WASHINGTON — The Federal Energy Regulatory Commission on Thursday gave preliminary approval to the second stage of its reliability standard to protect the grid from geomagnetic disturbances.
The commission’s Notice of Proposed Rulemaking (NOPR) would require grid operators to assess the vulnerability of their systems to a “benchmark” GMD event, which the North American Electric Reliability Corp. defined as a one-in-100-year occurrence. The standard (TPL-007-1, Transmission System Planned Performance for Geomagnetic Disturbance Events) would require planning coordinators and transmission planners to conduct the vulnerability assessments every five years. Entities that don’t meet performance requirements based on the assessments would be required to develop corrective plans to bring them into compliance (RM15-11).
NERC said mitigating strategies could include installation of hardware such as geomagnetically induced current (GIC) blocking or monitoring devices, equipment upgrades, training and operating procedures.
GMDs caused by solar storms are “high impact, low frequency” events. While the probability of a severe disturbance is low, it could have a severe impact on the grid, resulting in widespread blackouts and damage to equipment that could result in sustained system outages, FERC said.
Developing a GMD standard is “difficult work because we are working on a reliability threat that is not fully understood and as to which actual data are not readily and consistently available,” Commissioner Cheryl LaFleur said.
FERC ordered NERC to make changes to the proposed standard, including refining its definition of the benchmark event; requiring installation of monitoring equipment where there are gaps; and setting deadlines for completion of corrective actions. It also said it was considering shortening NERC’s proposed five-year period for full compliance.
Benchmark Event
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The commission said it was concerned with NERC’s “heavy reliance” on spatial averaging — averaging impacts based on a square area 500 km in width — for the definition of the benchmark event.
“The geoelectric field values used to conduct GMD vulnerability assessments and thermal impact assessments should reflect the real-world impact of a GMD event on the bulk power system and its components,” FERC wrote. “A GMD event will have a peak value in one or more location(s), and the amplitude will decline over distance from the peak. Only applying a spatially averaged geoelectric field value across an entire planning area would distort this complexity and could underestimate the contributions caused by damage to or misoperation of bulk-power-system components to the system-wide impact of a GMD event within a planning area.
“However, imputing the highest peak geoelectric field value in a planning area to the entire planning area may incorrectly overestimate GMD impacts. Neither approach, in our view, produces an optimal solution that captures physical reality.”
As an alternative, FERC said NERC could require entities to conduct GMD vulnerability assessments and transformer thermal impact assessment using both the spatially averaged reference peak geoelectric field value (8 volts per kilometer) and the peak geoelectric field value of 20 V/km as identified in NERC’s 2012 GMD report (“Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System”). Entities would be required to take corrective actions, using engineering judgment, based on the results of both assessments.
“That is, the applicable entity would not always be required to mitigate to the level of risk identified by the non-spatially averaged analysis,” FERC said. “Instead, the selection of mitigation would reflect the range of risks bounded by the two analyses and be based on engineering judgment within this range, considering all relevant information.”
Defining the benchmark event is essential to the standard, LaFleur said, “because if you don’t get the benchmark right, you’re not protecting against the right thing.”
Transformers
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The commission also ordered NERC to answer why it would not require qualifying transformers to be assessed for thermal impacts using the “maximum GIC-producing orientation,” saying it was concerned this could underestimate the impact of a benchmark GMD event.
“These concerns reflect in part the difficulty of replacing large transformers quickly, as reflected in studies, such as an April 2014 report by the Department of Energy that highlighted the reliance in the United States on foreign suppliers for large transformers,” FERC wrote.
LaFleur called for a strategy to allow quicker replacement of damaged transformers. “Those types of efforts will not just help the grid in its resilience to solar storms but against other risks such as physical security, cyber threats and major storms of all types,” she said.
Monitoring Devices
The commission said it also intends to change the standard to require installation of GIC monitors and magnetometers to fill any gaps in existing monitoring networks to ensure more complete data for planning and operational needs.
“To be clear, we are not proposing that every transformer would need its own GIC monitor or that every entity would need its own magnetometer,” FERC said. “Instead, we are proposing the installation and collection of data from GIC monitors and magnetometers in enough locations to provide adequate analytical validation and situational awareness.”
LaFleur noted that monitoring equipment is more widely available in other parts of the world than in the U.S. (NERC’s standard drafting team used field measurements from the magnetometer chain in Northern Europe in defining the benchmark event.) “That should not be the case,” she said.
The commission invited comment on whether it should adopt a policy governing recovery of the costs of the monitoring equipment.
‘Scaling’ Factor
The commission asked for comment on whether the impact of the “scaling” factor used in the benchmark GMD event definition to account for differences in geomagnetic latitude should be reduced. It noted studies indicating that GMD events “could have pronounced effect on lower geomagnetic latitudes.” For example, 12 transformers were reportedly damaged and taken out of service as a result of a 2003 GMD event in South Africa at -40 degrees magnetic latitude.
Deadlines
FERC also was dissatisfied that the proposed standard did not establish deadlines for developing or implementing corrective action plans. It said it plans to require corrective action plans to be developed within one year of the completion of the vulnerability assessment.
The commission also asked for comment on whether NERC’s proposed five-year implementation period could be shortened. NERC proposes a phased, five-year implementation period to allow time for entities to develop the required models, conduct vulnerability assessments and develop corrective action plans.
Comments on the NOPR are due 60 days after publication in the Federal Register.
Creditors of the 55-MW Fibrominn power plant — the first in the U.S. designed to burn poultry litter as its primary fuel — have won federal approval to gobble up the Minnesota facility from receivership.
The Federal Energy Regulatory Commission ruled Thursday that the transfer of the plant to Benson Power from owner PowerMinn is in the public interest (EC15-76).
Benson Power was formed to acquire and operate the plant and has no other FERC-jurisdictional or power-related assets. Benson is owned by CPV Biomass and several insurance companies that provided $202 million toward its construction. They include Prudential, The Hartford, John Hancock Life Insurance, Nationwide and Metropolitan Life.
The output of the Fibrominn plant will continue to be sold to Northern States Power under an existing 21-year long-term power supply contract.
The plant, located in Benson, Minn., was lauded after its 2007 opening for its practical use of waste from the region’s abundant turkey and chicken farms.
But it has struggled in recent years. Bird flu has reduced supplies of the odiferous biomass it turns into megawatts. The plant has had to turn to other bio material, such as wood chips.
Also making the plant less competitive are the drop in natural gas prices and improving economics for wind and solar energy. Two years ago, Fibrominn began defaulting on debt.
FERC found that the transfer of the plant will not result in adverse effects on competition or rates, nor inappropriate cross-subsidization of a non-utility asset. The commission said Class B and Class C members — largely consisting of the insurance companies — hold only a passive interest.
The insurance companies have indirect interests in other power ventures. Prudential, for example, has non-controlling interests in the 150-MW Elk River Wind Farm in Kansas. And Metlife has a stake in operations including the 32-MW Long Island Solar Farm.
The Class A holder, which will serve as sole management member of the plant, is CPV Biomass, which is owned by Silver Spring, Md.-based Competitive Power Ventures.
FERC said CPV does not own or control other generation in the MISO territory.
However, the former owners of PowerMinn’s parent company, the Herrick family, cried foul. They filed a motion to intervene in the transfer application, contending that they are owed payments related to production tax credits involving the plant. They expressed concern that their rights could be extinguished by the transaction.
But FERC ruled that the Herrick protest was outside of the scope of the proposal before the commission.
Future Viability?
As of January, the plant owed creditors nearly $240 million, while its fair market value was under $79 million. The application filed with FERC does not elaborate on the strategy Benson will take to improve the plant’s viability.
While designed to burn poultry litter for up to 90% of its fuel needs, the plant has relied mostly on more expensive wood chips. The Minnesota bird flu crisis has reportedly resulted in the deaths of nearly 4.2 million turkeys and nearly 1.6 million chickens since March.
Major poultry producers are making deliveries “when they can” from uninfected farms, the plant’s manager told the Associated Press.
Donald Atwood, a CPV vice president, told the AP his company has a multi-year contract to manage the facility for the note-holders.
“I don’t know what the lenders have in mind for the future,” Atwood said, adding that he expects to continue to burn poultry litter.
“We’ll adjust our fuel percentages based on market conditions,” he said. “I’m highly confident that the project will be successful.”
GROTON, Conn. — States and federal regulators need to keep consumers in mind when picking jurisdictional fights over control of the electric industry, Federal Energy Regulatory Commissioner Tony Clark said last week.
Clark
“We can’t have a war between FERC and the states on some of these issues and get consumers stuck in the middle,” he said in a keynote speech to the New England Energy Conference and Exposition on Wednesday.
“There has been an almost soft form of reregulation in parts of the market. We should acknowledge that that’s happening. We should also acknowledge that that may have an impact on other goals,” he said.
“We don’t want to be caught in the worst of all worlds, which in my mind is having just high enough capacity prices where we get everybody pretty darn well mad at us — we’ve got the congressional delegations mad at us; we’ve got governors mad at us; we’ve got consumer advocates made at us — and yet at the same time [the prices are] set at such a point that they may be being undermined by other things that are going on, so you’re not getting the investment that those prices would otherwise encourage because you have other state or local public policies that are undercutting that or maybe suppressing prices in some way.”
In addition, federal courts have been refereeing jurisdictional fights. Courts have struck down on constitutional grounds efforts by Maryland and New Jersey to sign contracts with new generators. (See Supreme Court Agrees to Hear Demand Response Appeal.)
And FERC Chairman Norman Bay has warned states seeking to implement rights of first refusal on transmission development that they may be interfering with interstate commerce. (See FERC Rejects Rehearing Request on SPP Order 1000 Filing.)
Clark pleaded for a cease fire. “There’s plenty of tools that FERC has and there’s plenty of tools that states have to go to war with each other,” he said. “In my mind it’s … a game you can’t win. So you can’t play it.”
Clark also talked about the commission’s unenviable role regarding the Environmental Protection Agency’s proposed Clean Power Plan.
“It’s not our rule,” he said. “And yet just about every potential negative impact that folks have brought up are things that are squarely within FERC’s wheelhouse. Whether it’s related to the need for infrastructure siting because of the push towards natural gas; whether it’s potential market issues that come up at the seams in markets …; whether it’s reliability issues, which in certain regions of the country we’re very concerned about — all of those are squarely within FERC’s wheelhouse.
“So whether we want the issue in front of us or not, the issue wants us.”
Eversource Energy customers will see a 35% drop in electric generation charges, to 8.228 cents/kWh from 12.629 cents/kWh beginning in July.
United Illuminating residential generation charges will decrease about 31% to 9.18 cents/kWh from 13.3108 cents/kWh.
For a typical customer who uses 750 kWh, the drop in generation prices will save more than $30 a month. The rates go into effect July 1 and last until Dec. 31.
New Haven officials and the current owners of the defunct English Station power plant want UIL Holdings to pay for a large share of the plant’s cleanup. Uri Kaufman, a representative for Asnat Realty of New York and Wilmington, Md.-based Evergreen Power, appeared before state utility regulators to comment during a hearing on the proposed $3 billion acquisition of UIL Holdings by Spanish energy giant Iberdrola.
Kaufman urged the Public Utilities Regulatory Authority to require the two merger partners to create a $60 million fund to pay for the cleanup of English Station, which sits on a 9-acre island in the Mill River. The site is riddled with carcinogens, heavy metals and other contaminants. United Illuminating, a UIL Holdings subsidiary, closed the plant in 1992 and paid Quinnipiac Energy of Killingworth $4.25 million in 2000 to assume ownership of the power plant and put $1.9 million in escrow to pay for cleanup.
Release of Trove of Emails Results in Another Public Hearing for Refinery
The Department of Natural Resources and Environmental Control extended a comment period until June 9 on proposed water use and wastewater permits for the Delaware City Refinery after previously undisclosed emails and records were released. The refinery still uses a 1950s-era system of withdrawing cooling water from the Delaware River and discharging wastewater that environmentalists say causes huge losses of aquatic life. PBF Energy, the refinery’s owner, says that upgrading the cooling system would cost $300 million, more than the purchase price of the facility.
In addition to the records that were released, the state denied a request from The News Journal for several hundred more documents, citing confidentiality rules. They include communications sent from Gov. Jack Markell’s office and his private email accounts.
“It appears if you want to secretly work out a deal on environmental issues in Delaware without any public input, the best approach may be to first break the law, and then negotiate secretly for what you want with the assurance that the public cannot be informed or involved,” said Dave Carter, conservation chair for Delaware Audubon.
Pence Signs New Energy Bill Releasing Utilities from Mandates
Pence
Gov. Mike Pence signed a new energy efficiency law that allows utilities to set their own conservation goals, rather than making them meet state mandates. The law also allows utilities to charge ratepayers to fund the programs. Environmentalists say the law, with its less-stringent oversight, will make it harder to attain Environmental Protection Agency-mandated emissions reductions.
The Utility Regulatory Commission rejected Duke Energy’s plan to upgrade its grid at a cost to ratepayers of $1.9 billion over the next seven years. Duke’s customers would have experienced a 1% rate increase each year, from 2016 through 2022. Ratepayer advocates said Duke’s plan contained provisions not covered by the 2013 grid modernization investment recovery law, such as $48 million for vegetation management, a $1.5 million customer contact computer program and a $177 million smart meter program.
Duke said it would file a revised plan. “We’re still reviewing the order and considering our options, but we remain committed to making critically needed investments to modernize our system for the benefit of our customers,” the company said in a statement. “This is one of the first times this new law has been interpreted, and it’s being clarified for all Indiana utilities at the commission and in the Indiana Court of Appeals.”
Chinese Company Building 28-MW of Wind Energy Plants
HZ Windpower, a wind energy subsidiary of China Shipbuilding Industry Corp., is planning to build 28 MW of wind facilities in the state. Lt. Gov. Kim Reynolds met with HZ Windpower executives last week and said the 14 2-MW turbines could be the first of many more for the state.
The turbines will be part of the “Community Wind” projects and will be in Creston, Dyersville, Mason City and Perry.
Canada Pledges to Cut Emissions by 30% by 2030, Still Behind US Goal
Aglukkaq
Canada announced it has set a goal to cut greenhouse gas emissions by 30% by 2030 and said it will set new regulations for various industries, including electric generation. A 30% reduction compares to the stated U.S. goal of 26% to 28% by 2025. Both countries are submitting their emission-reduction goals to the U.N. for a climate change agreement due to be signed in December in Paris.
“Canada’s ambitious new target and planned regulatory actions underscore our continued commitment to cut emissions at home and work with our international partners to establish an international agreement in Paris,” said Leona Aglukkaq, Canadian Environment Minister.
A bill that encourages the development of community solar projects was signed by Gov. Larry Hogan last week. The bill creates a three-year pilot program allowing community solar projects and will collect information on the projects and determine their impact on the state.
Community solar projects allow multiple owners to invest in a large-scale solar project and offset a portion of their electric bill with a share of the renewable power. Until now, such large projects were mostly the domain of utilities and investment companies.
Enbridge Agrees to $75 Million Settlement on Kalamazoo Spill
Enbridge has agreed to pay $75 million to settle legal claims related to a 2010 pipeline spill of more than a million gallons of crude oil into the Kalamazoo River. About $30 million will be spent on wetland and river restoration. The agreement, between the company and the state Department of Environmental Quality, also includes removing a dam on the river and improving recreational access on the river.
The company spent more than $1 billion in cleanup costs, but state officials acknowledged that not all of the oil residue was collected. The spill of heavy crude oil extracted from Canadian oil sands affected nearly 40 miles of the river and more than 4,000 acres along the river banks.
The company has yet to settle penalties with the Environmental Protection Agency. It paid a $3.7 million fine imposed by the National Transportation Safety Board for lax safety management.
State Gives Thumbs-up to Loop Line’s Early Completion
ITC Holdings has completed the third and final phase of its 138-mile “Thumb Loop” 345-kV line in the state about six months ahead of schedule. The line, capable of supporting capacity of up to 5,000 MW, wasn’t expected to be completed until late this year.
ITC said the loop line will meet the maximum identified wind energy potential in the state’s Thumb region as well as boosting regional system reliability and wholesale market competition. Gov. Rick Snyder has pointed to the line’s benefits in helping agricultural processing operations and for bringing more renewable energy to the grid.
Phase 3 comprises 56 miles of line in Huron and Sanilac counties and the Banner substation, near Sandusky. The original phase, begun in 2011, was 62 miles of lines and two substations in Tuscola and Huron counties. Phase 2 involved 20 miles of lines and substations in St. Clair and Sanilac Counties.
Lawmakers Ponder Cutting Solar Subsidies; Company May Fail
A solar cell manufacturer that failed to meet a hiring goal that was a condition of getting state loans could go out of business if state support is cut. Silicon Energy of Mountain Iron failed to hire the 25 solar panel production jobs it promised when it began getting the first of two loans totaling about $7 million. It has 11 workers now. A bill that passed the House would strip the subsidies.
“The Made in Minnesota solar program is a very expensive way to reduce pollution and create jobs,” Republican state Rep. Pat Garofalo said. Silicon Energy President Gary Shaver said low-cost solar panels from China “destroyed the market for us.”
Results of a two-year experiment with 400 customers of the New Hampshire Electric Cooperative will be announced soon. The distribution company that serves 80,000 customers in the central part of the state tested three new models for pricing electricity using smart meters.
Customers were divided into three groups: one remained on the standard rate per kilowatt-hour paid by all members of the co-op but with an in-home display that showed how much power was being used at any time of day in the home. The second group was on a “time of use” rate, with lower rates for off-peak hours, higher rates for peak hours and variations for each season. The third group had lower on-peak and off-peak rates but was charged a “critical peak rate” on the hottest days of the year, when system demand in New England was at its highest.
The experiment ran from November 2012 to November 2014. Thus far the results confirmed that the more information consumers get about their electricity usage, the less they use. A report will be issued in the summer.
A renewable energy fund is facing a cut of $50 million by legislators. A House bill seeks to slash that funding as part of an effort to make up for shortfalls in other areas of the budget. Currently, the fund provides rebates for homeowners and business owners installing solar panels. The fund is financed by utility companies, which must pay into the fund if they fail to buy a mandated number of renewable energy credits.
The Renewable Energy Fund rebate program began about six years ago and pays out an average of $4,300 per installation. The $50 million cut would nearly wipe out the fund’s budget for the next two years. The threat of the cut comes at a time when federal solar tax credits are falling from 30% to 10%, further squeezing the state’s new solar industry.
“New Hampshire has huge untapped potential,” said Kate Epsen, executive director of the New Hampshire Sustainable Energy Association. “People are trying to position themselves strategically.”
A state Senate committee passed a resolution calling for Congress and President Obama to reinstate the production tax credit for wind energy. The resolution now goes to the Senate for a vote. The production tax credit provided incentives for wind energy production but expired at the end of 2013. Supporters of the resolution said its expiration “wreaked havoc” in the state’s wind energy industry.
The state has been wrestling with wind energy issues for years. Most recently, the Board of Public Utilities rejected a proposed offshore wind farm that had been awarded $47 million in federal funding as too costly. In response, the state Senate passed a bill forcing the BPU to approve the project. The project still has not gained final approval.
Gov. Andrew Cuomo’s administration released an environmental review that is the penultimate step for a ban on hydraulic fracturing for natural gas in New York. The state Department of Environmental Conservation released a final version of the roughly 2,000-page document, known as the Supplemental Generic Environmental Impact.
“The final SGEIS is the result of an extensive examination of high-volume hydraulic fracturing and its potential adverse impacts on critical resources such as drinking water, community character and wildlife habitat,” DEC Commissioner Joseph Martens said in a statement. “We considered materials from numerous sources, including scientific studies, academic research and public comments, and evaluated the effectiveness of potential mitigation measures to protect New York’s valuable natural resources and the health of residents.”
Last December, the Cuomo administration announced it would ban high-volume fracking, citing concerns about its impacts on human health.
Entergy, the owner of the Indian Point nuclear plant, is planning to clean up several thousand gallons of oil that may have spilled into the Hudson River after a transformer exploded May 9. A fire suppression system extinguished the fire, but the plant shut down, according to a spokesman for the U.S. Nuclear Regulatory Commission.
The fire didn’t cause the release of any radiation and didn’t pose a threat to workers or the public, according to a statement on Entergy’s website. The nuclear plant is just 50 miles from midtown Manhattan.
McAuliffe Announces New Energy Efficiency Goals for State
Gov. Terry McAuliffe announced ambitious energy efficiency goals for the state, vowing to reduce consumption by 10% by 2020, two years earlier than the previous goal. He also announced the formation of a new group, the Executive Committee on Energy Efficiency, to help the state attain the goal.
Some studies show Virginia lagging behind other states in energy efficiency programs. Dawone Robinson of the Chesapeake Climate Action Network applauded McAuliffe’s plan. “Increasing energy efficiency is our lowest-hanging fruit when it comes to reducing the carbon emissions fueling severe weather and sea level rise,” he said.
Enbridge Plans to Bolster Oil Sands Pipeline Slowed By Zoning Board
A local zoning board in Dane County has held up plans by energy giant Enbridge to triple the capacity of a crude oil pipeline from northern Wisconsin to markets east in Chicago. The six-year-old pipeline, known as Line 61, delivers oil extracted from Canadian oil sands and would carry more crude oil each day than the proposed Keystone XL pipeline.
The Dane County Zoning and Land Regulation Committee told Enbridge it would need more pipeline insurance before it would consider granting the request to increase capacity. Enbridge says it has enough insurance already and argued that the zoning board is overstepping its authority by taking on responsibilities of federal regulators.
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.
