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October 30, 2024

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MISO Considering Raising Energy Offer Cap

By Tom Kleckner

LITTLE ROCK, Ark. — MISO said last week it may increase its energy market offer cap to $1,500/MWh this winter in response to expected FERC action.

Staff told the Market Subcommittee last week it is considering three interim energy offer cap options: 1) no change from current practices; 2) last winter’s revenue sufficiency guarantee (RSG) approach, which offered compensation through uplift; and 3) increasing the energy cap above the current $1,000/MWh.

miso

Because MISO has increased its reliance on gas-fired generation, a repeat of the gas price spikes seen during the 2014 polar vortex could result in hundreds to thousands of megawatts of capacity exceeding the current cap, Markets System Analyst Chuck Hansen told the group.

MISO’s market engineering team has already tested systems for energy offers up to $3,000/MWh and found no issues that would prevent a higher cap. The team also simulated higher gas prices by increasing offer curves for gas plants and found that market signals became distorted as the price signals reached the cap, Hansen said.

Hansen said increasing the energy offer cap to $1,500/MWh would accommodate gas prices reaching $100/MMBtu, but studies show offers above that would increase the likelihood of the system marginal price being greater than the value of the lost load when operating reserves are scarce.

“Anything we do should not be considered permanent, given FERC’s pending action,” said Jeff Bladen, MISO’s executive director of market design.

FERC on Sept. 17 announced its intention to take action on offer caps and other price formation issues, though it offered no timeline. The statement came in a Notice of Proposed Rulemaking (RM15-24) that would require organized markets to settle real-time energy and operating reserve transactions financially at the same five-minute time interval that it dispatches those resources. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)

MISO Market Monitor David Patton has been recommending five-minute settlements since his 2012 State of the Markets Report.

“Any time you’re selling a product,” Patton told the MSC, “I believe you should be paid for the value of the product in the time period it is being delivered.”

Some stakeholders expressed support for the 2014-15 winter solution and apprehension for raising the energy cap.

“We really want your feedback,” Bladen said, urging input on fixed-offer caps and whether generators should be able to recover verifiable fuel costs beyond the cap using uplift, as was the case last winter.

Based on the feedback (due Oct. 6), MISO will present and discuss its proposal at the Oct. 27 MSC meeting. It has targeted Nov. 1 for a FERC filing, with a Jan. 1 implementation date.

Hansen said FERC’s guidance will be incorporated into a permanent offer cap solution. He said MISO will continue to monitor neighboring RTO actions on offer caps and coordinate as appropriate.

On Thursday, two days after the MSC meeting, PJM stakeholders overwhelmingly approved increasing the RTO’s energy offer cap from $1,000/MWh to $2,000/MWh. (See related story, PJM Members OK $2,000/MWh Energy Market Offer Cap.)

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EPA Ozone Rule May Mean Changes for 30+ Coal Units

By Amanda Durish Cook

The Environmental Protection Agency last week tightened its ground-level ozone limits to 70 parts per billion (ppb), a less strenuous standard than some electric generators had feared and public health advocates had sought.

The National Ambient Air Quality Standards (NAAQS) rule could impact more than three dozen coal-fired electric generators lacking scrubbers or not using them full time.

In areas expected to need to reduce nitrogen oxides (NOx) emissions under the rule, EPA’s Regulatory Impact Analysis identified 37 coal-fired generators that either do not have selective catalytic reduction (SCR) systems (30 units, 5.4 GW) or have the scrubbers but do not always use them (seven units, 3.1 GW).

ozone
EPA estimates 358 counties will need to take actions to comply with the new ozone standard of 70 parts per billion. The count does not include California, which has separate standards.

In addition, new generators could be restricted in the more than 350 counties that EPA says will not meet the 70 ppb standard.

Ozone, the main component of smog, aggravates lung diseases, including asthma, emphysema and bronchitis. It forms when emissions of NOx, volatile organic compounds (VOCs), carbon monoxide and methane are heated by the sun. Utilities, industrial facilities, motor vehicle exhaust, gasoline vapors and chemical solvents are the major man-made sources of NOx and VOCs.

Industry Reaction

The agency last visited the issue in 2008, when it released a 75 ppb recommendation. EPA was considering a range between 65 and 70 ppb for an eight-hour average.

The Edison Electric Institute had pushed for a new standard at the top end of the range. “While compliance challenges remain with the new standard at 70 ppb, EPA has recognized the serious implementation concerns raised by stakeholders of setting the standard below 70 ppb,” EEI President Tom Kuhn said in a statement.

The ozone standard doesn’t directly apply to power producers but to their states. David Flannery, legal counsel for the Midwest Ozone Group, said that it’s “too early to tell” how either will be affected. The group represents coal-burning utilities including American Electric Power, Duke Energy and Ameren.

“States will have to decide how they’re going to apply this ambient air standard,” Flannery said. “There’s a mix of sources that contribute. This includes cars and mobile sources in addition to the industrial sources.”

Flannery said that states are still planning how to meet 2008’s 75 ppb rule. “Part of the criticism of the new standard is that the EPA introduced the new standard before the old one could be fully implemented,” he said.

Implementation

EPA said it is tightening the standard based on more than 1,000 recent studies that suggested the current limit did not adequately protect public health.

Assuming it survives anticipated legal challenges, the next step in enforcing the ruling is to designate attainment and nonattainment areas. States will have to suggest designation areas within a year; EPA will make designations by October 2017 using air quality data from 2014 to 2016.

States identified with nonattainment areas will be forced to devise emission inventories and establish a preconstruction permitting program. The preconstruction permits apply to “new or expanding sources of air pollution,” including power plants, industrial boilers and factories.

Any state containing nonattainment areas sorted into the “moderate” or higher category will have until 2021 to design state implementation plans demonstrating the pollution-reducing steps they will take to comply. Deadlines for compliance from nonattainment areas will range from 2020 to 2037.

The agency estimated the new standard will cost $1.4 billion while producing health benefits of $2.9 billion to $5.9 billion.

It says compliance with the new threshold will be made easier by existing environmental rules, including emission control requirements for motor fuels and vehicles, the Mercury and Air Toxics Standards (MATS) and the carbon emission reductions under the Clean Power Plan.

‘Missed Opportunity’

EPA says average ozone levels have dropped 33% nationally since 1980 and that more than 90% of areas designated nonattainment for the 1997 ozone standards now meet those standards. EEI says the electric power sector has reduced sulfur dioxide (SO2) emissions by 80% and NOx by almost three-quarters since 1990 despite increased power demand.

Michael Brune, executive director of environmental advocate Sierra Club, called the rule “a modest step” and “a missed opportunity.”

“Over the past seven years, medical scientists have been clear that any standard above 60 ppb puts our communities at risk and is especially dangerous to children, seniors and people with respiratory illnesses,” Brune said in a statement.

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FERC Sides with Developer in NYISO Dispute

By William Opalka

long island
Artist’s rendering of Caithness Long Island II.

FERC on Wednesday sided with a Long Island power plant developer in its dispute with NYISO over interconnection standards the ISO sought to apply to the company’s proposed 750-MW combined-cycle facility (EL15-84).

The developer of Caithness Long Island II filed a complaint July 10 claiming that NYISO’s application of a local reliability requirement violates its Tariff and FERC Order 2003.

Caithness sought to prevent NYISO from applying the Long Island local reliability interface transfer capability test to identify required system upgrades as part of its interconnection facilities study.

“We find that the Long Island guideline constitutes a deliverability test and therefore using it to identify system upgrade facilities is inconsistent with Order No. 2003 and violates the [Tariff],” FERC wrote.

Order 2003 requires transmission providers to offer two levels of interconnection service: energy resource interconnection service (ERIS) and network resource interconnection service (NRIS). ERIS is a minimal interconnection service and NRIS is a more flexible service for resources that seek to be designated network resources or capacity resources.

To obtain NRIS, the interconnection customer has to satisfy a deliverability test to ensure that its generating facility can be operated simultaneously at peak load along with other generators in the same electrical area and that any output produced above the area’s peak load requirements can be transmitted to other locations on the transmission provider’s system.

The Caithness II project in Brookhaven has proposed an interconnection with the Long Island Power Authority. Caithness had requested basic ERIS service.

Caithness complained that NYISO’s Long Island guideline would allow transmission owners to act unilaterally to cause “an unjustifiable increase in interconnection costs measured in the hundreds of millions of dollars” for the project.

FERC agreed, saying the guideline is “impermissible because it creates a conflict with the NYISO minimum interconnection standard by imposing a deliverability requirement on a project requesting energy-only interconnection under ERIS.”

While NRIS studies are required to identify network upgrades needed to allow the generator to contribute to meeting the overall capacity needs of the control area or planning region, ERIS studies are not, FERC said.

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Company Briefs

Chesapeake Energy, the Oklahoma City-based shale drilling company, laid off about 15% of its workforce last week, saying the cuts were necessary to survive the downturn in natural gas and oil prices.

“The current commodity price environment continues to be a challenge for our industry and for Chesapeake,” Chief Executive Doug Lawler wrote to employees. “While this was extremely difficult, we are acting decisively and prudently to enhance the long-term competitiveness and strength of Chesapeake.”

Chesapeake said it laid off 740 of its 5,000 employees. Chesapeake tried to weather the wholesale price downturn by ramping up production and selling off some properties, but it wasn’t enough.

More: Wall Street Journal; Associated Press

Xcel Shuttering 2 Sherco Units by 2026

Xcel Energy announced Friday that it would retire two units at its largest coal plant by 2026 to meet carbon emissions mandates under the Environmental Protection Agency’s Clean Power Plan.

The company’s analysis concluded it could close the units at the Sherburne County Generating Station, or Sherco, in Minnesota without affecting reliability. Xcel said the retirement, along with other planned changes, will cut its carbon emissions by 60% from 2005 levels.

It said it plans a transition period of eight to 10 years before final shutdown and is examining the possibility of using the site for a gas-fired plant or solar generation.

More: Midwest Energy News

FirstEnergy Solutions Dropping PECO Customers in October

The retail electricity arm of FirstEnergy has decided it can no longer afford the good deals it offered PECO Energy customers when the Ohio-based company ventured into the territory three years ago.

FirstEnergy Solutions mailed letters to its PECO customers, saying it was declining to renew the fixed-rate deals. If those customers don’t choose a different competitive supplier, they will revert to PECO by default. The company didn’t say how many customers it was dropping, but a similar contraction in western Pennsylvania earlier this year resulted in a reduction of 36,000 Duquesne Light customers being supplied by competitive energy suppliers.

“We didn’t have all that risk built into the pricing,” said Diane Francis, a company spokeswoman. “We actually had to go out and buy power for those customers.”

More: The Philadelphia Inquirer

Kenergy, Kentucky Municipality Argue over Development’s Energy

Kenergy has filed a lawsuit against Owensboro Municipal Utilities in a dispute over which utility has the rights to supply power to the mammoth Gateway Commons mixed-use development in Kentucky.

Kenergy claims the company is entitled to provide power in the part of Gateway Commons that falls within what the company calls its “exclusive service territory,” and that OMU is attempting to “selectively encroach” on that territory. But OMU claims in court documents the city utility has a “right” to provide power to the entire development because the Gateway Commons property is inside the city limits.

Gateway Commons is planned as a $334 million “lifestyle center” that will include residential, retail and entertainment centers.

More: Messenger-Inquirer

Overhead Line Upgrade Continues in New Orleans

Entergy New Orleans said work will begin this week on the second phase of $30 million in system improvements in New Orleans.

The utility is replacing existing overhead transmission lines with 3M aluminum conductor composite reinforced wire. According to Entergy, the lines will improve reliability and deliver more transmission capacity. The company also said it can complete the upgrade without having to replace steel transmission poles currently in use.

Work on the project, which began in mid-July with phase one, is scheduled to wrap up next March. The work is part of an effort to phase out the Michoud generating facility, which has produced power since the 1960s.

More: New Orleans City Business

Nebraska Utilities Look Out-of-State to Meet Their Energy Needs

A handful of local utilities in the northeast corner of Nebraska have decided to switch from the Nebraska Public Power District to a different supplier, taking advantage of the flexibility offered by the region’s power grid. The utilities say they will save some money under better contract terms.

South Sioux City signed a contract with Lincoln Electric System for electricity starting in 2017. A group of other municipal utilities — Northeast Nebraska Public Power, Wakefield and Wayne — all plan to buy electricity from Big Rivers Electric Cooperative in Kentucky in 2018.

NPPD’s 75 wholesale customers are weighing their options this fall because the state’s largest utility wants its customers to sign new 20-year contracts that start in January, to help it plan for the future. Buying power from elsewhere is possible now after Nebraska joined SPP in 2009.

More: Associated Press

North Dakota Wind Farm Project Underway After 8 Years

Xcel Energy recently broke ground on the $300 million Courtenay Wind Farm in eastern North Dakota, after eight years of planning and development work.

Geronimo Energy began the project in 2007 and turned it over to Xcel in May. The Courtenay project will supply 200 MW of electricity at its planned completion in late 2016.

More: The Jamestown Sun

Kentucky Munis Organize for Lower-Cost Electricity

Ten municipal utilities, including Owensboro Municipal Utilities, met for the first time recently to organize an effort to acquire power at a price lower than most of them now buy from PPL’s Kentucky Utilities.

Nine of the 10 utilities in the Kentucky Municipal Power Agency are now Kentucky Utilities customers. The 10th, Owensboro, has its own generation capacity and stands to be both a supplier and customer of the agency.

The board members addressed several organizational matters Sept. 24, including the election of officers, approval of bylaws, hiring staff and a request for proposals to buy electricity on the open market beginning in 2019 from coal, natural gas and possibly renewable energy suppliers.

More: Messenger-Inquirer

PSE&G’s Kinsley Solar Farm Lauded

Public Service Electric & Gas’ Kinsley Solar Farm was chosen as the New Jersey Association of Energy Engineers’ 2014 renewable energy project of the year.

The 35-acre, 11.18-MW facility, located on the former Kinsley landfill in Deptford, N.J., is part of PSE&G’s plan to build 125 MW of grid-connected solar. With 36,841 solar panels, the Kinsley farm provides enough electricity to power about 2,000 average homes annually.

Including Kinsley, PSE&G has seven solar farms built on landfills or brownfields. An eighth is expected to go into service by the end of 2015.

More: Public Service Enterprise Group

AEP Sells Commercial Barge Subsidiary for $400 Million

American Electric Power will sell AEP River Operations to American Commercial Lines for about $550 million. The commercial barge subsidiary delivers about 45 million tons of products annually, including 10 million tons of coal.

AEP expects to net about $400 million and plans to invest the funds in its regulated business. Meanwhile, it continues to evaluate the future of its competitive generation business.

More: American Electric Power

Columbia’s East Side Expansion Project Comes Online

Columbia Pipeline on Friday announced that the East Side Expansion Project has been put into service by subsidiary Columbia Gas Transmission.

“East Side is an important piece of our project backlog, which is designed to meet the needs of both producers and end-use markets over the next several years,” Columbia Pipeline Group President Glen Kettering said.

The two new pipeline loops create additional capacity for 312 million cubic feet of gas per day. They include 9 miles of line in Chester County, Pa., and another 9 miles in Gloucester County, N.J. The project also includes two new 4,700-horsepower compressors in Pike County, Pa., and two new 10,000-horsepower units in Northampton County, Pa.

More: Columbia Pipeline Group

Calpine Closes on Champion Acquisition

Calpine has closed on its acquisition of Champion Energy Marketing, a retail electric provider based in Houston. Previous reports valued the deal at $240 million.

Champion’s majority shareholder is Houston Astros owner Jim Crane and his Crane Capital Group. EDF Trading, a subsidiary of the France-based electric utility EDF, owned 25%.

“The addition of Champion Energy is an important step in our concerted effort to create more channels for our wholesale power by getting closer to customers,” said Trey Griggs, Calpine’s executive vice president and chief commercial officer.

More: Calpine; FuelFix

WEC Selling CNG Business Acquired from Integrys Purchase

WEC Energy Group has decided that operating a chain of compressed natural gas fueling stations doesn’t fit in with its overall business plan and is selling its Trillium CNG business.

Trillium was included in WEC’s $9.1 billion acquisition of Integrys last summer. It operates 66 public stations and 43 private fueling stations. Analysts put Trillium’s value at $140 million.

“It’s not their core business and feel that it would have better attention with someone who understands that business, versus a regulated utility,” company spokeswoman Lisa Prunty said. “Trillium continues to see robust growth in a rapidly developing industry and WEC sees significant value in Trillium. It’s a highly respected brand. However it’s just inconsistent with a utility risk profile.”

More: Milwaukee Journal-Sentinel

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Reports: Exelon Considering DC HQ to Win Pepco Deal

By Suzanne Herel

Chicago-based Exelon would open a headquarters in the district and offer more customer credits under a tentative agreement D.C. Mayor Muriel Bowser’s office has reportedly struck to support the company’s purchase of D.C.-based Pepco Holdings Inc.

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Bowser

While neither Bowser’s office nor the companies would confirm the draft settlement, several intervenors in the merger process told Bloomberg and the Washington City Paper that the document was being shared among interested parties on Friday.

The move comes as the D.C. Public Service Commission is scheduled to decide Wednesday whether to grant a joint request by the district’s attorney general and the companies to stay proceedings in the matter until Nov. 4. The request is an attempt to buy time to strike a deal that might be acceptable to the D.C. PSC, which unanimously rejected the acquisition in August. (See DC Halts Exelon’s Acquisition of Pepco Holdings; Pepco Stock Tumbles.)

Wall Street remains skeptical that Exelon will consummate the deal.

Exelon shares closed Monday at $30.30, up 1.6% for the day, while Pepco rose 0.4% to $25.41. But both remain about $2 below their prices on Aug. 24, before the PSC’s rejection.

Exelon Appeal

Last week, Exelon asked the agency to reconsider its decision, taking issue in a 43-page filing with the PSC’s findings that the deal would not be in the public interest and it would not be in the public interest to identify additional conditions that could make it so. (See Exelon Appeals DC PSC Decision; DC Mayor Confirms Negotiations.)

The filing came at the same time the mayor confirmed her office was discussing a settlement agreement with the companies that would constitute a new filing to the commission. Previously, Bowser’s office had said it agreed with a letter of opposition filed by Attorney General Karl Racine’s office listing 40 conditions that should be met for the deal to be accepted.

Negotiations Continuing

On Monday, Racine spokesman Rob Marus said it was premature to say whether the attorney general would support the outcome of negotiations, which he said were continuing.

“The settlement to be weighed in on is a different settlement,” he said. “The Office of the Attorney General has a role to weigh in early on in the process; now we’re in a different place in the process.”

Marus said Racine, whose former law firm did work for Pepco, had recused himself from the issue.

According to the City Paper, Robert Robinson, president of the Grid 2.0 Working Group, was among the intervenors who viewed the working settlement.

He said the district government won more concessions because of its initial opposition, but the agreement still represents an “about face” that doesn’t address all the issues. “We’re going to get locked into a deal of economic slavery, of continuing to pay higher and higher prices,” he said.

Unique Concessions

D.C. is the last holdout to the $6.8 billion deal, which already has been approved by FERC and regulators in New Jersey, Virginia, Maryland and Delaware. The states negotiated their agreements on a “most favored nation” status, meaning that if any subsequent agreement were more beneficial, it would have to be bestowed in kind on them.

In making its decision, the D.C. PSC said it weighed seven factors of public interest, among them the effects on ratepayers and shareholders, market competition and preservation of natural resources and the environment.

exelon
Berliner

Roger Berliner, a regulatory attorney and Montgomery County councilman who led opposition to the merger in Maryland, said he suspects the settlement will be largely unique to D.C. and not invoke changes to the other states’ agreements.

For example, he said, Pepco is headquartered in D.C. If Exelon agrees to open another headquarters, it wouldn’t have to provide the same concession elsewhere.

“It’s hard for me to imagine how they would strike a deal that would trigger the most favored nations clause,” Berliner said.

He also was skeptical about Exelon being able to offer a commitment to renewable energy that would overcome the commissioners’ concerns.

“We had settlement negotiations with [Exelon] and said, ‘If you are prepared to be the best in the country when it comes to renewables, we can have this conversation,’” he said. “Clearly that was something they were not prepared to do.”

That, Berliner said, underscored the concern — also perceived by some in D.C. — that Exelon’s nuclear portfolio presents an insurmountable conflict of interest with a commitment to renewable energy.

Sides Mobilize

In D.C., the most vocal support for the deal has come from the business community and dozens of charitable groups who receive funding from Pepco.

In a media blitz that included churches, minority groups and former D.C. Mayor Anthony Williams, supporters urged reconsideration of the merger, saying it would bring increased grid reliability, jobs and opportunities for minority businesses.

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Dinegar in an Exelon video with other D.C. business and civic leaders supporting the merger.

“We know that reliability will be enhanced,” James Dinegar, president of the Greater Washington Board of Trade, said in a video posted on the merger partners’ website. “It’s the right move for strengthening this region and then positioning us as we continue to grow to be the strongest region in the country.”

Pepco Chairman Joseph M. Rigby is a former chairman of the Board of Trade and currently serves on its senior council.

Opposition to Stay

Opposing the acquisition are more than half of the district’s Advisory Neighborhood Commissions and nearly half of the 12-member City Council. The Office of People’s Counsel, which also has advised against approval without significant concessions, could not be reached for comment on Monday.

Meanwhile, the Grid 2.0 Working Group and D.C. Public Power filed their opposition to the request for a stay.

If the settlement constitutes a new filing, Grid 2.0 argued, it and Exelon’s request for a reconsideration should be considered independently on parallel tracks.

In its filing, D.C. Public Power also offered an alternate solution: “There are, in fact, merger arrangements that can be practically implemented that fully satisfy public interest concerns [such as] DCPP’s proposal to buy Pepco’s D.C. assets in a divestiture from Exelon/PHI. The result would be an independent, D.C.-based not-for-profit electric power utility serving the interests of the citizens of the District of Columbia.”

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Baker: Hydropower Contracts Best Way to Lower Costs

By William Opalka

Massachusetts Gov. Charlie Baker said last week that long-term contracts for hydropower are the quickest and most cost-effective way for the state to reduce rising energy costs and reach greenhouse gas reduction goals.

The first-term Republican testified before the legislature’s Joint Committee on Telecommunications, Utilities and Energy in support of his bill to mandate the state’s utilities seek long-term contracts to procure hydropower.

hydropower
Massachusetts Gov. Charlie Baker testifying before the legislature in support of his bill to mandate that the state’s utilities seek long-term contracts to procure hydropower.

New England power generators have complained that elected officials’ urge to “do something” about rising power costs in the region risks market development just as power plant owners are willing to invest there. (See New England Generators: State Interventions Risk Market Development.)

Baker confronted that argument in his remarks that described how ISO-NE’s main concern is reliability and plant owners need to provide returns to their investors.

“When acting in line with their obligations, none of these players are primarily concerned with costs to the consumer or environmental considerations. That is the status quo,” he said. “We are left with the critical question of who addresses energy costs and environmental concerns. The answer to that question is us.”

The 2008 Global Warming Solutions Act mandates a reduction in greenhouse gas emissions of 25% from 1990 levels by 2020. A 2010 state energy plan said Massachusetts would need at least 1,200 MW of hydropower to reach the target.

“We are in danger of being out of compliance with our own law,” Baker said.

Hydropower on that scale would likely come from Canada, but nothing precludes hydro resources in the U.S. from bidding into any solicitations from the utilities, he said. Baker said hydro can be obtained under current law, but that is unlikely in the absence of long-term contracts.

The contracts would only be pursued if state regulators determined they were cost-effective, the governor said.

Baker also said he would consider testing the market for the viability of offshore wind projects and suggested the legislature could amend his bill to include that resource. The Cape Wind project in Nantucket Sound, under development for more than a decade, was halted after it failed to complete financing after a protracted legal battle.

The governor also repeated his call for action to reduce electricity costs, which are among the highest in the nation, through regional efforts. (See Baker: New England Must Sacrifice to Lower Costs.)

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FERC Launches Probe into MISO Capacity Auction

By Amanda Durish Cook

FERC has begun a non-public investigation over allegations of improprieties in MISO’s April capacity auction and will hold a technical conference on the matter Oct. 20.

The commission’s actions, disclosed last week, are in response to complaints filed by Illinois Attorney General Lisa Madigan, Southwestern Electric Cooperative, Illinois industrial energy consumers and the public interest group Public Citizen over MISO’s Planning Resource Auction, which resulted in a nine-fold price increase in Zone 4, which comprises much of Illinois.

Public Citizen called for an investigation in May into whether Dynegy improperly withheld capacity in Zone 4, an allegation the company has denied. Public Citizen also alleged that MISO brushed aside recommendations by its staff that Zones 4 and 5 be merged due to their concerns about Dynegy’s growing share of capacity in Zone 4 after the company acquired four generators there from Ameren.

Prices in Zone 4 cleared at $150/MW-day, compared with just $16.75 a year earlier.

FERC said it is holding the all-day conference to obtain additional information and “determine what further action, if any, may be appropriate” to address the complaints (EL15-70, et al). The conference, which will be webcast, will include discussions of current market power mitigation rules, the calculations of auction parameters and zonal boundaries.

The conference will be run by staff from the offices of General Counsel, Energy Market Regulation, and Energy Policy and Innovation. Stakeholders will have until Nov. 4 to submit post-technical conference comments.

FERC said the conference will not address the non-public investigation being conducted by the Office of Enforcement into “whether market manipulation or other potential violations of commission orders, rules and regulations occurred before or during the auction” (IN15-10). FERC said the investigation began “shortly after” the auction concluded April 14.

In its complaint in May, Public Citizen suggested that Dynegy could have inflated prices by either not offering some capacity or by offering some of it at such a high price that it would not clear.

Madigan filed a complaint saying that Dynegy’s increased generation portfolio in Zone 4 made it a “pivotal supplier” in the zone. Madigan also complained that in approving the Dynegy acquisition, FERC declined to look at its effect on competition and prices in Zone 4 and instead only considered a competitive analysis of MISO as a whole.

Dynegy CEO Robert Flexon defended the company’s bidding strategy in an interview in June, insisting no capacity was withheld. (See Dynegy Chief Unapologetic over MISO Auction Flap.)

MISO and its Market Monitor also contend the auction was the result of market dynamics, not improper conduct. (See Dynegy: No Evidence of Misconduct in Auction.)

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Federal Briefs

CecilAndrusSourceGov
Andrus

Former Idaho Gov. Cecil Andrus is suing the Department of Energy to get information behind a proposal to ship nuclear waste to a nuclear research facility on the Snake River. Andrus suspects the federal government intends to turn the facility into a permanent storage site for spent fuel from commercial reactors.

The former four-term governor sued after receiving mostly redacted documents under a Freedom of Information Act request. He says a 1995 legal agreement between Idaho and the department prohibits such shipments and called for the removal of nuclear waste already stored there.

“I suspect they know what they are planning will be very controversial and, for that reason, want to keep it secret,” he said in a statement.

More: Reuters

EPA Finalizes Coal Plant Toxic Metal Effluent Rules

epaThe Environmental Protection Agency released its final version of rules governing the release of toxic metals in the wastewater from steam electric power plants. The rules set limits on the amount of arsenic, mercury, selenium and nitrogen in the wastewater streams from de-sulfuring flue gases, and they set a zero limit on discharges from coal ash transportation.

The rules also encompass wastewater discharges from mercury control systems and coal-gasification wastewater.

The agency said that only 134 of the nation’s 1,080 coal-fired plants will need to make pollution-control investments and put the annual cost of compliance at about $480 million. The rules were last updated in 1982.

More: Power Magazine

NRC Finds Pilgrim Station’s Weather Tower Inoperable

PilgrimSourceNRCPilgrim Station, already under increased scrutiny from the Nuclear Regulatory Commission, has received failure notifications for four new negative findings from an August inspection.

The most recent inspection included a finding that Pilgrim’s primary weather tower was inoperable on eight occasions between 2012 and 2015 and without backup. If a radiological release occurred during those times, the plant would have had to rely on the National Weather Service for data, NRC said. It said the failings raised doubts that owner-operator Entergy could “protect the health and safety of the public in the event of a radiological emergency.”

Pilgrim was already noted as being among the nation’s three worst-performing nuclear generating stations. Entergy has said it may be too costly to correct all the deficiencies and is investigating the possibility of closing it.

More: The Patriot Ledger

Solar Energy Keeps Getting Cheaper, Lab Says

BerkeleyLabSourceBerkeleyPushed by technological and market advances, and an impending deadline for a key federal incentive, solar pricing is becoming more competitive, according to a report from the Lawrence Berkeley National Laboratory.

The lab said that utility-scale solar projects have been receiving about 5 cents/kWh in power sales agreements. Wholesale electricity prices in the U.S. ranged from 2 to 6 cents/kWh.

The prices reflect the 30% federal investment tax credit. That credit is scheduled to fall to 10% after 2016. The report — “Utility Scale Solar” — shows that installed project costs have dropped by more than 50% since 2009, and projects are performing at an average capacity factor of 29.4%, up from 26.3% in 2011.

More: Berkeley Lab

US Falling Behind in Offshore Wind Power, Professors Say

Firestone
Firestone

The U.S. has fallen behind in the development of offshore wind power, even as land-based wind and solar have taken off, according to an academic study.

A group of professors from the University of Delaware, writing in Proceedings of the National Academy of Sciences (subscription required), noted that offshore wind turbines were installed back in 1991 in Europe, but no such facilities dot the U.S. coasts.

“As we celebrate the 10-year anniversary of the U.S. Energy Policy Act of 2005, it is disheartening to see that while land-based wind and solar have reached new heights, U.S. offshore wind has remained a missed opportunity,” says the paper’s lead author, Jeremy Firestone.

More: UDaily

Federal Judge in Wyoming Blocks New Fracking Rules

Skavdahl
Skavdahl

A federal judge has blocked the Bureau of Land Management from implementing new rules concerning fracking on federal land. U.S. District Court Judge Scott Skavdahl said the agency lacks the authority to institute the new regulations.

The states of Wyoming, North Dakota, Colorado and Utah, as well as the Independent Petroleum Association of America and the Western Alliance, had sued to block the new federal rules, which they argued duplicated state rules, making it more expensive to drill for natural gas and oil in shale regions.

“Congress has not authorized or delegated to the BLM authority to regulate hydraulic fracturing and, under our constitutional structure, it is only through congressional action that the BLM can acquire this authority,” Skavdahl wrote in a 54-page decision.

More: Bloomberg Business

EPA Gives North Dakota Coal Plants Extra Time on Clean Power Plan

NorthDakotaDaveGlattSourceGov
Glatt

The Environmental Protection Agency has pushed the deadline for North Dakota to come up with a plan to meet its Clean Power Plan goals from fall 2016 to fall 2018. Under the new plan, the state is required to reduce carbon emissions 45% by 2030.

State environmental chief Dave Glatt said the 2016 deadline would have been nearly impossible to meet. “We spent 10 years developing a regional haze (pollution reduction) plan, and this is a lot more complicated,” he said.

EPA, in response to prodding from U.S. Sen. Heidi Heitkamp (D-N.D.), has promised to help determine the best ways to bring clean coal technology and renewables into the generation mix as part of the effort to meet the mandate.

More: Bismarck Tribune

TVA’s Sequoyah Reactors Get NRC License Extensions

SequoyaSourceNRCThe Nuclear Regulatory Commission last week granted 20-year license extensions to the Tennessee Valley Authority’s two Sequoyah reactors in Soddy-Daisy, Tenn.

“Extending Sequoyah operations will play an integral role in reducing our carbon emissions while reliably supplying electricity at the lowest possible cost,” said Joe Grimes, TVA’s chief nuclear officer.

NRC has granted license extensions to 78 U.S. nuclear reactors so far, each for 20 years. Applications for another 16 renewals are pending.

More: Associated Press; Chattanooga Times Free Press

NRC Announces Personnel Changes

The Nuclear Regulatory Commission announced several senior personnel changes as part of its plan to streamline operations.

Mike Weber, the current deputy executive director for Material, Waste, Research, State, Tribal and Compliance Programs, was named director of the Office of Nuclear Regulatory Research. Jennifer Uhle is moving from her position as deputy director for engineering in the Office of Nuclear Reactor Regulation to become director of the Office of New Reactors. Catherine Haney, director of Nuclear Materials Safety and Safeguards, will become Region II regional administrator in January.

The changes, said NRC Chairman Stephen Burns, “will put in place a management structure well suited to ensuring we accomplish our mission of protecting people and the environment even as we reduce our size and budget.”

More: World Nuclear News

Energy and Power Chief Announces Retirement

Representative Ed Whitfield of Kentucky
Whitfield

U.S. Rep. Ed Whitfield (R-Ky.), chairman of the House Subcommittee on Energy and Power, announced last week he will not seek re-election to a 12th term in 2016.

Whitfield, 72, a leader of the Republican opposition to the Environmental Protection Agency’s carbon emission rules, will stay through the end of his term in December 2016. Whitfield’s long-time aide, Michael Pape, and state Agriculture Commissioner James Comer, who finished second in the Republican primary for governor in May, have announced they will seek the seat.

Rep. Pete Olson (R-Texas), the subcommittee’s vice chairman, is the leading candidate to replace Whitfield as chairman of the panel. Whitfield’s departure also increases the odds that Rep. John Shimkus (R-Ill.) will succeed Rep. Fred Upton (R-Mich.) as chairman of the Energy and Commerce Committee. Upton must relinquish the chairmanship at the end of this term due to GOP term limits.

More: Associated Press; Lexington Herald-Leader; Politico

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PJM Markets and Reliability Committee Briefs

VALLEY FORGE, Pa. — PJM is proposing a Tariff change that would allow it to release Base Capacity resources to reflect the Capacity Performance resources it acquired in the transition auctions for the 2016/17 and 2017/18 delivery years.

The RTO uses its incremental auctions to sell excess capacity, or purchase more to replace shortfalls, based on changes to its load forecast. But PJM’s Tariff does not allow for such adjustments based on the additional capacity obtained in the transition auctions.

PJM obtained 4,246 MW of Capacity Performance for 2016/17 and 10,017 MW for 2017/18 in the transition auctions held in August and September.

The Tariff change, which will be brought to a Markets and Reliability Committee vote Oct. 22, would be effective for the third incremental auction for 2016/17 in February.

Independent Market Monitor Joe Bowring took issue with PJM Assistant General Counsel Jen Tribulski calling the amendment a “minor change.”

“This is a substantive change,” he said. “Why buy excess and sell it back? Why do you think that makes sense for the market?”

Stu Bresler, PJM senior vice president for markets, said that when PJM executed the transition auctions for Capacity Performance, it didn’t know what mix of Base and Capacity Performance resources would result.

“This was our intent all along, if we had a case where we had resources committed that weren’t previously committed,” he said. (See PJM Transition Auction Capacity not Included in Incremental Auction.)

In order for the Tariff change to be in place for the February auction, it needs to be filed with FERC by December.

New Methodology Would Decrease Projected Load

The MRC got a look at proposed changes to PJM’s load forecast methodology, which would mean a 2.6% drop in projected peak load for summer 2018.

Among the changes in methodology are the addition of an energy efficiency and saturation variable, a weather history shortened to 20 years and the addition of weather “splines,” which capture the relationship between weather and load, PJM staff said.

“The impact of energy efficiency has finally gotten to the magnitude that it will make a difference in our model,” PJM’s Tom Falin said.

The new methodology is predicted to reduce error rates from 6.6% to 1.5% on a three-year-out basis. (See “New Methodology Could Lower Summer 2018 Forecast by 2.6%; Winter Down 1.8%” in PJM Planning Committee Briefs.)

Members will be asked to endorse the final forecast in November, following the addition of updated economic data, equipment index trends and other data.

While the load forecast is expected to drop, PJM is recommending increasing the installed reserve margin (IRM) to 16.5% from 15.7%.

The proposed increase in the IRM came as a surprise to some members, who expected it to drop as a result of the implementation of Capacity Performance rules. (See “Proposed Increase in Reserve Margin Sparks Opposition from Load” in PJM Planning Committee Briefs.)

But staff said the increase resulted from changes in 2015 capacity and load models, as well as a decline in the capacity benefit of ties (CBOT) — expected capacity imports. The CBOT was reduced because the “rest of world” peak demand is becoming more coincident with the PJM peak.

Staff stressed that changes in the IRM may not have that much impact on the forecast pool requirement (FPR), which determines the amount of capacity procured in the annual Base Residual Auction.

Solution, Task Force Proposed to Curtail RegD Resources

PJM staff presented a provisional solution to address modeling problems that are causing PJM’s regulation market to purchase too much RegD megawatts at times.

They also proposed a charter for the Regulation Market Issues Senior Task Force, which will be assigned to track the issue.

The solution, which will be brought to a vote Oct. 22, would move the benefits factor curve to the left so that it is at zero at 40%. A cap of 26.2% also would be implemented during identified excursion hours — hours when dispatch frequently moves the regulation signal manually.

In addition, the group proposes a tie-breaker logic to rank RegD self-schedules or zero-cost offers. (See “Proposal Would Curtail RegD Resources in Regulation Market” in PJM Operating Committee Briefs.)

The changes to the curve and the tiebreaker would be evaluated quarterly and may be changed depending on the findings of the task force.

Manual Changes Approved

The MRC endorsed changes to the following manuals at its meeting last week:

— Suzanne Herel and Amanda Durish Cook

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Stakeholder Soapbox: Why PJM’s Capacity Performance Isn’t Good for the Markets

By Marji Rosenbluth Philips

It’s no secret that Direct Energy believes that PJM’s Capacity Performance market structure, approved by FERC, is both over-priced and unlikely to achieve its intended results. In this op-ed piece, we explain why.

pjmPJM’s Reliability Pricing Model was not designed to deal with winter peaks and the reliance on Marcellus shale gas. Nor did the RPM specifically target nuclear, coal and inefficient units for extra revenue.

Need for Comprehensive Overhaul

Instead of doing a comprehensive overhaul, and without much of a stakeholder process, PJM tried to Band-Aid the RPM and developed the CP structure in about four months.

This Band-Aid seems targeted less toward fixing an unreliable system and more to increasing revenues for certain generators. Otherwise why would FERC have exempted fixed resource requirement entities from having to make their system as reliable as the rest of PJM?

Direct Energy protested the CP transition auctions for several reasons.

Generators had already taken measures to improve their performance after the polar vortex.

PJM required consumers to fund a new winter testing program that allowed many generators to have “trial” runs so that there were far fewer operational challenges for units that had not been run in a while.

Generators themselves publicly reported making greater investments because the costs of non-performance during the polar vortex were so high.

And the transition money is unlikely to contribute to better performance during their three-year periods: nuclear units will still incur unanticipated forced outages, and gas generators will unlikely be able to firm up their fuel as few units have permits that allow dual fuel and burning of oil, or they lack space to install storage.

Moreover, payments are not high enough to allow generators to purchase firm gas supply. DE also protested the method by which the auctions were being cleared, because there were two ways to do it and PJM chose the more expensive way.

That is now all history. But our concerns continue.

Illusory Insurance?

Consumers are paying for what may very well be an illusory insurance policy. First, there is no guarantee that a polar vortex event will occur again. Consumers would be better off paying higher real-time energy prices when the system is stressed than doling out billions of dollars annually for an event that may not occur.

And even if it does, there is no guarantee that the generation will be there physically. As noted above, many generators cannot invest in dual fuel or storage facilities, and payments are not significant enough to fund new pipelines to procure firm transmission. Even if the payments were sufficient, unless generators enter into the gas markets during timely nomination periods, they cannot procure firm gas.

We believe that prudent generators are not going to invest more money into their facilities but are more likely to seek financial hedges to cover non-performance risk. So at the end of the day, physical performance is no more guaranteed under CP than it was under the RPM.

Moreover, we are now more than ever dependent on fewer generators to achieve reliability. There are numerous resources that could run for short periods of time, or during one season, that are no longer eligible to be providers of capacity.

This simply makes no sense: There is no reason why there cannot be differing payment structures for capacity. PJM says all megawatts are equal; but they already gave up on that concept when they introduced differing payment structures for demand response (which is a very valuable reliability tool in the wholesale markets that we hope the Supreme Court will recognize) and ran the transition auctions using two different products and clearing curves.

Diverse Resources

There is no reason why the RPM could not have been expanded to include more diverse resources and less expensive ones to help achieve system reliability.

The bottom line is that we strongly support the principles that generators should receive just and reasonable compensation for their performance, but that compensation should be commensurate with the benefits a unit provides to the system. Consumers have been asked to foot an extraordinarily high insurance bill that the chief regulator, FERC, admits is not based on any kind of consumer analysis or even comparative analysis of what is the most efficient way to achieve stated reliability goals.

This is the saddest part of our regulatory system today.

And we need to find a way to fix it. Somewhere in the calculus of how to run good markets, there needs to be an assessment of whether there is a more efficient way to get the same or similar benefits.

Marji Rosenbluth Philips is director of RTO and federal services for Direct Energy, one of the largest retail providers of electricity and natural gas in North America.

If you’d like to contribute an op-ed article for Stakeholder Soapbox, contact Rich.Heidorn@RTOInsider.com.