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.
WASHINGTON — EPA Secretary Gina McCarthy told no secrets last week as she continued her charm offensive in advance of the agency’s long-awaited greenhouse gas rules for existing power generators.
EPA Secretary Gina McCarthy
The proposed regulations are due to be released June 1, and McCarthy, the star attraction at a Bipartisan Policy Center forum April 7, knew she wasn’t allowed to spill the beans.
“I know I can’t be tellin’ what the rule says, so kick me if you think I’m starting to get on the verge,” she joked to BPC President Jason Grumet.
Instead, she continued her promises to provide states “flexibility” and to honor reliability concerns. She also made clear that the rulemaking to be released in about 50 days will not be the final word.
McCarthy, deputy Janet McCabe and other agency officials have won widespread praise for their outreach to state regulators, including a shout-out at the forum from Colette Honorable, president of the National Association of Regulatory Utility Commissioners (NARUC).
But McCarthy, an earnest, plain-spoken former state environmental regulator with a strong Boston accent, acknowledged that the warm and fuzzy feelings may evaporate once the details are released.
“I think we’re presenting a little bit of a rosy picture. I think everyone realizes that I’m a stark realist. I know the challenge we’re having,” she said near the end of her session, before being hustled out a side door away from reporters. “The only thing I really hope when this proposal goes out is that people will look at it and say ‘EPA listened.’”
Mission accomplished, said Honorable, who shared the stage with McCarthy at the Grand Hyatt hotel.
“Gina has certainly been no stranger to NARUC,” she said, playfully noting the contrast between McCarthy’s accent and her own Arkansas drawl. “She’s fearless. … It really has been a pleasure to engage with her.”
Informed by Further Discussion
The proposed GHG rules — now undergoing an interagency review — will leave “lots more room for improvement,” McCarthy said. As a result, she promised, the final rule will be “informed by further discussion” in the comment process.
“I think many times we get criticized because there’s so much change between the proposal and final. That’s when I dance in the streets. Because I think that is exactly as it’s supposed to be, because you’ve put concrete ideas on [the table] — instead of lofty discussions — and you start digging in to what really matters to people, which is all the details.
“It needs to be incredibly smartly crafted … to make sure it provides the flexibility that states need while continuing to provide the impetus for the carbon reductions we need,” she added. “States that are out in front can continue to be there and get rewarded for that and recognized for that, while states that haven’t yet gone down this road can craft a way to do that in a time frame that will be meaningful for them.”
RTO Involvement
NARUC President Collette Honorable
RTOs such as PJM “are going to have to be a strong voice” in the final rule, McCarthy said, “because the president has made clear … nothing we can do can threaten reliability.” (See related story, RTOs Weigh Role in GHG Compliance)
Honorable agreed that “certainly the regions will have a role to play.
“The nuance here is … who’s on first,” she added. “The states … are the sole entities with jurisdiction over things such as resource adequacy. We can’t allow utility regulators to check that duty.”
Not an Aspirational Goal
McCarthy made clear that while states will be given flexibility, the rule will be “federally enforceable. It is going to be a requirement.
“We are going to be looking at the state plans to determine whether or not they are conforming with the guidance and getting us significant carbon pollution reductions … We’re going to make them cost effective,” McCarthy continued. “We’re going to make them make sense. We’re going to recognize that different regions … are in different places [regarding compliance]. But we’re not going to rely on an aspirational goal.”
Don’t Reinvent the Wheel
That’s fine by the states, said Honorable. “We’re not saying let everything count. But we’re saying let’s not reinvent the wheel,” she said. “We aren’t saying ‘let’s throw it all against the wall and see what sticks.’”
McCarthy and Honorable led off the day-long conference, which also featured panels with economic and environmental regulators from New Jersey, Ohio, Delaware, Michigan and other states, and representatives from Dominion Resources and PJM. Several PJM staffers were among the hundreds watching from the ballroom or via webcast.
The panelists discussed the roles of energy storage, energy efficiency, combined heat and power, nuclear energy and carbon capture under the new rules.
Coal, Wind Roles
Commissioner Greg White, Michigan Public Service Commission
Jon Brekke, vice president of Great River Energy, said that worldwide coal capacity additions over the next five years will equal the current U.S. coal fleet, potentially negating any emissions cuts the U.S. makes.
“If you simply turn away from coal we won’t contribute to global solutions. We won’t contribute to technological development,” he said, urging continued research on carbon capture technology. “This is the country that can lead the world in innovation.”
Commissioner Greg White, of the Michigan Public Service Commission, put in a pitch for research to improve energy storage, which would address the intermittency of wind and solar. “It should be a national imperative,” he said.
PTC Help or Hindrance?
Speakers differed over the impact continuation of the production tax credit (PTC) for wind would have on meeting emission goals.
Commissioner Asim Haque, Public Utilities Commission of Ohio
Tom Vinson, the American Wind Energy Association’s vice president for federal regulatory affairs, predicted the PTC, which expired Dec. 31, will be renewed. Although wind’s costs have dropped substantially in the last decade, Vinson said the industry isn’t ready to compete without subsidies just yet.
But White noted that the PTC allows wind generators to make money even in overnight hours, contributing to negative prices that nuclear operators say threatens the viability of their carbon-free baseload generation.
Cost Concerns
The impact of the regulations on customer bills was on the minds of many of the panelists.
Ohio Public Utility Commissioner Asim Haque said he was concerned that his state, which is considering freezing its energy efficiency program, get credit for its past reductions. If the state legislature approves the freeze, he said, EPA shouldn’t take over the state program but simply require other savings. “I still think people will pursue energy efficiency,” he said.
Commissioner Jeanne Fox, New Jersey Board of Public Utilities
Pamela Faggert, Dominion Resources’ chief environmental officer, said the utility, which once had 17 coal-fired plants, expects to have only five by 2016. The company’s most recent Integrated Resource Plan includes “eight or nine” scenarios based on different levels of emission reductions that may be required by the EPA — with a big spread in potential costs. “We do expect the price of power will go up in the U.S.,” she said.
“It’s going to be a real test of agility for all of us,” said Robert Balazar, principal consultant for the Tennessee Valley Authority. “Where I come from we already have a large number of people who can’t afford their [electric] bills.”
Michigan’s White was one of several speakers who acknowledged the hard work is yet to come. The EPA is “saying all the right things, but I’m waiting for the details,” he said.
Elizabeth (Libby) Jacobs, chair of the Iowa Utilities Board, agreed. “Check with me … in July to see if we’re all still singing ‘Kumbaya,’” she said.
Powhatan Energy Fund, the firm that is waging an unusual public battle against the Federal Energy Regulatory Commission’s investigation of it for manipulative trading in PJM, is now also campaigning against the man chosen by the White House to be FERC’s new chairman. The nominee, Norman Bay, is a former federal prosecutor who has been FERC’s enforcement chief since mid-2009. (See PJM Trader Calls FERC on Manipulation Probe.)
The twin brothers who own Powhatan have a website devoted to combating FERC’s position on the transactions in question. Now that Bay has been tagged to lead the commission, “we’re out there actively trying to talk to senators and staffers about our story and spreading the word about the website and trying to get his nomination defeated,” an attorney for Powhatan said. The White House announced its nomination of Bay in January, but the Senate Energy and Natural Resources Committee has not scheduled a hearing on it yet.
CFTC to Give Public Power Assurance on Swaps Deals
The Commodity Futures Trading Commission will write a formal rule to fix a problem public power utilities have complained about since 2012. Soon after issuing a “no action” letter with assurances to public power in March, the CFTC said it would provide permanent assurance with a rule that effectively allows counterparties — natural gas companies, other utilities, power producers — to do “swaps” deals with public power without having to register as swaps dealers, as long as their aggregate swaps deals do not exceed $8 billion a year. The rule will put publicly owned utilities on the same basis as other energy companies. Current regulation sets a limit of $25 million a year, blocking traditional counterparties from doing these deals with public power.
US Power Plant Capacity Additions 2013 (Source: EIA)
A little more than 13,500 MW of capacity was added to U.S. utility-scale supply in 2013, less than half the amount added in 2012, the Energy Information Administration reported. Natural gas plants accounted for slightly more than 50% of the 2013 additions, with solar contributing nearly 22%, coal making up 11% and wind at almost 8%. California led the additions, followed at a good distance by Texas, Florida and North Carolina.
Among new gas plants, additions came nearly equally from combustion turbine peakers and combined-cycle plants. Nearly 60% of the gas capacity added was in California. Two coal plants accounted for all the added coal capacity: one in Texas and the 571-MW Edwardsport integrated gasification combined-cycle plant in Indiana.
The Department of Energy will open the door to new applications for renewable energy project loan guarantees during the second quarter of his year, Secretary Ernest Moniz said. Peter Davidson, head of the loan program, has suggested the revived loan guarantee program will focus on initiatives to help integrate renewables into the grid.
Under the low-emissions technology program, DOE recently finalized a guarantee for Georgia Power’s Vogtle nuclear project in Georgia and it is taking applications for coal- and petroleum-related carbon capture projects.
The Senate Finance Committee approved a tax-extenders package that includes a two-year extension of the wind energy production tax credit, which expired at the end of 2013. The 2.3-cent/kWh credit, as before, would apply to utility-scale production for the first 10 years of operation.
Two Californians and 14 other Democrats have introduced a bill to create what they are calling Clean Energy Victory Bonds, an effort to put the World War II financing mechanism to work for renewable power and clean energy technology.
In the measure sponsored by Reps. Zoe Lofgren and Doris Matsui, Treasury bonds in denominations as low as $25 would “leverage $50 billion investment to provide up to $150 billion in public and private financing to fund the production of innovative energy technologies.”
PJM and the Independent Market Monitor have reached an agreement on a rule change to reduce the number of Frequently Mitigated Units eligible for “adders,” but the proposal appears to face heavy opposition from generation owners.
Only units whose net revenues are not covering their avoidable cost rate (ACR) would be eligible for adders under the proposal presented to the Market Implementation Committee on first read last week.
The proposal represented a compromise by Market Monitor Joe Bowring, who had previously called for eliminating the adders altogether.
Had the proposal been in effect in 2013, it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire. “Implementing the screen would result in a notable smaller number of FMUs” receiving the compensation, said PJM’s Tom Zadlo.
In polling among members of the generation-heavy MIC subgroup that has considered alternatives, however, 72% of voters said they opposed the proposal. A nearly identical percentage said they would favor either of two alternatives.
One of the proposals that received support in the poll would set the adders based on a plant’s run hours. The second would limit the compensation based on the gross Cost of New Entry for the unit’s Locational Deliverability Area.
FMUs were allowed adders in 2006 to ensure that they cover their avoidable, or going-forward, costs. The adders are graduated: Generators that are cost capped for 60% of their running hours receive an adder of either 10% of their cost-based offer or $20/MWh; those capped for 80% or more of their hours can receive $40/MWh. Similar rules apply to “associated units,” which share physical and economic characteristics to FMUs. The idea is to keep units in service that otherwise would not be economically available.
Bowring said the adders had become unnecessary for most units since the introduction of the capacity market in 2007 and changes to scarcity pricing rules in 2012. (See PJM Reconsiders Adders on Cost-Capped Generators.)
Despite the lack of support for the PJM-IMM proposal in the poll, PJM officials said they intend to bring their plan to an MIC vote next month.
“Although it was spun as a compromise proposal it’s only a compromise between PJM and the IMM, not other participants,” said Dave Pratzon, who represents generators. “I don’t think … that this is the best way to move forward.”
“This is a load-gen[eration] issue,” responded Dave Mabry, of the PJM Industrial Customer Coalition. “Nothing is going to get sector-weighted support.”
PJM has dropped a plan that would have allowed dispatchers to cut interchange ramp limits in order to reduce price volatility and uplift, the RTO told the Market Implementation Committee last week.
The proposal was received coolly by stakeholders when PJM officials floated it at the MIC’s March meeting. (See Ramp Limits Cause Stir at MIC.)
After internal discussions among PJM staff, the proposal “has been taken off the table,” PJM’s Lisa Morelli told the MIC last week.
Dispatchers will continue to have the ability to limit ramp to protect reliability and may use it more frequently in the future, Morelli said. But PJM will develop manual language to clarify the circumstances under which such action may be taken, she said.
At a Federal Energy Regulatory Commission technical conference April 1, PJM Executive Vice President for Operations Mike Kormos said PJM might consider requiring interchange transactions be scheduled two or three hours in advance so that operators can avoid having too much supply. Current interchange rules allow scheduling with only 15 minutes’ notice.
Kormos said unexpected imports contributed to PJM’s nearly $600 million in uplift costs in January. (See PJM May Offer Firm-Fuel Premium.)
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.
