Kinder Morgan has scaled back a natural gas pipeline proposed for New England, but the changes will have little effect on the overall project to supply power plants and home-heating utilities.
Kinder Morgan filed an updated plan with the Federal Energy Regulatory Commission on June 2 for its Northeast Energy Direct project, saying it was eliminating local laterals and related facilities due to the inability to sign up utilities to support those spurs. “We just don’t have the customers,” Allen Fore, vice president of government affairs at Kinder Morgan, told TheBoston Globe.
The pipeline is planned to run from New York through northern Massachusetts, cut into New Hampshire and return to Massachusetts, where it will terminate in Dracut.
Kinder Morgan, the parent of project developer Tennessee Gas Pipeline, said it is eliminating a nearly 15-mile spur through seven Massachusetts towns and a 1-mile spur in Connecticut, along with a new meter station and modifications at three existing stations.
Remaining in the project are 37 miles of laterals running off the main line, which will mostly follow existing rights-of-way.
“This revised scope, which will be reflected in Tennessee’s next draft environmental report filing, will allow Tennessee to meet the needs for all the shippers that have executed binding precedent agreements for the project,” the company wrote (PF14-22).
The pipelines are controversial because they would import fracked shale gas from Pennsylvania and be funded by utility ratepayers. (See New England Governors Revise Energy Strategy.)
Kinder Morgan said the pipeline could bring more than 2 billion cubic feet of natural gas per day into the region. It plans to file a second draft of its environmental report next month and a final pipeline application with FERC in October.
Transmission developer LS Power Transmission is protesting Order 1000 compliance filings by NYISO, SPP and ISO-NE, saying they still favor regulated incumbents over independent developers. NextEra Energy also filed a protest in NYISO’s docket.
The protests, submitted last week, are to compliance filings the three regions made in response to Federal Energy Regulatory Commission orders in April and May.
LS Power praised NYISO for its handling of the stakeholder process, saying it was an “open dialogue that actually valued the exchange of ideas, rather than a perfunctory process, for process sake, that occurred in some regions that oppose Order No. 1000 at the regional planner level.”
It said its protest to the ISO’s developer agreement is limited to “sections that provide no ratepayer benefit but that have the potential to substantially increase costs either through increased financing costs or through a significant mismatch to the obligations undertaken by incumbent transmission owners proposing regulated backstop solutions.”
“Because both regulated and alternative projects will be evaluated against each other under the Order No. 1000 compliant process, it is important that the developer agreement impose no more stringent obligations on the developer of an alternative regulated solution than are imposed on incumbent transmission developers,” it wrote (ER13-102-007).
NextEra said the agreement burdens alternative developers without guaranteeing faster project completion. It said the deadlines within the agreement do not reflect the reality of project development schedules and that NYISO should not be given latitude to terminate a project agreement when the project is faced with obstacles beyond the developer’s control.
It said competitive bidders should only be disqualified if the only feasible route would alter an incumbent transmission owner’s use and control of its existing right of way and law or regulation prevents use of alternatives to those rights-of-way (ER13-366).
ISO-NE
In New England, LS Power said ISO-NE failed to delete certain language as ordered by FERC following its second compliance order from 2013 regarding backstop transmission solutions (ER13-193).
New York state is proposing to invest $1.5 billion in large-scale renewable energy development over the next decade under a revised procurement strategy to reduce costs.
Without a federal production tax credit, NYSERDA’s current 20-year REC contracts for wind result in a $33/MWh premium to market prices. The premium could be reduced to about $18/MWh using utility-backed PPAs with a developer that has a relationship with a YieldCo. Utility-owned generation is estimated to have a premium of less than $27/MWh.
The New York State Energy Research and Development Authority made the proposal in a report released early this month. “The current approach has been good, but we can do better,” said Richard Kauffman, the state’s chairman of energy and finance.
Unlike most state renewable portfolio standard programs, which delegate renewable purchases to utilities, New York designated NYSERDA to act as a central procurement agency.
NYSERDA said the $1.5 billion investment is comparable to the state’s spending since it created its RPS in 2004. The programs have led to the construction of 1,900 MW of clean generation, although the RPS goal of 29% for this year will not be met.
A 32-MW project on Long Island is the only large-scale solar project in the state, according to the Long Island Power Authority. The American Wind Energy Association says New York had 1,749 MW of installed wind capacity at the end of 2014.
The report recommends several new strategies that it said would allow it to obtain renewable resources at lower costs, optimize siting of projects and extend benefits to customers.
It said long-term bundled power purchase agreements would provide developers predictable revenue streams, allowing them to obtain cheaper financing and reducing the levelized cost by at least $11/MWh. Securitizing debt and opening projects to financing vehicles such as “YieldCos” — publicly traded companies formed to own operating assets that produce a predictable cash flow — could reduce costs further.
It also invited comment on whether utilities should be permitted to bid against other developers for renewable projects, saying the competition could also reduce costs.
Procurements should take into account not just price, the report said, but also plant retirements, price forecasts and integration with storage and demand response to ensure projects are sited where they provide the greatest system and customer benefits.
It called for ways to address insufficient demand volumes, contract durations and credit supports that it said had crimped voluntary renewable purchases.
A 10-year budget commitment of $1.5 billion would stimulate investment and help renewables become self-sustaining without subsidies.
The report was filed in response to a Feb. 26 New York Public Service Commission order laying out the role of renewables under the Reforming the Energy Vision overhaul of the state’s energy industry. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
The PSC will hold a technical conference to discuss the report, with initial public comments due July 22.
The Federal Energy Regulatory Commission last week denied rehearing in a challenge to PJM’s method of funding Financial Transmission Rights, closing a docket that had been in limbo for almost two years — and potentially clearing the decks for a unilateral rule change proposal by the RTO.
FirstEnergy had requested removal of real-time congestion costs from the calculation of transmission congestion charges, saying it would allow FTR holders to better hedge congestion.
“We continue to find that allocation of real-time balancing congestion to current FTRs has a reasonable basis, because FTR holders are in the best position to reflect the associated underfunding in the value of FTRs,” the commission wrote. “Allocation to other parties would not create any incentive to reduce real-time balancing congestion and would provide even less of an ability to provide any reflection of the value of the underfunding in any instrument.”
The commission gave no reason for the timing of its ruling (EL13-47-001) on the rehearing request, which was filed by FirstEnergy, J. Aron & Co., DC Energy, Vitol and Public Service Electric and Gas and its affiliates after the commission denied a complaint by FirstEnergy in June 2013.
But it came after just days after PJM suggested it may make a unilateral section 206 filing to break a deadlock among stakeholders over potential rule changes.
PJM’s June 2 filing with the commission noted that the FTR funding shortfall the companies had complained of had been resolved — at least for now, with FTRs fully funded since the current planning year began in June 2014.
PJM said it had addressed underfunding by being more conservative in its annual modelling of Auction Revenue Rights and FTRs, particularly the impact of transmission outages, market-to-market flowgates and loop flow.
“Thus, while FTR underfunding has been resolved for now, the consequence is that customers have experienced reduced ARR allocations,” PJM said. “PJM’s solution has therefore shifted revenues from ARR holders, through a reduction of the quantity of ARRs, to FTR holders, in the form of increased FTR funding … PJM believes that the resulting status quo is less equitable and desirable than it would prefer.”
“Redesigning the funding and allocation processes for FTRs and ARRs is fundamentally an issue of cost allocation among different classes of members. Therefore, it is unlikely that stakeholders will be able to come to consensus on a long-term solution to address PJM’s FTR design,” PJM said. “Indeed, PJM expects that in the future any significantly proposed market rule changes aimed for an improved, more efficient and equitable ARR and FTR design may have to be prompted by a filing made by PJM under section 206 of the Federal Power Act.”
MILWAUKEE — The final session of the Mid-America Regulatory Conference last week brought together top officials from MISO, SPP and PJM to discuss balancing short-term expectations with long-term planning.
“We did not know how fast the wind would develop [in the Midwest] under state [renewable portfolio standards],” said PJM CEO Terry Boston, who will be retiring later this year. “If I reflect back, a plan to build HVDC from this area of the country into the Mid-Atlantic would have been an excellent plan.”
Sam Loudenslager, principal regulatory analyst for SPP, said his region was surprised by oil shale development.
He recalled a recent tour of the Bakken region in North Dakota. “I came back telling our planners, ‘You’re not going to get it. You’re going to miss this big time because it’s growing like nobody’s business,’” he recounted.
“They’ll continue to pump as long as oil’s $35 a barrel. And if you get to the heart of the Bakken, they’re pumping at $22. And these are areas that have no transmission whatsoever.”
Richard Doying, MISO’s executive vice president of operations and corporate services, lamented that officials had not anticipated the Environmental Protection Agency’s Clean Power Plan a decade ago. “When we were doing our initial transmission planning, 111(d) was not a significant focus,” he said.
MISO asked the Federal Energy Regulatory Commission to dismiss a complaint filed last month alleging it billed more than $21 million in excessive transmission rates, saying Southern Co. and three Missouri utilities have misinterpreted its Tariff (EL15-66).
MISO transmission owners, which joined the RTO last week in asking for dismissal, were blunter, saying the utilities’ claims amount to “misrepresentations” of the Tariff.
Both maintain the utilities’ complaint is duplicative to a proceeding already underway before FERC that involves similar issues (EL14-19).
In their complaint filed last month, the utilities alleged that MISO improperly shifted and reallocated sunk costs and network upgrade costs from its legacy region in the Midwest to Entergy export customers in the South following Entergy’s integration into MISO in 2013. (See Utilities Accuse MISO of ‘Massive’ Overcharges.)
Bringing the case were 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.
Entergy Integration
The utilities were receiving transmission service from Entergy before it joined MISO under the terms of the Entergy Tariff. When MISO succeeded Entergy as the transmission provider, they became subject to MISO’s Tariff.
Long-term, firm point-to-point transmission service rates under the Entergy OATT vs. MISO OATT.
The utilities contend that MISO’s drive-out and drive-through charges are not applicable to their transmission service reservations and that if they were applicable they should be declared unjust and unreasonable. They claim that Attachment FF-6 of the MISO Tariff provides a broad exemption for their through-and-out transaction charges. They say 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.
Exemption Argument
In its response, MISO counters that the Tariff is clear that the utilities are not entitled to an exemption. The RTO maintains that FERC “has confirmed on several occasions” that through-and-out rates in question are applicable to transactions in the MISO South region.
“Over the past several years, the complainants have created an extensive paper trail in various proceedings, which casts doubt on their current Tariff violation claims. While the complainants have filed numerous pleadings to block and devalue the MISO South integration, those pleadings did not argue, until the instant complaint was filed, that MISO is violating the Tariff,” MISO said. “On the contrary, the complainants sought FERC action precisely because these rates were applicable.”
The RTO also said any dispute over its through-and-out rate should be resolved in the section 206 proceeding FERC initiated in February 2014 (EL14-19).
Increased Scope
MISO also said the fact that the charges may have increased does not render them unjust and unreasonable. Prior to the MISO South integration, service was limited to the Entergy transmission system. But now the utilities may redirect points of receipt or delivery on a region-wide basis, MISO counters.
“Not surprisingly, the complainants’ new charges reflect these benefits of scope, as well as many other unique benefits that a Day 2 RTO provides to its customers,” MISO said.
Finally, MISO contends that the utilities are seeking a preferential rate at the expense of other market players.
The Organization of MISO States voted last week to convene discussions on ways to improve the RTO’s stakeholder process and address friction between the RTO and some of its members.
OMS President Libby Jacobs noted that MISO has several efforts under way already, including a white paper that MISO’s Steering Committee will discuss Thursday on concerns that the stakeholder process has become “cumbersome and inefficient.” The MISO Advisory Committee has made stakeholder process improvement the “hot topic” for its October meeting.
“We certainly applaud MISO for their efforts,” Jacobs, of the Iowa Utilities Board, told OMS board members on June 11.
Richard Doying, EVP of MISO (L) and Elizabeth (Libby) Jacobs, IUB Commissioner and OMS President at MARC 2015 Annual Meeting
But she said, “We had some concerns that it didn’t appear there was a formal outreach to all the stakeholder groups to really weigh in on the process.”
OMS would convene the dialog but will likely hire an outside facilitator to moderate the discussions, she said.
The effort could help better document how the stakeholder and governance process works, look at best practices at other RTOs and help stakeholders identify priorities.
MISO’s white paper cites overlapping responsibilities among committees and insufficient focus on the most important issues as weaknesses in the current process.
Tensions
Tensions between some MISO stakeholders and the RTO have flared in recent months.
Transmission developers objected earlier this year to MISO’s approval of Entergy’s request for $217 million in out-of-cycle transmission projects in Louisiana. As out-of-cycle projects, they were excluded from competition.
The Consumer Advocates sector complained it was being disenfranchised after MISO denied its request for $200,000 in funding to help cover legal costs in a case before the Federal Energy Regulatory Commission on MISO transmission owners’ return on equity rates.
ISO-NE’s power prices dropped by more than 40% in the first quarter of 2015 thanks to lower natural gas costs, the Internal Market Monitor reported last week.
In a filing with the Federal Energy Regulatory Commission, the Monitor said a 43% decrease in the cost of natural gas from the previous year was largely responsible for the power price decline (ZZ15-4). Natural gas prices averaged $11.37/MMBtu, a drop from $19.95.
Day-ahead energy market prices averaged $84.84/MWh at the Massachusetts hub, down 41% from a year ago, while real-time prices averaged $81.97/MWh, a drop of 43%.
Also lower were real-time reserve payments (-80%), regulation payments (-56%) and net commitment period compensation payments (-67%).
Total wholesale market costs of $3.14 billion were down 41%. “Overall, market prices reflected the cost of providing energy, and energy market outcomes were competitive,” the Monitor said.
Pricing Flexibility
The IMM said generators are taking advantage of the flexibility resulting from the RTO’s Dec. 3 rule change allowing market offers to be made hourly and changed during the operating day. The energy market offer flexibility (EMOF) rule, which allows resources to respond to changes in production and opportunity costs, has been used primarily by natural gas generators.
“There has been a reduction in the volume of self-scheduling, in which generators assume a price-taking role, and to the extent to which generators vary economic minimum parameters to reach desired levels of output,” the Monitor said.
Some generators also took advantage of EMOF rules allowing them to offer negative prices to signal their desire to maintain minimum output levels.
Only hydro and wind resources offered negative prices in the day-ahead market. They were joined by some natural gas, biomass and coal resources in offering negative prices in the real-time market.
“On average, the amount of capacity offered in the real-time market at negative prices was equal to roughly 3% to 4% of load,” the Monitor said.
VALLEY FORGE, Pa. — This winter bumped aside last year’s peak load record, but PJM’s system experienced a fraction of the stress brought on by the January 2014 polar vortex. Generator outage rates, which exceeded 20% in 2014, were generally less than 15% in 2015.
Peak loads grew more gradually in Feb. 2015 than in Jan. 2014.
To figure out why, PJM researchers “did a deeper dive in different areas so we could understand the differences from last winter, and while we hit a new winter peak, why we did so much better,” Chantal Hendrzak, executive director for operations support, told the Operating Committee in presenting the 2015 Cold Weather Report.
Last year, recommendations for follow-up on winter preparedness filled pages. This year, there were five recommendations, all contained on one page.
A lot of the conversation, she said, revolved around whether this winter was colder, noting that it was most relevant to compare this past February with January 2014.
“We poked at weather in all sorts of different ways to understand what some of the differences were,” she said.
One of the findings was that while temperatures were colder this winter, the wind chill factors weren’t as severe in some areas. Including the wind chill factor, the low temperatures for Cleveland, Chicago and Columbus, Ohio, all were at least 14 degrees warmer this year.
Generator outage rates, which exceeded 20% in 2014, were generally less than 15% in 2015.
Wind chill can have more of an impact — and more quickly — on generators than temperature alone, depending on how insulated they are and if the units are not enclosed in structures, she said.
Staff also looked at the days leading up to peak loads. This year, she said, “we kind of baby-stepped into the peak load” as opposed to the large incline seen before last year’s peak.
In addition, she said, wind capability increased over the previous winter.
This winter, she said, pipelines were more proactive in making sure pressure was maintained for their firm customers, generation owners took a number of precautions to ensure their availability and more units were running on alternate fuel.
In addition to PJM’s initiatives to introduce the Capacity Performance product and improve gas-electric coordination, the new report recommended continuing efforts to improve the ability of generators to communicate their operational parameters to grid operators; building on the testing program for seldom-run units and winter preparation checklist; and continuing efforts to reduce energy market uplift.
This winter’s success led a number of stakeholders to question the need for PJM’s new Capacity Performance product, which aims to strengthen reliability by penalizing underperforming units and rewarding overperforming participants. (See FERC OKs PJM Capacity Performance Proposal; Bay Dissents.)
Hendrzak said the changes the RTO saw this winter were voluntary. “PJM believes we need a more sustainable approach, so we are continuing to move forward with CP,” she said.
Talen Energy, the merchant generation company formed by spinning off much of PPL’s generating assets and combining it with those of Riverstone Holdings, began trading on the New York Stock Exchange on June 2. The company issued shares at $20 but ended its first day at the $18.50 mark.
Trading under the symbol TLN, Talen has only hovered around $19/share through its first two weeks of trading and experienced a dip on Thursday and Friday to close out last week, finishing at $18.13/share. The company is now one of the country’s largest merchant generators, with about 15,000 MW in its fleet. Most of the assets are in PJM, along with some in ERCOT. To allay concerns from competitors, the company agreed to divest about 1,300 MW in PJM in a settlement with the Federal Energy Regulatory Commission.
Amazon.com announced that it is partnering with Community Energy Inc. to build an 80-MW solar farm in Virginia to help power its data centers in the state.
The $200 million solar farm, to be built on the Eastern Shore’s Accomack County, will be called Amazon Solar Farm U.S. East and should be operating by October 2016. When completed, the 250,000-panel solar farm will increase the state’s solar capacity by a factor of five. Virginia currently ranks 30th in the U.S. for solar capacity.
Amazon says it eventually wants to use renewable energy to power all its data centers.
DTE to Drop Renewable Energy Surcharge, Reducing Rates $15M Annually
DTE Electric has proposed dropping a 43-cent/month customer surcharge that pays for renewable energy.
Under changes in the utility’s renewable energy plan filed early this month with the Michigan Public Service Commission, DTE said the request would reduce electric rates by a total of $15 million a year. DTE also said it will be in compliance with Michigan’s renewable portfolio standard requiring electric utilities to supply 10% of their power from renewable sources.
Parent DTE Energy has a 1,000-MW renewable portfolio that it acquired from Michigan developers. DTE began assessing the renewable surcharge in 2009. Last year it reduced the charge to 43 cents from $3.
Meanwhile, DTE said it will explore the potential of a voluntary pilot program for customers who want to pay for more than 10% of their electricity from renewables.
Xcel Energy’s Southwestern Public Service last week scaled back its rate-increase request in Texas by nearly $23 million.
SPS last year filed for an annual revenue increase of $64.8 million, or 6.7%. On June 10, SPS revised its request to $42 million, or 4.4%. A number of interveners have been pressuring regulators for a rate decrease and in May the Public Utility Commission of Texas staff recommended a decrease of $2.6 million.
SPS is also seeking a waiver of PUCT’s post-test year adjustment rule, which would allow the company to include $392 million additional capital investment for the July-December 2014 period.
Duke Ordered to Stop Groundwater Contamination from Coal Ash Site
North Carolina environmental regulators ordered Duke Energy to stop one of its retired coal-fired power plant sites from polluting groundwater after tests showed heavy metals in nearby drinking water wells. The contamination, including boron, was found in three wells near the retired Sutton Steam Plant near Wilmington, N.C. Boron is an indicator of coal ash contamination.
The state gave Duke until July 9 to stop the spread of the contamination at the Sutton site. If it can’t, it could face further fines than the $25 million the state has already assessed the company in relation to leaching from the plant’s coal ash basin. Duke is appealing the fine. The company also recently reached a $102 million settlement with federal regulators concerning coal ash spills relating to the January 2014 spill at the Dan River.
North Carolina has hired a private law firm to assist it in its ongoing cases against Duke. “It is evident that Duke Energy is choosing to spend its virtually limitless legal resources to fight fines for clearly documented groundwater contamination stemming from its coal ash impoundments near the Sutton plant,” said Sam Hayes, general counsel for the state environmental department.
Fallout Grows Following Accusations Dynegy Manipulated MISO Auction
At least 16 stakeholders have filed notices at the Federal Energy Regulatory Commission to intervene in a request by a consumer group and the Illinois Attorney General for an investigation into whether Dynegy illegally manipulated MISO’s Planning Resource Auction last April.
The Illinois AG and the group Public Citizen Inc. point to a nine-fold price increase resulted in Zone 4, which includes much of downstate Illinois. (See Public Citizen to FERC: Investigate Dynegy Role.) Among those filing to intervene at FERC is the Illinois Citizens Utility Board, a public advocacy group that this week claimed that electric bills for downstate Illinois customers rose more than 10%.
Dynegy says it followed all the auction rules and the results were verified by an independent monitor.
Opponents to Exelon’s Medway Generating Plant Air Concerns at Meeting
Exelon Generation’s plan to build a two-unit, 195-MW generating station in the Boston suburb of West Medway drew opponents last week at a public information meeting.
Exelon plans to build the natural gas-fired units on the existing 94-acre site of the West Medway Generating Station, a three-unit, oil-fired 117-MW peaking station built by Boston Edison following the 1965 East Coast blackout. The oil-fired units only run about 100 hours a year, but the new gas-fired generators would operate about 14 hours a day.
Several residents said they were concerned about the plant’s needs for cooling water. According to the company, the units would need 97,000 to 197,000 gallons of cooling water each day. This would come at a time, said resident Brian Adams, when he and his neighbors “are told every day that we can’t water our lawns.”
Invenergy’s Proposed Jessup Plant Opponents Meet with Gov. Wolf
Pennsylvania Gov. Tom Wolf listened to the concerns of a small group of residents who are worried about Invenergy’s plans to build a 1,500-MW combined-cycle natural-gas plant in the Northeastern town of Jessup.
Four members of Citizens for a Healthy Jessup said the plant is being pushed through the siting and permitting process too quickly. They also expressed concerns that the plans for the plant seem to change. Wolf didn’t offer his own position on the plant.
Invenergy announced the project last November and said the site’s proximity to both the new Susquehanna-Roseland transmission line and shale gas supplies made it an attractive location. It was originally proposed to be a 1,300-MW facility. If built, it would be the state’s second-largest natural gas-fired plant, after PPL’s 1,722-MW Martins Creek plant in Northampton County.
Dominion Questions Zoning Ordinance’s Effect on Proposed Virginia Wind Energy Facility
Dominion Virginia Power is concerned that a proposed local zoning ordinance would create roadblocks to its proposed wind energy facility near Bluefield, Va. Dominion wants to build an industrial-sized wind farm on 2,600 acres it purchased near East River Mountain in 2009.
Opponents say the wind-turbine towers would ruin the view. Dominion, in a letter to Tazewell County officials, said that a recent proposed zoning ordinance change that would limit industrial expansion in the area, coupled with an existing tall structure ordinance, “significantly deters wind development” in the area.
County officials think the zoning issue could spell the end of the project. “This ordinance in my opinion is a death blow to that project,” said Charles Stacy, a member of the board of supervisors in Tazewell County’s Eastern District.
Options Limited for County Opposed to Dominion Tx Line Proposal
Orange County, Va., is considering making an attempt to block a proposed 230-kV transmission line between two rural areas near Culpeper, but the county attorney says little can be done to stop it.
Dominion Virginia Power has proposed running the line between Remington and Pratt, but local opponents fear the line would detract from the area’s scenic beauty. The alliance asked Orange County officials to see if there was a way to block the project.
County Attorney Tom Lacheney said last week that a review of existing laws and ordinances seems to indicate that Dominion will probably be successful in its attempts to build the line.
Duke Energy to Introduce ‘Swine Waste’ Gas into Plants’ Fuel Stream
Duke Energy has applied to the North Carolina Utilities Commission to buy gas produced from Midwestern swine farms for two of its North Carolina plants in order to comply with a state biofuel mandate.
Duke and other power producers say there are insufficient in-state supplies of gas produced from swine waste to comply with a state law, which mandates that 0.07% of energy be derived from pig manure. The mandate steps up to 0.2% by 2020.
The fuel would come from hog farms in Missouri and Oklahoma, where manure and other waste is deposited in a digester, which then collects the gas. The fuel would be used at Duke’s Dan River combined-cycle plant near Eden and its Buck combined-cycle plant near Salisbury.
Eight Utilities Joining Together to Form Emergency Equipment Stockpile
Eight U.S. utility companies are forming a consortium called Grid Assurance to stockpile large transformers, circuit breakers and other special equipment so they are available for emergencies. The venture will help the companies to more economically meet a Federal Energy Regulatory Commission mandate to have vital backup equipment available.
“Restoration of the transmission grid can be hampered by long lead times required to design, build and deliver” such equipment, one of the companies, American Electric Power, said in a statement. “Subscribers can call on equipment when they experience … physical attacks, electromagnetic pulses, solar storms, cyberattacks, earthquakes and severe weather events,” it said. The equipment would be stored at warehouses throughout the country.
In addition to AEP, the other companies in the program are Berkshire Hathaway Energy, Duke Energy, Edison International, Eversource Energy, Exelon, Great Plains Energy and Southern Co.
