There were more than a few concerned stakeholders at last week’s Members Committee webinar when Market Monitor Joe Bowring presented data showing that only 10 generating units were responsible for 38% of the RTO’s uplift charges in 2013.
Whose generators are they and where are they located? Bowring would like to tell you. But PJM officials said they are prevented by the RTO’s confidentiality rules from disclosing the names.
(Source: Monitoring Analytics LLC)
“The only way that’s ever going to get released by PJM is if we get a FERC order,” Executive Vice President for Markets Andy Ott told the Markets and Reliability Committee Thursday.
The 10 units were responsible for about $335 million of uplift charges in 2013. In total, PJM had $882 million in uplift, or operating reserve charges, for the year, a $231 million increase over 2012. Reactive service charges increased $263.5 million, while black start costs jumped $78 million. (See related story, Black Start Units to See More Green.) Balancing and day ahead charges decreased by a combined $110 million.
Ott said the recent spike in reactive charges is temporary – a result of coal plant closures forcing operators to order more out-of-merit dispatch -– and will be corrected by the addition of new generation and reactive upgrades.
“The reactive issue will be done before we could get [FERC approval for] language changes” to the confidentiality rules, Ott said.
Howard Haas, representing the Monitor, told the MRC the confidentiality rules don’t apply because it is not market-sensitive information. “This is a non-market payment. It’s not hedgeable, so there’s no problem in releasing the information,” he said.
Dave Anders, PJM manager of member services, said that while the Energy Market Uplift Senior Task Force is devising strategies to reduce uplift, PJM staff is considering operational changes it can make without modifying the Tariff or Operating Agreement. “Can we change the model and how we commit units? We may be able to take steps to limit the cost of reactive uplift,” he said.
Bruce Bleiweis, of DC Energy, said it was improper for PJM to take actions “that divide us all into winners and losers without subjecting it to the stakeholder process.”
Ott insisted the changes were permitted. “Similar decisions are made every day.”
The coal industry lobby that sank Ron Binz’ nomination to the Federal Energy Regulatory Commission won’t have a clear shot at President Obama’s new choice as FERC chair.
But that doesn’t necessarily mean smooth sailing for nominee Norman Bay, who has served as director of FERC’s Office of Enforcement since 2009.
While Binz, a former Colorado regulator, called for a new “regulatory compact” and opined on the future of coal and natural gas, those combing through Bay’s history will find little on utility law or energy policy.
A former federal prosecutor and law school professor, Bay has written extensively on criminal law and national security issues. But his opinions on the major policy issues facing the commission — the role of demand response and renewables, implementing Order 1000 — are unknown. Unlike most FERC commissioners in the last decade, Bay has never served as a state utility regulator.
Of the 15 FERC commissioners who have served since 2000, 10 served as commissioners or staffers at state regulatory agencies prior to their appointments. Four of the others worked in energy-related posts in state or federal legislative committees or executive agencies; one was a former utility executive. (See table.)
Of the 15 FERC commissioners who have served since 2000, 10 previously served as members or staffers at state regulatory agencies.
The last five chairmen served a median of 30 months before becoming chair. Only one, Patrick H. Wood III, served less than a year on the panel before his promotion.
Alaska Sen. Lisa Murkowski, ranking Republican on the Energy and Natural Resources Committee, had criticized Obama’s plan to elevate Binz directly into the chairmanship. She also has reservations about the president’s plans for Bay. “It’s curious that they would elevate him to chairman over existing qualified members,” spokesman Robert Dillon told Bloomberg News.
In his favor, Bay has no obvious enemy constituencies — except, perhaps for members of the energy bar, some of whom believe his office has been overzealous in its enforcement actions.
Harvard Law Graduate
The son of Chinese immigrants, Bay studied history at Dartmouth before getting his law degree from Harvard. He clerked with a judge on the Ninth Circuit appeals court and worked in the Legal Adviser’s Office of the U.S. State Department before beginning an 11-year stint as an assistant U.S. Attorney in Washington and Albuquerque, where he prosecuted violent crime.
In 2000, President Clinton appointed him U.S. Attorney for New Mexico, where Bay led a staff of more than 130 and inherited the government’s controversial case against Wen Ho Lee, a scientist at the Los Alamos Nuclear Laboratory.
Lee was indicted on 59 counts for allegedly stealing secrets about the U.S. nuclear arsenal for the People’s Republic of China. But after keeping Lee in solitary confinement for nine months, the government dropped the case in return for Lee’s guilty plea to a single count of mishandling classified material.
The judge who accepted the plea apologized to Lee for what he called misconduct by senior Justice Department officials and Bay’s predecessor as U.S. Attorney. In 2006, Lee received $1.6 million from the federal government and five media organizations to settle a civil suit he had filed against them for leaking his name to the press before charges had been filed.
Although he was not personally implicated in any wrongdoing, Bay was called before a Senate oversight hearing into the case. He resigned as U.S. Attorney in 2001, after the election of President George W. Bush.
As a professor at the University of New Mexico School of Law between 2002-2009, he taught criminal law, evidence, constitutional law, national security law, and ethics. His law journal articles include Prosecutorial Discretion in the Post-Booker World and Executive Power and the War on Terror.
Evolution of FERC Enforcement Unit
When manipulative schemes by traders at Enron and other power marketers roiled the Western energy markets in 2000-01, FERC’s enforcement staff consisted of 20 lawyers in the Office of General Counsel. The maximum penalty FERC could impose was $10,000 per violation per day.
Since then, FERC created a separate enforcement division now staffed with 200 economists, accountants, auditors, former traders and attorneys, including former prosecutors. (Full disclosure: RTO Insider editor Rich Heidorn Jr. worked for the Enforcement Division between 2002-2010.)
Bay created a new unit in 2012, the Division of Analytics and Surveillance, which runs automated screens to detect potential manipulative behavior.
Since passage of the 2005 Energy Policy Act, which increased the penalties to $1 million per violation per day, FERC has collected $873 million in civil penalties and disgorgements. They included cases against Morgan Stanley, Constellation Energy Group Inc., Deutsche Bank AG and JP Morgan Chase.
Barclays PLC meanwhile is fighting a FERC order that it pay a $453 million fine and $35 million in unjust profits over alleged manipulation of Californian and other western power markets by the British bank in the last decade.
But consumer advocates and other critics say regulators’ enforcement actions have neither provided sufficient deterrent nor made consumers and honest market participants whole. Moreover, some say regulators will never be able to catch up with clever traders looking to exploit the rules. (See JP Morgan Settlement: A Verdict on Electric Markets?)
Appellate Loss
FERC also has been criticized for overreaching in its enforcement under Bay. The D.C. Circuit last year threw out FERC’s market manipulation case against Brian Hunter, whose natural gas trades contributed to the collapse of hedge fund Amaranth Advisors LLC.
FERC had accused Hunter of selling natural gas futures contracts at the end of the trading day, which depressed the futures closing price but benefited the hedge fund’s swap positions in physical markets.
The court ruled that the agency had encroached on the jurisdiction of the Commodity Futures Trading Commission (CFTC), which sided with Hunter in the case in claiming exclusive jurisdiction over futures contracts.
“Although the Commission reads the Hunter decision as narrow in scope, some market participants interpret the decision more broadly to cover not only manipulation in the futures market, but also many additional transactions and products, including those squarely within FERC’s jurisdictional markets,” Bay told the Senate Banking Committee in testimony last month. “Accordingly, a legislative fix to eliminate uncertainty on this matter could ensure that FERC has the full authority needed to police manipulation of wholesale physical natural gas and electric markets.”
FERC and the CFTC took a step toward settling their long-running turf battle in January, signing two Memoranda of Understanding to address jurisdictional issues and information sharing.
Criticism of FERC Enforcement
At the National Association of Regulatory Utility Commissioners annual meeting in November, a panel including former FERC Chairman Joseph Kelliher and former General Counsel William Scherman attacked FERC’s enforcement as opaque and a threat to market liquidity.
Kelliher, now executive vice president for NextEra Energy Inc., said he now realizes “it’s much harder to comply [with market rules] than I thought.” He said the commission has not clearly defined what constitutes a “strong compliance culture,” a consideration when calculating penalties. Because most of FERC’s enforcement cases have resulted in settlements, the agency has not created a full record to define behavior it considers manipulative.
Scherman went further, saying that FERC’s actions are causing companies to leave the energy markets, reducing liquidity and increasing volatility.
They were joined in criticism by Harvard professor William Hogan, who said FERC needs to be transparent regarding its definition of market manipulation.
Bay was not present at the NARUC conference. His deputy, Larry Gasteiger, defended FERC’s record, saying it was following the direction of Congress, which allowed FERC to determine on a case-by-case basis whether trading behavior is manipulative.
LaFleur’s Future?
Bay’s nomination leaves the future of acting FERC Chair Cheryl LaFleur in question. LaFleur, named acting chair in November with the expiration of former Chairman Jon Wellinghoff’s term, told reporters last week she’d like to be renominated for another term, whether or not it was as chair. (See Acting FERC Chair Wants to Keep Her Job.) Her term expires in June.
Asked Friday whether President Obama will nominate LaFleur to a second term, a White House spokesman replied cryptically, “I have no personnel announcements to make.”
Wellinghoff, who hired Bay at FERC, reportedly lobbied for him as his replacement. “Norman Bay did a great job as the Office Director of the Office of Enforcement and I think he will make a great commissioner,” Wellinghoff said in an email to RTO Insider.
The Federal Energy Regulatory Commission ordered PJM to provide more information in support of its proposed limits on capacity imports, as opponents said the proposal would unreasonably increase prices.
PJM proposed methodology that will limit external generation resources in this May’s base capacity auction to 6,200 MW — a 17% drop from the volume of imports that cleared in last year’s auction. (See Members OK Capacity Import Limit; Prices May Rise.)
The commission’s Jan. 28 order (ER14-503) came after the MISO Market Monitor and others called on FERC to conduct fact finding on the proposal, contending the reduced competition from imports will increase PJM’s prices. PJM’s Market Monitor and some PJM generators, meanwhile, say the limit doesn’t go far enough to protect reliability.
Among the issues on which FERC requested more information were:
Protests by the PJM Market Monitor and the Indicated PJM Utilities, who contend that all external resources should be required to meet the standards set for resources exempt from the limits (firm transmission service, pseudo-tie, and must-offer requirement).
How PJM planners decided on the five external zones for calculating the limits.
How the methodology used to determine the capacity limits compares with that used to determine the installed reserve margin (IRM) for the capacity auctions.
The contention of MISO’s Market Monitor, Potomac Economics, that PJM should remove the requirement for unit specific deliverability testing. The MISO Monitor contends PJM’s requirement is based on an unrealistic notion that when PJM needs firm capacity-backed energy “from an external resource in MISO that the energy will be sourced at that particular unit.”
How the limit affects the MISO/PJM fact-finding effort on capacity deliverability across the RTOs’ seam.
PJM must respond to FERC’s questions within 30 days.
The PJM proposal won support from PJM generation owners, state regulators, the North Carolina Electric Membership Corp., the Electric Power Supply Association and others. Among those opposing the change in addition to the MISO Monitor are American Municipal Power (AMP) and the Illinois Municipal Energy Agency.
The Illinois agency contended the PJM proposal “grossly overreaches the problem claimed.”
AMP suggested the capacity import limits (CILs) were like “territorial allocations or refusals to deal, both of which can and often do run afoul of federal and state antitrust laws.”
AMP said it would be hurt by the limits because it owns generation in MISO that was planned when about half of its native load was in MISO. Less than 5% of AMP member native load remains in MISO as a result of the moves to PJM by ATSI in 2011 and Duke Energy-Ohio in 2012.
AMP says the value of its MISO generation “would be greatly impaired if PJM’s CILs were to prevent AMP from utilizing those resources to serve the capacity needs of its PJM-area members.” The company said it is already suffering from the “very substantial congestion charges AMP is assessed in bringing energy from MISO into PJM.”
The PJM Power Providers Group counters that the PJM proposal won more than 85% support in a sector-weighted vote by stakeholders.
The Maryland Public Service Commission staked out the middle ground, saying that while it “largely supports” the proposal, it has concerns that big reductions in imports from MISO could “significantly increase costs for end-users.”
It urged the commission to “fully utilize its evidentiary procedures” before ruling.
A proposed manual change on compensation for demand response prompted a protest from curtailment service provider Icetec Energy Services Thursday.
Icetec representative John Webster said one of the changes proposed by PJM goes beyond the ministerial detail included in manuals and should receive a full stakeholder hearing as a potential Tariff change. Webster said the change will have a “disproportionate impact on sophisticated end users with time-variable rates.”
PJM’s Pete Langbein, who presented the proposed manual change to the Markets and Reliability Committee Thursday, rejected Webster’s complaint, saying the changes are “absolutely consistent with the current Tariff.”
Under Order 745, PJM will compensate Economic DR at full Locational Marginal Price when it provides a net benefit to the system. Langbein said stakeholders asked for clarification on how PJM will apply the “net benefit” test.
In response, the Demand Response Subcommittee proposed that Manual 11: Energy & Ancillary Services Market Operations be revised to specify that compensation be limited to demand reductions executed in response to LMPs or PJM dispatch instructions and “that are not implemented as part of normal operations.”
The committee also recommended additional language identifying as ineligible for compensation: “Settlements based on load reductions from normal operations that would have occurred without PJM dispatch, or that would have occurred absent PJM energy market compensation.”
Webster said that addition will subject customers to a “motivational test” that will adversely impact those with time-variable rates — which he called “the next generation of demand response.”
WASHINGTON — Cheryl LaFleur, acting chairman of the Federal Energy Regulatory Commission, said yesterday she’d like to keep the top job and would use the pulpit to ensure electric markets and infrastructure adapt to a world of renewables, cheap gas and greenhouse gas regulations.
Acting FERC Chair Cheryl LaFleur ponders a reporter’s question.
“I would like to be renominated for another term,” LaFleur, whose current term expires in June, said at a press “roundtable” at FERC headquarters. “I’d also like to stay as chairman. Neither of those are up to me… but I’d like to be renominated under any circumstance.”
LaFleur was named acting chair in November with the expiration of former Chairman Jon Wellinghoff’s term and nominee Ron Binz’s flameout.
LaFleur said she had heard nothing from the White House about when President Obama will fill the commission’s fifth seat, or whether she is being considered for chair.
If she remains, she said, she would like to help ensure a smooth transition as the electric generation mix changes.
“We are going through a significant change in power supply in this country, when we look at renewables, when we look at the generational replacement — and that’s before you layer in whatever new carbon regulations come,” she said.
“I’d like to feel at the end of my time that the markets adapted and did what they needed to do for customers — kept the lights on at just and reasonable rates — and that the infrastructure was ready for those changes.
“And that’s quite a piece of work actually, because the infrastructure was built for the old world and not the world we’re moving into.”
Asked about FERC’s long running turf battle with the Commodity Futures Trading Commission, LaFleur said she believes the two Memoranda of Understanding signed with the CFTC earlier this month will help clarify jurisdictional questions.
She said legislation to further clarify the lines of authority “would be useful” but added, “I’m not actively on [Capitol] Hill lobbying.”
Stakeholders backed PJM’s proposal to eliminate speculation in capacity auctions, selecting it over four alternatives in a vote announced yesterday.
The PJM proposal will be the main motion considered by the Markets and Reliability Committee for a vote next month. It will be discussed in a first read at Thursday’s MRC meeting.
Because clearing prices in incremental auctions (IAs) are usually lower than those in the base residual auction (BRA), participants can profit by selling capacity in the BRA and buying out their commitments in the IAs. PJM and the Market Monitor say such buyouts are suppressing capacity prices and could undermine system reliability.
PJM’s proposed solution would reduce the number of incremental auctions (currently three) and set conditions eliminating the potential to arbitrage between the BRA and IA. The alternative proposals adopted some of PJM’s changes but differ in other details. All of the proposals would increase the penalties for failing to deliver promised resources.
The vote asked members of the Capacity Senior Task Force whether they could support the changes in each proposal. Forty-three voters, representing 206 members and affiliates, cast votes, with 141 (69%) backing the PJM proposal (#2 in the matrix).
Proposals by Old Dominion Electric Cooperative (#4) and the Market Monitor (#9) won support of 37% as did proposal 2a which married the PJM proposal with a “force majeure” requirement.
Exelon’s proposal (#10) won 22% support. (RC Cape May Holdings LLC withdrew its proposal before voting commenced last week.)
Qualifying Events
The Market Monitor had proposed that capacity offers be defined as representing “an enforceable commitment to physically deliver — excused only by either ‘qualifying events’ or ‘force majeure’ provisions.”
The Monitor defined a qualifying event as “a physical or regulatory event outside of a seller’s control and that was not reasonably foreseeable.” This would include deratings due to operational restrictions and certain construction delays. Excluded would be buyouts for economic reasons and cancellations or construction delays for “financial, commercial or permitting reasons.”
PJM, ODEC and Exelon declined to include the qualifying event provision in their proposals.
PJM staff said they believed the language was unnecessary in light of the other changes in their package and that it “would be too subjective to effectively administer and would introduce ambiguity and uncertainty for market participants, something we believe is important to avoid.”
Package 2a allowed replacement only under “force majeure” events, as defined in the Tariff.
MRC Vote
If the PJM plan fails to win two-thirds support in a sector-weighted vote of the MRC, the committee could consider the other proposals, which are summarized in the CSTF’s summary report.
The PJM proposal is summarized below:
Capacity Resource Deficiency Charge
Bidders who fail to deliver on promised resources currently must pay a capacity resource deficiency charge equal to the higher of 1.2 times the weighted average resource clearing price (RCP) or the RCP plus $20.
PJM would make the penalty to the higher of 1.5 times the RCP or the RCP plus $50, an increase over the status quo, but not a return to “2.0x” levels that used to be in effect.
PJM’s proposal would increase the penalty by about 25% to 38%, according to an RTO Insider calculation based on clearing prices from the 2013 base residual auction (BRA). The strictest proposals would increase that penalty by 50% to 67%.
Incremental Auctions (Currently three)
PJM would retain the final IA, one year before the beginning of the delivery year, with the other two occurring only if needed for PJM to obtain additional capacity due to increases in its reliability requirement. PJM would release capacity only in the final IA, the only one in which other capacity buyers could participate.
PJM sell offer price
PJM would continue the current practice — an upward sloping offer curve with starting price determined based on intersection of the variable resource requirement (VRR) curve and vertical line at current commitment level — but the price would be floored at the clearing price in BRA.
Allocation of 2.5% Short-term Resource Procurement Target
Current rules allocate 0.5% each to the first two IAs with 1.5% in the final IA. That would continue under PJM’s proposal, assuming all three auctions are held. If not, the allocation from any cancelled auctions would be carried over to the next auction.
Incremental Auction Settlement Calculation
Cleared sell offers and buy bids currently settle against the IA clearing price. PJM would continue to clear sell offers against the clearing price. Buy bids, however, would have to pay the clearing price plus the difference between the BRA and the IA clearing prices — eliminating the ability of market participants to profit by selling at a high price in the BRA and buying back at a cheaper price in the IA.
Prerequisites for BRA Participation
PJM would require all resources to sign a Non-Diversion Agreement, which prohibits the replacement of capacity committed in RPM for the purposes of selling to another market. Resources imported from outside PJM would be required to provide a Letter of Non-Recallability, signed between the resource owner and the host balancing authority.
An executed Facilities Study Agreement would be needed by planned generation greater than 20 MW.
Implementation Schedule
PJM would implement most changes for all auctions related to delivery year 2017/18, starting with this year’s BRA. The sell offer price and mitigation changes would become effective immediately upon FERC approval.
After last week’s widely-anticipated dividend cut, the question now facing FirstEnergy Corp. is whether its renewed focus on regulated operations will improve the beleaguered utility’s fortunes enough to regain Wall Street’s favor.
FirstEnergy announced on Tuesday it was reducing its quarterly dividend to 36 cents a share from 55 cents, a cut of more than one-third. The move followed a year in which the company’s stock fell 20%, making it the worst performer in the S&P 500 Utilities Index, according to Bloomberg.
FirstEnergy Stock’s stock performance vs. Exelon and the Dow Jones Utility Index(Source: Yahoo Finance)
Not a Surprise
The only surprise to some was that the cut — the first in the company’s 17-year history — wasn’t larger.
Although the company had resisted calls to cut the dividend, the move was widely anticipated by analysts as the company struggled to service its debt and fund capital spending.
Officials said last week that cheap natural gas and the lingering effects of the recession had undermined its competitive business at the same time its cash flow was pressured by about $1 billion in to-date unreimbursed storm damage.
“You have to take a look at reality,” CEO Anthony Alexander told an analysts’ call Wednesday. “The cost of equity became very, very expensive in a very short period of time. As we looked to a total repositioning of the company, this action seemed to be the most effective way to address what needs to get done.”
The company acknowledged that its focus on its unregulated business was a losing strategy at a time of flat demand growth, low energy prices and an unpredictable PJM capacity market. PJM’s real time load-weighted LMPs have dropped by more than 40% since 2008. RTO prices in the annual base capacity auction have fluctuated wildly over the same period, ranging from $16 to $174/MW-day, with a price of $59 last May.
“PJM’s capacity auctions, which are intended to provide support for competitive generators, do not and instead have delivered unpredictable and inadequate results,” Alexander said.
The company said it expects its regulated transmission and distribution businesses to account for more than 90% of its earnings going forward.
Cash Flow
FirstEnergy had negative cash flow of more than $1 billion in 2012 and 2013. Reducing the dividend will save the company $320 million in cash annually, reducing it to a level that can be supported by the more predictable regulated earnings, officials said. The competitive businesses should be self-supporting with potential “upside” if load growth and energy and capacity prices rebound.
Alexander said the moves will strengthen the balance sheet and credit metrics and “derisk the business overall.”
Response to Cut
The company’s shares fell 3% to $31.13 on trading of 14 million shares, three times the average volume, after the news Wednesday. It closed yesterday at $30.88.
The cut was in line with analysts’ consensus, according to Bloomberg, but less than some said was necessary. Analyst Paul Patterson, of Glenrock Associates, said the new dividend payout of 58% of regulated earnings “doesn’t sound particularly aggressive.” Kit Konolige, an analyst for BGC Partners LP said he had expected a 40% cut.
Moody’s Investors Service said although it welcomed the cut it was maintaining its negative outlook on the company’s credit.
Analysts on Wednesday’s call questioned whether the company was considering additional action, including more generation sales or closures, or the sale of the entire competitive operation.
“I’m not going to speculate on what’s out there” in potential sales opportunities, Alexander said in response to one question. “Right now we’re comfortable with the size of the fleet we have,” he added later.
Weak Earnings Forecast
While the dividend cut relieves pressure on the company’s cash flow, the earnings forecast officials outlined last week did little to inspire investor confidence.
The company said it expects to earn $2.45-$2.85 per share in 2014, down from a projected $2.95-$3.05 for last year.
“At the midpoint of guidance, FE has a forward multiple of 12x. For a company with earnings falling 10%, that is not a particularly attractive multiple,” analysts at Seeking Alpha wrote.
“Importantly, this guidance has to leave investors questioning whether FirstEnergy cut the dividend enough. The new dividend will still account for 58% of earnings from FirstEnergy’s main regulated business. Dividend payout ratios above 60% are often unsustainable, so if FirstEnergy’s business continued to erode, another dividend cut would not be out of the question.”
Others in Trouble?
FirstEnergy is hardly alone in its malaise. Exelon Corp. cut its dividend by 41% last February, and officials said it may close unprofitable generating plants this year if capacity prices don’t increase. (See Exelon to Close Generating Plants if No Rebound Next Year.)
Hugh Wynne, analyst with Sanford C. Bernstein & Co. said last week that even distribution utilities insulated from competitive wholesale markets, including Pepco Holdings Inc., could be forced to cut their dividends. (See related story, Pepco CEO to Retire)
Generation Fleet Leaner
With the deactivation of 5,000 MW of generation within PJM since 2012, and pending sales of other generation, the company’s 13,000 MW generation fleet will be about the same as before its 2011 merger with Allegheny Energy but one that is “more environmentally sound and efficient,” Alexander said. “It’s a much stronger platform of units,” Alexander said.
The company expects annual retail sales of about 100 million MWh, about 25% more than produced by the fleet.
Once it completes spending to comply with the Environmental Protection Agency’s Mercury and Air Toxics Standard (MATS) and retrofits at the Davis Besse and Beaver Valley nuclear plants, 85% of FE’s capital expenses will be on regulated operations, officials said.
“I don’t see us having to make any cash injections into the competitive business,” said Chief Financial Officer James Pearson. “Their cash flow should be sufficient to fund the capex over the next three years.”
Officials said they were making “aggressive” operations and maintenance reductions with discretionary spending only if it’s justified by a “fundamental upside shift in market dynamics.” For now, any additional free cash from competitive operations will be directed to strengthening the balance sheet or investing in regulated operations.
Bright Spots?
Officials said they were seeing “early indications of a sustained [economic] recovery” in FE’s service territories, projecting a 0.6% load growth in 2014, most of it from industrial customers. Shale gas activity has led to 210 MW of new industrial demand with an additional 430 MW of planned expansion.
The brightest near term opportunities are in the transmission business, with a 20% earnings growth projected for American Transmission Systems Inc. (ATSI) and Trans-Allegheny Interstate Line Co. (TrAIL).
The company also vows to be “far more active in distribution rate filings” than it has been in the past, with rate requests planned this year for West Virginia and Pennsylvania. It expects a ruling shortly from the New Jersey Board of Public Utilities on Jersey Central Power and Light Co.’s request for reimbursement of storm recovery expenses.
PJM will pay MISO $8.6 million to correct market-to-market accounting errors:
Merit Order (4/6/2013 – 7/17/2013) — During the summer seasonal allocation run, PJM incorrectly changed the dispatch priority for some of its generators that came on-line after the April 2004 “freeze” date, causing the units to be dispatched in the calculation of the allocation when they should not have been. This caused incorrect Firm Flow Entitlements (FFEs) to be used in the settlements processing.
Load Forecast (6/1/2013 – 8/14/2013) — The MISO monthly load forecast for MISO LBAs was not getting refreshed, causing the flowgate allocation calculation to use stale load forecast data. This impacted FFEs used in the M2M process.
PJM will begin processing the invoices next month.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
2. PJM MANUALS (9:15-9:25)
The MRC will be asked to endorse changes to Manual 14B: PJM Region Transmission Planning Process implementing PJM’s new capacity import limits.
Reason for Change: Stakeholders approved the limits in November out of concerns that PJM might lack sufficient transmission to accommodate its growing volume of capacity imports. Cleared imports grew from about 3,000 MW to more than 4,500 MW from 2009-2012 before more than doubling to nearly 7,500 MW this year.
Impact: The revised methodology will limit external generation resources in next year’s base capacity auction to 6,200 MW — a 17% drop from the volume of imports that cleared in the May 2013 auction, while also setting five import zones with their own limits. (See Members OK Capacity Import Limit; Prices May Rise.)
The committee will be asked to endorse changes to Manual 18: PJM Capacity Market to clarify Tariff provisions that allow substitutions of demand response resources.
The change would allow curtailment service providers to substitute a non-performing DR registration with one or more other DR registrations in the same geographic area and with the same lead time.
Providers may use Limited DR to replace Annual DR but the substitution will not count against Limited’s 10 dispatch-per-year cap. Annual DR has no limits on the number of dispatches.
4. QTU DEFICIENCY CHARGE AND CREDIT RATE (9:45-10:00)
Transmission developer H-P Energy Resources LLC will ask members to consider reducing what the company says are excessive credit requirements for Qualifying Transmission Upgrade (QTU) projects.
QTUs are small transmission projects — typically less than $10 million — that can be offered into the capacity market to relieve transmission constraints in Locational Deliverability Areas (LDAs).
The company told the MRC last month that the current rules require credit postings that can be multiples of the construction cost, creating a barrier to entry that artificially raises prices in LDAs.
The MRC will vote on a proposed problem statement and issue charge to consider changes in the requirements.
Wind power output can be adjusted to support power system reliability, instead of the rest of the system having to adjust to wind, a National Renewable Energy Laboratory study concluded. The study developed designs for new ancillary services and tested the use of active power control at the National Wind Technology Center to evaluate the impacts on turbine performance and structure. Because it may cost wind projects money to provide the service, there must be an economic incentive for it, NREL said.
A report by 100 clean-energy executives and energy industry experts may lend support to opponents of the Environmental Protection Agency’s proposed greenhouse gas regulations, which would require carbon capture and sequestration for new coal-fired plants. The report said the administration should “not rely on unproven or commercially unavailable technologies” including CCS.
The Environmental Protection Agency has defended its CCS requirement, citing a Southern Co. project in Mississippi expected to come online this year as evidence that the technology is proven. Opponents in Congress and elsewhere insist CCS is not proven and that where it is deployed it has government funding, which they say invalidates its use for standard-setting.
Separately, in action that EPA-rule opponents could use as they undertake challenges, the agency’s Science Advisory Board said it would not review the science supporting the rule, but expressed a “strong view” that sequestration may merit scientific review in the future.
Environmental groups asked a federal court to make the Environmental Protection Agency propose overdue standards for ozone. If the U.S. District Court for the Northern District of California grants the request, it would set a December 2014 deadline for a proposal and October 2015 for a final rule. EPA’s preliminary rule in 2010 was never finalized.
On the eve of a Supreme Court argument on the Environmental Protection Agency’s Cross-State Air Pollution Rule, Democratic governors of nine Eastern states were to ask EPA Dec. 9 to impose controls on Midwestern coal plants that they say damage air quality in their states. Even if CSAPR were upheld despite coal states and industry opposition, the Eastern states’ petition would mean additional controls on Midwest emitters if EPA granted it.
