The Federal Energy Regulatory Commission lacks proper controls for identifying and handling classified national security information, the Department of Energy’s Inspector General said last week.
Gregory H. Friedman issued his preliminary findings in a report issued on the eve of FERC’s appearance before the Senate Energy and Natural Resources Committee Thursday.
The IG review was initiated in March in response to news reports that included non-public information regarding FERC modeling on grid vulnerabilities and the investigation into the April 2013 attack on Pacific Gas and Electric Co.’s Metcalf substation.
The IG report said DOE’s subject matter experts concluded that at least one presentation created by commission staff should have been classified when it was created.
Article Cited
Although the report did not identify the presentation, Acting FERC Chair Cheryl LaFleur told the Energy Committee Thursday it was modeling created in early 2013 that was the subject of a March 13 Wall Street Journal article.
The article said the modeling indicated that disabling just nine critical substations could blackout the continental United States — a conclusion some experts have questioned.
“Based on preliminary information, we determined that the presentation was accessible to, and in specific instances, was viewed and handled by Commission employees who may not have had personnel security clearances and thus, were not fully aware of their obligation to protect the information,” Friedman said in a management alert. “Similarly, the document was reported to have been maintained on portable electronic equipment and transmitted via unsecured means.”
The document’s contents may “have been provided to both Federal and industry officials in unclassified settings,” the report added.
LaFleur had requested the IG review along with Senate Energy Chair Mary Landrieu, D.-La., and ranking member Lisa Murkowski, R-Alaska. LaFleur told the committee Thursday she had ordered FERC staff to make implementation of the IG’s corrective recommendations a top priority.
Scrubbing Computers
Cheryl LaFleur, acting chair, FERC
LaFleur said that the presentation was created in early 2013 and should have been classified at the secret level or higher, rather than as Critical Energy Infrastructure Information (CEII), a level of information that can be obtained by many FERC employees.
FERC responded to the IG findings by “gathering any paper copies we can find … wiping and scrubbing all databases and computers, and any portable devices across the commission,” LaFleur said.
She said the commission also is “reaching out to former employees including our former chairman [Jon Wellinghoff], and trying to get our arms around any information that may be out there.”
Wellinghoff, who was chairman from 2009 until December 2013, has been widely quoted in news accounts since leaving the commission during his campaign to raise awareness of the threat of sabotage. Each of the current commissioners has criticized Wellinghoff, both for going public with his concerns and for not doing more to address them when he headed the commission. (See FERC Criticism of Ex-Chair Mounts.)
Wellinghoff told Politico last month that he and another FERC official had briefed hundreds of people about the study and that the information in the Journal article was no secret. “There was no classified information,” he said. “There was no secret information and nothing was shared with anybody that was in any way part of some unpublished report.” He did not respond to requests for comment last week.
NERC: Attack was ‘Turning Point’
At least two saboteurs are believed to have taken part in the Metcalf attack, which caused more than $15 million in damage and idled the substation for nearly a month, but caused no power interruptions.
Gerry Cauley, president of the North American Electric Reliability Corp., who also testified before the committee, said the attack was a “turning point” that indicated security measures designed to keep intruders from getting onto substation property were insufficient.
“We’re doing the right things and were doing the right things on a prioritized basis,” he said. “… The Metcalf incident was serious but it’s also a good example of the resiliency of the grid — there were no customer outages.”
American Electric Power expects coal to represent 51% of its generation portfolio in 2020, down from 65% in 2012 but up from an earlier prediction of 46%. Coal’s gain will reduce growth in the company’s natural gas portfolio. Natural gas lost market share to coal last year in PJM due to rising gas prices.
Dominion is buying six California solar development projects with a combined output of 139 MW from Recurrent Energy. The acquisition will greatly raise Dominion’s solar portfolio from its current 41 MW in Georgia, Connecticut and Indiana. The new projects, which already have power purchase agreements and are under construction, are scheduled for commercial operation later this year or early in 2015.
Exelon Absorbs CENG Units, Bringing Fleet to 22,000 MW
Exelon has integrated the operations of Constellation Energy Nuclear Group’s five reactors into its own nuclear group, adding 4,200 MW of capacity to bring its nuclear fleet to more than 22,000 MW in 23 reactors at 14 sites. Exelon thus is the world’s third-largest nuclear operator, behind French state-owned Electricite de France (EDF), with 63,130 MW, and Rosenergoatom in Russia, which has 25,200 MW.
CENG still exists, with 50.1% owned by Exelon and 49.9% by EDF. But last summer the companies made a deal whereby Exelon lent $400 million to CENG to support a special dividend to EDF and granted EDF an option to sell its CENG stake to Exelon between January 2016 and June 2022 at fair market value.
The move was envisioned when Exelon bought CENG’s parent, Constellation Energy, in 2012. At that time the Nuclear Regulatory Commission approved the indirect transfer of the operating licenses, and now the NRC has approved a direct transfer.
Energy market rules have not kept up with “seismic shifts in how energy is produced and consumed,” Exelon Generation President and CEO Kenneth Cornew said. He cited the influx of natural gas, rapid expansion of subsidized renewables, smart grid, low demand growth and behind-the-meter technologies. Focusing on a theme Exelon has used heavily, Cornew told the Platts Global Power Markets Conference that markets need reform. The winter’s polar vortex, with its disruption of gas supply to power plants, highlighted a continuing need for baseload assets like nuclear power, he said, but “flawed market rules” and renewables subsidies result in failure to compensate nuclear for its reliability and zero-emission quality.
FirstEnergy CEO Anthony Alexander believes that “state and federal policymakers are manipulating the supply and demand, and distorting markets for electricity, to further advance the ‘war on coal.’” Speaking at a U.S. Chamber of Commerce event, Alexander lambasted state and federal energy policies that he said were “designed to achieve a social agenda.” He warned that efficiency, renewables, microgrids, rooftop solar and demand reduction are examples of what “sounds good” but are “untested policies” that will threaten reliability and raise power prices.
NRG Closes Deals to Grow Capacity, Retail Presence
NRG Energy closed on its $2.6 billion purchase of Edison Mission Energy generating assets and the $165 million purchase of Dominion Resources’ competitive retail electricity business.
Edison Mission’s nearly 8,000 MW brings NRG’s fleet to more than 53,000 MW, second-largest in the U.S. Dominion’s retail business will add more than 500,000 accounts to NRG’s retail footprint by the end of this year, doubling the company’s Northeast retail presence and expanding its leading retail position in Texas through the Cirro Energy brand.
Completion of the purchases followed on the heels of NRG’s purchase of Roof Diagnostics Solar, a solar sales and installation company.
PJM will resettle $89 million in bills due to logging errors that caused overcharges of load serving entities in the eastern portion of PJM and undercharges for those in the west. The improperly inputted data incorrectly placed RTO-wide charges entirely in the eastern zones, PJM’s Joe Ciabattoni told the Market Implementation Committee last week.
Ciabattoni said an unusual transaction code used during the polar vortex led to a “misunderstanding in the control room.” The “regional conservative operations” code has since been eliminated.
Suzanne Coyne, of PJM Settlements, said the issue was discovered in February and adjustments were made in the March bills, which were distributed last week.
More details will appear on Delmarva Power bills, after lawmaker complaints that there was too little information about state-mandated charges, including purchases of renewable power and the Bloom Energy surcharge.
In meetings at the Public Service Commission, a two-step process was agreed on: First, this summer, utility bills will add line items for the low-income fund charge, the Green Energy Fund charge and “renewable compliance charges,” which will be wind, solar and fuel cell charges lumped together. The next step comes in 2014, when wind, solar and fuel cell charges will be detailed. The PSC must approve the agreement.
The Bloom Energy charge is on bills because lawmakers allowed the natural gas-powered fuel cell energy to count for renewables requirements. A Bloom subsidiary put a project at two Delmarva substations, and customers are paying a surcharge each month for the energy.
The Public Service Commission approved a $15.1 million delivery rate increase for Delmarva Power, less than half the $38.9 million the company sought. It allowed a 9.7% return on equity instead of the 10.25% sought.
NRG’s Crane: Coal Plants ‘Essential’ for 3-10 Years
NRG Energy chief executive David Crane said that he has not developed a long-term plan for the Illinois coal plants the company just bought from Edison Mission Energy’s Midwest Generation. But he said they will be essential in the short term.
“The purpose of having old coal plants, to be frank, is keeping the lights on for the next three, five, 10 years,” he said. “All I can say is thank God” old coal plants were available in this winter’s frigid spells, he said, because “there just isn’t enough natural gas in the system.”
Asked about Exelon’s position opposing subsidies for wind and solar, NRG’s Crane called it “hypocritical,” when Exelon “purports to be this super-green company and also wants more subsidies for nuclear.”
ComEd is partnering with Nest Labs to offer up to $140 in rebates for customers who buy a Nest Learning Thermostat and participate in the utility’s demand response program. ComEd’s AC Cycling pilot program, in effect from June through September, can use Nest’s Rush Hour Rewards service to help reduce demand on the hottest days, the utility said.
Retailer IKEA US is buying a 98-MW wind farm in Hoopeston, Vermilion County, the company’s first wind farm investment in the U.S. and IKEA Group’s largest single renewable energy investment globally. Hoopeston Wind is being built by Apex Clean Energy and is expected to be online by the first half of 2015.
Big Sky Wind Farm (Source: ridiculousRICL.blogspot.com)
Big Sky Wind Farm west of Chicago now belongs to Pittsburgh-based EverPower Wind Holdings. Turbine-maker Suzlon Energy bought the 240-MW facility from Edison Mission Energy (EME) at the beginning of April and immediately sold it to EverPower, in a pair of transactions that resolved Suzlon’s long-running dispute with EME, which involved a $228 million loan Suzlon made to EME.
EME had withheld $208 million, charging that Suzlon supplied defective equipment. The sale price was not disclosed, but the deal provided cash-strapped Suzlon with liquidity, which is “very valuable” right now, Suzlon finance group head Kirti Vagadia said. He said in February that it expected to recover $90 million from the asset.
The Indiana Utility Regulatory Commission will look further into the fuel costs that Duke Energy Indiana has reported for its long-troubled Edwardsport integrated gasification plant, whose output fell to under 1% of capacity in February. The 618-MW plant ran at 4% in January. The state Office of the Utility Consumer Counselor claims the $3.5 billion plant consumed more energy than it produced during some periods in September, October and November, and pressed the IURC for more time to scrutinize Duke’s request for fuel cost recovery. Duke argues the plant is within its 15-month startup plan, but the commission agreed to take a deeper look.
The Public Service Commission approved Old Dominion Electric Cooperative’s 1,000-MW, gas-fired Wildcat Point generating project. ODEC plans to build the combined-cycle project next to its existing Rock Springs gas facility in Cecil County and is targeting a June 2017 in-service date. Transcontinental Gas Pipeline is applying for approval to build a pipeline to serve the project.
Retail customers will now be able to change energy suppliers more quickly, get budget billing plans as well as payment extensions and obtain other help with electricity bills – some things that Baltimore Gas and Electric has already been offering its customers since January’s price spikes. The Public Service Commission approved these provisions after hearing hundreds of complaints about prices, and about receiving misleading information from suppliers about their variable rates and how to cancel contracts.
People’s Counsel Paula Carmody said her office has been puzzled by variable rate contracts up to 48 cents/kWh, compared with BGE’s standard offer of 9.5 cents. Disclosure rules have to be changed, she said, and there should be consideration of capping variable-rate contracts.
The future of Pioneer Green’s wind project in Somerset County appears to be in the hands of Gov. Martin O’Malley, who will either sign or veto a lawmaker-approved bill to delay wind farm development within a 56-mile range of Naval Air Station Patuxent River while a study is done to see how turbines can operate without interfering with radar.
The bill targets Pioneer Green’s 25-turbine project, Great Bay Wind Energy Center. While the developer has an agreement with the military concerning operational measures to allay radar concerns, some interests are far from sanguine about it. O’Malley favors wind development and reportedly has been eager to move the Somerset project along.
But U.S. Rep. Steny Hoyer (D-Md.) and others have called for a delay. The Patuxent air base is a major economic presence in Maryland.
The Maryland Energy Administration is soliciting applications until May 15 for $1.1 million in grants for community-scale wind power projects, from 100 kW to 1,000 kW. Projects for Community Windswept grants must provide a benefit such as community ownership or serving load at a local community, academic or municipal facility.
Fishermen’s Energy is appealing the Board of Public Utilities’ denial last month of its plan to build a 25-turbine wind farm offshore Atlantic City. The appeal is “to clarify a number of apparent misunderstandings and misinterpretations,” including a large overestimation of the price of the project’s power, the company said. According to Fishermen’s, the BPU reviewed a price of $263/MWh while the real price is $199.
The state should look at a range of options for reviving its leadership in deployment of solar energy, according to a draft report, from establishing a “green bank” to help finance new installations to promoting more competitive procurement of long-term contracts. The report was prepared for the Rutgers University Center for Energy, Economic and Environmental Policy, which is working with the Board of Public Utilities on solar development volatility. The state used to rank second in the number of installations but has slipped to fifth. Policymakers are concerned about the boom-and-bust cycle.
After devastating outages in the last few years, the Board of Public Utilities is toughening its requirements for utilities’ vegetation management practices. “We’re going to get in your face a little bit more than in the past,” the BPU’s Jerome May told utility executives. While the board conceded that utilities generally do a good job with trees, it said more needs to be done, especially in communicating with local officials about tree-trimming policies.
Duke Energy has received bids for almost three times the 300 MW of new solar capacity it sought in a February request for proposals. The 300 MW would almost double the utility’s solar capacity in the state. The RFP targeted facilities larger than 5 MW and was limited to projects already in Duke’s transmission and distribution queue that could be completed by the end of 2015. Duke said it would select projects by October.
Communities along the Dan River on the North Carolina-Virginia border are pressing Duke Energy to use vacuum dredgers to clear the waterway of coal ash from a Feb. 2 spill. At least one county resolution also called on Duke to remove ash from all 13 ponds at several facilities in the river’s basin. According to the Roanoke River Basin Association, the pollution in the river from the Dan spill is hurting tourism in the economically depressed region.
In other action, a judge denied Duke’s motion to shield records related to ash-pond groundwater pollution while the separate federal criminal investigation is going on. The judge agreed with a Southern Environmental Law Center attorney to keep the documents public but said Duke could try later to seal some of the records as trade secrets if they could justify it.
Duke Energy East End Gas Works (Source: Duke Energy)
Duke Energy and Piedmont Natural Gas are asking for proposals to build and operate a second large natural gas interstate pipeline into North Carolina. Duke has opened five gas-fired plants in the state since 2011 and plans a continuing shift to gas. Piedmont’s customer growth last year was its highest since 2008 and continues to climb.
The state is now served by a Transco line that runs northeast diagonally through western North Carolina. Duke and Piedmont want the new pipe to take a different route. They are open to various kinds of ownership arrangements. The companies expect to select a proposal by the end of this year and to have the project completed by late 2018.
Duke Energy said it temporarily stopped using a vegetation management product that has raised a storm of public concern about safety. The product, Cambistat, stunts tree growth and keeps limbs away from power lines. Duke crews have injected the chemical into the soil near hundreds of trees; it plans on using the product in Charlotte, Greensboro and Durham. The company and the product maker maintain Cambistat is safe and actually makes trees healthier. A Duke spokeswoman said the company failed to inform customers adequately.
A new Columbus Energy Review Committee will explore whether the city should enter the energy aggregation market. The committee will meet with communities that already participate in aggregation to lower their costs. Most electricity aggregation occurs in northern Ohio. Mayor Michael Coleman and the City Council gave no specific motivation for investigating the option. Coleman spokesman Dan Williamson said only that “What the mayor and council president say is `it’s something worth studying.’”
Members of American Municipal Power are to meet this week to discuss how to proceed – appeal, settlement attempt or other route – after a federal judge rejected their effort to force Bechtel to pay up to $97 million for costs of a Meigs-area coal plant that AMP canceled in 2009. The judge ruled that AMP did not show Bechtel acted recklessly and thus the municipal power supply organization could not seek more than the $500,000 damages specified in the contract. Among AMP members, Coldwater Board of Public Utilities, for example, owes just more than $3 million in stranded costs, and Hillsdale Board of Public Utilities owes just more than $1 million.
FirstEnergy Gets Scrutiny For Cold-Spell Extra Fee
The Public Utilities Commission is investigating FirstEnergy Solutions for the one-time fee it is charging fixed-rate competitive-supply customers for its extra costs associated with the January cold spell. The company plans to attach a fee of $5 to $15 to residential bills and up to 3% to business bills. The commission is looking into how the contracts are marketed to customers.
FirstEnergy Solutions is taking heat in Pennsylvania, too, where Public Utility Commission Chairman Robert Powelson is one of its customers. Fixed rates are fixed rates, he said, and “I think there’s a stench” associated with the company’s fee.
The company’s extra costs came from the extraordinarily high wholesale prices in PJM when extreme cold struck the region, cutting some power supply.
Gas-Plant Cleanup Measure Pulled from House Agenda
Lawmakers stopped action on a measure that would have allowed utilities to charge customers for cleanup costs at 19th century manufactured-gas plants, where gas was made from coal and other fuels. The measure, part of a budget package, was pulled after it became more complicated with the addition of electric utilities to those that would be permitted to seek cost recovery for the cleanup work. Known costs so far are about $80 million for projects by natural gas utilities Duke Energy and Columbia Gas of Ohio. Electric companies American Electric Power and FirstEnergy each have 11 sites, for which cleanup costs are not yet estimated.
Opponents say customers should not have to pay, and they warn the proposal could signal a broad liability shift that could be extended to other arenas, like coal ash ponds and coal-fired plants. Doug Colafella of FirstEnergy called those predictions “just hyperbole.”
American Electric Power Ohio customers will pay $2.34 extra per household bill and $9.67 per business bill to cover the utility’s $57 million repair costs after the 2012 derecho. The Ohio Consumers’ Counsel had opposed the payment agreement that the Public Utilities Commission approved. AEP spokesman Phil Moye said the company probably would file for a similar deal in West Virginia to recover the $71 million in derecho costs incurred there.
Bill to Freeze Green Levels Gets Big Pro, Con Lobbying
As the legislature contemplates a bill that would freeze the state’s renewable power and energy efficiency mandates at their current level, big business interests are pressing lawmakers both for and against it. FirstEnergy is a leader in support of the freeze, along with Marathon Petroleum and Timken Co. while opponents include Honda, Whirlpool and Owens Corning.
The measure, Senate Bill 310, would halt at 2014 levels the renewables and efficiency levels set in a 2008 law, which raised the requirements annually to 25% by 2025. Some large users say the utility-bill fee for the program is costing much more than the benefits.
FE Making Changes to Help Prevent Lake County Outages
FirstEnergy will change insulators on power lines in Lake County, in The Illuminating Company territory, to cut the risk of another prolonged power outage after two outages in the first two weeks of March that left tens of thousands of customers without power. The work, which should be complete by the end of the year, will involve changing porcelain insulators to polymer insulators and adding switchers. Local officials told utility representatives that communication during the events was a problem. The representatives suggested conference calls and a special smartphone app to improve communications.
All of Ohio’s regulated utilities met Public Utilities Commission requirements for reliability last year, PUC documents show. American Electric Power had an average of 1.03 failures per customer with an average duration of 141 minutes — not counting major storms, which are excluded from the PUC standards. AEP had been aiming for less than 1.2 outages and 150 minutes in duration. Each company has its own requirements, set to take local conditions into account.
Former PUC Chairman Todd Snitchler has a new job in the Columbus office of McDonald Hopkins, a business advisory and advocacy law firm. He will provide expertise on energy policy and strategy, government affairs and regulatory matters. Snitchler cannot argue cases before the PUCO for two years, but will be able to practice before other state commissions.
In addition to its Columbus office, the firm has locations in Chicago, Cleveland, Detroit, Miami, and West Palm Beach. Its Washington D.C.-based subsidiary, McDonald Hopkins Government Strategies LLC, is headed by former Ohio Congressman Steven LaTourette.
PENNSYLVANIA
PUC Mandates More Retailer Info, Shorter Switch Time
Public Utility Commission member Pam Witmer urged lawmakers to adopt a set of PUC regulations that would give electricity customers more information about their accounts and the ability to switch suppliers more quickly. Spurred by thousands of complaints of sky-high bills from retailers for the extraordinarily cold snaps this winter, the PUC instituted new rules to require clearer contract language and more disclosure about variable rates. The new rules also cut the time it takes to switch from an average of between 11 and 40 days to three days.
The Energy Association of Pennsylvania, representing utilities, said it would be challenging to adopt the faster switch period in the six months allowed, and said utilities lack the technology to close out bills fast enough to meet the new switching timeline. EAP CEO Terry Fitzpatrick also said accelerated switching would do customers little good in a price crisis, as it would be too late by the time they received their bills.
Meanwhile, the PUC released data that showed two competitive suppliers – IDT Energy and Pennsylvania Gas & Electric – accounted for more than half of the complaints the commission received. Ten suppliers accounted for 83% of the complaints. Chairman Robert Powelson said the commission could ultimately revoke the licenses of abusive suppliers.
FirstEnergy Gets 14 Years To Close Little Blue Run
The Department of Environmental Protection gave FirstEnergy 14 years to close the large Little Blue Run coal ash impoundment, which is associated with the Bruce Mansfield plant in Shippingport. The 14 years is more time than environmentalists wanted but less than the company sought. In a closure permit, the DEP requires FirstEnergy to monitor groundwater and surface water from more than 300 locations instead of the 74 the company had proposed, and it requires the company to control noise, odors and particulate emissions, among other measures. FirstEnergy agreed to stop pumping coal-waste slurry into the 978-acre pond by the end of 2016.
The DEP said FirstEnergy has posted a financial assurance bond of more than $169 million, the largest ever required by the state for a waste management facility.
PPL’s Susquehanna 1,300-MW nuclear Unit 2 can go back to normal Nuclear Regulatory Commission oversight if it clears one more hurdle: a thorough inspection to make sure root causes of its problems have been addressed. NRC representatives said at a public meeting near the plant that PPL is meeting the objectives set to fix troubles identified after four unplanned shutdowns in 2012 and 2013 that caused the agency to put the plant in special oversight status. Only five other U.S. reactors are in the “degraded cornerstone” status.
At the meeting, PPL detailed measures it has taken to improve operations and noted that it plans to spend more than $20 million in capital improvements and $40 million for maintenance at the plant.
FirstEnergy Starts Rollout Of 2 Million Smart Meters
FirstEnergy is poised to roll out two million smart meters to customers in its four Pennsylvania-based utilities. The several-year deployment, managed by Accenture, will be one of the largest advanced-meter deployments on the continent.
Southside Electric Cooperative has begun steps to replace a Dominion Power distribution line with a co-op-owned transmission line, in a plan for relieving an outage problem connected with the line. The current line, which serves the co-op’s substation in Dinwiddie, was ranked second-worst of 246 Old Dominion Electric Cooperative’s wholesale-power delivery points in Virginia, Maryland and Delaware. Standards for a transmission line — wider rights of way, for example — will provide more reliability than the distribution line does, the co-op said, although some local concerns remain about impact on historical sites.
PJM took its first step toward requiring cold-weather testing of generators, briefing the Operating Committee last week on a proposed problem statement it hopes will result in improved preparedness next winter.
The RTO says it wants to add operational testing and to reinstate winter-capability testing similar to what was formerly required.
As envisioned by PJM, generators would be required to conduct operational tests in December in which they start their units, synchronize them to the grid and operate at economic minimum or above for at least the minimum run time of the unit. The requirement would apply to generators that operate infrequently and those with dual fuel capability.
The winter capability test, which would measure plant output capacity, could be similar to tests that were eliminated in 2010 due to economic concerns and the addition of regional reliability standards. Since 2010, PJM has accepted summer test data corrected for winter conditions.
PJM’s action was prompted by the 22% forced outage rates during the polar vortex in early January. While 24% of these outages were related to gas interruptions, the bulk of the remaining 75% — approximately 30,000 MW of lost generation — were units that failed to start due to mechanical issues.
Forced outage rates were lower during a late January cold snap, leading to the conclusion that testing units in December before extreme cold typically strikes would help identify potential issues prior to peak winter load conditions. (See Winter Testing May Be on the Horizon.)
“Part of the reason we wanted to bring this up as a problem statement is that we realize we don’t have all the answers,” said Executive Director of System Operations Mike Bryson. He added, “We don’t think we can afford to see [a repeat of] what we saw last winter.”
Some stakeholders had questions about implementing the tests and how broadly they should be applied.
“It’s hard to test these conditions when you’re not in these conditions,” said Brad Weghorst, of PPL. “I’m not sure how much more operational performance you’re going to get under extreme conditions when you’re testing in December.”
One stakeholder representing a utility said he’d like to see demand response resources be included in winter capability testing.
“To exclude a set of resources such as DR that provides a significant portion of PJM capacity is a poor choice,” he said. “[Resource providers] are all getting paid the same, so I’m not sure why they’d get a way out of this and we’d have to pay” for testing.
Bryson said language in the problem statement and forthcoming issue charge could be changed from “Cold Weather Generator Testing” to “Cold Weather Resource Testing” to include DR before stakeholder approval is sought.
The Operating Committee last week endorsed manual changes to implement lessons learned from last September’s heat wave and January’s bitter cold. The committee also endorsed changes to four other manuals that will implement new dispatch rules for demand response pending approval of proposed Tariff amendments.
The changes to Manual 13: Emergency Operations will allow declaration of Cold Weather and Hot Weather alerts several days in advance instead of the day before.
Many of the changes affecting the other manuals are dependent on Federal Energy Regulatory Commission approval of proposed Tariff revisions (ER14-822) allowing demand response to be dispatched more quickly and granularly. These include the split of DR into pre-emergency and emergency categories and implementation of 30-, 60- and 120-minute response windows.
Last month, FERC issued a deficiency notice requesting additional information on pre-emergency dispatch of DR and the reduction in the default response time from two hours to 30 minutes. (See FERC Questions May Delay New DR Rules.)
Some stakeholders expressed reservations about endorsing the revisions subject to FERC approval. Mike Bryson, executive director for system operations, said PJM wanted the manual changes now to ensure they would take effect in time for summer.
If FERC does not approve the Tariff amendments as proposed, he acknowledged “we do have to start over.”
Other manual changes endorsed by the Operating Committee include revisions to:
Manual 11: Energy and Ancillary Services Market Operations, specifying emergency DR price caps based on lead time, as well as an Economic DR price cap.
Manual 18: PJM Capacity Market, outlining DR compliance measures and rules, as well as exceptions to the 30-minute lead time requirement.
Manual 19: Load Forecasting and Analysis, adding pre-emergency and emergency DR language.
Stakeholders are still considering revisions to black start compensation following the rejection of two proposals in March, but zones currently identified as deficient won’t be in jeopardy when generation retirements rise in spring 2015.
PJM’s David Schweizer told the Operating Committee the RTO has awarded black start contracts in these zones for next spring.
PJM will also consider proposals received for zones that already have black start coverage to see if they provide better solutions. Schweizer said that all awards will be made within two weeks.
Black start costs will be posted for 2015 through 2017 after they are calculated by the Market Monitor, Schweizer said.
In February, two proposals that would have boosted payments to existing black start units by at least 40% failed to win stakeholder approval. (See PJM Won’t Act Alone on Black Start.)
As a result, the System Restoration Strategy Task Force is considering more modest changes, including:
Compensation for existing black start units not able to recover capital costs.
Recovery of North American Electric Reliability Corp. compliance costs.
Compensation for fuel types currently not compensated, including propane and hydro.
PJM review of base formula rate every five years.
The task force also is considering “back stop” proposals for zones that fail to attract sufficient resources in the future, Schweizer said.
WASHINGTON — For one hour last week, it was the government on the defense.
Top enforcement officials of the Federal Energy Regulatory Commission and the Commodity Futures Trading Commission assured energy lawyers they respect the due process rights of investigative targets, rejecting allegations that they have employed heavy-handed tactics.
“I think FERC really bends over backwards to provide a tremendous amount of process,” Larry D. Gasteiger, Deputy Director of FERC’s Office of Enforcement, insisted during an Energy Bar Association panel discussion on regulation of commodity traders.
Gasteiger and Rick Glaser, Deputy Director of the CFTC’s Division of Enforcement, were in agreement in rejecting allegations that their agencies employ “perjury traps.” But Gasteiger was left alone at the EBA’s annual meeting to defend FERC’s policy of naming individuals who have not been formally charged with wrongdoing.
Naming Individuals
“We don’t name people in complaints or orders unless we’re willing to charge them,” said Glaser. “Charging somebody in a federal complaint is a pretty big deal and that’s one thing. But then to drag somebody’s name into a federal complaint is also a big deal.”
Like the Securities and Exchange Commission and other agencies, the CFTC instead masks individuals as “voice broker A or senior trader B,” Glaser said. “It makes our orders and complaints very cumbersome to read. But we do it.”
FERC does name individuals in settlements, even if they have not been formally charged or been a party to settlement negotiations. And that is unfair, said panelist Michael L. Spafford, of Bingham McCutchen LLP.
Larry Gasteiger, FERC (L), Michael Spofford,Bingham McCutchen (R)
“If that person is not a party to the settlement they’ve had no ability to negotiate the terms of that settlement,” Spafford said. “…So then they’ve had no input into whether their name should be included … whether the facts surrounding their name are accurate, whether or not the document speaks truthfully to them.
“You can do what the CFTC, the Department of Justice, the SEC and several other government agencies do and say `trader A’ and get across the same deterrent effect,” he continued.
Gasteiger said the commission’s policy was an attempt to respond to industry and energy bar calls for more transparency about the enforcement process.
“I do not think the practice is either unlawful or a violation of any due process standards [in] the way that we engage in it,” he said.
“As we know transparency can be generally a good thing,” Gasteiger added. ”Unless you’re the subject of the transparency and then it becomes an issue.”
Perjury Traps
The two agencies were in agreement, however, on allegations that they have set “perjury traps” by not providing timely access to deposition transcripts.
Gasteiger called the perjury trap defense “a complete red herring and a smoke screen.
“FERC does provide access to the depositions. The issue is generally the timing of it — when, not if,” Gasteiger said. “There have been a couple of instances where [copies of transcripts were delayed] if we’re concerned the release could impede an ongoing investigation.
“So I want to be clear it’s not an issue of if whether you’ll get access to the deposition. Occasionally it’s a question of when,” he said.
Rick Glaser, CFTC
Glaser was also unapologetic.
”My suggestion is you have your clients tell the truth. … If your client is telling the truth there’s no perjury trap to be had,” said Glaser. “… We’re not trying to trick people in our … depositions. We’re trying to get information.
“The situations in which we have had concerns over when people have told us false and misleading things have been pretty clear that they were attempting to deceive us,” he continued. “This is not a grey area where we’re not sure whether you were going 35 miles an hour or 38.”
Glaser said “third parties” who are not targets of an investigation will often be provided copies of depositions before a probe concludes.
But he said the agency won’t release transcripts to targets until afterward. “We want people to give testimony that is straight forward and honest,” Glaser said. “We don’t want coordinated testimony.”
Spafford insisted Glaser’s concerns were unfounded. Regarding “shading the testimony,” he said: “I honestly don’t think that occurs.”
What is the End?
The agencies’ responses prompted moderator Robert S. Fleishman, of Morrison & Foerster LLP, to ask: “When is the investigation done?”
The question is especially timely for FERC.
Last month, an energy trading fund that has been the subject of a FERC investigation for more than three years without being charged released documents it says proves it has been unfairly hounded. (See PJM Trader Calls FERC on Manipulation Probe.) The principals of the trading firm have continued their campaign, lobbying the Senate to block FERC enforcement chief Norman Bay’s nomination as commission chairman and last week filing a Freedom of Information Act lawsuit to obtain agency records relevant to their case.
Gasteiger never answered Fleishman’s question, however. After conferring privately with Gasteiger, the moderator explained to the audience: “One of the things we’re talking about – generically – is whether something that deals with this issue is the subject of a public order or not.”
The panel’s consensus: “We’re not sure,” Fleishman said, moving on. “Next question.”
Fleishman then asked how the agencies decide whether to charge individuals, in addition to their companies, with fraud or market manipulation.
For this, Gasteiger had an answer.
“We take these cases extremely seriously, whether it’s individuals or companies,” he said. “We won’t take on a case unless we think we have an extremely solid case to present to the commission and if necessary to take it to a hearing before an [administrative law judge] or a district court proceeding.”
PJM is proposing a MISO scheduling product similar to the PJM-NYISO Coordinated Transaction Scheduling solution that gained conditional FERC approval in February.
At last month’s Joint and Common Market meeting, PJM presented an overview of the PJM-NYISO CTS, along with a proposed work plan for developing a similar product with MISO. Joint MISO-PJM stakeholder meetings are scheduled for April 28 at MISO and June 10 at PJM.
The meetings will be devoted to “setting up what the proposal will look like,” said PJM’s Rebecca Carroll, who provided the Market Implementation Committee with an update last week.
“We are trying to keep it as similar [to the NYISO product] as we can,” she said. “We would like the products to be complementary.”
PJM and MISO had discussed optimization in 2011 and 2012 but tabled the matter to pursue higher priorities. “The JCM has been up for one and a half years now. We thought it was time to take up this issue again,” Carroll said.
MISO Has Second Thoughts on Interface Pricing
The two regions are no closer to a solution, however, on eliminating the double counting of congestion in interface prices.
PJM wants MISO to agree on a common definition of the PJM-MISO interface to eliminate double counting that can inflate congestion calculations in market-to-market transactions. Transactions overestimate congestion when they settle with both RTOs because both are pricing its full effect on the constraint.
In February, PJM said it had concluded that its definition puts the interface too far west of the congestion. It proposed a revised definition comprised of 10 generator pnodes closer to the RTOs’ seam. MISO’s Market Monitor suggested an alternative that would eliminate the double payment by basing the settlement entirely on the monitoring RTO’s shadow price. (See PJM, MISO Seek Common Ground on Congestion Values.)
According to MISO’s presentation at the March 21 JCM meeting, MISO stakeholders found none of the proposals was “obviously superior” to the current definition and concluded it may be impossible to develop a methodology that provides more accurate signals in all situations.
MISO said it will continue to evaluate alternatives in the search for one that works better in most cases.
For now, however, Carroll said PJM and MISO will retain their current definitions.
Carroll said it appears the proposed changes stalled due to concern within MISO about the impact on Financial Transmission Rights.
Stakeholders endorsed rule changes last week to clarify that generation owners providing Tier 2 synchronized reserves will be measured in the aggregate when PJM evaluates their performance under a new penalty structure. The Federal Energy Regulatory Commission approved the new penalties effective Jan. 1 (ER14-297).
Manual 11: Energy and Ancillary Services Market Operations already included a business rule that allows resource providers to aggregate in order to use an over-responding resource to offset the deficiency of an under-responding resource, Suzanne Coyne of PJM told the Market Implementation Committee.
The MIC voted to add new language to the Tariff, Operating Agreement and Manual 28: Operating Agreement Accounting to reflect this rule.
