A former Nuclear Regulatory Commission employee was charged with trying to sell sensitive nuclear weapons information to a foreign government after he was caught by an FBI sting operation. Charles Harvey Eccleston’s attempts to glean information from government computers came to the attention of investigators after he entered an unidentified foreign embassy and offered to sell information.
Investigators said he offered to design malware that would pluck information from government computers in a method known as “spear-phishing.” He was caught in the Philippines on March 27.
NRC Approves Plan to Build at Fermi — but DTE isn’t Building
While the Nuclear Regulatory Commission has approved plans to build a new reactor at DTE’s Fermi 2 site, the company announced that it doesn’t plan to act on that approval.
A company spokesman said the construction license was sought to preserve DTE’s options. The plan allows for a 1,560-MW facility, which would boost the site’s capacity from the 1,170 MW already in operation.
DTE plans to retire some of its coal plants in the next five years, but the company said it is eyeing natural gas-fired plants if it pursues any immediate construction plans.
The Federal Energy Regulatory Commission approved Spectra Energy’s plans to begin site preparation work on its Algonquin Pipeline expansion in New Jersey. Called the AIM Expansion, the project is designed to improve natural gas supply to the Northeast Region of the U.S., which experienced gas shortages during winter peaks.
Delaware Urges Interior to Keep Offshore Water Survey-Free
Delaware’s top environmental official is urging the U.S. Department of the Interior to not permit any seismic surveys off the state’s coast because it is not part of the federal government’s immediate plans for oil and gas development.
“The extent of proposed surveys into waters offshore of Delaware does not correlate to the leasing program areas and we do not see the need for surveys in areas that are not currently subject to leasing,” Department of Natural Resources and Environmental Control Secretary David Small said in a letter.
The Interior Department has granted seismic surveying off the coasts of other Mid-Atlantic states. Information from the surveys will be part of the Bureau of Ocean Energy Management offshore lease programs.
NRC Investigating Incidents at Exelon’s Three Mile Island
The Nuclear Regulatory Commission is looking into two recent incidents at Exelon Nuclear’s Three Mile Island generating station in Pennsylvania. Two Sundays ago, a control rod dropped inside the reactor. Four days later, a valve opened and allowed steam to be vented into the atmosphere. Low levels of radiation were in the steam, according to the NRC and Exelon officials.
NRC investigators are determining the cause of both incidents.
FERC Grants Initial Approval to Palmetto Pipeline Project
The Federal Energy Regulatory Commission has granted pricing and service conditions for Kinder Morgan’s proposed Palmetto Pipeline. The pipeline runs from South Carolina to Florida. When completed, the pipeline will have the capacity to move 167,000 barrels of oil or petroleum products daily.
Kinder Morgan said the project will cost about $1 billion.
Tesla CEO Elon Musk announced the electric automaker’s next new product: the Powerwall, a modular battery storage system aimed at the residential sector. The lithium-ion battery pack, which can be combined with as many as eight other units, mounts to a wall and stores energy from solar collectors.
“If you have the Tesla Powerwall, if the utility goes down, you still have power,” Musk said. “The whole thing is an integrated system that works.” The components will be built at the company’s $5 billion Gigafactory now under construction near Reno, Nev. The company announced two versions of the battery: a 10-kWh unit for $3,500 and a 7-kWh one for $3,000, the latter of which is designed for daily cycling. Tesla is also marketing a version for the commercial sector called the Powerpack.
Initial reaction from analysts was positive. Tesla said it received more than 38,000 orders for the product, including 2,800 for the commercial version. “We’re basically sold out through the first half of next year,” Musk said.
Other companies are working on the same idea, including NRG Energy, which is developing battery storage products. “We have to be in this space,” NRG Home CEO Steve McBee said. “If your goal is to build a meaningful solar business that is durable over time, you have to assume that the solar business is going to morph into a solar-plus-storage solution.”
Dominion’s Annual Meeting Scene of Pipeline Protest
The Dominion Resources annual meeting drew more than 100 protesters opposed to the Atlantic Coast Pipeline. The Richmond, Va.-based company is a major partner in the $4.5 billion plan to build a 500-mile pipeline across rural parts of West Virginia, Virginia and into North Carolina to bring shale gas to eastern markets.
“I think that we’ll get the attention of the shareholders of the corporation that don’t realize they’re risking lives,” said Yvette Ravina of Churchville, Va., a rural area. Picketers gathered outside the site of the meeting, and at least six were inside the meeting itself.
CEO Thomas F. Farrell II said the pipeline would be critical to providing the natural gas necessary to meet growing customer demand, especially now that the pressure is on to meet Environmental Protection Agency emissions mandates. “Virginia and North Carolina in particular do not have enough gas infrastructure,” he said. “This is extremely important. … it’s going to result in much cleaner air.”
Exelon’s Oyster Creek Down for ‘Electrical Disturbance’
Oyster Creek Generating Station (Source: Exelon)
Exelon Nuclear’s aging Oyster Creek Generating Station was taken offline Thursday due to what the company termed “an electrical disturbance on the non-nuclear side of the plant.” They said there was no release of radiation.
“We want to make sure why it happened, but for public safety and the plant workers the plant is safely shut down,” said Nuclear Regulatory Commission spokesman Neil Sheehan. “Now it’s a matter of troubleshooting exactly what occurred.”
The 636-MW plant on the New Jersey coast also shut down in March. It is the oldest in the company’s fleet and is scheduled for decommissioning in 2019. The plant received a “white” performance indicator from the NRC because of four unplanned shutdowns in 2013 and 2014. It received a more serious “yellow” finding last month after problems were found with two of five reactor pressure valves.
Duke Energy will buy a 7.5% stake for $225 million in a proposed natural gas pipeline that is to run from Alabama, through Georgia and terminate in Florida. The other partners in the 500-mile Sabal Trail Transmission project are Spectra Energy (59.5%) and NextEra Energy (33%). The pipeline is scheduled to begin operations in 2017.
Southern Co. said it is researching the possible use of drones to inspect its thousands of miles of power lines. It has asked for and received clearance from the Federal Aviation Administration to test unmanned aerial systems for business purposes.
The company has more than 27,000 miles of transmission lines throughout the Southeast. COO Kimberly Greene said the use of drones could expedite storm recovery, and drone inspections could be done safely and cost effectively.
Southern Co. subsidiary Mississippi Power is partnering with Origis Energy to build a utility-scale solar farm in Sumrall, Miss. It will be Mississippi Power’s third renewable project in the state. The company is also building a 450-acre, 50-MW solar station in Hattiesburg, and a 3 to 4-MW facility in conjunction with the U.S. Navy at the Naval Construction Battalion Center in Gulfport. All three projects, pending approval of the Public Service Commission, are expected to be in service by the end of next year.
Ohio Religious Leaders Appeal to FirstEnergy for Reform
A group of 38 Ohio religious leaders, concerned about low-income customers, have asked FirstEnergy CEO Charles Jones to change the way the utility does business. “It’s time that we as citizens demand corporate America be accountable to us,” Eugene Ward Jr., a Baptist bishop from Cleveland, wrote in the letter to Jones. “We can’t afford the higher rates nor the damage that FirstEnergy is wreaking on our environment.”
Many of the clergy face staggering utility bills from heating and cooling old, inefficient churches. The group also denounced FirstEnergy’s attempt to get approval for its Electric Security Plan, which would guarantee income for underperforming plants.
“This subsidy would rob the poorest among us for the profit of a massive corporation and hurt families by forcing them to underwrite the costs of outmoded facilities whose harmful byproducts make them sick,” the letter said.
PPL’s Susquehanna-Roseland Tx Line About to Go into Service
A 130-mile, $632 million transmission line running from PPL’s Susquehanna nuclear plant near Berwick, Pa., to a substation near Newark, N.J., is set to go into service. Under construction since 2012, the development of the line prevailed despite community opposition. The line follows a previously existing transmission corridor through the Delaware Water Gap National Recreational Area. PPL officials said testing is being done on the line now, and it should go into service by the end of the month.
The 500-kV line was fast-tracked by federal authorities as part of the Obama administration’s drive to upgrade the nation’s power grid. It was constructed in collaboration with Public Service Electric & Gas.
Annual Market Report for RGGI CO2 Allowances Released
No evidence of anti-competitive conduct has been found in the market for Regional Greenhouse Gas Initiative CO2 allowances, according to Independent Market Monitor Potomac Economics’ 2014 Annual Report on the Market for RGGI CO2 Allowances.
Firms acquire the RGGI CO2 allowances in the primary market, mainly the RGGI CO2 allowance auctions, and can also buy and sell CO2 allowances in the secondary market. According to the Monitor, the average 2014 auction clearing price was $4.72, a 62% increase from $2.92 in 2013. Secondary market prices were generally consistent with auction prices at an average price of $4.82.
Demand for allowances at auction also increased in 2014. For the second year in a row, no allowances offered at auction have gone unsold. Compliance entities held 85% of the CO2 allowances in circulation at the end of 2014, an increase from 81% at the end of 2013.
PJM made it through the winter without having to invoke a temporary cost-based energy offer cap of $1,800/MWh, the Independent Market Monitor reported last week.
In the 75 days ending March 31 that the waiver was in effect, there were 54 cost-based offers between $1,000/MWh — the historical cap — and $1,800/MWh, but none cleared, according to the report, which the Federal Energy Regulatory Commission ordered in granting the waiver Jan. 16 (EL15-31). (See FERC OKs $1,800 Offer Cap.)
“None of the cost-based or price-based offers between $1,000 and $1,800/MWh cleared with an incremental rate above $1,000/MWh, although one unit with an incremental offer curve that included points below $1,000 and above $1,000/MWh was dispatched at incremental offers below $1,000/MWh on three days,” it said.
“The Market Monitor’s review … indicates that energy offers with scheduling rates or with incremental curve offer components above $1,000/MWh did not affect energy market prices or result in uplift payments to generators,” it said. “LMPs greater than $1,000 were the result of transmission constraint penalty factors and not the result of unit offers.”
The Monitor said it was “investigating the offer behavior of several units and will take appropriate actions consistent with Attachment M of the PJM Tariff.”
PJM requested the waiver over concern that some natural gas-fired generators might encounter the same fuel price spikes that occurred during the polar vortex in January 2014. PJM asked for the allowance to ensure that generators would recover their costs if called upon during periods of high demand.
In fact, the cold temperatures of this past winter sent PJM to a new winter record for electricity use on Feb. 14, and the RTO still was able to avert use of the higher cost-based offer cap. Demand hit about 143,800 MW, surpassing the previous peak of 141,846 on Jan. 7, 2014. (See Cold Sends PJM to New Winter Record.)
Analysts have attributed this winter’s lower natural gas prices to ample supply, a later onset of cold temperatures and increased imports of liquefied natural gas to the Northeast.
The waiver request was made as a section 206 filing after stakeholders failed over eight months to come to a consensus.
At the time the waiver was being debated, Market Monitor Joe Bowring said fewer than 25 offers had breached $1,000 in January 2014. While some of the proposed offers were in the $1,700/MWh range, he said, there had been no legitimate offers greater than $1,400/MWh.
VALLEY FORGE, Pa. — PJM will seek to recover up to $15 million in lost opportunity costs erroneously paid to generators that were on forced outages and not eligible for the credits, Chief Financial Officer Suzanne Daugherty told the Market Implementation Committee on Wednesday.
While Daugherty said the mistaken payments most likely extend beyond April 2013, the Tariff allows the RTO to recoup only 24 months’ worth.
“We will be contacting companies before any billing adjustments will go through,” she said. “This is not an immediate billing adjustment.”
The compensation applies to combustion turbines that are scheduled in the day-ahead energy market but are not committed in real time. However, if they are not able to operate in real time, they are not eligible for the credit.
Daugherty said in an interview that the issue came to light by chance several weeks ago.
“We were investigating a certain scenario that wasn’t even related” when staff came across instances in which generators had incorrectly or inconsistently recorded their forced outages in the eMKT system as compared with the eDART and eGADS systems, Daugherty said.
“EMKT is what we use to see if you’re eligible,” she said. Now, “we’re trying to go through and find the anomalies amongst them.
“It could be process issues, it could be training – we have no idea why they might not all have been reported consistently,” she told the committee, noting that it is the generators’ responsibility to report outages.
It will remain the generators’ responsibility to report outages, although PJM is considering adding a process that would flag discrepancies among the entries in the three systems, Daugherty said.
Daugherty said it will take weeks to refine the data and identify how many generators are affected and what their individual charges will be. The current estimate, she said, is that the total will not exceed $15 million.
In the meantime, she advised generators to check their own records. “If you got paid LOC in a time you reported a forced outage, you should know you’re likely to have a billing adjustment,” she said.
PJM stakeholders recently approved tighter rules on lost opportunity costs, correcting a provision that allowed generators to recoup start-up and no-load costs that they hadn’t accrued. The rule change is intended to remove incentives for units to clear in the day-ahead market but not in the real-time market. (See PJM Members Tighten Lost Opportunity Cost Rules; Tech-Specific Eligibility Retained.)
NYISO can force idled generators to allow use of their interconnections for reliability purposes, the Federal Energy Regulatory Commission ruled last week, saying that such actions do not constitute an unconstitutional “taking” under the Fifth Amendment.
The commission approved most of the tariff revisions NYISO proposed in its July 2014 filing, which was intended to clarify its rules regarding generator outage states (ER14-2518).
“We find that NYISO’s proposed tariff provisions concerning the termination of existing interconnection agreements and the requirement that a generator’s interconnection points can be temporarily used by the transmission owner during an outage do not constitute takings under the Fifth Amendment to the U.S. Constitution and, therefore, do not require ‘just compensation’ to affected generators,” FERC wrote.
The proposal defines generator outage states, including how long they may remain in them and their eligibility to participate in the capacity market. NYISO said the changes will incentivize generators to make repairs quickly and return units to the market, and provide grid operators more certainty when planning system reinforcements and expansions.
The ISO’s proposal would allow it to terminate a generator’s eligibility to participate in the installed capacity market after six months in a forced outage if repairs have not been started.
It also defined a “mothball outage,” referring to units voluntarily removed from service for reasons not related to equipment failure; they are also ineligible to participate in the ICAP market.
“We find that, in general, NYISO’s proposal to formally define various outage states, with related changes, will help increase predictability and transparency, and help ensure that the only units participating in the ICAP market are those that reasonably expect to be able to provide capacity during the delivery period,” the commission said. “We note that, although protesting parties take issue with various aspects of the proposal, they acknowledge that NYISO’s proposal is, in large part, beneficial to NYISO’s markets.”
The Independent Power Producers of New York challenged the proposal, saying it would interfere with contractual rights they had negotiated with transmission owners. While the group supported the six-month rule for participating in the ICAP market, it said FERC should reject a requirement that generators on outage respond to reliability needs by returning to service or making their interconnection points available.
The commission, however, said that the rule “will help resolve imminent reliability issues.”
Cost Provision Rejected
However, the commission rejected NYISO’s proposal that generators that fail to return to service in the time required pay costs incurred to install an alternative reliability solution.
IPPNY argued that the proposal would unfairly overcharge generators. It asked the commission to order a requirement that a generator pay the difference between the cost of the reliability solution and the amount customers would have paid if the generator had returned to service on time.
The commission said it recognized that a penalty structure may be appropriate to ensure generators return to service quickly.
But it said that “imposing the full cost of the alternative reliability solution on the generator is not just and reasonable because NYISO has not demonstrated that requiring a generator to pay the full cost provides a reasonable penalty for a generator not returning to service on the agreed upon date.” The commission urged the ISO to work with stakeholders on an alternate proposal.
The order is effective May 1, subject to a compliance filing NYISO must make within 30 days.
NEW YORK — Distributed resources are receiving too much blame for the utility industry’s problems, current and former regulators said at the Infocast Grid Transformation Summit 2015 last week.
From left to right: Michael DeSocio, NYISO manager of energy market design; Mike Kormos, PJM executive vice president of operations; Jim Davis, CEO of Smart Wires; and Elliot Roseman, VP of ICF International.
“I think the main problem is the declining sales of energy,” said Betty Ann Kane, chairman of the D.C. Public Service Commission. Kane said distribution-only utilities facing declining revenue due to their dependence on volumetric rates will find it difficult to modernize the system for rooftop solar and other distributed resources.
“We have started to move gradually — and I would say too gradually — away from the volumetric charges to have a customer charge pick up more of the costs,” she said.
In D.C., the monthly service charge for meter reading and grid connection has gone from $6 to $12 since 2007 and is headed toward $20, Kane said.
Other speakers at the conference, which drew about 100 people to the ONE UN New York hotel, spoke of renewable energy’s progress — and the backlash against it.
“There have been efforts in a number of states to pull back on [renewable portfolio standards],” said former Federal Energy Regulatory Commission chairman Jon Wellinghoff, now a partner in the law firm Stoel Rives. “On the other hand, there have been efforts to increase renewables. One of the most notable is California, which recently set its goal to 50%.”
Wellinghoff noted that renewables’ declining costs mean the mandates are less necessary than before.
“At the wholesale level we’re seeing wind at less than 3 cents/kWh and the average at utility-scale solar generation is less than 7 cents/kWh. That’s an average for all the contracts signed in 2014, while some are at 5 cents,” he said.
Fixed Costs vs. System Benefits
Wellinghoff also disputed claims that net metering and renewable subsidies result in low-income customers subsidizing wealthier customers able to afford rooftop solar. Wellinghoff cited studies showing that distributed resources provide net benefits to the grid.
“The problem is they’re not analyzing the entire benefits to the system with these distributed systems,” Wellinghoff said of critics. “You can’t look solely at the costs of energy, of retail rates versus wholesale costs. It’s avoiding new generation, it’s avoiding new transmission.”
“I think the concern about the cross-subsidization is solar is overplayed,” Kane agreed.
NREL Study
The National Renewable Energy Laboratory in Golden, Colo., is studying the operational challenges facing utilities on a 1-MW system with distributed solar, smart devices, electric vehicles and other technologies.
Bryan Hannegan, associate director of energy systems integration for the lab, described the questions NREL is attempting to answer: “When you have a more distributed and dynamic grid, how do you operate that in a way that doesn’t sacrifice reliability and affordability that consumers have come to expect, while pursuing the clean energy objectives we’ve set out for ourselves as a nation?”
The Federal Energy Regulatory Commission last week fined Maxim Power and one of its employees in a fuel-switching scheme that occurred in the summer of 2010.
Maxim was fined $5 million and employee Kyle Mitton was fined $50,000 for overcharging ISO-NE by offering into the day-ahead market with a price for oil-fired generation when in fact it was burning cheaper natural gas (IN15-4).
Only three members voted to impose the penalty, with Commissioner Tony Clark, who had previously expressed skepticism, dissenting. (See FERC Seeks $5M from Maxim Power; Clark Dissents.) Chairman Norman Bay, formerly head of the Office of Enforcement, did not participate in the decision.
“We find that respondents intentionally engaged in a fraudulent scheme, through misrepresentations and material omissions, to obtain and protect payments established by offers based on the price of oil, even though they ran the Pittsfield unit on lower-priced natural gas, which should have set their compensation,” FERC wrote.
The plant involved is a 181-MW dual fuel generator in Massachusetts, which was operating under a reliability must-run agreement at the time of the violations.
“As a result of Pittsfield’s high offer price, the grid operator often chose less expensive options and did not select Pittsfield to generate. Nevertheless, Pittsfield was often needed to ensure system reliability and so was requested to run despite its higher price,” FERC said.
Clark acknowledged that Maxim’s activities appeared “suspicious,” but he said Enforcement did not prove the case to his satisfaction. He also cited doubts about Mitton’s culpability.
“Staff’s case linking Maxim’s supply offers to a willful intent to deceive the Independent Market Monitor thus rests on the notion that while Mr. Mitton’s responses may have been technically correct and ultimately truthful, Mr. Mitton did not anticipate what information the Independent Market Monitor was really seeking and therefore his responses were too narrow and not as forthcoming as they should have been,” Clark wrote. “To me, such a fact pattern does not a $5 million penalty make.”
The majority disagreed, calling Mitton’s role “crucial to the fraudulent scheme.” The key to the dispute, it said, is a series of emails between Mitton and the Internal Market Monitor.
“Mitton personally sent emails to the IMM that conveyed the impression that Maxim needed to submit offers for the Pittsfield plant based on high oil prices because of supposed concerns about natural gas supply, even though Mitton was frequently able to procure much cheaper natural gas on those days, and even though Mitton himself had often purchased large amounts of natural gas before submitting day-ahead offers for Pittsfield,” the decision said.
Attorneys for Maxim and Mitton could not be reached for comment.
The SPP Board of Directors approved staff’s recommendation that it authorize construction for a 21-mile 115-kV line from Walkemeyer to North Liberal as part of a reliability solution in southwestern Kansas. The proposal had received almost 64% support from the Markets and Operations Policy Committee in April, falling short of the 66% needed to recommend it to the board.
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The board had approved the project in January but asked staff to evaluate an alternative proposed by Sunflower Electric Power that would have delayed the line, instead relying on operating guides for Sunflower’s 76-MW Cimarron River Station to provide relief from thermal or voltage violations.
Staff evaluated three options:
Option 1 would add a new substation with a 345/115-kV transformer on the Hitchland–Finney 345-kV line and a new 1-mile 115-kV line from the substation to Walkemeyer at an estimated cost of $17.8 million. Cimarron would be dispatched for up to 58 MW when needed to avoid violations.
Option 2, the staff recommendation, included option 1’s new substation and transformer but would add the Walkemeyer-North Liberal line for an additional $17.5 million, avoiding the need to rely on Cimarron for reliability. Although it had higher upfront costs, staff said option 2 was about $900,000 cheaper than option 1 on a net present value (NPV) basis over 40 years ($68.4 million vs. $67.5 million in 2015 dollars).
Option 3, which would have relied solely on the Cimarron plant, had an NPV of $78.5 million and only “marginally” solved voltage violations, staff said.
Following the MOPC meeting, staff reevaluated the options using an 8% discount factor, which reduced options 1 and 3 to an NPV of $49 million and $47 million, respectively (2015 $).
Al Tamimi, Sunflower’s vice president of transmission planning, policy and compliance, said the use of the operating guide and a phase shifter could delay the need for the Walkemeyer-North Liberal project until 2030.
Lanny Nickell, vice president for engineering, said staff’s recommendation was driven largely by the age and the slow response time of the Cimarron plant, which includes a 61-MW gas unit built in 1963 and a simple-cycle 15.5-MW combustion turbine added in 1967.
Although Sunflower has projected operation until 2030, “we don’t know how long this [plant] is going to last,” Nickell said.
In addition, he said the larger, 52-year-old unit requires a 30-hour startup time. “If we’re wrong — if we estimate demand too low — it’s too late to start that unit” to respond to real-time problems, Nickell said.
He added that Cimarron has averaged six days of forced outages annually during the summer months over the last three years.
Nickell called the Walkemeyer line a “no-regrets” option. “With options 1 and 3 there’s an opportunity for regrets in depending on generators that may not show up,” he said.
Sunflower disagreed. “Sunflower staff believes that SPP’s ‘no-regret’ solution contradicts its concerns with compliance with the newly effective TPL-001-4 reliability standard, and the use of Cimarron River Station to meet that standard contradicts SPP’s recommendation to include Phase II in the [Integrated Transmission Plan 10-Year Assessment] instead of the ITP [Near-Term Assessment],” the company said in a statement.
The reliability standard, which the Federal Energy Regulatory Commission approved in October 2013, allows transmission planners to plan for “non-consequential” load loss following a single contingency. (See FERC OKs Rules for “Non-Consequential” Load Loss.)
The SPP Regional Entity, which is seeking a renewal of its delegation agreement with the North American Electric Reliability Corp., is trying to assuage NERC’s concerns over the RE’s independence.
“As far as I know, it’s the negotiating team at NERC that has communicated” NERC’s concerns, RE Trustees Chairman John Meyer told the SPP’s Board of Directors/Members Committee meeting Tuesday.
SPP’s current five-year delegation agreement expires Dec. 31. It calls for renewal if SPP passes a NERC audit to ensure that SPP “continues to meet all statutory and regulatory requirements necessary to maintain its eligibility for delegation.” Either party may terminate the agreement by giving written notice at least one year before the end of the term.
Ron Ciesiel, general manager of the RE staff, said SPP officials were given a revised pro-forma delegation agreement about two weeks ago that removed the automatic renewal provision. He said RE officials plan to discuss it with NERC at an upcoming meeting.
SPP is the only RTO or ISO that also enforces reliability rules as a NERC regional entity. The Federal Energy Regulatory Commission raised its own questions about the RE’s independence in a 2008 audit. (The Texas Regional Entity was formerly a division of ERCOT, but it became an independent corporation in 2010.)
The audit concluded that SPP RTO management had supervisory control over SPP RE employees and that RTO employees had influence over NERC compliance monitoring and enforcement policies. The commission required SPP to hire a full-time RE manager and to eliminate all reporting relationships between RE employees and RTO employees. (Full disclosure: RTO Insider Editor Rich Heidorn Jr. was a member of the FERC team that conducted the audit.)
NERC did not respond to requests for comment.
Finance Committee Considering Changes to Administrative Fee
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The SPP Finance Committee is considering a change in the way it sets the RTO’s administrative fee rate.
Since FERC’s approval of SPP as an RTO in 2004, it has set the rate at a level designed to recover its annual budget plus or minus amounts necessary to true-up prior periods.
The fee has grown steadily along with the RTO’s increased level of services.
Because SPP projects operating budget expense levels to be more level and predictable than in prior years, the Finance Committee is considering two alternatives: continue the status quo floating rate, or a stable rate approach that would enable funding for contingency, reserves and capital expenditures in the annual budget.
The status quo will generally result in a lower rate in the near term and is consistent with SPP’s existing policy to maintain “generational equity.”
The stable rate proposal would improve the predictability of rates from year to year but will result in SPP’s recoveries being either higher or lower than expenses.
SPP expects a stable rate approach would result in a higher rate initially than the status quo because of a modest reduction expected in the status quo rate following the addition of the Integrated System load in October 2015. Under an example provided by the committee, the stable rate could rise from $0.38/MWh in 2015 to $0.39/MWh for 2016-2020, while the floating rate could fluctuate between $0.37/MWh and $0.38/MWh (see chart). The floating rate could result in operating cash shortfalls of as much as $79 million in 2020, versus $39 million under the stable rate.
Capital expenditures were projected to drop from $29 million in 2015, to $19 million next year and $15 million annually for 2017-2020, under the example.
The analysis did not include any financing to cover capital expenses or cash shortfalls.
Finance Chairman Harry Skilton said a level administrative fee would mean SPP keeps more cash on hand. “The question is what do we do with it?” he asked in inviting stakeholder feedback on the options. “Do members want SPP to borrow rather than them borrowing? We do have a fantastic credit rating.”
Skilton also said SPP may have to increase its pension contributions by $1 million beginning in 2016 due to the adoption of the 2014 mortality tables published by the Society of Actuaries, which predicts longer lifespans for retirees.
New Members Welcomed in Iowa, Minn., SD
Members approved three cooperatives for membership: Corn Belt Power, which provides power to nine distribution cooperatives and one municipal electric cooperative in 41 counties in northern Iowa; East River Electric, which serves rural areas of 41 counties in eastern South Dakota and 22 counties in western Minnesota; and Northwest Iowa Power, which provides power to seven distribution cooperatives in western Iowa.
MMU Hires Law Firm for Independent Representation
SPP has hired a D.C. law firm, Michael Best, to represent the Market Monitoring Unit, said Josh Martin, chairman of the Oversight Committee.
To ensure its independence, the MMU must have a different law firm than what the RTO uses, Martin said.
“There should be no question about the independence of the MMU,” Martin said. “If they need to make filings to FERC, they have the appropriate resources to do so.”
Markets and Operations Policy Committee Recommendations Approved
The board accepted the following Markets and Operations Policy Committee recommendations:
Approve new rules on how mitigated offers will be calculated for generators that fail market power tests, a solution that includes default values for variable operation and maintenance costs (Revision Request 69). (See SPP MOPC OKs New Rules for Calculating Mitigated Offers.)
Approve the selection of three futures scenarios for the 2017 Integrated Transmission Planning 10-Year Assessment to measure the impact of the Environmental Protection Agency’s proposed carbon emission rule. (See ITP10 to Include 3 Scenarios for Clean Power Plan.)
Reject a request from Western Farmers Electric Cooperative for a waiver from a rule barring base plan transmission funding for generation projects that push wind’s share of capacity above 20% of summer peak load. The Regional State Committee also voted to reject the waiver but agreed with other stakeholders that the 20% threshold should be reconsidered. (See Wind Waiver Rejected; SPP Members will Revisit Assumptions.)
Board Expands; Eckelberger, Skilton Re-elected
In a special Members Committee meeting, stakeholders voted to add up to three external seats to the Board of Directors, which currently includes six external directors plus SPP President Nick Brown. SPP spokesman Tom Kleckner said the change gives the board “flexibility … to add someone if the appropriate candidate comes along.”
The Corporate Governance Committee also nominated Board Chairman Jim Eckelberger and Vice Chairman Harry Skilton to new three-year terms. The election will be in October.
The Members Committee also added six member representatives as it expands to 20 from 15 and fills one vacancy: David Hudson, Xcel Energy (representing investor-owned utilities); Mike Risan, Basin Electric Power Cooperative (cooperatives); Stuart Lowry, Sunflower Electric Power Corp. (cooperatives); and Kristine Schmidt, ITC Great Plains (independent transmission companies), were elected to two-year terms, while Kelly Walters, Empire District Electric Co. (IOU), and Bob Harris, Western Area Power Administration – Upper Great Plains Region (federal power marketing agency), were elected to eight-month terms.
SPP’s Board of Directors rejected a recommendation to create a short-term reliability unit commitment (RUC) study as part of the intra-day RUC process (Revision Request 49).
The study would provide results for 15-minute intervals, allowing operators to make unit commitments with more granularity than the current one-hour study. SPP staff said it would reduce the number of real-time manual commitments.
The study won the backing of the Markets and Operations Policy Committee last month but ran into stiff opposition last week from representatives of Golden Spread Electric Cooperative and Nebraska Public Power District, who said they feared the new tool might exacerbate losses they are suffering as a result of SPP’s dispatch of their quick-start units.
The quick-start units, which cost at least twice as much as regular combustion turbines, can be at full capacity in five minutes or less.
Golden Spread said that SPP should first fix its real-time balancing market software so that it recognizes quick-start resources as always “online” and available to the market. When the units are dispatched manually by operators through the RUC process instead of economic dispatch, they cannot set prices in the real-time market.
“So they just get the market price — which normally is much lower than the actual price — and need to be made whole,” Ron Thompson of Nebraska Public Power District said in written comments on the proposal. “If there is [an] issue and the unit does not perform as intended, the ‘make whole’ payment may be less or potentially not occur and the unit owner will be subject to much higher operating cost than what the market paid.”
At times, Golden Spread’s quick-start 168-MW Antelope units near Abernathy, Texas, are covering half of SPP’s regulation, Mike Wise, Golden Spread’s senior vice president of commercial operation and transmission, told the committee.
Wise said starts for the 18 Wärtsilä reciprocating engines at Antelope increased to almost 13,000 between March 1 and Dec. 3, 2014, compared with about 3,000 starts during the same time period in 2013, before the start of the Integrated Marketplace, a four-fold increase. About 41% of the starts in 2015 resulted from RUC instructions by SPP operators.
“They shouldn’t be getting RUC’ed at all,” Wise said. “They should be dispatched by the day-ahead or real-time market.”
Wise said SPP should create a ramping product to create the proper economic signals for quick-start and other fast-ramping resources. “This market should have a ramping product that is the envy of the country. We have got the wind resources that are the envy of the country,” Wise said. The short-term study “is not the answer. The ramping product that we are working on is the answer.”
One director asked about deferring to the new tool until the ramping product is developed. “I don’t want to make a bad situation worse,” he said.
Richard Dillon, director of market design, said it will likely be months before there is a proposed ramping product for members to consider and that once approved, it will take considerable software development to implement.
Chief Operating Officer Carl Monroe said the tool would automate “something we’re already doing manually. It doesn’t change [Golden Spread’s] situation at all.”
With the rejection, the measure was returned to the MOPC.
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