That was the question Independent Market Monitor Joe Bowring posed during his Year in Review presentation at PJM’s Annual Meeting last week, setting off a lively debate with one of the consultants that Richard and Kevin Gates, enlisted in their high profile defense against market manipulation allegations.
“If the rules are imperfect, is it OK to do anything not explicitly prohibited?” Bowring asked.
He quickly provided his own answer. “It is not permissible,” he said, citing what he called the “duty” of market participants to inform RTO officials and federal regulators of such “money trees.”
Bowring referred to PJM’s poorly designed rules on rebating excess line losses, which allowed the Gates brothers’ Powhatan Energy Fund and a handful of other traders to profit through what the Federal Energy Regulatory Commission later called riskless, back-to-back up-to-congestion trades. The rules were later changed. The Gates brothers and their associates — despite stopping the practice after being warned by Bowring — are now facing up to $29.8 million in fines. (See FERC Staff Seeks $30 Million Fine in Powhatan Case.)
“Almost all of the market knew these opportunities existed and chose not to take advantage of them,” Bowring said. “That raises the question: Who’s the smartest guy in the room? The guy who took advantage or the guy who didn’t?”
That brought a response from consultant Roy Shanker, who is quoted on the Gates’ brothers’ website criticizing FERC’s case. “It’s really unfair to have an ill-defined affirmative obligation to do something,” Shanker said.
On the website, Shanker says he believes the Gates and their associates “were simply engaging in rational economic decision making.” He rejected FERC’s contention that the trades were riskless “wash trades.”
In response to Bowring, Shanker cited traders that schedule power deliveries through the IMO interface with Ontario’s Independent Electricity System Operator. Bowring has identified the interface as a location where traders can manipulate PJM’s pricing rules by breaking transactions into multiple “back-to-back” transactions, a practice he has called “sham scheduling.” (See Monitor Gives Lukewarm Review to PJM ‘Sham Scheduling’ Fix.)
“It may be a money tree or there just may be [ambiguity] about the rules,” Shanker said. “We know that ambiguity is out there. It sits like a heavy stone on everyone.”
“When you find something, [the RTOs should] identify it, post it and try to change the rules,” Shanker said. “Because you can’t hit every [possibility] that doesn’t mean that you do not try to address some.”
“Would you be supportive if we proposed such [an affirmative obligation] rule?” Bowring asked.
“Yes,” Shanker responded.
He later explained that he would support “the coupling of an affirmative obligation on market participants” with a “safe harbor” that would protect traders from manipulation charges as long as they stop activity of concern after being specifically warned. “Then it is up to RTO or IMM to act to clarify or change rules,” he said, adding that he was speaking for himself and not the Gates brothers.
Andy Ott, senior vice president for markets, said he, too, would support such a rule. As long, he said, as it was not seen as an “inoculation” for traders that have done something not explicitly listed.
The state is offering a cash rebate of up to $3,000 to buyers of electric cars. An incentive program offers customer rebates and will provide dealers with bonuses for selling electric or hydrogen vehicles. The incentive program is funded by $1 million that the state received as a condition for approving the 2012 merger of Northeast Utilities and NStar into Eversource Energy.
The funds are enough to offer rebates for as many as 457 electric or hydrogen vehicles. The program will allocate $800,000 for cash rebates and $200,000 for dealer bonuses.
The state has 1,625 electric vehicles registered as of May 18. The rebates are available to state residents, businesses and municipalities that buy or lease electric vehicles. Fifteen vehicle models qualify.
Boston-based consumer advocacy group Acadia Center and Eversource Energy are sparring over a state bill that would cap fixed-rate charges to customers of electric utilities. An Acadia report found that more than half of Eversource’s customers would see their electric bills decrease if the legislation, which would cap fixed-rate charges at $10, is approved.
Eversource argues that more than half of its customers would see an increase in their overall bill if the fixed charge is lowered and that a $10 fixed charge is more regressive than a $19.25 fixed charge. Daniel Sosland, Acadia’s president, said the utility is misleading lawmakers. An Eversource spokesman said the company stands by its analysis of the legislation’s impact.
A statewide electricity purchase pool, as an alternative to Delmarva Power & Light’s standard offer, is unlikely to bring customer savings, and costs could be higher under some scenarios, according to a state consultant advising against the idea.
Exeter Associates reported the conclusion after a nationwide survey of aggregation programs. State lawmakers called for a study last year.
However, state officials could consider other options, Exeter said, including allowing customers to specify shares of electricity from renewable power sources or options that let customers specify peak use times.
Delmarva has about 260,000 customers who subscribe to the company’s standard offer.
Opposition Against Exelon-PHI Merger Grows as Comment Window Nears Close
A fifth councilmember came out Friday against Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc., expressing “serious concerns” about the deal in a letter to the district’s Public Service Commission. The 27th of the district’s 40 Advisory Neighborhood Commissions formally opposed the deal.
The district is the last entity to decide on the merger, which Maryland regulators narrowly approved on May 15 and Delaware approved several days later. Public comment in the district closes May 27. (See Update: Md., Del. PSCs OK Exelon-Pepco Deal.)
“While it is clear that this merger would provide great benefit to PHI shareholders, the benefits to ratepayers do not appear proven or clear,” Councilmember Brianne Nadeau said.
Should the commission approve the merger, she said, members should consider using the proposed Customer Incentive Fund to support development of renewable energy sources for low- and fixed-income residents.
The Public Utilities Commission won’t reconsider its controversial decision to cut $38 million in proposed funding from an energy efficiency program. The commission’s 2-1 vote means that funding the Efficiency Maine Trust will fall to the legislature. The trust subsidized the purchase of 2.5 million energy-efficient light bulbs for consumers last year and helped more than 3,000 businesses convert to energy-saving equipment.
The PUC voted in March not to provide the funding for the trust, after a close review of language in the 2013 energy law showed that a single word was missing, apparently as the result of a clerical error. On Wednesday, PUC Commissioners Mark Vannoy and Carlisle McLean argued that petitioners for reconsideration had not brought forward additional information to support changing the panel’s March 17 decision.
Bowie homeowners are beginning to take advantage of a solar cooperative purchasing program sponsored by the city and Maryland Sun, a renewable energy nonprofit organization.
Thirteen residents have signed contracts, 18 are considering proposals and 12 have site visits scheduled, said Maryland Sun program director Corey Ramsden.
At 157 committed members, Bowie is the largest collective the group has created in the state. It has 27 similar co-ops running in Maryland, D.C., Virginia and West Virginia.
A union representing 1,900 Eversource Energy workers in the state has authorized its leaders to strike over stalled negotiations on a new contract. The current contract expires at midnight on June 1.
The Utility Workers Union of American Local 369 said its members voted “overwhelmingly” to allow the strike if its leaders so choose. The union said in a statement that Eversource and the union have been unable to agree on provisions about staffing, health care and the possible elimination of a no-layoff clause.
Minnesota Power’s Great Northern Tx Line Gains OK from PSC
The Public Serivce Commission approved Minnesota Power’s certificate of need for its 500-kV Great Northern Transmission line, a crucial step in the estimated $710 million project. The 220-mile line would deliver hydro power from Manitoba to northeastern Minnesota.
A separate route permit is pending. So is a permit from the U.S. Department of Energy to approve the cross-border line.
Legislation that would pave the way for an orderly sale of Eversource Energy power plants was pulled from the House floor at the last minute last week. The bill would set the stage for a “universal settlement” on a variety of utility issues that would affect customer rates. Eversource has proposed to sell its power plants, but who would pay for the losses that would be incurred is a sticking point. (See Eversource to Sell New Hampshire Plants.) Some legislative leaders also are concerned the bill would pre-empt an ongoing review of electric rates by the Public Utilities Commission.
South Jersey Gas last week filed an amended application including “new details” with the Pinelands Commission seeking approval for a 22-mile pipeline that would carry natural gas to a power plant in northern Cape May County.
The proposed pipeline, which would largely follow a roadway through part of the protected, 1.1 million-acre Pinelands Forest Management Area, has been criticized by conservationists and four former governors. The Pinelands Commission blocked it last year in a 7-7 vote.
But the project is heavily supported by Gov. Chris Christie, who since then has replaced a long-time advocate on the commission with a new member, Robert Barr, who has not disclosed his position on the project.
With the retirement of the Oyster Creek nuclear plant in 2019, PJM and the state Department of Environmental Protection have said that repowering the B.L. England plant — which would use natural gas instead of coal — is necessary to retain reliability on the grid.
The New York Power Authority has approved a contract with about 560 workers from the International Brotherhood of Electrical Workers, including about 215 at the Niagara Power Project in Lewiston. The deal is retroactive to April 2011, when the previous contract expired, and runs through March 31, 2019.
The contract includes wage increases for each year starting in 2014 and requires the union members to increase their contributions to the cost of their health insurance. The wage increases are 3.5% in 2014, 2% in 2015 and 2016 and 2.5% in 2017 and 2018. IBEW members who have been working at NYPA since the expiration of the previous contract will receive a $4,000 lump-sum payment; others will receive a pro-rated payment.
Heavy winter snow caused ground-mounted photovoltaic panels at a large solar farm in Feura Bush to collapse. The 4.5-acre facility is owned by Constellation Energy, which sells power to an Owens Corning insulation plant next door. Owens Corning has said that the farm will be able to offset the costs of about 6% of the factory’s electricity needs. None of the panels went offline during the winter but all need to be remounted for optimal position.
New York State Electric & Gas filed for an increase in electricity delivery charges that would add about $8 to the average residential customer’s monthly electric bill. The increase would cost consumers about $126 million. NYSEG said it needs the increase to help pay for an expanded program to manage vegetation along the 35,000 miles of electric lines it maintains across its upstate service territory. The company also is seeking to recover more than $260 million in restoration costs that it incurred during storms such as Sandy in 2012. State regulators would review the proposal over the next 11 months, with the earliest effective date in May 2016.
FirstEnergy Heading to Hearings on Income Guarantee
Hearings begin in June on FirstEnergy’s request for an income guarantee for seven plants in the state, a case that already has generated thousands of pages of filings with the Public Utilities Commission.
Under the plan, the plants would be guaranteed enough income to cover costs plus a profit. Consumers would make up the difference if the actual income fell short; if the plants exceeded their targets, customers would receive credits.
The FirstEnergy plan affects Davis-Besse Nuclear Power Station, the coal-fired W.H. Sammis plant and the company’s share of jointly owned coal-fired plants.
PUCO has rejected similar proposals from American Electric Power and Duke Energy, but it said their underlying concept was legal.
More layoffs will be coming soon for Murray Energy because of low prices and demand for the coal it mines, its CEO said last week. The St. Clairsville company operates 13 mines in West Virginia, Ohio, Illinois, Kentucky and Utah.
“We had 8,600 employees until last month. We’ve had to reduce some since then. I can’t keep all those jobs,” Robert E. Murray told a gathering of the North American Coal Bed Methane Forum.
Coal prices are down about 10% from a year ago. Murray blamed low demand on environmental rules and cheaper natural gas.
“If I had to describe today’s coal industry … I call it extremely dangerous,” he said. “Not from a safety standpoint, from survival.”
PUC OKs PECO’s Updated, Pricier Long-Term Upgrade Plan
The Public Utility Commission approved PECO Energy’s updated long-term gas infrastructure improvement plan, which is expected to cost the Philadelphia-based company more than $534 million and take two decades to complete.
The two-year-old plan was amended earlier this year, in part to speed up the replacement of at-risk natural gas mains. While those pipelines make up just 12% of the entire system, they are responsible for nearly all of PECO’s leaks.
Under the proposal, spending on upgrades would jump from $34 million to $61 million by 2018. Total costs would rise from the initially forecast $371.3 million to $534.4 million.
Rhode Island Fast Ferry has been awarded a 20-year contract to operate a specialized boat for the construction and maintenance of a five-turbine wind farm that Deepwater Wind will install in waters near Block Island starting this summer. The new vessel will transport workers to and from the offshore wind farm, which will be the first of its kind in the U.S. The company will spend $4 million to build the boat and train crew members to operate it. It is expected to be ready to provide crew and equipment support in spring 2016 in advance of the installation of the turbines for the Block Island Wind Farm.
Fearing Levee Breach, Entergy Shuts Down Hydro Plant
Entergy took its Lewis Creek units 1 and 2 offline Saturday night in order to lower reservoir water levels and reduce the risk of levee failure.
“This is absolutely the right decision for the protection and safety of Montgomery County residents and the long-term reliability of the plant,” said Sallie Rainer, CEO of Entergy Texas. Company and MISO officials said that taking the two 271-MW units offline will not result in any immediate reliability issues.
On Thursday, Entergy Texas notified local authorities of the potential for a failure due to heavy rainfall that saturated the earthen dam near Willis. The company is hauling in truckloads of limestone rock to stabilize the base of the levee.
3 Down, 2 to Go in Wisconsin Energy-Integrys merger
The Public Service Commission last week finalized its approval of Wisconsin Energy Corp.’s $9.1 billion acquisition of Integrys Energy Group.
The Federal Energy Regulatory Commission and the Michigan Public Service Commission previously signed off on the deal. The Wisconsin PSC had only indicated verbal approval.
That leaves regulators in Illinois and Minnesota next to give their blessings. Any drama likely would come from Illinois, where Chicago Mayor Rahm Emanuel late last year asked the state Commerce Commission to reject the acquisition.
Southern Co. and three Missouri utilities say that MISO has billed them more than $21 million in excessive transmission rates since Entergy joined the RTO in December 2013.
In a complaint filed Wednesday with the Federal Energy Regulatory Commission, the companies accuse MISO of imposing a “massive and unlawful increase” for power moved over the Entergy system (EL15-66).
Long-term, firm point-to-point transmission service rates under the Entergy OATT vs. MISO OATT.
It alleges MISO shifted and reallocated sunk costs and network upgrade costs from its legacy region in the Midwest to Entergy export customers in the South. The companies allege the allocations violate MISO’s Tariff and FERC findings that — with the exception of certain multi-value projects — point-to-point export services are provided under a no-cost-sharing rule.
Bringing the complaint are Kansas City Power & Light’s Greater Missouri Operations Co., The Empire District Electric Co., Associated Electric Cooperative Inc. (AECI) and five Southern Co. affiliates: Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power.
MISO spokesman Andy Schonert said that FERC is already litigating these issues in docket EL14-19, a section 206 proceeding it initiated in February 2014. “These claims are not new,” he said. “We are reviewing the legal arguments and plan on responding.”
FERC began that case to investigate MISO’s proposed regional “through and out” rate. AECI complained that most legacy customers would be charged a zonal rate based on the facilities in their zone. Thus, the co-op argued, it and other customers would be forced to pay rates based on both the MISO and Entergy footprints after the Entergy integration into MISO.
The case was consolidated with others involving challenges by stakeholders in the South over what Entergy should be able to collect in rates as part of MISO. Many of those disputes have been under settlement talks over the last two years. Last week, FERC terminated settlement procedures and set the matter for hearing.
‘First of its Kind’
At the heart of the new complaint is the no-cost-sharing provision in MISO’s Tariff that, according to plaintiffs, acknowledges the historical lack of coordinated planning between MISO’s legacy region and the newly added Entergy region.
With no basis to conclude that customers of one region benefit from projects planned and constructed to benefit customers of the other region, the Tariff provides that any system-wide rate or cost allocation under the Tariff “shall be limited to the planning area where the project terminates,” the complaint states.
Because FERC noted that Entergy’s integration into MISO as the “first of its kind,” the commission justified the separation of the MISO footprint into two distinct regions for cost allocation and rate design purposes, the utilities say.
They asked FERC to force MISO to modify rate schedules in the Tariff related to export service and to ensure that the no-cost-sharing rule be applied to exports from the Entergy region.
The complainants said they were customers of Entergy prior to its MISO integration and hold long-term, point-to-point transmission service contracts with the company.
Charges for long-term, point-to-point transmission service under Entergy’s Open Access Tariff have jumped from $1.78/kW-month to $3.33/kW-month — an 87% increase — since Entergy joined MISO, they said.
“This massive rate increase should never have happened. It was and remains unauthorized,” the utilities said.
Increases Detailed
The utilities say much of the transmission is used to move wind generation from the Southwest to the Southeast.
When Entergy joined MISO, “it essentially became a continental divide stretching from the nation’s northern border to [the] southern border — with MISO as the gatekeeper for the delivery of Western wind to Southeastern loads and delivery of low-cost Southeastern base-load generation to Western loads,” the complaint states.
Southern said it has paid $8 million more in transmission fees between December 2013 and April 2015.
KCP&L said it paid Entergy $6 million a year for point-to-point transmission service prior to MISO but that the amount has nearly doubled since then.
AECI said it is paying $8.3 million a year, up 94% since Entergy joined MISO.
Empire District, based in Joplin, Mo., said only that its total costs for point-to-point transmission service on Entergy’s system have doubled.
The Federal Energy Regulatory Commission said last week that the single-step discounted cash flow (DCF) analyses that it formerly used are adequate to support rate complaints made before it changed the rules.
FERC made the assertion in denying requests by Xcel Energy and the New England Transmission Owners that it reconsider its orders establishing hearing and settlement judge proceedings in return on equity (ROE) disputes.
The rulings involved complaints that sought to reduce the New England TOs’ ROE (EL13-33 & EL14-86-001) and two ROE disputes between Xcel’s Southwestern Public Service Co. (SPS) and Golden Spread Electric Cooperative (EL13-78 & EL12-59).
Opinion 531
Golden Spread has two agreements with SPS: a power purchase agreement with a 10.25% return on equity (ROE) and a transmission agreement with an 11.27% ROE. In April 2012, Golden Spread filed a complaint with FERC, using a single-step DCF analysis to show that SPS’s ROE in both agreements should be reduced to 9.15%. The co-op filed another complaint in July 2013 using more recent data but again asserting the 9.15% ROE.
Xcel and the New England TOs contended that the old, one-step DCF methodology is not valid because of the commission’s June 2014 ruling Opinion 531, which changed its DCF methodology to a two-step process it has long used for natural gas and oil pipelines that incorporates long-term growth rates. The commission issued Opinion 531 on the same day it ordered the hearing proceedings in the Golden Spread complaints. (See FERC Splits over ROE.)
FERC disagreed, saying that both Xcel and the New England TOs misinterpreted the commission’s findings regarding the one-step DCF methodology in Opinion 531. The commission did not find that the one-step DCF methodology was inadequate, FERC said Thursday. “Rather, the commission found that, given the evolution of the electric industry, it had become more appropriate to use the two-step DCF methodology to determine what ROE to set as a public utility’s ROE.”
“That the two-step DCF methodology ‘is preferable to the one-step DCF methodology’ for ultimately setting a public utility’s ROE does not preclude the commission from relying on DCF studies using the one-step DCF methodology” in complaints made prior to Opinion 531, FERC said.
Golden Spread vs. SPS
FERC also disagreed with Xcel’s assertion that Golden Spread’s July 2013 complaint only served to extend the maximum 15-month refund-effective period for its April 2012 complaint. Golden Spread filed the later complaint the day before the first complaint’s refund period expired.
“Golden Spread filed two separate complaints, based on different facts, thereby commencing two separate proceedings,” FERC said. It noted that though both of Golden Spread’s analyses determined a 9.15% figure, this was a median ROE produced from different ranges: 7.51 to 10.59% in 2012 and 6.37 to 11.51% in 2013. Therefore, “we expect the parties in this case to litigate a separate ROE for each refund period,” the commission said.
New England TOs
The New England TOs had cited the use of the single-step DCF as one of their grounds for seeking rehearing of FERC’s orders on two ROE challenges: the commission’s June 2014 order on a December 2012 complaint (EL13-33) and its November 2014 order on a July 2014 complaint filed by a different group of complainants (EL14-86).
Both complaints alleged that the New England TOs’ 11.14% base ROE was unjust and unreasonable.
In addition to dismissing objections to the single-step DCF analysis, the commission also rejected the New England TOs’ argument that the commission erred in EL13-33 because the ROE that the complainants sought to change was already within the commission’s “zone of reasonableness.”
The commission disagreed. “The zone of reasonableness produced by a DCF analysis does not create a zone of immunity for a utility’s ROE. Showing that a utility’s existing ROE is unjust and unreasonable ‘merely requires showing that the commission’s ROE methodology now produces a numerical value below the existing numerical value.’ Therefore, the commission appropriately concluded that [the complainants] made a prima facie showing that New England TOs’ 11.14% base ROE might be unjust and unreasonable.”
The Federal Energy Regulatory Commission gave NorthWestern Corp. its blessing Thursday to issue up to $950 million in securities over the next two years.
The securities include $250 million in equity, $300 million in secured debt and $400 million in unsecured debt. NorthWestern said that the funds received from the issuance would go toward refinancing $150 million in first mortgage bonds in Montana in addition to paying for normal business activities.
FERC approved the issuance although NorthWestern’s 1.73 interest coverage ratio fell below the commission’s 2.0 benchmark. NorthWestern explained that this was because the analysis included interest expenses from $450 million of debt it issued in November 2014 to finance its purchase of 11 hydroelectric plants from PPL Montana but not a corresponding rate increase approved by the Montana Public Service Commission.
Duke Pleads Guilty to Coal Ash Charges, Fined $102 Million
Duke Energy pleaded guilty in federal court last week to nine criminal violations of the Clean Water Act for polluting four major rivers with toxic coal ash. U.S. District Court Judge Malcolm J. Howard accepted the guilty pleas and fined the company $102 million.
The violations stem from coal ash spills or leaches into four rivers from five power plants in North Carolina, including a massive spill into the Dan River last year.
Federal attorneys and company officials reached a plea agreement after negotiations earlier this year, and the pleas and fines signal the end of federal action against the company. Duke still faces charges and fines from North Carolina environmental officials, as well as a shareholder suit filed against it in Chancery Court in Delaware.
Suit Alleges Duke Board Members Leaned on NC Regulators on Ash Issue
A shareholder suit against Duke Energy alleges that the company’s board of directors lobbied North Carolina environmental regulators to limit the company’s legal exposure from coal ash spills. The suit has been sealed in an agreement between both the shareholder filing the suit, Judy Mesirov of Philadelphia, and the company. But according to some of the unsealed documents, Mesirov alleges that some Duke executives and board members exposed the company to billions of dollars in liability because of their actions.
Duke has been battling legal claims since a massive coal ash spill polluted the Dan River last year. The company reached a $102 million settlement with federal authorities related to the incident but faces state charges related to groundwater contamination stemming from other ash spills.
FirstEnergy is closing the largest coal ash dump in the U.S. — Little Blue Run in Beaver County, Pa. — and is now looking for a place to dispose of the 2.5 million tons of coal ash produced by its Bruce Mansfield plant in nearby Shippingport, Pa.
It has two sites selected so far, but both require transportation of the ash by barge on the Ohio River. FirstEnergy is seeking permits from the Pennsylvania Department of Environmental Protection to let it use a now-closed ash dump at the retired Hatfield’s Ferry coal plant as an interim measure.
The company is under a consent order to close the Little Blue Run site by the end of 2016, partly because of toxins leaching out of the site and into ground and surface water.
Entergy’s Arkansas Nuclear One Garners Lowest Marks in NRC Review
Entergy’s Arkansas Nuclear One in Russellville was ranked near the bottom in the Nuclear Regulatory Commission’s annual operations safety review, the agency said recently. The ranking was the result of “a significant decline in plant performance,” NRC said.
That included a fatal accident in 2013 and a series of flaws with the plant’s flood-control systems that turned up during an NRC inspection.
The commission has allowed the plant to continue operations because it has seen improvement, an NRC official said. “The NRC does believe that the plant can operate safely and therefore they have not been asked to shut down. They have demonstrated sustained improvement so far with making corrective action to some of these issues that we’ve discussed.”
North Dakota Co-op Gets $12.5 Million for Tx Lines
The U.S. Department of Agriculture awarded Slope Electric Cooperative a $12.5 million loan to expand its electrical transmission system in western North Dakota. The money will go toward building 66 miles of power lines in Adam, Bowman, Hettinger and Slope counties. The co-op also received a $431,600 grant for smart grid projects.
We Energies’ Plan to Invest More in Coal Plant Draws Criticism
We Energies has applied to the Wisconsin Public Service Commission to spend about $100 million to upgrade coal handling and storage at its Oak Creek coal-fired station, saying it could save customers $16 million to $25 million a year. The upgrades would allow the 10-year-old plant to use softer, cheaper Wisconsin-mined coal, leading to fuel savings that would be passed on to customers.
The Citizens Utility Board and Clean Wisconsin objected, saying the softer coal would produce more emissions.
“At a time when the state of Wisconsin must develop a plan for cost-effective carbon dioxide emission reductions, We Energies is proposing to significantly increase CO2 emissions,” said Katie Nekola of Clean Wisconsin. “In its short-sighted pursuit of fuel cost savings, the utility ignores the long-term costs of increasing CO2 output, both to ratepayers and the environment.”
Consumers Energy Retiring ‘Classic Seven’ Coal Plants
Consumers Energy is retiring 32% of its generation fleet by April 2016 in an effort to reduce emissions and increase sustainability. “These plants, which we call our ‘Classic Seven,’ have provided reliable, affordable energy for Michigan residents for decades, but it doesn’t make economic sense to spend more to keep them running,” said David Mengebier, Consumers Energy’s senior vice president for governmental and public affairs.
The company announced the plant retirements in its Accountability Report, in which it says that since 1998 it has reduced particulate emissions at its plants by 91%, nitrous oxide by 78%, sulfur dioxide by 53%, mercury by 28% and carbon by 13%. The only U.S. utility closing more coal plants is AEP Ohio.
Allete Buying 100-MW Wind Farm in Pennsylvania from AES
Allete Clean Energy is buying a 100-MW wind farm in Troy, Pa., from AES for $108 million, plus an undisclosed amount of existing debt. Armenia Mountain Wind is near the New York-Pennsylvania border and has 67 1.5-MW turbines that were installed in 2009. The facility’s output is sold through power purchase agreements that expire in 2025. Allete, which owns six wind farms, bought three of them from AES. Armenia Mountain is the largest in its portfolio.
DTE Energy is building Michigan’s largest solar panel array outside of Ann Arbor. The 1.1-MW facility, with 4,000 photovoltaic panels, will produce enough electricity to power 185 homes, according to the company.
DTE has already received approval from Ann Arbor Township to build on the 8-acre site. When completed later this year, it will join nearly 9 MW of solar generation the company has in 22 sites in the state. The company is investing in renewable energy as a result of a state mandate to obtain 10% of its energy from renewable sources by 2015.
In its first quarterly State of the Market Report for 2015, PJM’s Independent Market Monitor found that market performance was better than in the first three months of 2014, but it identified areas needing attention, including the ability for participants to increase markups in tight market conditions and flaws in the capacity market.
PJM’s response detailed how the polar vortex and winter storms of 2014 tested the reliability of the grid, making apparent the need for some improvements.
“The January 2014 events call attention to many of the recommendations the IMM has made in previous State of the Market Reports regarding performance incentives for capacity resources, the need to enforce annual performance for demand resources and for ensuring as much flexibility as possible regarding generator operating parameters,” PJM said.
Similarly, the Monitor’s report noted that the markets have reflected February’s unusually cold weather.
“PJM markets did work during the extreme conditions, but the experience continues to highlight areas of market design that need improvement,” it said.
For one, it is “more critical than ever” to fix capacity market prices, the Monitor said.
“The underlying capacity market issues have not been addressed,” it said. “For example, uplift remained high in large part as a result of inflexible unit parameters, which were based, in many cases, on inflexible gas supply arrangements; outages were high, performance incentives remain weak, prices in the capacity market remain well below replacement costs and there is no resolution of the disconnect between the incentives facing electric generating units and the incentives facing gas pipelines, which is a barrier to the construction of new pipeline capacity.”
Withholding Concerns
The quarterly review concluded that energy prices generally reflected competitive behavior. But, it said, “the behavior of some participants during the high demand periods in 2014 and 2015 raises concerns about economic withholding.”
“In particular,” the Monitor said, “there are issues related to the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage.”
The fact that January 2014 was so severe, however, makes a quarter comparison difficult to interpret, Market Monitor Joe Bowring said. “It’s important to remember to put things in longer terms, in historical perspective,” he said.
He pointed to the load-weighted average of real-time LMPs as example. The average fell 45.2%, from $92.98/MWh in the first three months last year to $50.91/MWh this quarter. But that is 36.1% higher compared with the same period in 2013, the Monitor noted, as well as higher than the same quarters in 2009-2012.
“Even though prices went down dramatically, they’re really not that low,” Bowring said, also noting that they were higher than 11 of the 16 first quarters since the markets began in 1999.
The decrease in prices over last year is a result of lower fuel prices and demand, along with better grid operations, according to the report.
“Another key point is that markup remains significant. It was higher in terms of percent,” he said. “Markup is an indicator of non-competitive behavior. To the extent that we see markup cropping up, it’s a concern to competitiveness and an important flag for people.”
Meanwhile, total energy uplift charges for the quarter — still high compared with recent years — dropped by $560.6 million to $186.9 million, a 75% decrease, from last year.
Net revenues, while higher than in the first quarter of 2013, were “uniformly lower” compared with last year, which reflects the very high net revenues in January 2014.
Demand Response
The Monitor also touched on the Supreme Court’s upcoming review of an appellate court ruling voiding the Federal Energy Regulatory Commission’s jurisdiction over pricing of demand response in energy markets (Electric Power Supply Association v. Federal Energy Regulatory Commission). The Monitor said the situation “does create an opportunity to rethink the ways in which demand-side resources can most effectively participate in wholesale power markets based on market principles.
“Demand response should be on the demand side of the capacity market rather than on the supply side.”
It went on to say, “Demand resources should be provided a fair opportunity to compete, but demand resources should no longer be provided special advantages inconsistent with competitive markets. This approach would work regardless of the final decision of the EPSA case.”
PJM Releases Annual Report
PJM on Monday also released its 2014 Annual Report. The theme “Anticipate, Adapt, Advance” will be the subject of discussion at the RTO’s annual meeting in Atlantic City this week.
At the New England Energy Conference and Exposition last week, industry experts said there is no evidence that distributed generation is leading to a “death spiral” for traditional utilities.
Rigby
“We know it’s an issue; with time it could unfold very differently. But for now it’s not really affecting utility credit ratings,” said Peter Rigby, global head of Standard & Poor’s risk analytics and research.
Marone
Anthony Marone, senior vice president of customer and business services at UIL Holdings, said that despite state incentives, rooftop solar’s penetration remains small and has not impacted UIL’s business model. But continued growth will create “equity” issues, he said.
“If you have many times the penetration today, you start to create potentially isolated problems on certain circuits or feeders or certain neighborhoods,” Marone said. “If in every neighborhood there were two systems, maybe it’s no problem. But if you all of the sudden have three, now you’ve got to upsize the transformer, or [if] you have to do other things, the question becomes who pays for that? Is it the consumer who installed the generation or is it society as a whole?”
In May 2013, the Federal Energy Regulatory Commission issued Order 779 requiring the North American Electric Reliability Corp. to develop a standard to protect the grid against geomagnetic disturbances caused by solar storms. The commission said it was acting to close a “reliability gap.” (See FERC Orders Rules on Geomagnetic Disturbances.)
For stage two, FERC required NERC to determine the severity of a “benchmark” GMD event — the threshold against which covered entities would evaluate their system’s vulnerability and develop protective strategies.
What is the threat?
GMD events occur when the sun ejects charged particles that can cause changes in Earth’s magnetic fields. A solar particle can reach Earth in 17 to 96 hours.
NERC determines the severity of a GMD based on the “geoelectric field” — the electric potential measured in volts per kilometer on the earth’s surface — a reflection of the rate of change of the magnetic fields.
The geoelectric field acts as a voltage source that can cause geomagnetically induced currents (GICs) to flow on transmission lines. The magnitude of the geoelectric field is impacted by the geomagnetic latitude — the proximity to Earth’s magnetic north and south poles — and the ability of the planet’s crust to conduct electricity hundreds of kilometers down to its mantle. Local earth conductivity impacts the severity of the geoelectric fields that are formed during a GMD event; a lower earth conductivity results in higher geoelectric fields.
What is covered by the standard?
The standard would apply to planning coordinators, transmission planners, transmission owners and generation owners who own or whose planning coordinator or transmission planning area includes a transformer with a high side, wye-grounded winding connected at 200 kV or higher.
How is the benchmark event defined?
NERC proposed defining the benchmark GMD based on a one-in-100-year frequency of occurrence. Its definition is composed of four elements: (1) a reference peak geoelectric field amplitude of 8 V/km; (2) a scaling factor to account for local geomagnetic latitude; (3) a scaling factor to account for local earth conductivity; and (4) a reference geomagnetic field time series or wave shape to allow analysis of the impact on equipment.
The benchmark estimates that a one-in-100 year GMD event would cause an 8 V/km reference peak geoelectric field at Québec’s geomagnetic latitude and earth conductivity.
The 1989 solar storm that caused the collapse of the Hydro- Québec grid illustrates the potential risk. Shortly before 3 a.m. ET on March 13, 1989, a large impulse in the geomagnetic field was detected near the U.S.-Canada border. That started a series of disturbances that brought down the grid serving Montreal and the rest of Québec within about 90 seconds. The storm also caused large disturbances in the U.S., damaging some transformers severely — including one at the Salem nuclear plant in New Jersey — and nearly knocking out PJM and transmission systems from New England to the Midwest.
NERC’s standard drafting team “spatially averaged” four different station groups of data from Northern Europe, each covering a square area about 500 km wide (310 miles). The team noted that the reliability standard is designed to address wide-area effects caused by a severe GMD, such as increased volt-ampere reactive (var) absorption and voltage depressions.
“Without characterizing GMD on regional scales, statistical estimates could be weighted by local effects and suggest unduly pessimistic conditions when considering cascading failure and voltage collapse,” NERC said.
NERC used scaling factors to adjust the 8 V/km value for different geomagnetic latitudes and earth conductivities.
What is required by the proposed standard?
The proposed standard has seven requirements:
Planning coordinators and transmission planners must determine their responsibilities for maintaining models and performing studies needed to complete the GMD vulnerability assessment specified in Requirement 4.
Planning coordinators and transmission planners must maintain system models and GIC system models needed to complete the GMD vulnerability assessment.
Planning coordinators and transmission planners must have criteria for acceptable system steady state voltage limits for their systems during the benchmark GMD event.
Planning coordinators and transmission planners must conduct a GMD vulnerability assessment every 60 months based on the benchmark GMD event.
Planning coordinators and transmission planners must provide GIC flow information for use in the transformer thermal impact assessment (Requirement 6) to each transmission owner and generator owner that owns an affected transformer within the planning area.
Transmission owners and generator owners must conduct thermal impact assessments on affected transformers where the maximum effective GIC value provided in Requirement 5 is 75 amperes per phase (A/phase) or greater.
Planning coordinators and transmission planners must develop corrective action plans if the GMD vulnerability assessment concludes that the system does not meet the performance requirements.
The Federal Energy Regulatory Commission on Thursday conditionally accepted the interregional transmission planning and cost allocation proposals by ISO-NE, NYISO and PJM (ER13-1957et al), completing the commission’s initial review of all of the interregional compliance filings required under Order 1000.
FERC found that the three regions complied with its requirement that neighboring transmission planning regions propose a common interregional cost allocation method by agreeing on the use of an avoided-cost method. As permitted by Order 1000, they proposed to apply their avoided-cost allocation to all selected interregional transmission facilities, rather than having separate interregional cost allocation methods for different types of interregional projects.
FERC said the filing conformed to its requirement that interregional cost allocation methods address regional reliability and economic needs as well as transmission needs driven by public policy requirements.
The commission previously ruled that an avoided-cost method was not permissible as the sole cost allocation method for regional transmission projects because it would “not allocate costs in a manner that is at least roughly commensurate with estimated benefits because it does not adequately assess the potential benefits provided by that transmission facility.”
However, it concluded that an avoided-cost only method is permissible for interregional transmission.
“We find that the interplay between the regional transmission planning and interregional coordination requirements of Order No. 1000 address, at the interregional level, the commission’s concerns regarding use of the avoided-cost only method at the regional level,” it wrote.
The commission rejected avoided-cost-only allocation for regional projects because a regional facility that resulted in a more cost-effective transmission solution than what was included in the roll-up of local transmission plans would not be eligible for regional cost allocation if there was no transmission facility in the local transmission plans that it would displace.
In contrast, the commission said it believed “there will be regional transmission facilities identified in the regional transmission planning process that are needed to meet transmission needs driven by reliability, economic and/or public policy requirements that potential interregional transmission facilities may displace.”
The filing updated the Northeastern Protocol, which the three regions adopted in 2004 to facilitate the exchange of information and establish a committee structure for the coordination of interregional planning. The Joint ISO/RTO Planning Committee, comprised of staff representatives from the regions, will be charged with evaluating interregional transmission solutions with input from the Interregional Planning Stakeholder Advisory Committee, which is open to stakeholders.
The commission required the regions to make only minor ministerial changes in compliance filings due in 60 days.
GROTON, Conn. — Robert Ethier has a dream: A day when ISO-NE no longer needs constant stakeholder meetings to tweak its market rules.
Ethier
“We’ll know when we’ve hit on the right market design when we don’t need to make changes to accommodate the changes in the fundamentals,” Ethier, vice president of market operations for ISO-NE, said during a panel discussion at the New England Energy Conference and Exposition last week. “A good, stable, robust market design should adapt to pretty much whatever you can throw at it.”
Ethier said that although New England’s market has work to do to improve demand-side response and integrate the dispatch of wind, it has made progress over the last decade.
“The market is being driven much more by the fundamentals and by policy than by market design. … These markets are really being driven by the larger forces that are changing our economy — changes in fuel prices, changes in technology, changes in policy needs and desires. And that’s really what ought to be driving the markets. It shouldn’t be the market design that’s dominating the discussion.
“I hesitate to say this but I almost think we can see the day when the rate of change in the markets really decreases because the markets have the flexibility they need to react to whatever gets thrown at them,” he said.
