President Obama last week named Cheryl LaFleur as chairwoman of the Federal Energy Regulatory Commission effective July 30 and said new Commissioner Norman Bay will succeed her in the top spot on April 15, 2015.
LaFleur has been serving as acting chair since Nov. 25, when former Chair Jon Wellinghoff resigned.
Bay, who has served as director of FERC’s Office of Enforcement since 2009, won confirmation to the commission under an unusual agreement that Obama wouldn’t promote him to the chairmanship for nine months.
The compromise was crucial to winning the votes of some who criticized Obama’s plan to make Bay — who has never been a regulatory commissioner — chair immediately upon his appointment.
The last five FERC chairmen served a median of 30 months before becoming chair. Only one served less than a year on the panel before his promotion.
The four-unit, 2,422-MW coal-fired Roxboro Steam Plant in in Semora, N.C., is one of the largest power plants in the United States. (Source: Duke)
The North Carolina Eastern Municipal Power Agency is selling its stake in four Duke Energy Progress power plants to Duke in a deal valued at $1.2 billion, the organizations announced last week.
The agreement involves about 700 MW at two coal-fired plants and three nuclear units. When the deal closes, Duke will be the sole owners of the Roxboro Unit 4 and Mayo Unit 1 coal plants, and the Brunswick Units 1 and 2 and Harris Unit 1 nuclear stations. All of the plants are in North Carolina.
Duke also entered into a 30-year power-purchase agreement to supply wholesale power to the 32 municipalities represented by NCEMPA. The terms of that agreement were not released.
The deal will allow the agency to unburden itself of a large chunk of the approximately $1.9 billion in debt under which it has been struggling.
The single-unit, 900-MW Harris Nuclear Plant is located near New Hill, N.C. (Source: Nuclear Regulatory Commission)
“NCEMPA’s decision to sell its power generating assets was driven by a desire to lower its power costs and reduce its risk of generation ownership,” said NCEMPA spokesperson Rebecca Agner on Friday. “This agreement will reduce NCEMPA’s outstanding debt by more than 70% and make our costs more competitive. After the sale, NCEMPA will not own any generation assets.”
The agreement needs approval from the Federal Energy Regulatory Commission and several state agencies.
Duke spokesman Jeff Brooks said the agreement was attractive for the company for a number of reasons. He acknowledged that the $1.2 billion sales price was somewhat higher than “book value” of the plants, but he said having sole ownership “will provide long-term fuel savings,” benefiting both Duke and its customers.
“These units were among the least costly [in the Duke fleet] to operate from a fuel standpoint,” he said. In buying back the 700 MW of capacity, Duke will be able to increase wholesale energy revenue while lowering its average fuel costs.
Municipalities will benefit from lower debt service costs.
Although Duke has retired a number of coal units in the region in recent years, the Roxboro and Mayo plants are among its youngest and have already seen substantial emissions control retrofits.
“We have made substantial investments in emissions control and dry ash” collection, Brooks said. “The coal units are among the cleanest in the nation.”
The two nuclear stations could run for at least two decades. The licenses for Brunswick Units 1 and 2 are good until 2034 and 2036, respectively. The Harris license expires in 2046.
The Markets and Reliability Committee last week endorsed two manual changes and approved changes to rules on black start compensation and auction-specific transactions.
Manual Changes
Members endorsed changes to Manual 37: Reliability Coordination to update the System Operating Limits (SOL) definition and violation language (sections 3.1, 3.2) to conform to the North American Electric Reliability Corp. standard.
Revisions to the cost allocation section of Manual 14B: PJM Region Transmission Planning Process also won endorsement. The changes describe the current solution-based methodology as detailed in the PJM Tariff.
Revisions to Manual 14A: Generation and Transmission Interconnection Process were deferred to await coordination with MISO. The revisions are intended to reflect changes in how interim deliverability studies are conducted.
Black Start Compensation, ‘Back Stop’
Members approved a “back stop” mechanism for acquiring black start services through transmission providers when PJM solicitations fail to obtain service for a zone. Members also approved minor Tariff and manual changes relating to the compensation of black start units. (See PJM to Seek Smaller Black Start Changes.)
The new rules:
Allow energy-only black start units to be compensated. There was previously no mechanism to compensate energy-only generators through the base formula rate.
Allow automatic load rejection (ALR) units to recover NERC Compliance costs as documented to the Market Monitor.
Allow fuel-storage compensation for liquefied natural gas, propane and oil. Previously, only oil storage was compensated.
Limit black start units sharing a common fuel tank to claim the fuel-storage compensation for only one unit, closing a loophole.
Schedule a review of compensation formulas every five years (down from the current two years) to align it with the RTO-wide black start solicitation.
The System Restoration Strategy Senior Task Force had considered several proposed changes but none of the others received the minimum 50% support to forward it to the MRC for consideration. With its work complete, the task force will be sunset, said MRC Chairman Mike Kormos, PJM’s executive vice president for operations.
Auction-Specific Transactions
Members gave final approval to a manual change that will make it easier for banks to purchase capacity providers’ revenue streams. The change, proposed by Citigroup Energy, will allow auction-specific transactions to be entered into PJM’s eRPM system after the auction that initiated them. Previously, such transactions could not be submitted to PJM until after the third incremental auction for a delivery year. (See Stakeholders Look to Expedite Auction-Specific Transactions.)
PJM will increase performance penalties and incentives and seek ways to incorporate firm gas transportation in energy prices under an initiative announced last week to reduce generator outage rates.
PJM CEO Terry Boston announced the initiative, which he said resulted from a three-day meeting of the Board of Managers and discussions with present and former leaders of the Members Committee and stakeholder sectors.
The action was prompted by January’s extreme cold, when as much as 22% of PJM’s generation suffered forced outages, three times the normal winter rate.
“We would have to interrupt load if this happened in [future] winters,” Boston told the Markets and Reliability Committee Thursday, noting that the RTO will lose about 8,500 MW of generation to retirements by the winter of 2015/16. “We feel [changing capacity rules] has to be one of our highest priorities.”
Officials said the changes may increase capacity costs but should also reduce volatility during tight supply/demand conditions.
Redefinition of Capacity
“You should think of this as a holistic redefinition of what capacity is,” said Andy Ott, executive vice president for markets.
Members’ initial response to the initiative — which PJM said would be conducted under expedited procedures outside the normal stakeholder process — was muted.
David “Scarp” Scarpignato of Direct Energy questioned whether PJM would bring proposed changes to “advisory” votes before the MRC or Members Committee.
Gregory Carmean, executive director of the Organization of PJM States (OPSI), expressed concern that additional costs would be largely for winter performance while capacity cost allocation is based on summer loads.
Carl Johnson, representing the PJM Public Power Coalition, expressed misgivings over the initiative during a later MRC discussion regarding the Triennial Review of capacity auction parameters.
Johnson said stakeholders haven’t received enough information on the cost impact of the parameter changes, which include a potential increase in the Installed Reserve Margin. Referring to PJM’s plans to “redefine” capacity Johnson said, “When we don’t understand what we’re buying when we buy capacity, to say we’re going to be buying more of it, we cannot support.”
The Consumer Advocates of PJM States discussed the initiative yesterday and was expected to issue a statement later this week.
Fuel Security
A key part of the new definition will be fuel security, meaning incentives are likely to encourage nuclear generators, dual-fuel units and firm gas contracts.
“At 20 mph [the speed at which gas flows], there’s not a lot of difference between just-in-time delivery and too dang late,” Boston said.
He also referred to two coal plants that were unable to operate in January because they lacked natural gas needed to start up. “Twenty thousand dollars’ worth of fuel oil could have brought those units up,” Boston said. “I would pay that now.”
More Flexible Operations
Officials also will be seeking to reverse a trend toward less flexible unit operating parameters. In a 23-page white paper issued Friday, PJM said unit flexibility has dropped as a result of staffing reductions and other cost cuts. (See Problem Statement on PJM Capacity Performance Definition.)
Ott said limits on unit flexibility must be a function of operational limits, not financial concerns. “We’ve seen units with three starts per day reduced to one; units with very short minimum run times became very long minimum run times,” he said.
The effort will also seek to boost operations and maintenance spending to improve generator availability on “low probability peak events” such as January’s polar vortex or last September’s unexpected heat wave.
“Generation owners may choose to cut O&M costs or choose not to make investments that enhance availability as a means to manage costs,” the report noted. “In making such a decision, the generation owner has implicitly or explicitly made a calculation that the benefits of such measures [increased net revenues] do not cover these ‘additional’ costs.”
Generator owners also have complained that there is no way to reflect such costs in supply offers.
“Competitive pressure to clear in the RPM capacity market may push generation owners to not make these investments if they feel other competitors are taking a similar strategy due to the risk of pricing themselves out of the market,” the report said.
Insufficient Penalties
PJM said current penalties for capacity resources that are unavailable during the 500 “peak” hours per year are insufficient.
The Tariff defines summer peak hours as Hour Ending 1500 to HE 1900 on non-holiday weekdays from June through August. Winter peak hours are HE 800 to HE 900 and HE 1900 to HE 2000 on non-holiday weekdays in January and February.
Penalties are assessed only if the forced outage rate during peak hours (EFORp) is more than the five-year average forced outage rate (EFORd5) of the resource.
Generators are often able to avoid even these penalties because the Tariff forgives outages related to a lack of gas as “Out of Management Control (OMC).”
“The penalties for being unavailable during the pre-defined peak hours … provides no incentive to make investments in O&M or infrastructure to enhance availability since there is little risk of incurring a capacity market penalty for being unavailable during reliability critical events,” the report said.
The current structure “provides an incentive for generation owners to hide the real cause behind an outage, or to shift the cause of an outage to a third party such as a gas pipeline” and claim it as OMC, the report said. However fuel delivery contracts and installation of dual-fuel capacity “are business decisions well within the control of the generation owner.”
‘Enhanced’ Liaison Committee Process
PJM officials said they will invoke a never-used “Enhanced Liaison Committee” process so that the new rules can be filed with the Federal Energy Regulatory Commission in time for the winter of 2015/16.
“If Polar Vortex conditions occurred in 2015/16 and outage rates were as high as PJM experienced in January 2014 … PJM would almost certainly experience a loss-of-load event,” the report said. PJM hopes to reduce outages this winter by resuming winter generation testing.
The process — developed by the Governance Assessment Special Team (GAST) in 2011 and documented in Manual 34 — was created to allow members to provide input on issues for which consensus is unlikely and the board acts independently.
“There will be a lot of opportunity in the next two months for dialogue,” promised Dave Anders, director of stakeholder affairs.
PJM has scheduled two meetings — 1-4 p.m. Aug. 12 and 18 — to discuss the initiative and the problem statement white paper.
On Aug. 20, PJM plans to release a draft white paper detailing proposed solutions; it will be the subject of a third meeting from 9 a.m. to noon Aug. 22. Stakeholders’ written comments on the second paper will be due Sept. 12, followed by a fourth meeting to receive additional comments Sept. 24.
The enhanced liaison process will begin Oct. 7 when PJM issues the final version of its solutions whitepaper. Additional input from stakeholders will come through coalitions, which will be required to submit briefing papers by Oct. 28.
The board will meet with the Enhanced Liaison Committee Nov. 4.
The proposed solutions may incorporate cold-weather initiatives being conducted by other committees, including energy storage participation in RPM (Planning Committee); qualifying transmission upgrade (QTU) credits and unit market offers (Market Implementation Committee); and cold weather resource performance improvements and gas unit commitment coordination (Operating Committee).
Arbitrage Technical Conference
General Counsel Vince Duane said PJM will ask FERC to delay scheduling of a technical conference the commission ordered in May, when it rejected the RTO’s plan to curb speculation in capacity market auctions. The conference is to develop solutions to eliminate arbitrage opportunities between the base residual auction (BRA) and incremental auctions (IAs).
“Any conversations with FERC thus far I would characterize as very preliminary,” Ott said in response to a stakeholder question.
Exelon, a company primarily known for its generation fleet, continued its customer-buying spree last week when it announced an agreement to buy Integrys Energy Services for $60 million.
Integrys is a competitive retail electricity and natural gas company with nearly 1.2 million customers across 22 states and D.C.
Exelon will fold those customers in with its existing 2.5 million retail electricity and gas customers served by its Constellation subsidiary. Integrys has commercial and industrial customers across more than 100 utility service territories, primarily in the Northeast. Its residential customers are mostly in Illinois, Michigan and Ohio.
Why is Exelon getting into retail when other utilities such as Dominion are getting out?
“We continue to see growth opportunities in our competitive businesses and the value of matching load to generation, which was one of the primary reasons for our acquisition of Constellation in 2012,” Exelon spokesman Paul Adams said last week. “Integrys Energy Services is a well-run company with an attractive customer base in key markets.”
Chris Crane, Exelon’s president and CEO, also emphasized matching load to generation. “Integrys Energy Services’ geographic footprint is a perfect strategic fit for Constellation and will create opportunities to reach more customers and grow the business, particularly in regions where Exelon also owns significant generation assets,” he said.
The agreement is the latest divestment move by Chicago-based Integrys Energy Group. In June, it announced it would sell its regulated utility operations — Michigan Gas Utilities, Minnesota Energy Resources, North Shore Gas, Peoples Gas, Upper Peninsula Power Company and Wisconsin Public Service — to Milwaukee-based Wisconsin Energy for $9.1 billion.
Others have also decided to get out of the retail business. Dominion Resources announced in March it would sell its retail electric business to NRG Energy.
NRG is paying $165 million for Dominion’s 600,000 retail customers in Illinois, Maryland, New Jersey, Ohio, Connecticut, New York, Massachusetts and Texas. Exelon is paying $60 million for 1.2 million customers.
In April, the company announced plans to buy Pepco Holdings Inc., which will add nearly 2 million distribution customers to its regulated customer count while increasing its rate base to almost $26 billion from $19 billion.
In March, Exelon announced that it was buying Indianapolis-based ETC ProLiance Energy. ProLiance is a retail supplier of natural gas with about 2,500 commercial and industrial customers in eight states. The terms of that acquisition were not released at the time.
One of the prizes of buying a retail business like Integrys is that it will allow Exelon to compete for some of the valued municipal contracts its regulated utilities, such as Commonwealth Edison, have been losing to retail companies. This includes the contract for a large chunk of Chicago’s customers. In 2012, Exelon lost 700,000 residential customers in Chicago to a retail energy business — Integrys.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee meeting Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Valley Forge covering the discussions and votes. See next Tuesday’s newsletter for a full report.
2. PJM Manuals (9:10-9:20)
Members will be asked to endorse the following:
Revisions to Manual 37: Reliability Coordination to update the System Operating Limits (SOL) definition and violation language (sections 3.1, 3.2) to conform to the North American Electric Reliability Corp. standard. Includes updates to various references and the Interconnected Reliability Operating Limit (IROL) table (Section 3.1).
Revisions to Manual 14A: Generation and Transmission Interconnection Process to reflect changes in how the interim deliverability studies are conducted. Language was added regarding projects proposed for interconnection to PJM and those seeking connections with MISO. Stakeholders in MISO are reviewing similar language; the manual may require additional changes depending on their feedback.
Updates to the cost allocation section of Manual 14B: PJM Region Transmission Planning Process to describe the current solution-based methodology as detailed in the PJM Tariff. There are no changes to the actual method or calculation.
3. System Restoration Strategy Task Force (SRSTF) Recommendations (9:30-10:00)
Members will consider minor Tariff and manual changes to the compensation of black start units. The System Restoration Strategy Senior Task Force considered several proposals but only one received the minimum 50% support to forward it to the MRC for consideration. (See PJM to Seek Smaller Black Start Changes.) The proposal would:
Allow energy-only black start units to be compensated. There is no mechanism to compensate energy-only generators through the base formula rate.
Allow automatic load rejection (ALR) units to recover NERC Compliance costs as documented to the Market Monitor.
Allow fuel-storage compensation for liquefied natural gas, propane and oil. Currently, only oil storage is compensated.
Limit black start units sharing a common fuel tank to claim the fuel-storage compensation for only one unit, closing a loophole.
Schedule a review of compensation formulas every five years (down from the current two years) to align it with the RTO-wide black start solicitation.
Facing a barrage of criticism from environmentalists, New Jersey officials and spurned bidders, PJM’s Board of Managers has delayed action on planners’ recommendation that it select Public Service Electric & Gas to fix the Artificial Island stability problem.
Instead, the board will allow PSE&G and finalists Transource Energy and Dominion Resources to “supplement” their proposals in response to finalist LS Power’s offer to cap its project cost at $171 million — $40 million to $90 million less than the PSE&G project.
“The project costs included in any such supplemental proposals to PJM will be factors considered in the final selection for an Artificial Island solution. However, the Board has reiterated that cost is only one of several considerations that will drive a final decision,” Vice President for Planning Steve Herling said in a letter to the Transmission Expansion Advisory Committee yesterday.
Herling said PJM will respond to the criticism of its recommendation and its handling of the solicitation — the first under the Federal Energy Regulatory Commission’s Order 1000 — at the Aug. 7 TEAC meeting. Planners also will discuss “any issues that require further analysis,” Herling added.
PJM also will contact the Nuclear Regulatory Commission to discuss how some of the proposals might impact the switchyards for Artificial Island’s occupants, the Salem and Hope Creek nuclear plants.
The board made its decision in a closed meeting Tuesday and announced it yesterday in a liaison meeting with PJM members.
Comments Mostly Critical
The board received 10 comments from bidders and other stakeholders after PJM planners announced their decision to recommend PSE&G last month. Only PSE&G and the Delaware Public Advocate supported the recommendation. Delaware said it preferred the planners’ recommendation — a 500-kV line between the Hope Creek nuclear plant and Red Lion, Del. — because a 230-kV southern path to Delaware would allocate the entire project cost to Delaware ratepayers.
Wetlands are among the sensitive ecosystems that would be impacted by the northern 500-kV path chosen by PJM planners. (Source: PSEG)
LS Power, Atlantic Grid Development, Dominion and Transource contended the proposal selected was technically inferior and/or more expensive than their own proposals. Exelon and Pepco, which made a joint proposal, said they would not challenge the recommendation but joined the others in criticizing the process as unfair and lacking transparency.
New Jersey’s Board of Public Utilities and Division of Rate Counsel criticized PJM’s recommendation as more expensive and presenting more of a permitting risk than the southern alternative because of its impact on sensitive environmental areas. The Sierra Club and the Delaware Riverkeeper Network said they shared the state’s concerns over the environmental impact of the northern path.
PJM’s choice “is very damaging environmentally, and not just to one important ecological resource, but to hundreds,” Delaware Riverkeeper Maya K. van Rossum said. The Riverkeeper Network is a non-profit organization formed to “advocate, educate and litigate” on behalf of the river. It promised it would “be active and committed” in its opposition to the 500-kV proposal.
Process Not Followed
Several of the bidders criticized PJM for failing to follow the procedures spelled out in PJM’s Order 1000 compliance filings, which revised Schedule 6 of the Operating Agreement.
PJM had said it would invite transmission developers to develop solutions to individual transmission needs and choose the best proposal from among the submissions. If none of the proposals were satisfactory, PJM could either revise its problem statement in a new solicitation window or develop its own solution and designate the incumbent transmission owner(s) to build it.
The bidders say that PJM changed the requirements by adding a unity-power-factor requirement — typically required for new generation interconnections — which none of the 26 proposals could meet.
Instead, the planners proposed adding a static var compensator (SVC) to all of the finalists’ proposals at an additional cost of $80 million.
PSE&G Proposal
PSE&G’s winning proposal was estimated at $1.066 billion before PJM planners eliminated two 500-kV lines from it. That reduced the project’s cost by more than three-quarters to a range of $211-$257 million, making it equal to an LS Power 230-kV proposal that was the cheapest among the finalists, PJM said.
“Although credited to [PSE&G], the selected Hope Creek to Red Lion 500-kV solution is nowhere close to the originally submitted proposal,” American Electric Power, co-owner of Transource, said in its July 18 letter to the board. “A modification that results in a more than 75% reduction in scope from what was originally proposed is a new project and should be treated as such.”
LS Power insisted its proposal would cost only $149 million and offered to cap its recovery at $171 million, a savings of at least $40 million to $90 million over the PSE&G project. (See Losing Bidders Blast Artificial Island Choice.)
Exelon and Pepco said that PJM had failed to provide the transparent selection process it promised FERC. “Following the filed process would likely have resulted in a significant reduction of more than a year’s worth of hard work performed by, and expenses incurred by, all participants,” they wrote.
In his letter to the TEAC yesterday, Herling said PJM was committed to improving its process to ensure fairness and transparency. “Order 1000 … has created entirely new processes, which are especially challenging when evaluating transmission solutions as complex as those required for the Artificial Island stability issues,” he said.
Cheryl LaFleur has won plaudits for her leadership since taking over as acting chair of the Federal Energy Regulatory Commission in November and won 90 votes for her renomination to a second five-year term on Tuesday. But she did it without any help from the Democratic senators from New York.
Charles Schumer and Kirsten Gillibrand were among seven senators to vote against LaFleur, along with Democrats Ben Cardin and Barbara Mikulski of Maryland, Democrat John E. Walsh of Montana and Republicans Jerry Moran and Pat Roberts of Kansas.
The New York senators are angry over LaFleur’s support for the New York ISO’s creation of a capacity zone in the Lower Hudson Valley that has led to increases in prices. The zone took effect May 1, following FERC’s unanimous approval last August.
The issue spilled into the Senate’s confirmation debate as Majority Leader Harry Reid (D-Nev.) referred to a Wall Street Journal editorial the day before that characterized the capacity zone plan as “a federal takeover of New York’s electric grid.”
“I’ve spoken to both nominees and they’ll take a hard look at that. When [the editorial] came out yesterday I directed attention to that and that will be addressed by both of them and they have said so,” Reid said.
In March, Schumer wrote to LaFleur, saying FERC’s approval of the new zone is “unacceptable to me, the New York Public Service Commission and to residents and businesses throughout the Hudson Valley who feel aggrieved for having to pay immediate rate hikes after a record winter of high energy costs.”
“As we both know, this winter has brought extreme low temperatures, and consequently high energy costs, to everyone in New York,” Schumer told LaFleur. “Imposing an additional cost increase on Hudson Valley residents is unfair and will place an undue burden on many of my constituents.”
However, FERC in late May denied a rehearing requested by Schumer and various New York agencies, political leaders and utilities. The matter is now pending before the U.S. District Court of Appeals for the Second Circuit.
FERC acknowledges that electricity costs will rise in the short run but says that higher price signals are needed to encourage construction of generation and transmission to serve New York City and the nine counties to its north. FERC said the congestion issue has been discussed since 2006 without a solution. Consumers have been shielded from higher prices since that time, it noted.
Previously, the Lower Hudson Valley was paying capacity prices set for the areas of New York outside of the city and Westchester County. The FERC order combines the Hudson Valley with the City/Westchester zone, whose capacity prices have historically been much higher.
The New York Power Authority claims the zone pricing only creates a windfall for power generators that will total more than $1 billion over the next three years.
Central Hudson Gas & Electric, which serves the Poughkeepsie area, says that capacity revenues from auctions in May and June more than doubled from the same months a year ago. That will increase monthly bills by 6% for residential customers and 10% for large industrials, the company said.
In its petition to FERC, NYISO said that the transmission bottleneck threatened reliability in and around New York City. The FERC order requires utilities to buy at least 88% of their capacity from generators within the zone.
State officials opposing the zone say that two large transmission projects are being planned to eliminate the bottleneck and that locally based generation is not needed. One transmission project would create a corridor from the Canadian border to New York City, making renewable energy generation from upstate more readily available.
FERC maintains the projects are not guaranteed to be built and, at best, are years from completion.
FERC also rejected a proposed phase-in of the zone. It said any delay would impair the market’s ability to send more efficient investment price signals.
The United States Court of Appeals expedited the appeal process when it required opening briefs filed by June 27. A ruling is anticipated in the fall.
The D.C. Circuit Court of Appeals signaled Friday that it may take another look at the court’s order voiding the Federal Energy Regulatory Commission’s authority over demand response compensation.
A three-judge panel of the D.C. Circuit ruled May 23 that FERC Order 745 violates state ratemaking authority. (See Court Throws Out Demand Response Rule.) FERC asked the circuit on July 7 to conduct an en banc review of the 2-1 ruling.
In a one-page order Friday, the court told the Order 745 challengers — the Electric Power Supply Association, American Public Power Association, National Rural Electric Cooperative Association, Old Dominion Electric Cooperative and Edison Electric Institute — to file a joint response to FERC’s petition within 15 days.
In its petition for review by the full D.C. Circuit, FERC acknowledged the rarity of rehearing. It noted that the commission has sought such a rehearing only once in the last 18 years — a case in which the Supreme Court reversed the circuit’s original decision.
Order 745 requires PJM and other RTOs to pay DR providers full locational marginal prices.
FERC said a review was warranted because the May 23 ruling “severely departs” from previous rulings on FERC’s jurisdiction under the Federal Power Act. A broad reading of the ruling could potentially invalidate DR participation in any wholesale market — energy, capacity or ancillary services — FERC said.
PJM joined FERC in seeking a review of the ruling, saying the loss of DR would be disruptive to operations. PJM General Counsel Vince Duane acknowledged that the court grants less than 1% of the rehearing requests it receives but said the odds were better in this case because of the implications of the ruling.
Superconducting cable (foreground) is able to carry 10 times as much power as traditional cable. (Source: American Superconductor)
Commonwealth Edison is teaming with an engineering company to boost the reliability of Chicago’s electric grid and protect it against terrorism by installing three miles of superconductor cable beneath the city’s Loop district.
Funded in part by a $60 million grant from the Department of Homeland Security, the project is expected to be the first commercial-scale deployment of American Superconductor’s Resilient Electric Grid system (REG).
American Superconductor spokesperson Kerry Farrell said that the project, now in the design stage, will supplement part of ComEd’s underground distribution system.
“Superconductors are an alternative to copper wire – smarter, stronger, smaller. [ComEd] will use the cable to connect existing substations together, increasing the capacity of the grid without rebuilding” or adding more substations or transformers, she said.
The new superconducting cable looks more like ribbon than traditional thick, twisted, sheathed cable and is able to carry 10 times as much power.
“This is the first major deployment of superconducting cable of this size, probably the largest project like it in the world,” Terence R. Donnelly, ComEd executive vice president and chief operating officer, said in an interview. Previous demonstration projects have been deployed in South Korea and with Long Island Power Authority.
In Case of Emergencies
Substations typically serve specific areas and are isolated from one another to prevent a domino-like failure scenario. But that isolation means that one substation is unable to shoulder more of the load in the event another substation is taken out by a storm, technical failure or terroristic attack.
The REG will allow instant transfer of load in such an event, leading to a more robust and reliable system, Farrell said.
Donnelly said the project is part of an effort to update ComEd’s transmission and distribution system.
“We’ve read about threats to electric power grids, such as the attack on the grid in California, and we were looking for ways to use technology to protect against things like superstorms and the possibility of terrorist attacks,” he said. “We wanted to use technology to develop a smarter, more reliable and more secure grid. And we think [the superconducting cable] would provide a solution to back up substations, not in just a catastrophic event, but also in routine operations.”
ComEd selected the Chicago Loop, the city’s central business district, because of its importance “as a key area of trade, finance and government.”
ComEd and American Superconductor declined to put a price tag on the project.
But in a June filing with the Securities and Exchange Commission, American Superconductor reported that the first phase — the evaluation and development of the installation plan — would take six to nine months and cost $1.5 million. The remaining phases of the project would cost the remainder of the $60 million — the total amount of revenue American Superconductor expects from the ComEd project.
After the design stage, Donnelly said it will take two to four years to complete the installation. He said an evaluation will be done to see if the REG should be expanded in the ComEd system, or in the other Exelon-owned systems, Baltimore Gas and Electric Co. and PECO.
