late January amounted to an emergency that harmed confidence in the wholesale markets and threatened reliability. “Delaying the issuance of the order could have threatened reliability by discouraging generators from making their units available,” FERC said, adding that its broad waiver was consistent with past orders during emergencies.

FERC’s denial of the PSC’s request was mostly procedural: the PSC had requested a detailed report from the Monitor explaining the basis for determining make-whole payments. The PSC filed its request on Feb. 21; one month later, the Monitor filed its report.

October 27, 2014June 15, 2023

EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans

PJM officials are developing contingency plans for their 2015 capacity auctions in the wake of last week’s stay of the D.C. Circuit Court of Appeals’ EPSA ruling.

PJM General Counsel Vince Duane said it will be at least next spring before the Supreme Court decides whether to review the D.C. Circuit’s ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission) throwing out the Federal Energy Regulatory Commission’s Order 745.

On Monday, the D.C. Circuit granted a stay until Dec. 16 on its ruling in order to give U.S. Solicitor General Donald B. Verrilli Jr. time to file a petition for certiorari on FERC’s behalf. If Verrilli files the petition, the stay will remain in effect until the Supreme Court rejects the request, or accepts it and decides the case on its merits.

Although the D.C. Circuit’s May 23 ruling explicitly concerned FERC’s jurisdiction over demand response in energy markets, some believe it also jeopardizes the inclusion of DR in FERC-regulated capacity markets. To avoid legal vulnerabilities, PJM on Oct. 7 proposed eliminating DR as a capacity supply resource and instead having load-serving entities offer DR and energy efficiency to reduce their capacity obligations.

Duane said the stay does nothing to provide additional certainty regarding the May 2015 Base Residual Auction.

“If [the Supreme Court justices] take the case, you have another year of not knowing what the rules for DR participation are,” Duane said in an interview last week.

“If cert isn’t granted, that’s the walk-off home run. That’s the end of it. There’s no more appeals,” he added. “And we are right on the eve of a capacity auction and the question then is what rules can apply now that EPSA is the law of the land and we have Tariff sheets that are kind of antiquated.”

As a result, Duane said, PJM is considering contingency plans, based on the Oct. 7 white paper that assume the EPSA ruling stands. Demand response aggregators have questioned whether the EPSA ruling will affect FERC’s jurisdiction over capacity. They say the RTO’s proposed response will upset existing business relationships and reduce DR’s role. (See ‘Poof’ Goes the Demand Response?)

EPSA Response

Electric Power Supply Association CEO John Shelk responded to the stay with a statement calling on PJM to assume the D.C. Circuit’s ruling stands.

“EPSA remains confident that the D.C. Circuit’s decision will stand and that Order 745 will eventually be vacated,” Shelk said. “The key now is moving forward on plans for an orderly transition that take into account not only what the decision requires with respect to demand response participation as supply in the energy markets but also its implications for the capacity markets. Even lawyers who disagree with the court’s conclusion that FERC lacks jurisdiction agree that the ruling’s legal rationale logically means that demand response cannot be a supply-side resource in capacity markets.”

ISO-NE Response

ISO-NE spokeswoman Marcia Blomberg said Friday that the ISO is continuing with its plans to seek FERC approval for rules allowing DR to provide operating reserves and participate in the Forward Reserve Market effective June 2017.

“However, given the legal uncertainty regarding the future of Order 745, and the fact that the full integration of demand response into energy and reserve markets will require two years of work to modify software and system infrastructure, the ISO will decide in early 2015 whether to begin devoting resources to meet the June 1, 2017, implementation date, or to ask for a delay until the legal questions are resolved,” Blomberg said.

FirstEnergy Complaint

The court ruled that Order 745, which required PJM and other RTOs to pay DR resources market-clearing prices, violates state ratemaking authority.

FirstEnergy Solutions filed a complaint with FERC within hours of the May 23 ruling, demanding that PJM throw out the DR that cleared in the May BRA for delivery year 2017/18.

On Wednesday, PJM filed a response in opposition to the FE complaint, saying that FE’s demand that PJM recalculate the 2014 auction results without DR would be “extremely damaging to the market certainty that is critical to sustaining investment in electricity infrastructure.” (EL14-55)

Instead, PJM said it will submit Tariff revisions around New Year’s that will seek to minimize litigation risk by proposing that:

Load-serving entities be permitted to submit price-responsive bids into the capacity auction beginning with the May 2015 BRA, as outlined in the white paper;
Demand response capacity commitments already made for the 2014/15 through 2017/18 delivery years be honored “subject to an orderly, voluntary exit path for capacity demand resources that anticipate losing their energy market compensation as a result of EPSA”; and
Changes be made to incremental capacity auction rules to support a transition, including a provision precluding any new demand resource offers in RPM auctions by retail end users or by aggregators of retail customers.

“PJM expects to ask the commission to accept these changes to serve at least as a ‘stop-gap measure,’” the RTO wrote, “perhaps to be effective only until such time as the commission and industry stakeholders have had an opportunity, once jurisdictional questions are finally resolved, to consider and develop generic and more considered options for demand response participation in organized wholesale electricity markets.”

In its own response, PJM’s Independent Market Monitor told FERC it opposed recalculating the 2014 auction but “generally supports the objective of” the FE complaint.

“Granting this objective as it pertains to future [capacity] auctions would permit the correction of faulty rules that have interfered with the efficient performance of the PJM capacity market design,” the Monitor wrote.

Praise from LaFleur

Because FERC’s direct authority to initiate legal action ends at the D.C. Circuit, FERC Chairman Cheryl LaFleur said that the decision whether to seek a Supreme Court hearing will be made by Verrilli. “That office has the exclusive authority to make that decision for the U.S. government — all the agencies. As with other agencies, we work behind the scenes with them,” she said during a keynote address at PJM’s Grid 20/20 conference Tuesday.

LaFleur said she was unable to talk about the pending FirstEnergy complaint. But she praised PJM’s “very thoughtful” white paper.

“I appreciate your contributing to the discourse on this,” she said. “Because we have a pending complaint before us on how we treat demand response in the markets right now, I haven’t been able to be a part of that discourse, but I’m glad it’s going on.”

October 27, 2014June 15, 2023

Michigan Gov.: Wisconsin Energy-Integrys Merger Could Stifle Competition

By Chris O’Malley

Wisconsin Energy Corp.’s proposed $9.1 billion acquisition of Integrys Energy Group has generated some notable opposition — including Michigan Gov. Rick Snyder.

On Oct. 17, Snyder and Michigan Attorney General Bill Schuette asked the Federal Energy Regulatory Commission to reject the merger, which would create one of the Midwest’s largest electric and natural gas utilities (EC14-126).

Wisconsin Energy and its subsidiaries already control most of the generation in Michigan’s Upper Peninsula. Michigan officials say the merger would give Wisconsin Energy a 60% ownership interest in the area’s only transmission system operator, American Transmission Co. (ATC).

“The level of concentration in both generation and transmission in the Upper Peninsula by one company as a result of this merger is a major concern for Michigan. This concentration will provide the [utilities] market power in the region that could negatively affect competition and rates,” Snyder and Schuette wrote.

Milwaukee-based Wisconsin Energy, parent of We Energies, and Chicago-based Integrys, whose holdings include Wisconsin Public Service and Michigan Gas Utilities, announced the merger June 23.

If the merger is approved, the combined companies will serve more than 4.3 million gas and electric customers in Wisconsin, Illinois, Michigan and Minnesota.

Most of the merging utilities’ generation is in the so-called Wisconsin and Upper Michigan region, or WUMS.

In their request to intervene, the Michigan officials said Wisconsin Energy and Integrys failed to analyze the relevant geographic market in determining market power, significantly understating “both the horizontal and vertical market power that the merged utility will have,” including the adverse impact such market power could have on rates and competition in Michigan’s Upper Peninsula.

Wrong Market Studied

The officials assert that the relevant geographic market is not the entire MISO footprint but WUMS, which includes the Upper Peninsula.

“Michigan contends that it is completely inappropriate to use MISO’s footprint, which includes parts of 16 states and one Canadian province, as the geographic market for assessing market concentration,” the state wrote.

Michigan pointed to findings by MISO’s Independent Market Monitor, as of the start of energy markets in April 2005, as identifying WUMS and North WUMS as narrow constraint areas (NCAs). “In designating submarkets as NCAs, the commission has effectively recognized these areas as separate and distinct geographical markets,” Michigan said.

Michigan says the merger could shift 93% of the cost of retiring the Presque Isle generating plant — $90.2 million — from Wisconsin ratepayers to a “much smaller set” of ratepayers in Michigan’s Upper Peninsula.

Great Lakes Utilities Protest

The proposed merger is also problematic for some utilities, including Wisconsin-based Great Lakes Utilities.

GLU’s members include municipal electric utilities in 12 Wisconsin and Michigan cities that are neighboring utilities to Wisconsin Energy and Integrys. GLU is a wholesale power customer of both.

GLU’s protest complains that the merger is likely to result in “substantial” increases to the cost of wholesale power. GLU also asserts that the merger will “strengthen Wisconsin Energy’s hand in transmission planning and cost allocation issues at the expense of other entities.”

In particular, GLU said the acquisition of Integrys will consolidate the ownership of ATC. Wisconsin Energy controls 26% of the voting shares in ATC while Integrys controls 34%.

“Without diversity of opinion and perspective, ATC’s function as an independent entity will be less certain,” GLU said.

A spokeswoman for Wisconsin Energy, Cathy Schulze, said the utility will respond to the protests soon.

October 24, 2014June 15, 2023

PJM, IMM Post Capacity Performance Cost-Benefit Analysis as Members Form Battle Lines

[Editor’s Note: This article was amended Oct. 28 to put FERC Chairman Cheryl LaFleur’s comments in context. See clarification below.]

PJM’s proposed Capacity Performance product would cost ratepayers as much as $6 billion over the next four years, with long-term costs of as much as $700 million annually, the RTO and Independent Market Monitor Joe Bowring said in a joint paper Thursday.

The cost-benefit analysis was released two days after Federal Energy Regulatory Commission Chairman Cheryl LaFleur indicated support for PJM’s efforts in a speech at PJM’s Grid 20/20 conference in Washington and stakeholders announced 15 coalitions that will argue for changes in the plan.

Almost 80 stakeholders joined at least one of the coalitions, which include two load groups and seven representing generators (including gas, hydro, renewables and independent power producers). Other groups represent project finance interests, storage developers and companies specializing in energy efficiency and demand response.

The largest group is the Transition Coalition, with 19 members led by Michelle Gardner, director of regulatory affairs for NextEra Energy Power Marketing. It is concerned with rules that will apply for delivery years 2015/16 through 2017/18.

PJM Gains Allies

The release of the joint cost-benefit paper indicates that PJM will have the Market Monitor on its side in the debate before FERC. Bowring, who had expressed skepticism about PJM’s original proposal, said the RTO’s amended Oct. 7 plan addressed his major concerns. (See Revised Capacity Performance Plan Wins Bowring’s Support.)

The proposal also received an unofficial boost from LaFleur in her keynote address Tuesday at the Grid 20/20 conference. LaFleur said she agreed with PJM’s goals of finding a way to “value base load properly without losing sight of the other resources and how to assure that the fuel will be there for reliability.”

“We certainly will look closely at any proposal that comes in. But I think the purpose of understanding what it is we want the market to do and really trying to refine the definition — while not easy — is exactly what we should be doing,” she said.

[Clarification: FERC spokesman Craig Cano said Oct. 28 that while LaFleur “is supportive of [PJM’s] goals,” she wants to make clear that she has not prejudged the proposal.]

Cost-Benefit Analysis

The analysis released by PJM and the IMM projects both the increased capacity costs and energy market savings based on an assumption that the new Capacity Performance product, with its higher expectations and penalties for non-performance, will reduce outage rates by 6 percentage points in winter and 3 percentage points in summer.

Had the product been in place in 2014, it would have reduced energy load payments by 8.7% in January and February ($975 million) and 8.5% in June-August ($725 million), according to the analysis.

The proposal’s requirement that generator dispatch parameters reflect their physical characteristics during Hot and Cold Weather Alerts would have reduced January’s uplift payments by 83% ($500 million), the analysis says, resulting in total energy cost savings for the year of $2.2 billion.

The analysis uses the $2.2 billion savings in future projections, beginning with delivery year 2016/17.

Over the long term, PJM and the Monitor say, the changes will have a net cost of $300 million to $700 million, with net savings in years with extreme weather.

Next Steps

The coalitions have until 5 p.m. Oct. 28 to submit briefing papers to the Board of Managers, which will decide on the final proposal submitted to FERC.

The coalitions will make oral presentations to the board at an “Enhanced” Liaison Committee meeting at the Cira Centre in Philadelphia Nov. 4. The meeting will be teleconferenced for PJM members and state commission and FERC representatives, but no members of the media will be permitted.

October 20, 2014June 15, 2023

APPA Study Rekindles Capacity Debate

Less than 3% of generation capacity constructed in 2013 was developed solely for sale into organized electricity markets, with the majority of projects supported by long-term bilateral contracts or built by vertically integrated utilities to serve their own loads, according to a study released last week by the American Public Power Association.

Of the 14.7 GW of new generation covered in the study, two-thirds were built with purchased power agreements and about 32% were constructed by utilities or customers. APPA said the study, Power Plants Are Not Built on Spec, validates its contention that the mandatory capacity markets in PJM, ISO-NE and NYISO “do not support the stable long-term financial arrangements required to build new power plants.”

APPA wants the Federal Energy Regulatory Commission to replace the mandatory capacity markets with voluntary residual markets, where states and local public power and cooperatives can procure their capacity through bilateral contracts.

APPA released the report last week as panelists at the Organization of PJM States Inc. annual meeting were in the middle of a discussion on the future of PJM’s capacity market.

PJM Market Monitor Joe Bowring told the meeting he didn’t need to review the study to respond to it.

“We have heard these claims before,” he said. “The notion that one-off bilateral contracts are better for customers I think has been disproven time and time again. It actually gives market power to sellers. This is the same APPA that had complained it can’t get prices low enough in bilateral contracts.”

Panelist Neal Fitch, senior director of regulatory affairs for NRG Power Marketing, noted that the study did not consider how much capacity the markets retained that might have otherwise retired.

James Wilson, a consultant to the consumer advocates for New Jersey, Pennsylvania, Delaware, Maryland and D.C., said he agreed with APPA that capacity markets are a “very expensive and very administrative and very inefficient way to” ensure resource adequacy.

“The capacity market is one way to go,” Wilson said. “The other way is what ERCOT is doing. ERCOT’s got an energy-only market and every few weeks you read about another new power plant.”

October 20, 2014

FERC Opens Investigations Probing Generators, Potential Gas Index Gaming

By Rich Heidorn Jr.

WASHINGTON — The Federal Energy Regulatory Commission has opened three investigations into questionable activity from last winter but has not found evidence that “widespread or sustained market manipulation” contributed to high natural gas and power prices.

Staffers from FERC’s Office of Enforcement (OE) announced the probes at the commission’s monthly meeting Thursday.

One of the investigations focuses on an allegation that a market participant attempted to suppress a monthly natural gas index to benefit short financial derivative positions.

The other two probes are seeking to determine whether generators may have profiteered “through offer behavior that resulted in increased uplift payments,” FERC said. All three investigations are at an “early stage,” FERC said.

Screens Tripped

OE’s Division of Analytics and Surveillance conducts regular monitoring of the natural gas and electric markets, including automated screens to detect anomalous trading activity that may indicate market manipulation.

To determine the causes of the extreme price spikes in January, OE supplemented its screenings with interviews with market participants and analyses of non-public market data from RTOs and ISOs, including physical and virtual bids and offers, market awards, marginal cost estimates and uplift payments. Staff compared the physical trading with financial derivative positions, using its newly granted access to the Commodity Future Trading Commission’s Large Trader Database. OE’s Division of Energy Market Oversight and Division of Investigations also took part.

The focus included the gas price spikes at the Transco New York trading hub, where prices rose to $120/MMBtu on Jan. 22, as well as the $40 price at the Chicago trading hub in late January.

Alerts from the commission’s natural gas surveillance screens resulted in conference calls with companies to obtain explanations for their physical trading and financial positions. “With one exception, which has resulted in an ongoing investigation, staff concluded that the companies contacted had valid explanations for their trading,” staff said in a presentation to the commissioners.

The consensus among those interviewed was that the high gas prices resulted from the “extreme and universal nature of the cold weather,” staff said.

“Also, market participants reported that less hedging of natural gas at the first of month price had occurred in light of certain additions of new delivery capacity into the New York area and forecasts of warmer weather than actually occurred,” staff continued. “The reduced hedges left many entities exposed to very volatile daily prices that occurred during January and February and may have increased price volatility as entities covered short positions. The depletion of natural gas storage was also a factor. Market psychology was also important as the price spikes were unprecedented. For example, market participants feared significant price premiums and lack of adequate counterparties.”

Gas demand was increased by conservative operator actions resulting from the mismatch between gas and electric operations, such as PJM’s decision to commit some gas generators over the Martin Luther King Jr. holiday weekend to ensure their availability the following Tuesday.

Because of the high level of generator outages, OE also searched for patterns of outages across generator fleets and conducted discussions with RTO market monitors to identify potential economic withholding.

Staff also investigated allegations of improper behavior it received through the enforcement hotline but determined that none of the allegations had merit.

October 20, 2014June 15, 2023

IPL Wins Waiver from MISO Must-Offer Rule for Retiring Eagle Valley Units

By Chris O’Malley

ipl — Concept art of IPL’s new natural gas plant that will replace Eagle Valley. (Source: IPL)

The Federal Energy Regulatory Commission last week approved Indianapolis Power & Light’s request for a limited waiver from MISO’s must-offer requirement, relieving the company of having to purchase replacement capacity after its coal-fired Eagle Valley units retire in 2016.

The commission emphasized its decision (EL14-70) related to “an unfortunate timing mismatch” between the compliance deadline for the Environmental Protection Agency’s mercury rule and MISO’s planning year. It “in no way ties our hands to granting waivers under a different set of circumstances,” Commissioners Tony Clark and Philip Moeller said in a concurring statement.

Commissioner Norman Bay dissented, saying the one-time waiver “creates an unfortunate precedent that erodes MISO’s capacity construct, undermines the bilateral market for capacity and blurs, unnecessarily, a line that had once been bright.”

Timing Mismatch

IPL said it needed the waiver because it plans to retire Eagle Valley’s 216-MW Units 3-6 just ahead of the April 16, 2016, extended deadline on compliance with EPA’s Mercury and Air Toxics Standards (MATS), which falls six weeks before the end of MISO’s planning year on May 31.

IPL complained that there was no clear mechanism within MISO’s Tariff that would permit it to buy replacement capacity to cover the six-week gap.

Otherwise, IPL said it might be forced to retire the plant in mid-2015 and purchase capacity to meet its planning resource margin requirements. IPL told the commission it would need to spend up to $22 million to purchase replacement capacity for the entire year. IPL said capacity prices in the bilateral market had tripled recently as a result of the timing dilemma.

New Generation in 2016

The utility is building a 650-MW gas generator to replace the six 1950s–era Eagle Valley units in Martinsville, Ind., but the new generation isn’t expected to be on-line until late 2016.

“Our customers should not be made to pay for the ongoing costs of operating these units for 10 ½ months going forward plus the cost of procuring an additional full year of capacity in order to fill a capacity hole that is for a six-week period,” the company said.

MISO opposed IPL’s request, telling FERC on July 25 that such waivers “anytime during the last five months of a planning year could result in a substantial deficit in resources needed to meet demand.”

MISO noted that the five-month period would include the winter, “and as we learned during the polar vortex events of this past winter, winter demand can be significant even in a summer-peaking region.”

Not Needed for Reliability

But Clark and Moeller said MISO informed IPL that its units were not needed for reliability beyond April 16, 2016. They also said IPL indicated it would have abundant reserve margins of 47% and 20%, respectively, in April and May 2016.

Clark and Moeller said the waiver “avoids unnecessary costs for Indiana ratepayers and does not create reliability issues that would cause undesirable consequences for third parties.”

The commissioners also cited testimony by IPL that Indiana utilities had provided MISO with their generation outage schedules far in advance, so that MISO could conduct a maintenance margin study for future years. MISO’s analysis demonstrates that MISO Zone 6, in which IPL is located, has a sufficient planning reserve margin even after accounting for scheduled outages, the commissioners added.

“While we appreciate MISO’s concern for resource adequacy, it is clear that MISO’s reservations are based more broadly on resource adequacy concerns in the MISO region as a whole and not on concerns directly related to Indianapolis Power’s request for waiver of the Eagle Valley units.”

Bay’s Dissent

In his dissent, Bay noted that IPL had offered to purchase replacement capacity for the six weeks on the condition that it be available at a just and reasonable rate. “Under the circumstances of this case, I would take up Indianapolis Power on its offer,” Bay said. “This approach is effective and pragmatic, all but ensuring that MISO will receive the necessary capacity, while providing Indianapolis Power with one form of its requested relief.”

MISO is still reviewing the FERC order, MISO spokesman Andy Schonert said Thursday. “Our chief goal is ensuring reliability across our footprint, and we will continue to work with stakeholders to address solutions that meet reliability needs today and in the future.”

No Precedent

Addressing the potential of other utilities retiring coal plans in the same time frame to also seek waivers, the commissioners stressed the IPL decision was based on facts and circumstances “in this specific case,” signaling it would evaluate other such waiver requests on a case-by-case basis.

Alliant Energy, MidAmerican Energy, Xcel Energy Services and Consumers Energy were among utilities that made filings in support of IPL’s request.

In a filing last August, Consumers Energy said it’s in the same boat as IPL, with plans to shutter its 940-MW Classic Seven units on April 15, 2016, due to MATS.

Consumers said that it, too, would have to essentially “over-procure” capacity for 10 ½ months to meet MISO resource adequacy requirements — or potentially be exposed to replacement costs or a deficiency charge for the six-and-a-half-week period.

But MISO downplayed the idea that other generators beyond IPL are grappling with the six-and-a-half-week gap between the MATS deadline and the end of the MISO planning year. “MISO is not aware that any other market participants believe their circumstances would necessitate early retirement to comply with MISO’s tariff provisions,” the ISO said.

Also protesting IPL’s request was NRG Power Marketing and GenOn Energy Management, providers of bilateral capacity. NRG said IPL “correctly” notes that there’s no guarantee that bilateral capacity will be available, but “it is highly likely that such capacity will be available on a bilateral basis — and at far less than the cost of new entry.”

NRG also contends that requiring IPL to pay the market price for capacity during a period of scarcity “should not be considered a ‘problem.’ It is the market at work.”

October 20, 2014

NETOs to Pay Refunds in ROE Case

By William Opalka

The Federal Energy Regulatory Commission last week affirmed its June order reducing the return on equity (ROE) for the New England Transmission Owners (NETOs), ordering the companies to provide refunds from Oct. 1, 2011.

The commission decided in June that it would begin using a two-step discounted cash flow methodology for electric utility ROEs, similar to that used for natural gas and oil pipelines. Ruling in the New England case, the commission said the new “zone of reasonableness” for ROEs was 7.03-11.74%. (See FERC Splits over ROE.)

The commission said in the June order that it lacked the evidence needed to decide one of the inputs to the two-step DCF methodology: the appropriate long-term growth rate to use.

In the “paper hearing” that followed, FERC said all parties agreed that gross domestic product (GDP) is the appropriate long-term growth rate and that the commission properly calculated the GDP growth rate in this case at 4.39%.

The commission last week unanimously agreed, finalizing the tentative ROE of 10.57% it had assigned.

The NETOs, which include Northeast Utilities, Central Maine Power, National Grid and NextEra, were ordered to provide refunds, with interest, within 30 days for the 15-month period.

The refunds represent all excess revenues the NETOs received since the complaint was filed in October 2011, a period in which the utilities were getting paid an ROE of 11.14%.

The case resulted from a 2011 complaint by state consumer advocates and attorneys general throughout New England, which alleged that the NETOs’ 11.14% base ROE was unjust and unreasonable because capital market conditions had changed since the base ROE was established in 2006.

FERC split 3-1 over its first application of the new formula, tentatively setting the ROE for New England transmission owners at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range.

The previous zone ranged from 7.3% to 13.1%. Thus, although the commission chose a higher position within the range, the reduced top end resulted in a decrease from the NETOs’ previous ROE.