SPP last week issued its first competitive transmission solicitation, inviting developers to bid on construction of a 21-mile 115-kV line between North Liberal and Walkemeyer in southwestern Kansas.
The SPP Board of Directors approved staff’s recommendation that it authorize construction of the project on April 28.
The board originally approved the project in January but asked staff to evaluate an alternative proposed by Sunflower Electric Power that would have delayed the line by relying on operating guides for Sunflower’s 76-MW Cimarron River Station to provide relief from thermal or voltage violations. (See Walkemeyer Transmission Projects Wins SPP OK.)
The request for proposals (SPP-RFP-00001) was sent May 5 to transmission developers that had cleared the RTO’s qualification process.
It is SPP’s first competitive solicitation under the Federal Energy Regulatory Commission’s Order 1000, which removed federal rights of first refusal for incumbent transmission owners. An “industry expert panel” will review, rank and score proposals received.
VALLEY FORGE, Pa. — Despite a fee structure designed to encourage early submissions, PJM continues to receive too many interconnection requests late in the queue. As a result, planners introduced a problem statement and issue charge at the Planning Committee last week to find a better solution.
Planners proposed a new task force whose key assignment would be to “remove ineffective methods and identify new methods to incentivize new service customers to enter the queue earlier,” according to the issue charge.
“We’re of a mind that some of the rules need to be stripped out and replaced with something else,” said Steve Herling, PJM’s vice president of planning. “If it doesn’t serve a purpose, then maybe we strip that out, but it has to be replaced with something to incentivize.
“Maybe if you come in late and you’re deficient, you get first in line in the next queue,” Herling said. “If it’s time to start and you’re not on the boat, you wait for the next one.”
Herling said the problem statement would be returned to the committee next month for refinement.
Planners told the PC in January that they would be seeking stakeholder input on how to incent interconnection customers to submit their requests earlier. (See PJM to Try Again to Speed Interconnection Filings.)
Under the current structure, the deposit for applications filed in the first four months is $10,000; for the fifth month it is $20,000; and for the last month, $30,000. Nevertheless, about half of all queue submittals are filed in the last month, and about one-third in the final day of the window, creating a workflow crunch for planners.
Could Planning Upgrades Help Mitigate Uplift?
The PC began work on an assignment from the Markets and Reliability Committee to consider uplift among the problems to be addressed by grid upgrades under the Regional Transmission Expansion Plan.
Since July 2013, the MRC’s Energy Market Uplift Senior Task Force has been studying ways to reduce out-of-market make-whole payments, such as those for generators usually needed only for voltage support. So far this year, PJM has accrued $193 million in uplift charges, including $105 million in February alone.
“Are there [transmission] upgrades that might be more cost effective than running the generation that we’re currently operating?” asked Adam Keech, senior director of market operations.
Herling encouraged stakeholders to think about how to identify problems. He said the PC would conduct more substantive discussions at the next meeting.
PAR Charter Not Ready for Endorsement
The PC postponed a vote on the charter for a group charged with considering phase angle regulator transmission injection and withdrawal rights after a stakeholder complained that it had been posted too late under PJM rules.
The group will consider whether and how PARs can participate in the market and receive injection and withdrawal rights at PJM’s border, PJM’s Aaron Berner said.
The group will meet next on Thursday and is continuing to look for stakeholders interested in participating. So far, he said, about 20 have expressed interest.
Federal regulators last week said they support a settlement under which Ameren Illinois would refund $7.1 million to resolve a dispute over its purchase of Central Illinois Light Co. in 2003 and Illinois Power in 2004.
The settlement was filed April 14 by Ameren and a customer group consisting of the Illinois Municipal Electric Agency, Prairie Power Inc., Southern Illinois Power Cooperative and Wabash Valley Power Association. Federal Energy Regulatory Commission trial staff filed initial comments in support of the settlement on May 4 (AC11-46).
At the heart of the case is how Ameren Illinois accounted for goodwill in connection with the acquisition of the two Illinois utilities when it conducted a corporate reorganization in 2010.
As part of the reorganization, $197 million of goodwill that had been on Central Illinois’ books and $214 million of Illinois Power goodwill were transferred to Ameren Illinois.
In July 2012, FERC determined that Ameren Illinois and its predecessors had inappropriately included the $411 million in their common equity. The inflated rate base resulted in excess collections from ratepayers.
FERC also said the improper inclusion of goodwill in equity caused excessive collections under Allowance for Funds Used During Construction.
In a 2012 refund report required by FERC, Ameren contended it did not owe a refund. Even after removing goodwill from its capital structure, the company said, it was owed $19.7 million, plus $3 million in interest, because it had failed to include the cost of debt redemptions in Ameren and Illinois Power’s annual transmission revenue requirements from 2005 to 2012. FERC rejected Ameren’s claim in 2013, saying its proposed adjustments went beyond the scope of its July 2012 order.
The proposed $7.1 million refund would be paid to network integration transmission service customers for the period from June 1, 2005, through Dec. 31, 2014. The amount will be reduced by $2.1 million if a refund is ordered in a separate docket over Ameren’s booking of income tax overpayments (FA13-1).
If the settlement is approved by FERC, Ameren would also have to make adjustments to its common equity for Attachment O, removing $291.8 million for 2013 and $292.2 million for 2014.
A former Soviet spy who lived in the United States for more than 35 years under an assumed identity has been working since 2011 as director of software development for NYISO but never had access to any sensitive data or operations, officials said.
The power grid operator responded to a CBS “60 Minutes” report that aired Sunday, in which “Jack Barsky” revealed his Cold War past, when he posed as an American in the 1970s and 80s in the hopes of gaining access to high ranking government officials.
Born Albrecht Dieterich in East Germany, he was recruited by the KGB as a student. He assumed the identity of Jack Barsky after Soviet agents provided him the birth certificate of an American boy who died at age 10.
Barsky told CBS he was directed to infiltrate the office of Zbigniew Brzezinski, President Jimmy Carter’s national security adviser from 1977-1981 but never got close to the official. He said his biggest coup was providing Soviets enterprise software designed by an insurance company for which he worked.
Barsky, who lives northeast of NYISO headquarters in Rensselaer, was placed on administrative leave recently when he told the ISO he was going to be the subject of a “60 Minutes” report.
According to his LinkedIn profile, Barsky came to NYISO after serving as chief information officer for NRG Energy from 2006 to 2010 and ConEdison Solutions from 2002 to 2006. The companies confirmed his employment to Capital New York.
“According to the story on ‘60 Minutes,’ Mr. Barsky appears to have had regular contact with the FBI over a period of many years that was not publicly disclosed. The FBI generally informs a company such as the NYISO of any potential cyber security threat of which it is aware. We have a long standing and productive relationship with the FBI and at no time did the FBI indicate that this employee posed a threat,” NYISO spokesman David C. Flanagan said.
“Out of an abundance of caution, we have conducted internal forensic reviews of physical and computer records and have not discovered any security threats or any indication that the employee engaged in improper behavior. The employee did not have direct access to grid operations or energy market systems that would enable manipulation of software. Further, the individual did not have physical access to our control rooms.”
Flanagan said NYISO has hired an outside firm to “to conduct a separate analysis to confirm our findings.”
Flanagan would not say if the recent departures of two NYISO executives — Jennifer Chatt, vice president for human resources, and Tom Rumsey, senior vice president of external affairs — were related to the Barsky revelation. Rumsey’s departure came just weeks after he received a promotion announced in January. (See NYISO CEO Stephen Whitley to Retire in 2016; Dewey, Rumsey Promoted.)
According to the “60 Minutes” report, Barsky was discovered in 1997 by the FBI, when he was working as a computer programmer in New Jersey. His last name had appeared in materials provided to the government by a KGB defector in 1992.
Barsky was never arrested or charged, as the FBI determined he would be of no value in jail; he was more useful living freely as he was debriefed about KGB operations.
Barsky had been ordered back to Germany in 1988 when the Soviets told him his cover had been blown, but he refused out of devotion to his American child. Under the threat of death, Barsky told “60 Minutes,” he concocted a story that he was suffering from AIDS and could only be treated in the U.S. The Soviets left him alone and he continued to live and work undetected.
Barsky, 70, told the Albany Times-Union that he is writing a book about his life.
PJM’s regulation market is purchasing too much from fast-responding “RegD” resources, negatively affecting regulation and reliability, at the same time the RTO is incorrectly compensating those providers, the Independent Market Monitor said in a report presented last week to the Operating Committee.
Howard Haas of Monitoring Analytics said the root of the problem is an incorrectly defined marginal benefit factor that describes the relationship between RegD and traditional RegA resources.
While the MBF should be indicating when there is a diminishing return on the use of either resource, it has resulted in the over-procurement of RegD. In addition, it has led RegD resources to be alternately overpaid and underpaid. On average, Haas said, RegD resources have been undercompensated 46% from October 2012 through March using the current method.
“We never seem to be paying it the right amount,” Haas said. “It’s sending a strange signal to the market.”
PJM operators already had observed decreased market optimization during times when a large percentage of RegD is on the system. It provides more than 42% of response on average, shooting up as high as 70% during some events.
Last week, PJM presented the OC with a problem statement and issue charge to investigate the issue. The IMM wants to add to the inquiry an investigation into how the MBF is being defined and applied.
“If we follow it through, we’re going to correct more than one issue,” Haas said.
However, stakeholders agreed that the problem statement had been so substantially broadened since it was initially proposed that it was not ready for a vote. (See “Too Much of a Good Thing? PJM Concerned Fast Response Regulation Crowding Out Traditional Resources”, PJM Operating Committee Briefs.)
Instead, it will be reworked in a series of special OC meetings.
ISO-NE said a power plant owner facing millions in what it says are mistaken capacity charges had plenty of time to correct the record, and that amending auction results after the fact would undermine the market.
Canal Generating Plant
GenOn Energy Management, a unit of NRG Energy, asked the Federal Energy Regulatory Commission last month for relief from what it called an “anomalous, illogical and patently unfair circumstance.”
GenOn said ISO-NE credited its Canal 2 generator in Sandwich, Mass., with capacity of only 303 MW — rather than the plant’s actual 556.5-MW output — in the March annual reconfiguration auction (ARA) for the 2015-2016 capacity commitment period that begins June 1. (See ISO-NE Error Could Cost GenOn Millions.)
GenOn said the RTO mistakenly underestimated the plant’s capacity and then submitted a demand bid on GenOn’s behalf for the difference, forcing the company “to buy out of a capacity supply obligation that Canal 2 is fully capable of fulfilling.”
In an answer, ISO-NE said it was GenOn’s responsibility to correct the capacity values the RTO posted in October in preparation for the auction and that granting its request would set a dangerous precedent (EL15-57).
“The ISO is not in a position to discern the soundness of, or reasoning behind, the business-related actions (or inactions) of active and sophisticated market participants like GEM, much less to prevent them from making costly mistakes,” ISO-NE wrote.
“Granting the requested relief would undermine important principles of auction finality, eroding certainty and confidence in the markets and setting a possibly dangerous precedent,” ISO-NE continued. “Finally, the March 2015 ARA results are used as inputs to monthly bilateral arrangements and monthly reconfiguration auctions; these processes are already underway, and a change to the March 2015 ARA results could cause significant disruption.”
ISO-NE also said similar “corrections” could cause substantial harm to other parties. “If the March 2015 ARA had instead included more supply offers than demand bids, post hoc removal of the Canal 2 demand bid would have required a re-running of the auction and would have stripped some of the resources of the capacity supply obligations acquired in the first iteration.”
Increased electric infrastructure investments in Illinois helped boost Ameren’s first-quarter profits by 12.4%.
The St. Louis-based utility reported net income of $108 million ($0.45/share) compared to $96 million ($0.40/share) last year. The earnings-per-share results were 7-10 cents higher than analyst estimates.
Revenue was $1.56 billion compared with $1.59 billion a year earlier.
Ameren said it benefited from increased electric delivery and transmission infrastructure investments and from an order by the Illinois Commerce Commission approving recovery of additional costs, which added 4 cents to earnings.
The regulatory climate in Missouri was less favorable, reflecting a reduction in allowable cost recovery for vegetation management, infrastructure investment costs and certain storm costs. The state also reduced return on equity to 9.53% from 9.8%.
Even so, Ameren held firm on its estimated full-year diluted earnings per share of $2.45 to $2.65.
Weather, Integrys Merger Costs Bruise Wisconsin Energy Q1 Earnings
Wisconsin Energy said first-quarter profit fell 6%, citing a warmer winter than a year ago and the costs related to its proposed acquisition of Integrys Energy.
The company reported net income of $195.8 million ($0.86/share) compared with $207.6 million ($0.91/share) in the first quarter of 2014. Revenues fell 18% to $1.39 billion. The company said 2014 revenues were higher due to the polar vortex and higher spot market prices for natural gas.
The Federal Energy Regulatory Commission and the Michigan Public Service Commission have already approved the Integrys deal. The Wisconsin Public Service Commission last month indicated it will likely approve the deal, to the chagrin of industrial and consumer groups that want Wisconsin Energy to promise specific rate savings to customers as a result of the $9.1 billion merger. Regulators in Illinois and Minnesota have yet to sign off on the deal.
Nuke Charge Slams Xcel Energy’s Q1 Profit
Xcel Energy’s first-quarter net income fell 41% from a year earlier on a milder winter and a $129 million pre-tax loss related to a 2013 upgrade of its Monticello nuclear plant.
The Minneapolis-based company reported a profit of $152 million ($0.30/share) compared with $261.2 million ($0.52/share) in the first quarter of 2014.
Profits took a 16 cents-per-share hit due to the loss stemming from the Monticello project. In 2013, Northern States Power-Minnesota completed a project to uprate the Monticello nuclear facility to 671 MW from 600 MW, at a cost of $748 million.
That was more than a 2008 estimate of $320 million. The Minnesota Public Utilities Commission completed a prudence review in March, determining that $333 million of the costs must be recovered over the life of the project.
Revenues of $2.96 billion were down 7.5% from the same quarter last year, largely on milder winter weather that reduced consumption.
Xcel reaffirmed full-year earnings per share of $2 to $2.15.
If the Federal Energy Regulatory Commission keeps its word, virtual traders in PJM should have clarity by the end of October on whether up-to-congestion transactions will be subject to additional charges.
In opening a section 206 docket on the issue last year, the commission said it would rule within five months after it receives comments following a technical conference.
The technical conference was held Jan. 7. On April 29, the commission issued the request for follow-up comments, which are due May 29 (EL14-37).
In September, FERC ordered the 206 proceeding to determine whether PJM is improperly treating UTCs differently than incremental offers (INCs) and decrement bids (DECs). While INCs and DECs are charged uplift and subject to the financial transmission rights forfeiture rule, UTCs are exempt from both.
UTC trading volumes collapsed after Sept. 8, the refund-effective date set by FERC for any uplift assessments. Some financial traders have discussed an interim fee on UTCs in an effort to encourage trading pending resolution of the case. (See Cool Response to Proposed 7-Cent Fee on Virtual Transactions.)
Among the questions on which FERC solicited comment were:
How should the injection/withdrawal points for the virtual transaction be identified?
Should the defined “worst case” node be limited to the market participant’s own transactions?
Should the FTR forfeiture rule collectively assess the net impact of a market participant’s entire portfolio of INCs, DECs and UTCs instead of the current rule, which assesses virtual transactions one at a time?
Should counter-flow FTRs and bids that relieve congestion remain exempt from FTR forfeiture rule calculations? Should financial transactions that improve day-ahead and real-time market price convergence be exempt from the forfeiture rule?
Should UTCs be assessed uplift?
Do UTCs impact unit commitment decisions?
Should market participants be allowed to net INC and DEC transactions for the purpose of uplift allocations?
Extreme winter temperatures, while not as severe as last year, continue to play a major role in companies’ earnings results and business strategies.
PSEG
Public Service Enterprise Group reported 2015 first-quarter net income of $586 million ($1.15/share) compared to $386 million ($0.76/share) for the same period last year, a 52% increase.
While the company cited the strong performances of Public Service Electric & Gas and its generation business PSEG Power, operating earnings only increased slightly from the previous year and revenue dipped slightly. The biggest boon for the company was a $264 million settlement it reached with its insurers to recover losses due to Superstorm Sandy, $159 million of which is reflected in the first-quarter report.
PSEG had filed a lawsuit against the insurance companies in the summer of 2013, claiming they had denied it full coverage for its losses. A New Jersey Superior Court judge sided with the company in March. “The claims related to Superstorm Sandy insurance coverage are now fully resolved,” PSE&G spokeswoman Karen Johnson said.
Operating earnings for PSEG Power fell slightly by 5%, but due in part to the settlement, the business’s net income rose from $164 million to $335 million, a 105% increase. Most of the settlement money was for damages to the subsidiary’s plants.
“PSE&G is delivering on the promise of its expanded distribution and transmission investment program, while the reliable performance of PSEG Power’s generating assets and its gas market expertise during one of the coldest winters on record helped us deliver value for our customers,” CEO Ralph Izzo said.
Duke
Duke Energy reported 2015 first-quarter net income of $864 million ($1.22/share) on $6 billion in revenue.
While revenue fell from the nearly $6.3 billion it brought in a year ago, Duke’s earnings per share were well above analysts’ expectations of $1.14/share. A year ago, the company posted a first-quarter loss of $97 million after a $1.4 billion write-down of its Midwest Generation business. In March, Duke completed a $2.8 billion sale of the business to Dynegy.
Duke’s domestic utility businesses performed well despite the challenges of multiple winter storms, including Duke Energy Carolinas customers setting a record on Feb. 20 for peak use, CEO Lynn Good said. This offset weak international results, due in large part to an ongoing drought in Brazil that drove up the cost of purchased hydropower.
FirstEnergy
FirstEnergy’s first-quarter net income rose almost 7% to $222 million ($0.53/share) despite a 7% drop in revenue to $3.9 billion, the company said. Last year it reported earnings of $208 million ($0.49/share) on first-quarter revenue of $4.2 billion.
In an earnings call with analysts, CEO Charles Jones cited a revised strategy in the company’s competitive sales business as the primary driver of both the increased earnings and decreased revenue. FirstEnergy reduced its predicted annual load obligation to 68 million MWh, compared to 99 million last year, Jones said. The company also reduced the number of residential and small business customers it serves in weather-sensitive areas.
“This strategy, together with improved plant operations, helped to mitigate the potential downside from this year’s severe first-quarter weather and demand conditions, even though our region experienced four more below-zero days this February than last January,” Jones said. He also noted that PJM set a new winter demand peak in February. (See Cold Sends PJM to New Winter Record.)
The company also cited an increase in earnings from its regulated transmission segment, a result of prior investments, it said.
Dominion
Dominion Resources reported a 41% increase in net income for the first quarter, from $379 million ($0.65/share) last year to $536 million ($0.91/share) this year.
Operating earnings for the quarter, however, fell nearly 4%, and revenue fell 6%, from $3.63 billion last year to $3.41 billion this year. While earnings were largely the same from last year across most segments, Dominion noted a drop in its merchant generation business — earnings fell by nearly 9% — as one of the primary factors in the decrease in operating earnings.
CFO Mark McGettrick told investors that the drop was primarily due to poor power prices for its merchant generation in New England. Otherwise, weather conditions in the company’s service areas were “favorable,” which added 5 cents more per share in operating earnings than normal, he said.
PPL
PPL more than doubled its first-quarter profits, reporting earnings of $647 million ($0.96/share) versus $316 million ($0.49/share) in 2014.
Revenues were $3.17 billion, up from $1.19 billion in the first quarter of 2014, when it recorded $1.46 billion in losses on physical and financial commodity sales.
The company cited strong results from its regulated operations in the United Kingdom, Pennsylvania and Kentucky and earnings from infrastructure investments.
PPL expects to close the spinoff of its competitive generation business into Talen Energy on June 1.
“Moving forward as a purely regulated utility company, we remain confident in our ability to achieve annual earnings growth of 4 to 6% through at least 2017, based on the continued strong performance of our regulated businesses, the rate base growth expected from significant projected infrastructure investment and $75 million in targeted, corporate support cost savings that have been identified as part of our corporate restructuring,” CEO William Spence said.
Con Ed
Consolidated Edison reported first-quarter net income of $370 million ($1.26/share) compared with $361 million ($1.23/share) in 2014.
Revenue for the company’s regulated utilities fell by 4.4%, from $2.22 billion to $2.12 billion.
“The company experienced strong financial performance in the first quarter, and our workforce performed admirably during the challenges of a persistent, lingering winter,” said John McAvoy, chairman and CEO of Con Ed. “We are also very pleased with a proposed settlement with the New York State Public Service Commission that will keep electric delivery rates flat for our customers through 2016.”
MISO and SPP are considering $276 million in potential transmission upgrades under a joint model for identifying congested flowgates that could be relieved by economic projects.
Emerging from that joint process so far are four potential projects that could generate $438 million in benefits to the RTOs over 20 years, RTO officials said last week at a meeting of the SPP-MISO Interregional Planning Stakeholder Advisory Committee.
Four projects may not sound like much. But it’s progress considering the RTOs’ contentious relationship since December 2013 when New Orleans-based Entergy joined MISO rather than SPP, which had served as the Independent Coordinator of Transmission for Entergy’s system since 2006.
Most visible is a dispute over flows between MISO’s northern region and its new, southern region. MISO began limiting flows between the regions last spring after SPP complained that MISO had breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW physical contract path.
But that dispute seemed distant as staff from both RTOs convened last week in Little Rock, Ark. Some even joked that they’ve been talking so much with those at the other RTO that they’ve memorized their phone numbers.
“We’ve learned a great deal about each other’s processes,” said Clayton Mayfield, an economic planner at SPP.
Collaboration has also improved modeling practices and provided a better understanding of neighboring stakeholder groups, said Jenell McKay, a senior analyst at MISO.
Stakeholders and staff at SPP and MISO came up with 67 potential economic projects using a joint model based on each RTO’s regional model. It projected transmission needs for 2019 and 2024.
That was whittled down to seven projects with potential, but three of those didn’t provide a minimum 5% benefit set as a threshold under the joint model.
The four projects seen to have the most potential totaled $276 million. They include new and upgraded transmission lines and transformers in Louisiana, Kansas and Nebraska. Benefits range from a 21% congestion reduction to a complete reduction in congestion.
Still Fine-Tuning List
Mayfield cautioned that the project list is preliminary and that more projects will likely emerge from the ongoing collaborative effort.
He noted that some projects initially identified were dismissed, and others added, after assumptions changed about the future of the Tennessee Valley Authority’s Shawnee units. MISO’s 2014 Transmission Expansion Plan originally contemplated that Shawnee Units 1-10, totaling 1,369 MW, would be retired, but TVA has since decided to keep nine of the Shawnee units in service.
The IPSAC joint analysis is expected to result in final project recommendations by June 30. The committee also is looking at a handful of reliability projects to reduce overloads.
More Potential
Other joint studies may be underway. McKay said the RTOs have had discussions regarding a study involving the effects of the Environmental Protection Agency’s proposed Clean Power Plan.
Pat Hayes, senior transmission policy specialist at Ameren, told the committee it could be helpful if staff conducts a “post mortem” regarding what differences the RTOs ran into and how they could have impeded a project from going through.
Kip Fox, director of transmission strategy and grid development at American Electric Power, said his “personal observation” is that the RTOs are working better together. He noted, however, that MISO and PJM have not been able to get moving on a seams project after four years. “I don’t want the same thing to happen here,” he told the committee.
