When the Clean Power Plan was released last year, New York’s grid operator was concerned with its impact despite the state’s membership in a regional carbon trading regime.
Changes made in the final plan based on input from grid operators — combined with a more pronounced shift toward gas generation and renewables in New York as new power plants move closer to completion and the state has committed another $1.5 billion for clean energy over the next decade — seem to have allayed those fears.
“Based on our initial review, it appears EPA responded positively to major concerns regarding reliability in the draft rule, and that the final rule is generally favorable to New York,” NYISO spokesman David Flanagan said.
EPA also added a reliability safety valve and a requirement that states seek grid operators’ reliability assessments on their implementation plans.
“A reliability safety valve will allow a state to propose a modified emission standard for an affected generator for a temporary period of time to address an unforeseen emergency situation that threatens reliability,” Flanagan said.
In June, the state committed to reducing all greenhouse gas emissions by 40% from 1990 levels, cutting energy consumption in buildings by 23% from 2012 levels and getting half of the state’s energy from renewable sources.
While New York is ahead of most other states, it will have to make decisions on retirements of aging, fossil fuel plants and the future of the Indian Point nuclear facility.
New England
The New England states — members of the Regional Greenhouse Gas Initiative, along with New York — are generally well ahead of the targets set in the Clean Power Plan, in some cases by several years. EPA has recognized RGGI as a model compliance tool.
Connecticut, Massachusetts and New Hampshire have less stringent goals for the 2022 interim period, reflecting what EPA calls a “smoother glide path.” However, those states have more stringent goals by 2030 compared to other states.
Connecticut’s interim goal is 899 lbs/MWh and its 2030 goal is 786 lbs/MWh; Massachusetts is at 956 and 824, respectively; Rhode Island, 877 and 771; and New Hampshire comes in at 1,006 and 858.
Maine no longer has any of the coal-burning power plants considered the primary target of the emissions reductions. Under the goals, Maine would have to reduce its carbon dioxide emissions per megawatt-hour of electricity by 10.8% by the year 2030.
Vermont is one of three states, along with Alaska and Hawaii, exempted from the rules. Vermont’s largest source of electricity is hydropower imported from Canada. The Green Mountain State has some in-state dams and two wood-burning power generators.
The Union of Concerned Scientists issued a report last week that said the Northeast states are among 20 states that have made commitments (including carbon caps, coal plant closures and mandatory renewable electricity and energy efficiency standards) that put them more than halfway toward meeting their 2030 targets. Sixteen states are likely to surpass the targets, the group said.
FERC last week approved bylaw changes allowing SPP to add up to three seats to the RTO’s Board of Directors.
The revisions also incorporate corresponding modifications to quorum and voting requirements, effective Aug. 15.
SPP President Nick Brown and Board Chair Jim Eckelberger.
SPP’s board is currently comprised of seven independent directors, including President Nick Brown. The RTO says expanding its board to up to 10 persons would “foster a measure of flexibility” and further director succession planning, “with due consideration given to director tenure, knowledge sharing and risk management.”
SPP’s Corporate Governance Committee recommended the revisions in April, when they were approved by the Members Committee.
Brown said last month the governance committee will be evaluating the results of a solicitation for board candidates, the first such search SPP has conducted in seven years. The committee will discuss the issue further during its Aug. 27 meeting.
VALLEY FORGE, Pa., — PJM will continue the generator testing begun last winter with only minor changes after members rejected proposals to expand the program.
More than 62% of more than 130 stakeholders who responded to a poll said they preferred continuing the program — begun last winter in response to the high number of generator outages during the 2014 polar vortex — with only minor changes, PJM’s David Schweizer told the Operating Committee last week.
The proposal included only minor changes requiring generators to submit a primary and alternate date for the exercise; submit results of the exercise to PJM; and report completion of the cold weather preparation checklist through eDART. Manual 14D: Generator Operational Requirements also will be revised to clarify combined-cycle offers for generators exercising one combustion turbine on alternate fuel.
Members rejected three other options that would have made larger changes to the program, including option 2, which would not compensate Capacity Performance resources for participating after the winter 2015/2016. It received only 42% support.
Option 3, which received 34% support, would have expanded the exercise period -– currently the month of December -– to Nov. 1 through Jan. 15; increased the maximum temperature to 40 F from 35 F in the southern zones; and increased the maximum test allowed daily from 1,000 MW to 1,200 MW. It also would have included a reevaluation of the program after winter 2015/16 to determine whether it should be continued.
Option 4, a combination of options 2 and 3, also received 34% support.
The testing, which cost about $7 million last year, was credited with improving generator performance during the winter of 2014/15. (See Why Did PJM Grid Fare Better This Winter?)
PJM Seeks to Eliminate Disconnect on Metering Requirements
PJM plans to modify Manual 1: Control Center and Data Exchange Requirements to “close the gap” between PJM requirements and generator practices regarding metering.
PJM’s Ryan Nice presented the OC with a first read on a problem statement to create a task force to draft new manual language. “Some of these gaps are pretty extensive,” Nice said.
Nice said the revised manual will clearly delineate requirements for monitoring and control metering used by PJM’s state estimator and revenue metering used in settlements.
“This is the raw data” for settlements and operations, Nice said. “So it really behooves everyone to pay attention to this.”
Members should send the names of those interested in joining the task force to ryan.nice@pjm.com.
PJM Moves to Tighten Training, Certification Requirements
The System Operations Subcommittee will consider ways to increase compliance with PJM training and certification requirements under an issue charge approved by the OC.
The SOS will only suggest changes to section 3.3 of Manual 40: Certification and Training Requirements, which deals with compliance, and not to the actual requirements, as detailed in section 3.2, said Glen Boyle, manager of system operator training. The subcommittee’s work will also not deal with North American Electric Reliability Corp. requirements, Boyle said.
PJM has been tracking non-compliance among several generation dispatchers, demand response providers and energy storage device operators for months and the situation has not improved. The subcommittee will “look for options to get these companies back into compliance,” Boyle said. (See “Generators’ Non-Compliance Continues” in PJM Operating Committee Briefs, June 15, 2015.)
PJM also briefed members on other changes to Manual 40. The changes, intended to clarify PJM’s processes, will be brought to a vote at the next OC meeting.
Closed-Loop Interface Set for Dominion Chesapeake
PJM last week declared a closed-loop interface near Norfolk, Va., in the Dominion zone to address voltage or thermal problems that could result from an N-1-1 contingency during transmission upgrades expected to be completed by the end of the year.
The DOM-CHES closed-loop interface near Norfolk, Va. (in blue), was created to address voltage or thermal problems that could result from an N-1-1 contingency during transmission upgrades expected to be completed by the end of the year.
The interface, effective Aug. 14, will allow the RTO to set sub-zonal real-time prices for load management or generation during high load conditions or emergency transmission outages in the Dominion Chesapeake area, protecting the load pocket. The interface would be modeled for the day-ahead market but not for financial transmission rights.
Bath County SPS Extended for Cloverdale-Lexington Outage
PJM will extend the Bath County special protection scheme (SPS) during an outage required for upgrades to the Cloverdale-Lexington 500-kV tie line between the Dominion and American Electric Power zones.
The line is expected to be out of service from January through June 2016 during a reconductoring project and again from mid-September 2016 through mid-October 2016 for replacement of the Cloverdale transformers. The SPS will address the loss of one of six generators in Bath County and potential congestion on a 138-kV line as a result of the outage.
The SPS was initiated in September 2014 for the Dooms-Lexington 500-kV project, which is expected to be complete by the end of 2015.
PJM and Dominion will consider extending the SPS beyond 2016 to address other pending upgrades in the western Virginia area, PJM’s Liem Hoang told the OC.
Behind-the-Meter Initiative Yields 1,000 MW
PJM has identified about 1,000 MW of behind-the-meter generation as a result of an initiative following the September 2013 heat wave that caused two days of load shedding.
PJM was forced to cut power to 44,000 customers in southern Michigan, northern Ohio and northwest Pennsylvania as temperatures unexpectedly hit the mid-90s and the RTO found itself without enough generation during the fall maintenance period.
A third day of load sheds was avoided after the city of Sturgis, Mich., provided 8 MW of relief through conservation and its behind-the-meter generator. PJM had not been aware of the generator before the emergency. (See Heat Wave To-Do List Grows Longer.)
“If we had seen that [generation] early, we have indications that [Sturgis] would have been happy to come on to avoid having to shed load,” PJM Vice President of Operations Mike Bryson told the OC.
As a result of the incident, PJM began seeking information on other behind-the-meter generation in February. The project identified the nearest Bulk Electric System substations, so that operators can conduct distribution factor studies to determine how effective they would be in addressing constraints.
PJM’s Joe Mulhern said any relief from the generators would come on a voluntary basis because the RTO’s current rules provide no way to compel or compensate them. Such generators are eligible for energy market and ancillary service revenues, however.
Bryson said PJM will have to discuss the issue with each of its 14 states individually because of varying jurisdictional rules.
“We would be open to any of these kinds of discussions with them,” Bryson said.
PJM to Tighten Long-Term Transmission Outage Rules
PJM plans to revise its rules regarding long-term transmission outages in order to protect FTR revenues.
The current rules in Manual 3: Transmission Operations require transmission owners to submit any outages longer than 30 days by Feb. 1 so that they can be accounted for in the annual FTR auction.
But Simon Tam told the OC that some TOs have submitted two or more consecutive outages of less than 30 days at the same location and were not covered by the requirement. “Sometimes they’re not able to project every single piece of work they need to do … and need to extend the outage,” he said in a second briefing to the Market Implementation Committee.
Under the new rules, which will be added to the manual during a scheduled revision this fall, PJM will evaluate outages exceeding 30 days on the same line or transformer within an eight-month time span. If the outage causes a shortfall in FTR revenue, PJM will require the TO to reschedule it or pay for the congestion it causes, Tam said. The plan will be phased in over a year for TOs unable to meet the Feb. 1, 2016, implementation.
PPL’s Frank “Chip” Richardson expressed concern with the change at the MIC briefing, saying it could delay upgrades needed for the reliability of the system. He added that TOs have no way to recover congestion costs they might be assessed.
“We’re not going down the road of wanting TOs to pay for congestion,” Tam responded. “The intent is for the TO to do a little more advanced planning.”
If the upgrade in question is critical and should not be delayed, PJM can declare an emergency and the TO can complete the upgrade without a congestion charge, Tam said.
The New York Public Service Commission on Thursday approved a temporary 5.2% rate surcharge on delivery charges for Rochester-area electric customers, while a final agreement to keep the R.E. Ginna nuclear plant operating is hammered out.
The commission approved the surcharge, effective Sept. 1, to prevent “rate shock” while the final price tag for a reliability support services agreement is negotiated between Rochester Gas & Electric and Constellation Energy Nuclear Group, the plant’s owner (14-E-0270).
Industrial customers, environmentalists and consumer advocates had opposed the surcharge, arguing that the need for an increase was hypothetical until the RSSA is finalized.
The PSC, which had ordered the agreement to keep the plant operating until transmission alternatives are built, rejected requests to wait until the final costs were determined.
“If the commission does nothing, the costs associated with the RSSA, if later approved, could build to … being more than a 20% increase,” said Doris Stout, director of accounting at the PSC.
PSC staff estimated the rate increase would be about 10.4% if collection was delayed until January. RG&E estimates that its deferred collection will reach approximately $39.3 million from the effective date of the RSSA through the end of this month and will continue to grow, with interest.
RG&E has a balance of about $155 million in rate credits, which opponents of the rate surcharge want to use. Stout said using too many of these credits would adversely affect RG&E’s credit. PSC staff recommended, and the commission approved, that customer credits would be used to make up the difference between the amount collected from the surcharge and the cost of the RSSA.
The 5.2% rate was chosen in part because it matches estimates of the first-year revenue requirement for the Ginna Retirement Transmission Alternative, a project that would eliminate transmission constraints preventing the delivery of more generation into the Rochester area. PSC staff estimate the project will cost almost $140 million, with an in-service date of May 2017.
“I think what the staff has proposed here today is an elegant solution to a difficult problem,” Commission Chair Audrey Zibelman said at the meeting, citing the need to avoid rate compression while preserving the RG&E’s financial stability.
“I thought it made a huge amount of sense to say let’s set the level of the surcharge at the expected level of the transmission replacement because that’s a cost we know will be a long-term cost for the company to incur,” she added later.
Stout noted that requests for temporary rate increases are rare, saying the last she recalls was in 1996 for Niagara Mohawk.
“Although the scope and nature of RG&E’s ultimate liability to Ginna is uncertain, given that the RSSA may not be approved in its current form or at all, the reasonable costs of the reliability service obligation that was imposed upon Ginna in November ultimately must be recovered in some fashion,” the commission wrote. “An important element of just and reasonable rates is price stability and the avoidance of rate shock to consumers from sudden, significant increases.”
The agreement, set to be retroactive to April 1 once approved, would cost about $175 million a year and be effective through late 2018. Constellation said it wants to retire Ginna, which it says it lost more than $150 million between 2011 and 2013.
Ginna Negotiators File Extension
Negotiators for Exelon and RG&E have asked for a second extension as they try to hammer out an agreement to keep the plant operating.
“We will be seeking another short-term extension to allow for continued negotiations. Exelon remains committed to working with RG&E and a number of stakeholders to reach an agreement that will allow Ginna to continue providing safe, reliable energy to the region,” Exelon spokeswoman Maria Hudson said.
Under the terms of the RSSA, Exelon could have ended negotiations and closed the plant this month. The companies had asked on July 31 for an extension that expired Monday.
Meanwhile, a New York power plant owner asked FERC on Wednesday to rehear its complaint that the Ginna agreement is suppressing capacity market prices (ER15-1047).
The company said Federal Power Act Section 205 gives FERC jurisdiction over the “price-suppressive” effects of the RSSA and that the commission misunderstood the company’s reasoning.
“The commission should grant rehearing because its failure to consider whether the RSSA is just and reasonable in light of the effect it will have on the rates the NYISO pays to suppliers in NYISO’s capacity market is in violation of the commission’s statutory duty, in contradiction of prior commission orders and judicial precedent, and is arbitrary, capricious and not based on substantial evidence,” the petition states.
ISO-NE and the New England Power Pool Participants Committee want to begin using the RTO’s system-wide sloped demand curve in their Annual Reconfiguration Auctions.
The organizations submitted proposed Tariff changes to FERC that would apply the curve — first used in the ninth Forward Capacity Auction earlier this year — to the ARAs beginning in June 2016 (ER15-2404).
Under the current rules, demand in ARAs is represented by the fixed value of the installed capacity requirement.
The proposed changes “simply incorporate the system-wide demand curve used in an initial Forward Capacity Auction into the Annual Reconfiguration Auctions so that demand will be represented consistently in both FCAs and ARAs,” the petition said.
“Such consistency in the demand model from auction to auction avoids predictable, structural price differences,” Matthew C. Brewster, lead analyst in ISO-NE’s market development department, wrote in accompanying testimony.
Demand in import- and export-constrained capacity zones will continue to be established by local sourcing requirements and maximum capacity limits, respectively, the RTO said.
The RTO will conduct three ARAs to allow for the exchange of capacity supply obligations prior to the 2018/19 capacity commitment period covered by FCA 9.
The changes would not affect how suppliers participate in reconfiguration auctions. But unlike current rules, in which clearing occurs only through matching of counterparty offers and bids, clearing would occur using the demand curve, even without a counterparty.
The changes received the unanimous support of the NEPOOL Participants Committee and near-unanimous support from the NEPOOL Markets Committee.
Power generators have opposed a system-wide sloped demand curve and advocate a zonal demand curve to reflect capacity constraints in parts of New England. (See ISO-NE, NEPOOL Oppose Demand Curve Change.)
VALLEY FORGE, Pa. — PJM planners have selected 11 small market efficiency projects and narrowed the list of proposals for its biggest congestion problem to 12 candidates.
The 11 projects — all transmission owner upgrades — have a combined cost of $59.2 million, with a benefit-cost ratio of 15.6 and estimated 2019 congestion reductions totaling $50 million. The PJM Board of Managers is expected to consider planners’ recommendations of the projects at their meeting in October.
“These are all locational type projects … they’re cheap fixes basically,” PJM’s Tim Horger told the Transmission Expansion Advisory Committee on Thursday. Over 15 years, “you’re going to see hundreds of millions” in savings.
The 12 proposed fixes for the AP South/AEP-DOM constraints will undergo further analysis, including an initial cost review and sensitivity analyses for changes in load forecasts, fuel prices and interface ratings.
About 20 of the larger proposals passed the 1.25 benefit-cost threshold. The 12 finalists are those that continued to meet the 1.25 threshold using a base case incorporating the 11 small projects and also reduce congestion for combined 2019 and 2022 simulations with minimum production costs and load payment savings of $20 million.
They range in cost from $15.7 million to $300.7 million.
Vice President of Planning Steve Herling said it was possible — though unlikely — that the AP South/AEP-DOM fixes could displace one or more of the 11 smaller local projects. “We’ll pull one of [the smaller projects] out of there if we have to,” he said.
Sharon Segner of LS Power questioned PJM’s method of winnowing the list, saying the RTO’s Tariff requires such projects be based only on the zone seeing reduced load payments.
(Click to zoom.)
“When you have multiple projects that all pass, the Tariff doesn’t tell us how to decide [among them],” Herling responded. “We’re having to use our judgment.”
Segner said PJM had told stakeholders that selections would be made based on the highest cost-benefit ratios. “That’s what motivates the market,” she said. “Otherwise it becomes pretty subjective and loosey-goosey.”
In total, PJM received 93 market efficiency proposals, including 35 transmission owner upgrades ranging from $100,000 to $68 million and 58 greenfield projects with costs of $9.2 million to $432.5 million.
Second Proposal Window Opens
PJM opened a second transmission proposal window Aug. 5, seeking solutions to 2020 transmission owner criteria violations and reliability problems identified from planners’ light load analysis. The RTO will accept proposals through Sept. 4.
No Projects Arise from ARR Review
The annual review of auction revenue rights feasibility resulted in no transmission upgrade projects, planners said. Already-approved upgrades were identified for violations on most of the 45 paths analyzed over the 10-year horizon. Three paths in the ATSI zone that saw violations in years nine and 10 will be monitored for potential upgrades in the future.
PJM: Despite Lack of Cost Allocation Rules, MISO Project Too Good to Ignore
PJM doesn’t know how it would allocate costs from its share of a potential transmission upgrade MISO is considering in southern Indiana, but the project’s potential to fix longstanding stability problems at American Electric Power’s Rockport substation is too compelling to ignore, planners said.
“The challenge is this is a market efficiency project in MISO and a reliability project in PJM” — a combination for which there are no cost allocation rules in the PJM-MISO joint operating agreement, Herling said. “This is just such a good opportunity we don’t want to let it go by.”
The area has added thousands of megawatts of generation but no new transmission since 1989. As a result, the Rockport substation has operated under a special protection scheme involving relays, and tripping and ramping down of generators. About 4,400 MW of generation was tripped in a 2007 incident.
PJM will have to move quickly; MISO planners intend to recommend the winning project to the MISO Board of Directors in December.
Initial results of PJM’s analysis are expected in time for MISO’s Aug. 19 Planning Advisory Committee meeting.
“It could be a win-win,” said PJM’s Chuck Liebold.
Planners Reevaluating Pratts Project
PJM is reconsidering its selection of the Gordonsville-Pratts-Remington transmission upgrade after learning that it will require 15 to 18 miles of new right of way, far more than initially believed.
In February, planners recommended the proposal from Dominion Resources and FirstEnergy at an estimated cost of $129 million to $164 million.
“We want to double check to make sure we’re doing the right project,” said General Manager of System Planning Paul McGlynn, who said planners will evaluate a Gordonsville-Remington route among the alternatives.
The Virginia State Corporation Commission, which would have to approve the project, says that existing rights of way should be given priority as the locations for transmission additions.
A representative for Madison County, Va., urged PJM to reject the original plan. He said the scale of the project is out of proportion to the rural county — population 13,000 — which is dependent solely on farming and tourism and has no public water or sewers. “That’s the question — the need versus what’s being proposed,” he said.
McGlynn noted, however, that the project is not being driven solely by load in the Pratts area.
PJM solicited solutions in its second Order 1000 proposal window last year.
Four developers suggested 16 proposals, including two transmission owner upgrades and 14 greenfield projects. Only six of the proposals were judged to have solved the violations. Two losing bidders, ITC Holdings and LS Power’s Northeast Transmission Development, have challenged the choice in letters to the PJM board. (See Tx Developers Challenge PJM Choice on Pratts Project.)
Planners will reevaluate the options in September and make a recommendation to the board in October.
It had been four years since ERCOT last set a new demand record, but the Texas grid has been making up for lost time since August began. In the last two weeks, ERCOT has set three new hourly peaks, topping 69,000 MW in demand for the first time ever on Aug. 10.
ERCOT says while the summer temperatures are partly attributable to the increase, the state’s explosive population growth is the real driver.
“A large part of the demand we’re seeing is customer growth over the last few years,” said ERCOT COO Brad Jones last week.
Jones made his comments a few hours after ERCOT issued a conservation alert and asked customers to limit electricity usage during the 3-7 p.m. peak-demand hours Aug. 13. Triple-digit temperatures and outages at several power plants brought the ERCOT system perilously close to its 2,500-MW reserve threshold.
The system set a new all-time peak hourly demand Aug. 10 when it eclipsed the 69,000-MW mark for three consecutive hours, hitting a record 69,783 MW between 4 and 5 p.m. Operating reserves remained above 3,000 MW during the day, Jones said.
ERCOT previously set demand records Aug. 6 (68,912 MW) and Aug. 5 (68,459 MW). Until then, the ISO’s previous record was 68,305 MW, set Aug. 3, 2011.
At this pace, ERCOT will surpass August 2011’s record production of 38.2 GW of energy.
Jones said ERCOT imported power through its two links with SPP but avoided calling for load curtailments or other emergency operations thanks to conservation by consumers. Market prices jumped to about $1,700/MWh during the day.
Population Growth
The U.S. Census Bureau says Texas’ population has grown by 1.8 million people from 2010 to 2014, a 7.2% increase. The state’s population — almost 27 million at the end of 2014 — is expected to double by 2050.
According to the state comptroller, more than 100,000 single-family building permits and 64,000 multi-family permits have been issued in the 12 months ending June 2015.
The comptroller also said Texas’ real gross domestic product grew by 5.2% in 2014, compared with 2.39% for the U.S. The state’s unemployment rate was 4.2% in June, down from 5.0% in June 2014; it has been at or below the national average for 102 consecutive months.
Jones noted ERCOT serves some of the fastest-growing cities in the country. Houston, San Antonio, Dallas, Austin and Fort Worth are among the 16 most populous cities in the U.S.
Some 4,800 MW of new generation will be coming online in the next three to four years, Jones said.
ERCOT said it will continue to monitor conditions as summer demand continues and call for conservation when needed. It has asked Texans to raise thermostats 2 to 3 degrees during peak hours, use fans, limit the use of large appliances to off-peak hours and close blinds and drapes during the afternoon.
“Voluntary conservation can help us reduce the potential for additional measures, such as rotating outages, to ensure reliability throughout the ERCOT grid,” said ERCOT’s Director of System Operations, Dan Woodfin, in one of many press releases the ISO has issued this month.
SPP: Hot, but not Breaking Records
The SPP footprint has seen some of the same triple-digit figures as Texas, but the RTO has not topped its record demand peak of 54,949 MW, set Aug. 3, 2011. Its high for the year came in July, when the SPP Balancing Authority recorded a peak of 45,873 MW.
LITTLE ROCK, Ark. — SPP announced Monday it has appointed former FBI agent Mark Bowling as its director of compliance and security. Bowling will oversee SPP’s compliance policies and procedures, including national and regional reliability standards and tariff provisions, and he will be responsible for corporate security monitoring and response.
Bowling
Bowling, who served as an FBI special agent for 20 years, also worked for the U.S. Department of Education Office of Inspector General. He has investigative experience in computer intrusion, computer fraud, counter-terrorism, national security and counterintelligence. Prior to joining the FBI in 1995, Bowling was a naval nuclear engineering officer with the United States Navy for six years.
Michael Desselle, SPP’s vice president of process integrity and chief compliance and administrative officer, said Bowling’s “expertise in identifying and mitigating cyber threats will be extremely beneficial in leading the effort to protect our critical infrastructure assets.”
The power outage that darkened the White House and much of D.C. on April 7 began with the failure of a 230-kV lightning arrester in the Pepco portion of the Ryceville, Md., substation 40 miles south of the district, according to a briefing by the North American Electric Reliability Corp. last week.
The outage, which caused a “severe, prolonged voltage sag” in the D.C. area, began about 12:39 p.m. when Pepco’s protection systems failed to isolate a fault on the 230-kV line.
Two separate and redundant protection systems failed, the first as a result of a loose connection to an auxiliary trip relay circuit, the second due to “intermittent discontinuity” in an auxiliary trip relay circuit, according to a presentation to NERC’s Member Representatives Committee.
NERC presentation shows damaged lightning arrester at Pepco substation.
Pepco and Southern Maryland Electric Cooperative lost 532 MW of load for as long as two hours. Some customers automatically switched to back-up power sources, while customer protection systems separated others from the grid due to low voltage. The outage affected the Maryland peninsula bounded by the Potomac River on the west and the Chesapeake Bay on the east.
Panda Power’s Brandywine 202-MW combined-cycle plant and the Calvert Cliffs nuclear units 1 and 2 (1,779 MW) tripped offline. Brandywine returned to service after about an hour; Calvert Cliffs returned two days later.
Investigators found damage to an A-frame structure at the Ryceville substation, including pitting near burned arresters and a downed static wire. An A-phase conductor was found detached outside the fence line.
There was no evidence of burning to the A-phase arrester, suggesting that mechanical failure resulted from the arc burning off the insulator and the weight of the line breaking the arrester free from the structure.
Talen Energy released its first earnings report as an independent company last week, reporting net income of $26 million ($0.26/share) for the second quarter of 2015.
That’s based mostly on “legacy” data from the company’s plants, which were owned by PPL and Riverstone Holdings before Talen’s formation on June 1. Collectively, these plants’ profits doubled from $13 million ($0.13/share) in the second quarter of 2014. The company’s operating revenue stayed consistent for both periods, at $1.07 billion.
“Strong operational performance from our nuclear and gas generation assets led to improved financial results in the quarter,” CEO Paul Farr said in a statement.
During a conference call with investors, Farr said the Susquehanna nuclear plant performed well in spite of Unit 2’s cracked turbine blades, which have now been repaired. Talen will replace the blades for both Units 1 and 2 during the plant’s next scheduled fuel outage.
Farr also said that Talen will announce by the fourth quarter what assets it will be divesting to meet FERC’s conditions for approval of the company’s creation.
Despite the company’s optimism, Talen’s stock price remains low, closing at $15.95 last week. That’s well below the $20/share when the company went public.
“We do not believe our current share price reflects the underlying value of our business, and capital discipline will remain our top priority,” Farr told investors.
Upcoming Transactions
Talen reported adjusted EBITDA of $171 million for the quarter, a 35% increase over the same period last year.
Talen predicts EBITDA of $990 million for 2016 based on two deals expected to close by the end of the year.
One is the acquisition of three plants from MACH Gen that will see the company enter the NYISO market. (See Talen Entering NYISO in $1.2B Deal.)
The other is the sale of its renewable energy business to California-based Energy Power Partners. The deal was announced in June, and Talen filed for FERC approval earlier this month (EC15-182).
The $116 million sale ($1,785/kW) includes 25 wind, solar and biofuel facilities totaling 65 MW in PJM and ISO-NE.
