PJM will create a temporary pricing interface in the ATSI Black River area as a result of a transmission outage. The interface will capture in LMPs operator actions taken to relieve thermal or voltage problems resulting from high loads.
Most of the load buses defining the BLKRIVER closed-circle interface are in the ATSI transmission zone. It will be modeled in the day-ahead market if operators know they will be deploying sub-zonal load management before market deadlines. It will not be modeled in Financial Transmission Rights markets.
The interface will be effective Sept. 1 through Oct. 31, 2014, when the transmission outage is scheduled to be completed.
PJM’s Market Monitor made no new recommendations in its second-quarter report, but that doesn’t mean Joe Bowring didn’t have anything to say.
Instead, the Monitor used his newest State of the Market report to repeat longstanding recommendations and warn stakeholders not to overreact to the winter’s extreme weather, which sent prices skyward and brought the RTO uncomfortably close to having to cut loads.
“Particularly in times of stress on markets and when some flaws in markets are revealed, non-market solutions may appear attractive. Top-down, integrated resource planning approaches are tempting because it is easy to think that experts know exactly the right mix and location of generation resources,” the Monitor wrote.
But the Monitor said the lure of integrated planning, cost-of-service rates and subsidies for favored generation technologies should be resisted because “the market paradigm and the non-market paradigm are mutually exclusive.”
“Once the decision is made that market outcomes must be fundamentally modified, it will be virtually impossible to return to markets.”
The Monitor said criticism of the performance of PJM’s energy and capacity markets is legitimate. But he added, “Before market outcomes are rejected in favor of non-market choices, markets should be permitted to work.”
Capacity Prices Suppressed
The report repeats previous calls to eliminate limited demand response and the 2.5% demand offset from the capacity auction, saying the two combined to reduce revenues in the 2017/18 Base Residual Auction by $3.4 billion, or 31%.
“Premature and uneconomic retirements and the failure to make economic investments in new entry are both the results [of the price suppression]. … The most fundamental required change to the capacity market design is the enforcement of a consistent definition of a capacity resource so that all capacity resources are full substitutes for one another.”
The report said the 22% forced outage rate in early January was evidence that current capacity market rules have insufficient incentives and penalties.
“At present, only half of capacity market revenues are at risk for failure to perform on high demand days. Gas-fired units with a single fuel are exempt from any capacity market revenue impact that results from lack of fuel outages on high demand days. … An increase in capacity market prices must be accompanied by a strengthening of capacity market incentives so that customers can be assured of getting what they pay for.” (See related story, Reaction Muted as PJM Pitches New Capacity Product.)
Below are some statistical highlights from the 442-page report.
Prices, Revenues
The load-weighted average LMP was 84% higher in the first six months of 2014 than the first half of 2013 ($69.92/MWh vs. $37.96/MWh). High fuel prices played a large role in the increase. Had fuel prices been equal to the first six months of 2013, LMPs would have risen only 52% to $57.71/MWh.
All technology types received big increases in net revenues due to the extraordinary prices early in the year: combustion turbine (+730%); combined-cycle (+202%); coal (+338%); nuclear (+96%); wind (+32%); and solar (+14%). All figures assume that these are new plants.
Market Power
Baseload generation had an average Herfindahl-Hirschman Index (HHI) of 1,174 in the first two quarters, making it moderately concentrated under the Federal Energy Regulatory Commission’s Merger Policy Statement.
Intermediate generation averaged 1,719, at the high end of moderately concentrated, but rose as high as 5,693. FERC considers an HHI above 1,800 as highly concentrated (equivalent to between five and six firms with equal market shares).
Peakers averaged a highly-concentrated 6,119 and rose as high as 10,000, similar to patterns seen in 2013.
Nevertheless, market power mitigation ensured that energy, capacity and regulation markets produced competitive results, the Monitor said.
Marginal Units
Coal (47.6%) and gas (41%) units were marginal in all but about 11% of real-time hours in the first six months. Oil set prices for 5.7% of hours while wind units were responsible for about 5%.
In all but 1.4% of wind’s marginal hours, the marginal price was at (23%) or below (76%) $0/MWh.
PJM officials yesterday proposed sweeping changes to the capacity market to address concerns over the poor performance of generators in early January, when as much as 22% of PJM’s generating fleet was unable to run.
The centerpiece of the proposal is the addition of a new “Capacity Performance” product that would supplement existing Annual Capacity, Extended Summer and Limited Demand Response offerings.
The new product would include generation, DR and energy efficiency providers that can guarantee their availability during hot and cold weather alerts and maximum emergency generation alerts. The resources would need to demonstrate they can produce their committed installed capacity for 16 hours for each of three consecutive days.
Fuel Access
For generators, that would require access to fuel and no long notification or start times.
Gas generators would have to show they have dual-fuel capability or have secure gas supplies through a combination of firm delivery service or access to storage. Coal generators would have to demonstrate that they have taken steps to ensure their coal piles and conveyors will not freeze.
All eligible generators would have to demonstrate sufficient weatherization and operations and maintenance procedures to ensure that the unit can operate “through extreme hot or cold weather conditions.”
Penalties would be assessed for every hour that energy is not delivered, but the penalty could be offset by energy produced by a non-capacity resource in the generation owner’s portfolio.
Annual DR providers would have to be available 24 hours a day all year and ensure reductions for 16 peak hours over three consecutive days. “This requirement effectively means DR must be present summer and winter,” PJM said.
2015/16 Concern
PJM said its action was prompted by concern that a 22% outage rate in the winter of 2015/2016, “coupled with extremely cold temperatures and expected coal retirements, would likely prevent PJM from meeting its peak load requirements.”
Officials said the changes would have no immediate impact on the RTO’s installed reserve margin (IRM) calculation because “existing IRM calculations already assume higher capacity performance than is occurring, meaning that the new product should produce performance that already is factored in to the IRM calculation.”
The existing annual capacity product would be renamed “base capacity.”
PJM would establish maximum product quantities for the Limited DR, Extended Summer and Base Capacity products based on their combined reliability impact.
“This method will calculate the amount of Capacity Performance resources that can be displaced by the sum of Limited DR, Extended Summer and Base Capacity products until there is a 10 percent increase in the [loss-of-load expectation],” PJM said. “By applying such a method, PJM will allow resources with availability limitations to clear in RPM auctions only up to maximum quantities which do not significantly increase reliability risk.”
Cost Allocation
The changes would take effect for the May 2015 Base Residual Auction (BRA), with a transitional mechanism to address reliability requirements for delivery years 2015/16 through 2017/18.
PJM offered two options for assigning costs under the new construct.
One would continue current rules, which assign capacity costs to load-serving entities based on their daily unforced capacity obligation. This would recognize that while the changes are primarily intended to improve winter performance the “critical period” penalties should also improve summer reliability.
An alternative would be to allocate the additional costs of the Capacity Performance product based on zonal winter peak load forecasts.
[Editor’s Note: RTO Insider will have a full report on the PJM proposal, and stakeholders’ reactions to it, in Tuesday’s edition.]
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees 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 Valley Forge covering the discussions and votes (note change from normal location in Wilmington). See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:25)
The committee will be asked to endorse the following manual changes:
A. Manual 12: Balancing Operations. Updates Section 4.5, “Qualifying Regulating Resources,” for clarity, accuracy and consistency, including a description of current regulation testing procedures; consolidates “PJM Actions” from previous subsections into Section 4.5.
B. Manual 14B: PJM Region Transmission Planning Process. Adds language that describes Capacity Emergency Transfer Limit (CETL) easily resolved constraints to match that in the Tariff. (See MRC / MC Approvals.)
The committee will be asked to approve changes to parameters used in capacity auctions: the cost of new entry (CONE), the energy and ancillary services (E&AS) offset and the variable resource requirement (VRR) curve. The changes, which were considered by the Capacity Senior Task Force in PJM’s triennial review, would be implemented for the 2015 Base Residual Auction (BRA).
The packages of proposed changes brought to a vote will be based on the results of a formal CSTF poll, which will be completed before the MRC meeting.
In informal polling at the CSTF, only two of nine packages received more than 50% support: Public Service Enterprise Group’s package B and Dayton Power and Light’s package I (both 57% in favor). The two packages are identical in seven of 11 attributes, differing only on calculation of gross CONE, net E&AS offset, VRR shape (system) and net CONE method (RTO). (See table.)
In the informal polling, a majority also favored increasing the weighted average cost of capital in calculating gross CONE, with 57% expressing support and another 13% saying they would consider it, while 31% were firmly in opposition.
Changes to the levelization method found little support, with 71% saying they support the status quo. Changes to the net E&AS offset also proved unpopular, with only 40% wanting to abandon the status quo.
A majority — 59% to 63% — favored changing the VRR curve from the current concave shape to a convex shape.
The Maryland Public Service Commission sent PJM a letter detailing its opposition to three changes to the VRR curve proposed by the RTO: moving the curve’s “point a” to the right to increase capacity price levels sooner if reserve levels are threatened; changing to a convex shape from the current concave curve; and moving the entire curve an additional 1% to the right.
The PSC said PJM’s proposal is based on unduly conservative assumptions and would be expensive for consumers. Had the changes been in place for the last three BRAs, total capacity spending would have increased by $1 billion to $1.7 billion, a PJM simulation estimated.
BRAs are held three years before the delivery year, with the RTO able to acquire additional capacity in interim auctions. The PSC said this structure “provides an adequate time period for PJM and government to react to” any shortfalls. The PSC also said an analysis by The Brattle Group for PJM ignores this flexibility, “thus severely overstating the risk of inadequate generation, which it asserts as justification for PJM’s modified VRR curve.”
4. REGIONAL PLANNING PROCESS SENIOR TASK FORCE (RPPTF) (10:30-10:40)
The committee will be asked to approve Operating Agreement revisions defining supplemental transmission projects. (See PJM’s `To Do’ List.)
5. POWER METER AND IN-SCHEDULE DATA SUBMITTAL DEADLINES (10:40-10:50)
Members will consider proposed manual and Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data to address problems with reporting output for non-utility generators. (See PJM MIC OKs Settlement, Credit Changes.)
The committee will vote on proposed manual and Reliability Assurance Agreement changes recommended by the Market Settlements Subcommittee that would allow EDCs to submit corrections to Peak Load Contribution and Network Service Peak Load assignments until noon on the next business day. The changes are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)
7. FTR/ARR SENIOR TASK FORCE (FTRSTF) PROBLEM STATEMENT, ISSUE CHARGE AND CHARTER (11:00-11:30)
Members will discuss, and may vote on, proposed updates to the FTRSTF problem statement, issue charge and charter. The task force was formed to evaluate the causes for Financial Transmission Rights underfunding and determine whether enhancements can be made to the current FTR and Auction Revenue Rights processes to improve FTR funding levels.
Members Committee
2. CONSENT AGENDA (1:20-1:25)
B. The committee will be asked to approve a “back stop” mechanism for acquiring black start services through transmission providers when PJM solicitations fail to obtain service for a zone. Members will also vote on minor Tariff and manual changes relating to the compensation of black start units. Both sets of changes were approved by the MRC July 31. (See MRC Briefs.)
WASHINGTON — A federal appellate court Friday upheld the Federal Energy Regulatory Commission’s landmark Order 1000, rejecting arguments from those who claimed FERC exceeded its authority and those who complained it didn’t go far enough.
A three-judge panel for the D.C. Circuit Court of Appeals unanimously rejected challenges to FERC’s jurisdiction and claims that allowing competition in transmission development will harm reliability, saying it found them “unpersuasive.”
The 97-page order by Judges Thomas B. Griffith, Nina Pillard and Ann Wilson Rogers was a complete vindication for the commission and a shutout for challengers.
The ruling responded to challenges from 45 petitioners and considered input from 16 intervenors. The main threat to the order came from challengers in the Southeast and West who alleged the commission exceeded its authority under the Federal Power Act in requiring that public utility transmission providers participate in regional transmission planning, and in eliminating incumbent transmission providers’ monopoly on building and running transmission.
The court found that FERC had authority under Section 206 of the FPA to require:
Transmission providers participate in a regional planning process;
Removal of federal rights-of-first-refusal provisions “upon determining they were unjust and unreasonable practices affecting rates;” and
The allocation of the costs of new transmission facilities based on forecasted benefits.
In addition, the court found that:
There was “substantial evidence of a theoretical threat to support adoption of the reforms” in Order 1000;
FERC “reasonably determined that regional planning must include consideration of transmission needs driven by public-policy requirements;” and
FERC “reasonably relied upon the reciprocity condition to encourage non-public utility transmission providers to participate in a regional planning process.”
FERC Chairman Cheryl LaFleur said she was pleased with the ruling. “Our nation needs substantial investment in transmission infrastructure to adapt to changes in its resource mix and environmental policies,” she said in a statement. “Order No. 1000 is critical to the commission’s efforts to support efficient, competitive and cost-effective transmission.”
Order 1000, issued in July 2011, changed the process for planning and paying for new regional and interregional transmission lines. It also allows independent developers to compete with traditional utilities in building new lines.
The ruling was not a surprise for those who attended oral arguments in the case in March. The judges questioned attorneys seeking to overturn the order far more aggressively — and interrupted them far more often — than they did when responding to FERC’s attorneys. (See Appellate Court Skeptical of Order 1000 Challengers.)
Below is a summary of the issues raised by the challengers and the court’s response.
MANDATORY REGIONAL PLANNING
Petitioners led by the South Carolina Public Service Authority alleged the commission lacks authority to mandate transmission planning because the FPA only allows FERC “to regulate existing voluntary commercial relationships.” As precedent, the petitioners cited the D.C. Circuit’s 2004 ruling that invalidated FERC’s attempt to change the composition of the California ISO board of directors.
The court said Order 1000 was justified by the commission’s concern that a lack of competition would lead to higher costs for new transmission needed to address environmental, economic and reliability concerns.
“Reforming the practices of failing to engage in regional planning and ex ante cost allocation for development of new regional transmission facilities is not the kind of interpretive ‘leap’ that concerned the court in CAISO but rather involves a core reason underlying Congress’ instruction in Section 206” to remedy unjust or unreasonable rates and practices, the court said.
Petitioners embraced a “false premise” that commission-mandated transmission planning is new, the court said, citing prior commission Orders 890 and 888.
The judges also said the challengers mischaracterized “mandated transmission planning as mandating binding commercial relationships.”
The allegation that Order 1000 interferes with state regulation of planning “poses a closer question,” the court acknowledged. “But while petitioners’ argument is not without force, relevant precedent” supported FERC, the court ruled, saying “the commission possesses greater authority over electricity transmission than it does over sales.”
‘THEORETICAL THREAT’ BASIS FOR ORDER 1000
Opponents said the commission failed to provide evidence needed to justify the rule and that it was improperly seeking to change already just and reasonable planning practices.
The commission justified Order 1000 on the “theoretical threat” that “the narrow focus of current planning requirements and shortcomings of current cost allocation practices create an environment that fails to promote the more efficient and cost-effective development of new transmission facilities.”
The court said the challengers “misconceived the nature of the commission’s evidentiary burden.”
It backed FERC’s conclusion that Order 890 was insufficient to ensure just and reasonable rates because it did not require transmission providers to consider regional transmission alternatives that might be more cost effective than solutions identified in local transmission plans.
The challengers’ contention that FERC had failed to recognize that electric transmission is a natural monopoly “misconceives the basis for the competitive benefits predicted by the commission,” the court said. It cited antitrust literature that concludes that competition for a natural monopoly can be beneficial.
“Even in a naturally monopolistic market, the threat of competitive entry (e.g., through competitive bidding) will lead firms to lower their costs, which thereby generally lowers cost-based utility rates,” the court said.
REMOVAL OF FEDERAL RIGHTS OF FIRST REFUSAL
Public Service Electric and Gas and other incumbent transmission owners contested Order 1000’s requirement that utilities eliminate from their tariffs and agreements certain rights of first refusal (ROFR). ROFRs give incumbents the option to construct any new transmission facilities in their service territory, even those proposed by third parties.
Continuing ROFRs would discourage non-incumbents from identifying cost-efficient projects, resulting in the development of transmission facilities “at a higher cost than necessary,” the commission said.
The challengers said the commission should be required to provide evidence that existing ROFRs were adversely affecting rates. Such evidence did not exist, they contended, because awarding projects to non-incumbents would mean the loss of economies of scale and scope.
The incumbents also contended that eliminating ROFRs would undermine reliability because non-incumbents might lack the financial backing or technical expertise to complete essential projects on time.
The court said FERC properly addressed reliability concerns by continuing ROFRs for projects that would be located entirely within a utility’s service territory and would not be subject to regional cost allocation.
The challengers also said there was only a tenuous relationship between the incumbents’ monopolies and rates. As a result, they contended, FERC lacked authority to remove them under Section 206, which is limited to practices “affecting” a rate.
The court again made a distinction between Order 1000 and the CAISO case cited by opponents.
“The relationship between rights of first refusal and rates is far more direct than the relationship between corporate governance and rates. Nothing suggests that replacing the members of a board will necessarily affect rates. … The challenged orders here provide what was lacking in CAISO: an economic principle that directly ties the practice the commission sought to regulate to rates.”
The court also rejected arguments that differences between the FPA and the Natural Gas Act (NGA) undercut FERC’s jurisdiction.
While the NGA contains a provision analogous to FPA Section 206 that gives the commission authority to regulate practices affecting rates, it also contains a separate provision expressly authorizing the commission to regulate the construction of natural gas pipelines. The FPA does not include a similar provision regarding construction of electric transmission.
The court said it found the petitioners’ argument “unconvincing,” concluding that Section 206 does not “unambiguously” limit the commission’s authority.
“We think that the commission’s reading of Section 206 is reasonable. Petitioners give us no persuasive reason to think otherwise,” the court ruled. “…The challenged orders take great pains to avoid intrusion on the traditional role of the states.”
The court also rejected complaints that the ROFR removal violates the Mobile-Sierra doctrine, which presumes that freely negotiated wholesale-energy contracts are just and reasonable unless found to seriously harm the public interest.
Some petitioners argued that the commission unlawfully deprived them of their rights of first refusal without first making the finding required to rebut the Mobile-Sierra presumption. The court said FERC had committed to hearing the petitioners’ Mobile-Sierra arguments when it reviews the new tariffs utilities must file to comply with Order 1000.
COST ALLOCATION
Order 1000’s cost allocation rules came under fire from both sides, with some challengers accusing FERC of overstepping its authority, and ITC Holdings and others urging stronger measures.
The court said the commission had used a “light touch” in requiring that the costs of new transmission are allocated to beneficiaries while leaving the details to transmission providers.
ITC contended Order 1000 is inconsistent with the commission’s cost causation principle because it required interregional transmission lines to be approved by each transmission planning region in which the line is located.
The commission acknowledged that its rule “may lead to some beneficiaries of transmission facilities escaping cost responsibility because they are not located in the same transmission planning region as the transmission facility.”
FERC said it went this route because “allowing one region to allocate costs unilaterally to entities in another region would impose too heavy a burden on stakeholders to actively monitor transmission planning processes in numerous other regions.”
The court said it would not second guess the commission’s compromise. “The commission’s balancing of the competing goals of reducing monitoring burdens and adopting policies that ensure that cost allocation maximally reflects cost causation is wholly reasonable under the deferential review we accord in rate-related matters.”
PUBLIC POLICY REQUIREMENT
FERC faced three challenges to its requirement that transmission planners account for federal, state and local laws and regulations, such as renewable portfolio standards.
One faction said FERC exceeded its authority while a second said FERC should have required transmission planners to consider the needs of load serving entities. A third said the rule was too vague, leaving transmission providers unable to determine what is required of them.
“None [of the arguments] is persuasive,” the court ruled, saying they were based on misunderstandings of the rule.
The court said those challenging FERC’s jurisdiction “seem to argue that the commission can only exercise authority to promote goals specified in the FPA and that the public-policy mandate cannot be justified with respect to any of those goals.”
“This argument misunderstands the nature of the mandate. It does not promote any particular public policy or even the public welfare generally. The mandate simply recognizes that state and federal policies might affect the transmission market and directs transmission providers to consider that impact in their planning decisions.”
RECIPROCITY
The commission was also attacked from two sides for its requirement that non-public utility transmission providers that want access to a public utility’s transmission lines must participate in transmission planning and cost allocation. Non-public utilities, such as municipal utilities and rural cooperatives, are not subject to Section 206 of the FPA, and thus not directly covered by Order 1000.
One group of challengers said the commission lacked justification for expanding the reciprocity conditions of Orders 890 and 888 to include planning and cost allocation. The Edison Electric Institute said the commission should have mandated the participation of non-public utilities in planning and cost allocation.
“Both contentions miss the mark,” the court said, saying the commission’s conditional requirement for non-public utilities had “a reasoned and adequate basis.”
The reciprocity condition in Order 1000 “is fundamentally the same [as that required by Orders 888 and 890]. … The current orders simply apply that principle to transmission planning and cost allocation,” the court continued.
“The commission provided an adequate justification for that change — namely, that non-public utilities that take service from public utilities will benefit greatly from the reforms announced in the Final Rule, because ‘a well-planned grid is more reliable and provides more available, less congested paths for the transmission of electric power in interstate commerce.’”
PJM is hesitating on plans to introduce more sophisticated modeling of combined-cycle plants because of an inability to quantify potential savings and reports of escalating prices.
Currently, a combined-cycle plant must be entered into eMKT as either a combustion turbine or steam unit. Neither option captures its true capabilities, which can vary greatly based on unit configurations and use of duct burners.
PJM has been considering spending about $1 million on software from Alstom that it believes will give it more flexibility. But PJM’s Tom Hauske told the Operating Committee that PJM and the Market Monitor have been unable to quantify savings to justify the software purchase.
Joel Luna of Monitoring Analytics said the model would result in more efficient use of combined cycles with multiple configurations, allowing PJM to decide the optimal configuration depending on expected load and system conditions. It also would make the most of the peaking segment of PJM’s combined-cycle plants by allowing operators to make better decisions about how to schedule such units based on their technical parameters.
Luna said the result will be greater operational flexibility, more accurate pricing and reductions in uplift and production costs.
In 2013, there were 291 instances in which operators ran a combined-cycle plant at its minimum load for its entire operating interval — suggesting inefficient use of PJM resources.
If better software could reduce those start costs by half, Hauske said, it would produce savings of $2.4 million. “That’s not a firm number,” he cautioned.
“We have reasonable qualitative reasons [for making the change],” said Mike Bryson, executive director of system operations. “We’re a little concerned that we don’t have great quantitative stuff.”
“If we can’t quantify the savings, are we going to spend $1 million?” Luna asked stakeholders.
“A million would be worth spending,” answered Dave Pratzon of GT Power Group, which represents generators. Pratzon said he was concerned by reports that the Southwest Power Pool has reportedly put their purchase of the Alstom software on hold because of costs rising as high as $4 million.
But he added, “If we thought we had a good solution for $1 million, I think it would be worth doing.”
Duke’s Ken Jennings agreed, saying less efficient modeling inhibits the ability to regulate system frequency.
SPP spokesman Tom Kleckner said SPP had planned to implement the software in November 2015, but there were concerns about the potential cost, which led the board two weeks ago to ask for further study. “The board wanted to have a more detailed cost-benefit analysis,” he said. SPP declined to discuss specific cost figures.
Hauske said PJM is unaware of any region using the Alstom software, although he said MISO is considering a June 2015 implementation.
A MISO spokeswoman said yesterday that the software program is under review but denied plans for a 2015 deployment.
“If the evaluation demonstrates positive prospects, MISO will work with stakeholders to develop a detailed design and implementation plan,” MISO said in a statement. “At this stage, we haven’t purchased any production level product, and there is no current plan of implementing this enhancement in 2015.”
Bryson noted that PJM’s Aug. 1 white paper stressed the need for flexibility. “That’s another reason to keep it on the table,” he said.
The Dooms-Lexington 500-kV line in Virginia will begin an extended outage next month and through winter to accommodate a rebuild of the 40-mile span.
The rebuild (Regional Transmission Expansion Plan project b1908) was ordered to prevent overloads on the line following the retirements of Chesapeake Units 1-4 and Yorktown Unit 1 generators.
The line will be out of service from Sept. 8 through June 5, 2015, returning to service for summer 2015 and then going offline again from Sept. 7, 2015 through Dec. 31, 2015.
To avoid limiting the output of the Bath County pump storage hydro plant, a special protection scheme (SPS) will be armed as needed to trip the Bath County generating and pump units on the loss of the Bath County-Valley 500-kV line. An existing Bath County “thermal” SPS will continue to be used as needed.
The project will also cause a potential thermal constraint on Valley transformer 1 for loss of the Dooms-Valley or Cloverdale transformers. Low voltages are possible from the loss of Bath County-Valley.
PJM authorized continuing work through the winter to reduce the overall outage duration by at least six months and coordinate it with other RTEP outages: the Cloverdale-Lexington 500-kV line in 2016 (AEP); the Cunningham-Elmont 500-kV line in 2016/2017; the Dooms-Cunningham 500-kV line in 2018; and the Mt. Storm-Valley 500-kV line in 2019/2021.
PJM planners identified no reliability issues during the winter outage. The rebuild is expected to be completed by June 2016.
Norman Bay, with Richard Gates looking on, at his Senate confirmation hearing responding to questions about his handling of the Powhatan case.
In 2009, a Ph.D. electrical engineer turned energy trader shared with a suburban Philadelphia portfolio manager a seemingly unbeatable way to make money trading in the PJM market. The key was a poorly designed market rule that overcompensated up-to-congestion (UTC) trades with rebates for transmission line losses.
It was so easy, portfolio manager Kevin Gates said later, that “a monkey throwing darts at a dartboard” could have made money.
Gates feared PJM would realize its mistake before long. But in the meantime, he told his investment partners, they “should drive a truck through that loophole.”
That they did. By ramping up volumes on UTC trades that had little or no underlying risk, they made $4.7 million over five months in 2010 before PJM asked the Federal Energy Regulatory Commission to change the rule.
Four years later, the profits have shrunk, as Gates and his partners have spent more than $1.5 million on lawyers and consultants fighting a FERC investigation.
Last week, FERC staff issued a Notice of Alleged Violations against Gates and his partners, setting the stage for a showdown in a case that some critics say illustrates the excessive zealousness of FERC’s Office of Enforcement under former Director Norman Bay. The notice was filed the day after Bay was sworn in as the commission’s fifth member.
The facts, for the most part, are not in dispute. Thus the case will turn on legal interpretations: Were Gates’ trades riskless, and thus improper, “wash” trades, as FERC contends, or permissible “spread” trades? Did FERC provide proper notice that seeking profits through the line-loss rebates alone was improper? And if FERC thought it had a strong case, why did it wait nearly four years to bring it?
The following account of the case is based on records released by Gates and interviews with some of the principals.
Investment Fund Expands into Energy
Kevin Gates and his identical twin Rich manage private investment funds from an office in the Philadelphia suburb of West Chester, Pa. In 2008, the brothers met Houlian “Alan” Chen, who had emigrated to the U.S. in 1995 after receiving his doctorate degree in power engineering from Tsinghua University in Beijing.
Chen worked for about 10 years as a power analyst for several energy companies, creating models to forecast power prices, before forming his own investment fund in 2007.
Chen mostly traded up-to-congestion trades. UTCs, which load-serving entities use to hedge congestion risk, earn or lose money based on price changes between the day-ahead and real-time energy markets at individual pricing nodes. UTC traders profit if the difference between DA and RT prices is in the direction bid by the trader and the difference was large enough to cover the costs of scheduling the transactions.
Soon after meeting them, Chen began trading on behalf of the Gates brothers and their investors, who wanted to expand their investment options. Chen typically invested $4 of the Gates’ group cash for every $1 of his own.
Chen changed his trading strategy after he began receiving rebate payments, or transmission loss credits (TLCs), in October 2009.
Transmission Line Losses
PJM charges those moving power on its grid a fee to account for line losses — energy lost as heat during transmission. PJM’s method treated every transmission as if it were the last transmission in the system. Because this charged each buyer for the most problematic transmission at the time, it collected far more than actual losses.
Although UTCs don’t involve the movement of physical energy, UTC traders then had to reserve transmission service for each transaction, making them eligible for the line-loss rebates.
Chen discovered the rebates were far more than what he had paid for line losses and thus a potential source of profits. After several months of this found money, Chen and his investors began increasing the volume of their trades in February 2010. They were among a handful of traders who PJM says netted $19 million in unjust profits through the rebates.
Paired Trades
To profit on the rebates and limit the risk of loss due to the DA-RT price differences, Chen made paired trades, buying a day-ahead position in MISO and selling it at a point in PJM, while doing the same thing in the opposite direction.
At first, Chen chose an A-to-B, B-to-C trading formula, choosing “A” and “C” nodes whose prices closely tracked each other, such as Mount Storm, W.Va., site of Dominion’s largest coal-fired generator, and Greenland Gap, W.Va., the location of a Dominion wind farm 11 miles to the east. One of his favorite trades was Mount Storm to the MISO interface paired with MISO to Greenland Gap.
Had he and the Gateses continued this pattern, FERC might not be pursuing him now.
But on May 30, 2010, Chen and his partners were shocked when the UTC between MISO and Greenland Gap unexpectedly spiked and the Mount Storm-MISO trade that was intended to offset it failed to move.
Chen’s trades lost almost $180,000 on the change in price spreads. The $18,000 in scheduling costs was offset by the $22,000 in line-loss rebates, resulting in a net loss of more than $176,000.
Chen told Kevin Gates that the large volume of his trades may have contributed to the divergence between the two legs, saying “I suspect the trades we put on affected the day-ahead model runs.”
As a result, Chen changed his strategy, frequently dropping the A-to-B, B-to-C formula for a simple A-to-B, B-to-A round trip.
Assuming both legs of the matched pair cleared, this eliminated the risk of any price difference between the two trades. And that, said FERC, made them improper “wash” trades — transactions that involve no economic risk, no net change in ownership and serve no legitimate business purpose.
FERC had encountered wash trades before. Its investigation of market manipulation in the California and Western energy markets in 2000 and 2001 found that several energy trading companies, including Enron, had engaged in wash trades to create the illusion of liquidity and affect price indices to which contracts are linked. Although the commission then had no regulations on wash trading, such trades were prohibited in markets regulated by the Commodity Futures Trading Commission.
Moving the Market
In their preliminary findings, FERC staff told Chen and Gates that their large trading volumes “adversely affected the whole PJM market.” They cited a discussion between Chen and the other investors in which they acknowledged that their volumes were “moving the market.” A Gates associate complained that “we are trading too much and are bumping up against volume” and suggested they “scale back.”
Between February 2010 and early August 2010 — when PJM asked FERC to approve Tariff changes to close the loophole (ER10-2280) — Chen, Gates and their partners acquired 620,000 MWh eligible for the rebates, turning a $4.7 million profit. The rebates were large enough to cover the scheduling and transmission costs in more than 80% of the hours in which Chen used the identical pair strategy, according to FERC.
Legal Debate
Chen and the partners say their trades were not wash trades because they had a legitimate business purpose: Chen and his investors were making money on the trades.
They also faced the risk that one of the legs might not clear and they would be exposed to the DA-RT price differences. That would occur if the price spread they bet on was too low.
FERC rejects that argument, saying that Chen always bid a spread higher than historical experience for his selected nodes and usually bid at the maximum $50/MWh. The matched trades, FERC said, “never failed to clear.”
FERC’s authority to police market manipulation, which was expanded in the 2005 Energy Policy Act, largely mirrors the Securities and Exchange Commission’s trading rules.
The commission said Chen’s trading was similar to the conduct that the SEC and the Third Circuit Court of Appeals found illegal in the Amanat case, in which a trader seeking to collect rebates based on trading volume used a computer program to enter thousands of sham trades that bought and sold the same securities within a very short time period.
Gates and Chen countered with an affidavit from former SEC attorney Richard Wallace, who said that “trading for the purpose of collecting a rebate is considered a lawful and recognized practice in the securities markets.” When the SEC changed rules to prevent rebate-seeking trading, Wallace said, it did not seek to punish the traders who took advantage of the old rules.
FERC also rejected claims that Chen had no notice that profiting from the rebates alone was improper.
In the 2008 Black Oak Energy case, in which the commission confirmed the basis for PJM’s distribution of the refunds, staff said the commission sought to avoid a market rule in which “arbitrageurs can profit from the volume of their trades.”
Chen’s attorney, John N. Estes III, reads the Black Oak case far differently. In his response to the staff’s preliminary findings, Estes said that while the commission acknowledged the risk of arbitrageurs profiting from trading volume, it never said it was improper to do so.
“To conclude otherwise would fundamentally alter the obligations of market participants,” Estes wrote. “Rather than make decisions consistent with existing price signals, Enforcement’s theory of this case expects them to second-guess whether or not certain aspects of the Commission-approved markets are ‘appropriately’ functioning, and then adjust to their behavior accordingly.”
The investors’ attorneys also said their clients made no attempt to conceal their trading strategy. Thus there was none of the “fraud, artifice or deceit” typical of true market manipulation.
FERC said Chen and Kevin Gates were aware that their trading strategy carried regulatory risk.
“It really concerns me if PJM ever reverts back to those days without [transmission loss credits] or the TLC calculation was/is incorrect and we have to pay back all or some of the TLC refunds, we are going to be in big trouble,” Chen said in a message to Gates.
Gates responded: “[i]f you’re really concerned, then I’m really, really concerned” and suggested they “contact a law firm, the FERC or PJM to try to get more insight into this issue.”
They never did so, FERC says.
Estes said Chen’s trades “added value” to the PJM markets by contributing to price discovery and, “to the extent they caused day-ahead prices to move closer to real-time prices, they promoted market efficiency. They cannot be considered ‘wash’ transactions because they made money and because there was always a nonzero risk that Dr. Chen would be exposed to real-time price spread changes.”
Investigation Begins
FERC began investigating Chen and his partners in August 2010, after being alerted by PJM. Chen had stopped his round-trip trading immediately after receiving a call from PJM Market Monitor Joe Bowring on Aug. 2, 2010.
Over the next three years, Chen and his partners responded to FERC data requests and sat for depositions while their lawyers sparred with FERC’s attorneys and provided affidavits from an economist and an attorney supporting their position.
After one deposition, according to Kevin Gates, a FERC attorney told his lawyer, “He’s a businessman. He should know it’s cheaper to settle than to fight this.”
One company that engaged in similar trades, Oceanside Power, did go that path, agreeing to settle the charges against it by disgorging profits of $29,563 and paying a fine of $51,000 (IN10-5).
But Gates and Chen refused.
In October 2011, FERC said a charging decision was “imminent,” according to William M. McSwain, attorney for the Gates brothers.
FERC did not act, however, until August 2013, when FERC staff delivered a 28-page “preliminary findings” letter summarizing why they thought Chen’s trades were improper. Attorneys for Chen and Gates rejected the arguments and reiterated their demand that FERC end the investigation.
FERC refused.
Gates Goes Public
Frustrated, Kevin Gates began planning a publicity campaign to make the case that he and his partners had been unfairly hounded by FERC.
On Jan. 30, President Obama nominated Bay, then director of FERC’s Office of Enforcement, to fill the seat of former FERC Chairman Jon Wellinghoff.
A month later, Gates went public, launching a website that included much of the correspondence between FERC and the investors’ attorneys and written and video testimonials from an all-star cast including Harvard professor William Hogan and Susan J. Court, Bay’s predecessor as FERC enforcement chief.
FERC critics rallied in support of Gates and Chen, saying the case illustrated the agency’s overzealousness. Former FERC general counsel William Scherman cited the case in a Wall Street Journal op-ed published days before Bay’s Senate confirmation hearing.
FERC Gets More Teeth
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.
In the 2005 Energy Policy Act, Congress granted FERC expanded authority to police manipulation and increased its maximum penalties to $1 million per violation per day.
FERC’s enforcement unit is now staffed with about 200 economists, accountants, auditors, former traders and attorneys, including former prosecutors.
Under Bay, a former U.S. Attorney, FERC has issued orders demanding more than $1.1 billion in penalties and disgorged profits in market manipulation cases.
At Bay’s Senate confirmation hearing in May, the Gates brothers were sitting in the row behind him. Richard was on camera, over Bay’s shoulder, during the entire two-hour hearing as several Republican senators pressed the nominee to address Scherman’s criticism that Bay was driving Wall Street banks out of energy trading with heavy-handed enforcement tactics.
Bay survived the onslaught and was sworn in last Monday. On Tuesday, FERC issued a “Staff Notice of Alleged Violations,” the commission’s first public acknowledgement of the investigation. Later last week, staff sent the Gateses’ attorney a “1b 19” letter notifying them that staff would recommend the commission seek penalties.
(Although FERC’s preliminary findings challenged $4.7 million in profits the investors made between February and August 2010, the notice issued last week cites only trades made after June 1 on behalf of Chen and the Gateses’ Powhatan Energy Fund.)
De Novo
While most of FERC enforcement cases that become public are quickly settled, Chen and Gates vow that won’t happen in their case. Thus the next step will likely be a commission vote on whether to issue an Order to Show Cause.
If he can’t persuade the commission to drop the case McSwain said, the case will end up in a U.S. District Court.
It would be the third case contested in a de novo court review, joining pending cases involving Barclays bank and Richard Skillman.
Barclays is in federal district court in California, fighting an order that it pay a $453 million fine and disgorge $35 million in unjust profits over alleged manipulation of California and other western power markets. In Maine, energy consultant Richard Silkman is challenging a $1.25 million penalty. One central point of contention is how broad the federal court’s review should be, with FERC arguing for a narrow interpretation. (In addition, BP is challenging a $28 million penalty before a FERC administrative law judge.)
Members of the energy bar say those cases, along with the Chen/Gates case, will help to clarify questions about the limits of the FERC’s expanded enforcement authority.
Their attorneys say Chen and the Gates brothers are looking forward to their day in court.
“If we end up in federal court we start from scratch,” McSwain said in an interview. “It’s the first time we have a neutral decision maker.”
The Market Implementation Committee approved several changes recommended by the Market Settlement and Credit subcommittees regarding data submission deadlines and credit requirements.
Power Meter and InSchedule
One set of changes, which will be effective June 1, 2015, would extend the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data to address problems with reporting output for non-utility generators. The delay will allow a higher percentage of actual load data to be reported in InSchedule, particularly for EDCs with smart meters, and reduce the reconciliation adjustments.
Power Meter deadlines would be extended by an hour:
Monday – Thursday Operating Days: Next business day @ 4 p.m. Eastern Prevailing Time (EPT)
Meter correction data deadlines would be extended by one month. The change would allow more time for generators and EDCs to gather data, improving accuracy of submitted corrections and reducing or eliminating later bilateral adjustments. PJM also would gain additional time to process and include the meter corrections in the bill.
In addition, load reconciliation data will be considered in balancing operating reserve (BOR) for deviation calculations. The change will affect all participants with BOR deviations. Load reconciliation billing would be performed under the current 60-day schedule.
Capacity Charge Reconciliation
The MIC also approved a change to provide relief for Pennsylvania EDCs squeezed by PJM and Pennsylvania Public Utility Commission deadlines.
PJM requires EDCs to upload their Peak Load Contribution (PLC) and Network Service Peak Load (NSPL) data to eRPM 36 hours prior to the operating day. The Pennsylvania PUC issued an order in April requiring that EDCs switch customers to new energy suppliers within three business days of notification of the switch. Under the PUC’s previous rules, it took 11 to 40 days to switch electric suppliers.
The new rule gives EDCs only one day to update their records to recognize the change and correct the PLC and NSPL values, raising the possibility of retail suppliers receiving inaccurate capacity charges.
The revised schedule retains PJM’s 36-hour-advance submission deadline but allows corrections to be made until noon the next business day.
Virtual Transactions Credit Requirement Reduced
As a result of improved cleared data availability under the eCredit system, the MIC approved a reduction in the credit requirement for virtual transactions to two days (one day of submitted bids for next market day plus one day of cleared bids) from four days (submitted bids for upcoming market day plus cleared bids for three prior days).
Also changed was the definition of credit available for virtual transactions, which would no longer include “billed” profits. The Credit Subcommittee said such profits cannot be depended on for recovery of transaction losses, because they are being committed to payout at the time a loss would be discovered.
Competitive Power Ventures plans to begin major construction next month on its 661-MW combined-cycle plant in Maryland despite an unfavorable ruling last week from the Federal Energy Regulatory Commission.
FERC rejected CPV’s request that it declare the company’s contracts with regulated utilities in New Jersey and Maryland “just and reasonable.” CPV filed the request in early June, believing that FERC’s approval would nullify appellate courts’ determinations that the contracts violated FERC’s ratemaking powers. (See Rebuffed By Courts, CPV Seeks FERC End-Around.)
Instead, FERC said, “In considering whether the rates, terms, and conditions in a contract are just, reasonable and not unduly preferential or discriminatory under the FPA, the contract must first be a valid contract.” As the contracts had already been found invalid by the courts, FERC rejected the filing.
CPV announced Friday that it has obtained financing from 15 lenders, led by GE Energy Financial Services, for the $775 million St. Charles Energy Center in the Southern Maryland community of Waldorf.
CPV Chief Financial Officer Paul Buckovich told The Baltimore Sun that the costs are much higher than if the company had come to lenders with the original contracts. “The financing is much more expensive and less beneficial to sponsors and ultimately to the ratepayers,” he said.
CPV has already begun preliminary site work on the Waldorf site. The plant will be built under a “medium-term contract financing” that will require CPV to refinance five years after starting operations. The arrangement is similar to that used to build CPV’s Woodbridge, N.J., plant, which is also under construction.
CPV had sought to build two plants supported by contracts with utilities in Maryland and New Jersey. Each contract was based on a benchmark amount; if CPV’s capacity revenue was less than this amount, the utilities would pay CPV the difference. If the revenue was more, CPV would pay the utilities.
The utilities were forced to sign the contracts by each state’s public utilities commission, which led to them filing lawsuits.
