Page 1597 – RTO Insider

November 25, 2014

PJM Board Taking Extra Time on Capacity Performance Decision

By Rich Heidorn Jr.

The PJM Board of Managers won’t make its Dec. 1 target for filing the RTO’s Capacity Performance proposal with the Federal Energy Regulatory Commission, CEO Terry Boston told members last week.

As a result, PJM will likely post two sets of parameters for the May 2015 capacity auction — one assuming the status quo and one assuming FERC approval of what the board ultimately files.

Boston also said he will recommend that the board’s Section 206 filing not incorporate PJM’s proposal to eliminate demand response as a supply resource. The proposal, outlined in an Oct. 7 white paper, would make load-serving entities responsible for incorporating DR in reduced demand estimates. (See PJM DR Cos. Confident; Reject PJM EPSA Response.)

Boston said PJM should delay changes in its DR rules pending the resolution of a potential Supreme Court review of the D.C. Circuit Court of Appeals’ Electric Power Supply Association ruling voiding federal jurisdiction over DR compensation. “We think the courts and FERC have to do their job,” Boston said. “CP will work either way.”

Boston said the board, which heard from 50 speakers during a four-hour meeting with stakeholder coalitions on Nov. 11, met the day afterward and also conducted a two-hour teleconference with PJM staff last week. The board plans to meet again after Thanksgiving. “The board knows where each coalition stands,” Boston said. “They are weighing all sides of the issue.”

NJ Regulators OK Pass-Through

Meanwhile, the New Jersey Board of Public Utilities decided last week to allow bidders in its February Basic Generation Service auction to pass through “unanticipated” capacity costs approved by FERC.

Retail customers that do not choose alternative suppliers obtain their power through the BGS auctions. In New Jersey, 85% of residential ratepayers and 70% of small commercial customers rely on BGS.

The BPU said it acted because it was unlikely FERC would rule before the next BGS auction in February and it feared potential bidders would decline to participate or include large risk premiums to cover the uncertainty.

BPU President Richard S. Mroz said the action would ensure “the integrity and competiveness” of the auction. “Faced with the uncertainty of federal action on a draft PJM proposal, there was good reason to believe that electric suppliers would either not participate in the upcoming auction or would bid much higher prices to mitigate unknown risks,” he said.

Md. Auction Sees Reduced Participation

The Maryland Public Service Commission blamed uncertainty over the CP proposal for a nearly 50% drop in bidder participation in its Oct. 20 auction for Standard Offer Service, Maryland’s method of supplying customers that do not shop.

The state’s four investor-owned utilities sought 2,184 MW for residential and small and medium commercial customers. The PSC said only five suppliers submitted bids on one or more of the 10 products available in the auction, down from nine in the previous auction.

Only two bidders offered to supply residential and small commercial customers, and only one bidder made offers for several other products.

Pepco (330 MW of combined residential and small commercial customers), Potomac Edison (46 MW of 12-month and 24-month residential supply) and Delmarva Power & Light (122 MW of residential and small commercial) each received only one bid.

Overall, the PSC received bids totaling 1.8 MW for every megawatt it sought, compared with a 3-1 ratio in the previous auction.

“Although the Maryland PSC accepted the bid results and determined that the SOS auction was in line with market conditions, the material reduction in generator interest in bidding in the auction is a cause of great concern,” PSC Chairman W. Kevin Hughes said in a letter to the PJM board.

In testimony to the PSC, Maryland’s bid monitor, Boston Pacific, concluded that “the current level of uncertainty was great enough to keep many bidders from offering for the longer-term residential and [small commercial] products.”

November 25, 2014June 15, 2023

Con Ed Opens New Front in PSEG Transmission Allocation Dispute

By William Opalka

Consolidated Edison of New York has opened a new front in its attempt to persuade federal regulators that it’s been saddled with an unfair share of two transmission upgrades in northern New Jersey.

The company filed a complaint on Nov. 10 with the Federal Energy Regulatory Commission stating its opposition to a cost allocation formula that PJM has devised for the upgrades (EL15-18). Con Ed said it is being overcharged by about $650 million for the projects.

PJM assigned Con Ed $629 million of the costs of a $1.2 billion transmission upgrade to address a short-circuit problem in the Public Service Electric and Gas transmission zone outside New York City. PJM said Con Ed’s responsibility resulted from its use of the “Con Ed-PSEG wheel,” in which Public Service Enterprise Group, PSE&G’s parent company, takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City. PSE&G was allocated $52 million of the cost.

Con Ed was also assigned $51 million of PSEG’s $100 million Sewaren storm-hardening project.

In April, FERC rejected Con Ed’s attempt to avoid paying for the short-circuit project but said it wanted more information on how PJM performed the distribution factor (DFAX) analysis that determined Con Ed’s share of the cost. (See FERC Rejects Con Ed Challenge on Tx Upgrade.)

Con Ed also said PJM’s Tariff requires a review of instances where PJM’s cost allocations will produce “objectively unreasonable” results.

The company said the new complaint will provide a more holistic consideration of the cost allocation than the rate filing that prompted FERC’s earlier order.

“FERC has recognized that parties have a right to challenge previously approved cost allocation methodologies,” Con Ed spokesman Bob McGee said. “As such, Con Edison exercised its rights under the Federal Power Act and challenged the cost allocations themselves, the decisions and actions taken by PJM in producing the cost allocations and the discrete elements of PJM’s Tariff that caused these unjust, unreasonable, unduly discriminatory and preferential results.”

November 25, 2014June 15, 2023

FERC Scrutinizing Presque Isle Rate Increase for Upper Peninsula

By Chris O’Malley

The Federal Energy Regulatory Commission has ordered hearing and settlement procedures on MISO’s proposed cost allocation for the Presque Isle Power Plant, which would cause steep rate increases for residents in Michigan’s Upper Peninsula.

The Nov. 10 ruling (ER14-2860, ER14-2862) comes after a flood of ratepayer and political pushback to MISO’s system support resource agreement (SSR) that blocks Wisconsin Electric Power Co. (WEPCO) from closing the aging and costly generator near Marquette, Mich.

MISO sought the SSR last year after determining that the 400-MW coal-fired plant was needed for reliability of the region’s grid.

Upper Peninsula ratepayers would shoulder the bulk of the estimated $100 million annual cost to keep Presque Isle in operation. Michigan and Wisconsin utility regulators say the cost of keeping the plant in operation is unreasonable. (See Michigan: FERC Favors Transmission in Presque Isle Dispute.)

The Michigan House of Representatives on Nov. 6 passed a resolution calling on FERC to reverse its acceptance of MISO’s cost allocation, which it said would saddle Upper Peninsula residents with 99.5% of the Presque Isle costs. The resolution asks FERC to divide the cost in “a more equitable manner.”

Dozens of cities and towns drafted similar resolutions and filed them with FERC. A number of businesses in the Upper Peninsula complained that their monthly costs would rise by several hundred dollars a month and that they would be forced to cut jobs.

FERC’s files were filled with complaints from residential ratepayers, as well.

“I am a semi-retired elder on a very limited income. Having to pay $30 to $50 more on my electric bill would be an extreme hardship for me and many others like me,” wrote Ruth Pickem, of St. Ignace, Mich.

“If Wisconsin does not have to pay because they do not benefit from the plant, then we should not have to either. We do not benefit from this plant! Close it!” Pickem added.

The uproar over Presque Isle even triggered bipartisan legislation from Michigan lawmakers in Congress, Democratic Sen. Debbie Stabenow and Reps. Dan Benishek (R) and Gary Peters (D).

“The Power Act,” introduced earlier this month, would essentially require FERC to overrule decisions by the North American Electric Reliability Corp. if a review found it resulted in “unjust and unreasonable” rate increases.

The bill’s sponsors said NERC’s intervention “upended” an earlier FERC finding that Upper Peninsula ratepayers should bear only 14% of Presque Isle’s operating costs.

WEPCO has expressed interest in adding new generation in the Upper Peninsula.

Other studies have been conducted into the possibility of building new transmission to the Upper Peninsula, although that would likely cost hundreds of millions of dollars. A combination of both new transmission and generation remains under debate.

A hearing date in the Presque Isle SSR matter has yet to be scheduled.

November 25, 2014June 15, 2023

Schneider, Foster, Rogers Win Backing for New Terms

pjm — From left to right: Board of Managers Chairman Howard Schneider; board member “Neel” Foster; and board member Sarah Rogers. (Source: PJM Interconnection LLC)

The PJM Nominating Committee voted last week to renominate Board of Managers Chairman Howard Schneider and board members John McNeely “Neel” Foster and Sarah Rogers to new three-year terms.

The three nominations will be brought to a vote by members at the PJM Annual Meeting in May. The Nominating Committee also is seeking a candidate to fill the unexpired term of Bill Mayben, who plans to retire in 2015. Under the Operating Agreement, Mayben’s replacement must be someone with expertise in the operation or concerns of transmission-dependent utilities.

Meanwhile, the Members Committee elected new members to the Nominating and Finance committees, as well as sector whips (see table).

Katie Guerry of EnerNOC was elected to a one-year term as MC vice chairman. She will assume the position in January, when Jim Jablonski of the Public Power Association of New Jersey becomes chairman, succeeding Dana Horton of American Electric Power.

November 25, 2014

MISO to Look Closer at Low-Voltage Threats to System

By Chris O’Malley

MISO plans to unveil a plan next spring for monitoring and managing low-voltage facilities that can cause overloads on its transmission system.

The plan, which will focus on sub-100-kV lines, is in response to the Sept. 8, 2011, Southwest blackout that cut power to 5 million people in Arizona, Southern California and Baja California in Mexico.

Investigators found that the loss of a 500-kV transmission line owned by Arizona Public Service Co. increased power flows through lower voltage systems in parallel to significant transmission corridors, according to a 2012 report by the Federal Energy Regulatory Commission and North American Electric Reliability Corp.

“The flow redistributions, voltage deviations and resulting overloads had a ripple effect, as transformers, transmission lines and generating units tripped offline, initiating automatic load shedding throughout the region in a relatively short period of time,” the report said.

MISO said a transmission owner’s request that the ISO manage some of its low-voltage facilities also was a driver in the initiative.

MISO will identify low-voltage systems that impact the bulk-electric system and establish criteria to determine what it should monitor or manage. MISO would monitor the low-voltage elements by including them in models and tracking power flows against operating limits. It would include the most important low-voltage lines in its congestion management and transmission planning.

Under its current proposal, MISO would include in its N-1-1 contingency analyses an assessment “of BES elements that would potentially overload and trip facilities on the low-voltage system that would propagate back to BES” or that would cause the models to fail to solve, indicating possible system instability.

A low-voltage facility would be deemed to have an impact on the BES if the trip of low-voltage facilities causes an overload greater than 100% of the emergency rating on a BES element or results in an unsolved power flow, and the initial BES contingency has a 3% line outage distribution factor (LODF) on the low-voltage candidate facility.

The effort is not intended to broaden the definition of the BES, MISO spokeswoman Jennifer June Lay said. “This is considered a BES reliability issue that is part of the ongoing reliability services provided by MISO and would result in no additional services to be marketed.”

MISO said it is working with stakeholders to develop a final methodology. It said it will update assessments of the low-voltage systems every two or three years.

Asset owners would be able to examine results, validate findings and comment on solutions, such as whether existing mitigation is available to avoid overloads of a low-voltage facility.

The 2011 Southwest blackout proved pricey for utilities.

FERC has meted out at least three penalties so far, including a $12 million penalty announced last summer against the Imperial Irrigation District. The non-profit California utility violated four reliability standards for transmission operations and planning said to have undermined BES reliability, regulators charged. FERC also said IID fell short in coordinating operations planning with neighboring systems. FERC only collected $3 million from IID, as it ordered the utility to spend $9 million on reliability enhancements.

Yesterday, FERC announced a settlement with the Western Area Power Administration’s Desert Southwest Region, which it said had violated three reliability standards in the blackout. WAPA agreed to improvements, including the modeling of “critical external facilities and facilities operated below 100 kV that can impact system operating limits on its transmission system,” FERC said.

November 25, 2014

DOE IG Investigating FERC Enforcement

By Michael Brooks

In response to requests from several senators from both parties, the Department of Energy’s Inspector General has begun an investigation into the Federal Energy Regulatory Commission’s Office of Enforcement.

“After reviewing this situation, we have determined that we will be undertaking a review of aspects of FERC’s enforcement program,” Inspector General Gregory Friedman said in a letter to Republican Sen. John Barrasso of Wyoming.

The letter is dated Oct. 23 but was only recently made public.

Barrasso and Sen. Susan Collins (R-Maine) had written Friedman in September, asking him to investigate allegations in an Energy Law Journal article by former FERC counsel William Scherman that “the FERC enforcement has become lopsided and unfair.”

The senators requested that Friedman look into allegations that enforcement targets “are not being given actionable notice by FERC of conduct” that “constitutes market manipulation.” The senators were also concerned that companies “who do not otherwise appear frequently before FERC are held to different standards.”

Quid Pro Quo?

The senators also pointed to Commissioner Norman Bay’s written answers to questions posed by the Senate Energy and Natural Resources Committee after his confirmation hearing in May, shortly after Scherman’s article was published. Sen. Lisa Murkowski (R-Alaska) asked about the appearance of quid pro quo regarding FERC’s approval of Exelon’s 2012 merger with Constellation Energy Group, which occurred the day after Constellation agreed to a settlement with the Office of Enforcement. Murkowski noted that the settlement agreement made reference to the merger.

Bay answered, “To the best of my recollection, I did not indicate to the parties involved in the Exelon-Constellation merger that it would be prudent to settle the pending enforcement matter to get the merger approved. I do not know whether anyone else at FERC did so.”

“Given these circumstances, did the former FERC chairman [Jon Wellinghoff] or any member of FERC’s staff suggest or actively or effectively require that a regulatory approval would be contingent upon the ‘voluntary’ settlement of an enforcement dispute?” the senators asked Friedman.

Barrasso had pointed criticism for Bay at the future FERC chairman’s confirmation hearing. “I find this very troubling,” Barrasso told Bay regarding Scherman’s allegations. “I believe this raises serious questions about your fitness to be on the commission. I also believe that these tactics have contributed to driving investors out of the electric market and that means a less reliable grid and higher costs to consumers.” (See Analysis: LaFleur Cruises, Bay Bruises in Confirmation Hearing.)

Sen. Robert Casey (D-Pa.) also wrote to Friedman about FERC’s enforcement tactics in July. Casey did not bring up specific allegations, only asking whether or not the office was violating any due process or confidentiality laws.

“I appreciate that FERC investigates matters that may bring instability or fraud to the energy marketplace,” Casey wrote. “However, to do this fairly and effectively, it is important that FERC’s policies on investigations and enforcement actions be transparent.”

Bay and his successor as enforcement chief, Larry Gasteiger, have defended the office’s work. (See FERC, CFTC Reject Due Process Complaints.)

2014 Report on Enforcement

News of the IG’s investigation came as FERC last week released its annual Report on Enforcement.

The report highlights eight settlements in fiscal year 2014 that resulted in almost $25 million in civil penalties and disgorgement of $4 million in unjust profits. Some of these penalties were offset by reliability enhancements that FERC ordered. For example, FERC penalized the Imperial Irrigation District $12 million for its role in the 2011 Southwest blackout, but this was offset by the $9 million spent by the utility on reliability enhancements. (See related story, MISO to Look Closer at Low-Voltage Threats to System.)

Otherwise, the largest of these penalties was against Louis Dreyfus Energy Services ($4.3 million) “for virtual transactions made to increase the value of the company’s position in financial transmission rights” in MISO. The company also paid a $3.3 million disgorgement to MISO under the settlement.

FERC also collected $4 million from Erie Boulevard Hydropower for failing “to adequately maintain and operate dam safety mechanisms” and $2 million from Arizona Public Service Co. for, among other violations, failing “to perform necessary operational planning studies.”

Gas Index Manipulation

Among the settlements is one with Direct Energy Services, in which the company agreed to pay a $20,000 penalty and disgorge $31,935 for manipulating natural gas prices in May 2012. FERC said the company lowered prices at the Algonquin and Transco Zone 6 hubs by buying next-day physical index gas and selling comparable volumes of fixed-price gas. The company’s action lowered the Gas Daily Index, benefiting the company financially, according to the report.

The report notes that Direct Energy self-reported the violation, and its “quick action due to its strong compliance program and its cooperation with Enforcement’s investigation resulted in relatively small civil penalty and disgorgement payments.”

At FERC’s monthly meeting last week, Bay asked enforcement staff what led Direct Energy to self-report the violations. Staff member Michael Raibman said that after the company’s outside counsel gave a presentation regarding the Constellation settlement, a trader went to his supervisors, saying he suspected that some of his colleagues were engaged in the type of activity described in the presentation. Direct Energy’s compliance division then began an internal investigation the next day, Raibman said.

“So how helpful was the transparency provided in the commission’s order in the Constellation settlement?” Bay asked.

Raibman replied that Direct Energy said it had found it very helpful “because they knew exactly what it was that we had found troubling Constellation and were able to identify the same pattern in their trading very, very quickly.”

November 25, 2014

New England Generators: Exclude DR from Capacity Auction

By William Opalka

New England power generators are joining FirstEnergy’s effort to expand a court ruling that would prevent demand response providers from participating in capacity auctions.

The New England Power Generators Association asked the Federal Energy Regulatory Commission Nov. 14 to order ISO-NE to exclude such resources from the Forward Capacity Market (EL15-21).

In May, the D.C. Circuit Court of Appeals threw out the commission’s Order 745, which required RTOs and ISOs to pay demand response providers for energy at LMPs. The Electric Power Supply Association had sued FERC, claiming the commission exceeded its jurisdiction. FirstEnergy Solutions then filed a complaint with FERC, seeking to expand the challenge.

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 on FERC’s behalf to send the case to the U.S. Supreme Court. (See EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans.)

NEPGA, which represents 26,000 MW of generating capacity in New England, asked FERC to issue an order by Jan. 15, two weeks before ISO-NE is set to begin its next Forward Capacity Auction on Feb. 2. An order at that time would “ensure that clearing prices are not distorted by the participation of resources that cannot lawfully participate in that auction and that will be unable to fulfill their obligations if selected,” the NEPGA complaint states.

NEPGA also argues that the reasoning of the D.C. Circuit’s jurisdictional holding in the EPSA case — that FERC was erroneously attempting to regulate a retail product — was not limited to the energy markets. Demand response capacity resources must be excluded from participating as supply in capacity auctions because they can’t fulfill their energy must-offer obligations as required by ISO-NE’s Tariff, the complaint states.

November 25, 2014

Duke Energy Eyes Natural Gas Production

By Ted Caddell

After investing in natural gas-fired generation and committing to a $2 billion pipeline investment, Duke Energy now says it might get into gas production.

Duke Chief Financial Officer Steve Young told the annual Edison Electric Institute Financial Conference Nov. 11 that the company’s increasing dependence on natural gas means wellhead investments could make sense for the company.

“Gas prices have some volatility and investments in gas reserves might make sense,” Young said, according to a Bloomberg News account of the conference.

Young didn’t make any specific references to natural gas production investments, but it was the first time a Duke executive raised such a possibility. Since then, the company has declined to make public any plans for natural gas production investments.

“Duke Energy is in the early stages of evaluating investments in shale gas production,” company spokeswoman Jennifer Zajac said. “There are no immediate plans and the company will not make any decisions on the matter any time soon.”

Zajac said Duke is carefully watching another company’s move in that direction, however.

”Duke Energy will continue to monitor Florida Power & Light’s request for a rate-base shale gas production framework from the Florida Public Service Commission,” she said.

The idea is that instead of passing on gas costs to customers as it does now, Duke could control the price at the wellhead, lock in prices for customers and earn a profit on the investment. It would need regulatory approval for such a plan.

NextEra Energy, FPL’s parent company, generates 52% of its electricity using natural gas and has invested in natural gas pipelines. It is pushing for approval of a 600-mile, $3.7 billion natural gas pipeline into Florida from a hub in Alabama. It would partner for the project with Spectra Energy Partners.

Earlier this year, FPL said it was partnering with PetroQuest Energy to develop more than three dozen natural gas wells in the Woodford Shale region in southeastern Oklahoma. It is waiting for the Florida PSC to approve the company’s plan to invest in natural gas production as a long-term program and add it into its rate-base case. Currently, the Florida PSC allows the company to engage in short-term fuel hedging agreements to smooth fuel price volatility. FPL said it expects a decision from the PSC by late this year or early next year.

Like NextEra, Duke is investing in gas-fired generation and pipeline construction. Earlier this year, Duke said it would partner with four other companies to build a 550-mile, $5 billion pipeline to bring Marcellus and Utica shale gas to Virginia and eastern North Carolina. Called the “Atlantic Coast Pipeline,” it would have a capacity of 1.5 billion cubic feet of gas per day. Duke would own 40% of the pipeline. (See Duke, Dominion Propose 550-Mile, $5 Billion Pipeline for Shale Gas.)

At the North Carolina CEO Forum in Raleigh on Oct. 23, Duke CEO Lynn Good noted that its generation portfolio is increasingly dependent on natural gas. “By 2013, it was 20%, and we think it is going to be more and more and more as we go forward,” Good said, according to the Charlotte Business Journal. As recently as 2008, she said, “it would have been close to 0%.”

As part of its $9 billion generation fleet modernization program, the company retired about 3,830 MW of older coal-fired units in recent years, and it says that number will grow to nearly 6,300 MW, about a quarter of its earlier coal fleet. It is building a $600 million gas-fired plant in South Carolina and a $1.5 billion plant in Citrus County, Fla.

The company generated 55% of its power with coal in 2005, a share projected to drop to 38% by 2015. Gas, which was responsible for only 5% of its 2005 output, is expected to generate 24% of its power next year. Duke owns about 50 GW of generation in the U.S.

November 25, 2014

MISO Consumer Advocates Renew Fight over TO Equity Structure

By Chris O’Malley

MISO consumer advocates last week asked the Federal Energy Regulatory Commission to reconsider their request to cap the equity component of transmission owners’ capital structure at 50%. The advocates also renewed their request to eliminate transmission rate incentives for RTO participation and independence.

The commission rejected both requests Oct. 16, but it ordered an evidentiary hearing on complaints that the base rate of return on equity of MISO’s 24 transmission operators is not just and reasonable (EL14-12).

The commission said the challengers failed to demonstrate that the capital structure and incentive rules were unjust. FERC also ruled that evidence showing that certain MISO TOs have higher amounts of equity than they need to maintain good credit ratings and attract capital was insufficient grounds for investigating their capital structure.

Consumer advocates from Indiana, Iowa, Michigan, Minnesota, Missouri and Wisconsin argue in their latest filing that “the allowed ROE and the ratemaking capital structure must be considered together and both subject to reasonable standards.”

They said there’s evidence that transmission-only companies with lower operating risk can finance with greater amounts of financial risk or leverage while supporting an investment-grade bond rating. They said “today’s changed financial market” warrants a lower cap on the equity component.

ITC Holdings Cited

As an example, the advocates pointed to ITC Holdings and its utility subsidiaries. While those subsidiaries set transmission rates based on a commission-approved 60% equity ratio capital structure, ITC seeks to maintain an adjusted debt-to-total capital ratio of 70%, the advocates said.

Bond ratings of the ITC companies reflect a common equity ratio of 30%, not the 60% used to set ITC’s and Michigan Electric Transmission Co.’s FERC transmission rates, the advocates contend. ITC’s bond ratings are “only slight lower” than its FERC-regulated operating subsidiaries.

“That fact means that the FERC-regulated ITC subsidiaries could be capitalized with much lower (and much less expensive) common equity ratios, just as the parent (ITC) does and still maintain investment-grade bond ratings,” they said.

Customers who must pay for the much more expensive equity capital allowed in ITC’s subsidiaries’ 60% ratemaking capital structure “are not getting any debt cost advantage of that extreme equity ratio because the parent company leverage holds down the bond rating that could otherwise be achieved with such a high equity ratio.”

OMS Weighs In

The Organization of MISO States also requested that FERC rehear TO capital structure and continued use of incentive transmission adders for independence and RTO participation.

“If not reviewed alongside the ROE, the resulting costs in these two areas could lead to rates that will be higher than necessary to achieve investment grade utilities that build needed transmission,” OMS said. “Requiring the parties to review base ROE without looking at all the relevant factors that impact end-use rates rests on the faulty notion that these elements are discrete and disconnected from each other.”

OMS cites the ability of ITC Transmission and METC to receive a 100 basis-point adder for being an independent transmission company.

FERC opened the door to ROE fights in June, when it changed the way it sets return on equity rates for electric utilities to something akin to the process it uses for natural gas and oil pipelines. FERC ruled in a case involving a New England transmission owner, tentatively setting the “zone of reasonableness” at 7.03 to 11.74%.

The TOs’ ROE is currently 12.38%, except for American Transmission Co., which has a base rate of 12.2%.

Settlement Judge Dawn E.B. Scholz reported last week that the parties had made progress in a settlement conference Nov. 13. Another session was set for Dec. 16.

MISO industrial customers said previously they see the potential to reduce transmission rates by $327 million in year.

November 25, 2014June 15, 2023

Duke Sees $3.4B Coal Ash Cleanup Bill; Who’s Next?

By Ted Caddell

Duke Energy this month filed a plan with North Carolina environmental agencies to remove millions of tons of coal ash from four sites in the state, the beginning of a multi-year $3.4 billion remediation effort. Duke, which reported operating revenue of $26.4 billion last year, has not said how the cost will impact earnings.

Other coal-burning utilities may also be facing large cleanup bills as state and federal regulators increase their scrutiny following spills by Duke and the Tennessee Valley Authority.

So far, storage and disposal of coal ash and related materials is not federally regulated. That is expected to change on Dec. 19, when the Environmental Protection Agency is scheduled to announce a long-awaited rule.

The EPA proposed coal ash rules in 2010 but, under political pressure from industrial groups, the White House sent the rules back for rewriting. It took a court-ordered consent decree to set the Dec. 19 deadline.

Utilities are waiting to see whether the proposed rule, now at the White House for review, will classify coal ash as “hazardous,” which would require more strict remediation and disposal rules than classification as “special wastes.”

140 Million Tons Annually

Earthjustice, an environmental group that successfully argued in court for the December deadline, says in a report that there are 208 documented cases of contamination caused by coal ash spills. It says that coal-fired power plants generate about 140 million tons of coal-related ash and sludge a year, all of it containing toxic materials.

Public opinion turned against Duke after a pipe at an impound pond on the Dan River near Eden, N.C., failed, dumping 39,000 tons of coal ash sludge, containing toxins such as arsenic, boron, cadmium, lead and mercury, into the river.

The result was state legislation approved in August that could be a model for other state efforts. The North Carolina law, a compromise enacted during a special session, requires elimination of leaks at coal impounds but does not require removal. It left open the question of whether the cost of coal-ash remediation could be passed on to customers while setting up a Coal Ash Commission under the state Department of Public Safety.

Under the law, all basins at four of Duke’s sites — Asheville Steam Electric Plant, Dan River, Riverbend Steam Station and the L.V. Sutton Steam Electric Plant — must close by August 2019.

Duke’s remediation plan goes further. On Nov. 13, the company said it will permanently close the sites and excavate and move more than 5 tons of ash from them. It said it has 108 million tons in basins throughout North Carolina, 30 million tons in landfills and 14 million tons at its own plant sites. The company also said it is developing plans for the next phase while awaiting approval for the work at the first four sites.

“We think these excavation plans go beyond the specific information requested by the state, demonstrating our commitment to closing ash basins in a way that continues to protect the environment, minimizes the impact to neighboring communities and complies with North Carolina’s new coal-ash management policies,” said John Elnitsky, Duke’s senior vice president of ash-basin strategy. “We are prepared to proceed as soon as we have the necessary approvals from the state.”

TVA: $3.2 Billion

Duke is not the only utility confronting the coal ash issue.

The Tennessee Valley Authority this summer agreed to pay $27 million to settle claims from property owners who said they suffered damage from a 2008 spill of 5 million cubic yards of contaminated coal ash. The settlement came after a 2012 ruling from a U.S District Court judge that TVA violated its own policies. The failure of a storage pond dike at TVA’s Kingston Fossil Plant allowed tons of coal ash sludge to flow into the Emory and Clinch rivers, contaminating properties downstream.

TVA says it has spent $1.2 billion on cleanup so far and has committed to converting its wet ash storage to dry ash, at a cost of another $2 billion. The $27 million settlement is on top of about $80 million it spent to settle about 200 other Kingston-related claims. It also gave $43 million in economic-development grants in the area. That makes about $150 million in claims and grants and $3.2 billion in cleanup costs. TVA reported $11 billion in operating revenue in 2013.

It was the Kingston spill that spurred the EPA rulemaking.

Following Duke’s spill, other companies found themselves drawn into the spotlight. Two environmental groups filed suit against Louisville Gas & Electric for what they say is illegal dumping of coal ash into the Ohio River. LG&E said the treated water it releases into the river is within the limits of its state-issued discharge permits.

In a report issued last week, a Wisconsin environmental group said utilities could be contaminating drinking water by using coal ash for structural fill without first lining the deposit sites to prevent leaching in the state.

The organization, Clean Wisconsin, said the state allows such “beneficial reuse” and that up to 85% of coal ash generated in the state is reused.

“In Wisconsin, large coal plants alone generate nearly 1.8 million tons of toxic coal ash annually, of which 85% goes to ‘beneficial use’ projects. This includes dumping under churches and schools, under or atop roads, on park paths and more,” the report states. The group called for the state to adopt rules like North Carolina’s.