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November 16, 2024

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MC/MRC Final Approval: ARR Modeling Revised

The Markets and Reliability and Members Committees approved modeling changes for the annual Auction Revenue Rights (ARR) allocation to reflect the return of transmission facilities to service after outages.

The current tariff states that if any ARR requests made during stage 1A of the allocation process are not feasible because of transmission outages, PJM will allow the allocation by increasing the capability limits of the binding constraints. The increased limits are then used in subsequent ARR and Financial Transmission Rights allocations and auctions for the planning year.

During the ARR allocation for the 2013/2014 planning year, PJM found infeasibilities on some paths due to planned transmission outages in the annual process that were not scheduled to be out of service every month of the planning year. Continuing the increased ratings in subsequent auctions would overstate transmission capability, exacerbating FTR underfunding.

The changes to section 7.4.2(i) of the Operating Agreement will exclude increased capability limits in monthly auctions for months in which the transmission facility is not out of service.

The MRC agreed to waive the normal 60-day review period so that the changes can be implemented in time for the May monthly balance of planning period FTR auction.

PJM contact: Tim Horger

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MRC Action: Peak Load Contribution Review

The Markets and Reliability Committee approved a request from the Capacity Senior Task Force for clarification regarding its issue charge on Peak Load Contribution (PLC) measurements of demand resources.

The issue charge directed the group to explore the interaction of PLC with end-user cost assignments and DR providers’ revenues from capacity market auctions.

“We had trouble figuring out what the problem was” because of the wording of the problem statement, said task force chair Sarah Burlew.

Aaron Breidenbaugh, of EnerNoc, opposed expanding the scope of the issue charge. Stability “has been sorely lacking” in demand response, he said.

David Scarpignato, of Direct Energy Business, said he would like more transparency on how PLCs are calculated by electric distribution companies.

The revised problem statement was approved 2.64-2.36. It breaks the issue into three problems:

  • Customer PLC Risk: Customers that want to be fully interruptible but don’t know their PLC three years in advance of the Base Residual Auction (BRA)
  • PLC Accuracy: Customer load changes are not incorporated in PLC until approximately one year later
  • Review accuracy and transparency of PLC measurements and — if changes need to be made — consider potential alternatives.

The revised problem statement will be assigned to the Demand Response Subcommittee because the task force is slated to sunset. The subcommittee was asked to decide by Dec. 1 whether any changes are necessary and to make such changes by July 2014 to allow time for FERC approval before the 2018 Base Residual Auction.

PJM contact: Sarah Burlew

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MRC Action: Calculating Capacity Values for Intermittent Resources

The Markets and Reliability Committee approved a problem statement to protect intermittent generators (e.g., wind) from being assigned artificially depressed capacity values as a result of curtailments directed by PJM.

PJM began excluding all curtailed hours in its capacity calculations for the summer 2012 capacity auction. The removal of the curtailed hours can still hurt a generator’s capacity value, however, because curtailments generally occur during periods of high generation. While the curtailments often last only 10 minutes, PJM systems are programmed to remove any hour from the calculation that includes a curtailment, regardless of its duration.

The issue was assigned to the Planning Committee. The group will analyze the magnitude of the issue and evaluate alternate calculation methods and tariff and manual revisions required to implement them.

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Tariff Changes OK’d for East Kentucky Integration

The Members Committee approved tariff and agreement changes to allow integration of the East Kentucky Power Cooperative into PJM effective June 1. The changes, which affect the tariff, operating agreement, reliability assurance agreement and transmission owners’ agreement, are similar to those made for the recent integrations of American Transmission Systems, Inc. and Duke Energy Ohio and Kentucky.

The Markets and Reliability Committee also heard a first read on changes required to Manual 13: Emergency Operations.

The 16-member cooperative, which joined PJM as an Other Supplier in 2005, estimates it will save almost $132 million over the next decade by taking advantage of PJM’s economies of scale and generation diversity. The winter-peaking system (2,500 MW) will increase PJM’s generation capacity by 2.5% and transmission net­work by 4%. (See earlier story.)

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Consumer Advocates Seek Director

Consumer advocates in PJM are looking to hire a director to represent them before the RTO and the Federal Energy Regulatory Commission.

The Consumer Advocates of PJM States (CAPS), which was formed last year, issued a request for proposals for an individual or firm to represent them in stakeholder meetings and to coordinate communications and strategy. April 8 is the deadline for submitting a response.

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CFTC Approves Dodd-Frank Exemption for RTOs

By Rich Heidorn Jr.
PJM Insider

WASHINGTON  (April 2, 2013) — The Commodity Futures Trading Commission agreed Thursday to exempt PJM market transactions from most of its regulations, ceding authority to the Federal Energy Regulatory Commission.

But it is unclear whether CFTC’s action will end its turf skirmishes with FERC because the agency retained its right to police RTO trades under its anti-fraud and anti-manipulation authority (see pg. 2 of the order). Also unclear is the impact on small traders that don’t meet the criteria for the CFTC exemption.

Acting on a petition by PJM and other Regional Transmission Organizations and Independent System Operators, the CFTC relinquished most oversight over energy, capacity and ancillary product transactions already regulated by FERC. The exemption also applies to ERCOT, which is regulated by the Public Utility Commission of Texas (PUCT).

The commission’s 5-0 ruling is nearly identical to the proposed order it issued August 28, but includes expanded definitions of covered transactions and parties.

The Dodd-Frank Wall Street reform act encouraged the jurisdictional handoff by inserting a section in the Commodity Exchange Act (CEA) underscoring FERC’s authority over RTO transactions.

Exempt Transactions

Exempted are FTRs (p. 13), day ahead and real time energy transactions, including demand response (p. 14); forward capacity transactions (p. 14-15) and Reserve Regulation Transactions (p. 15-16). Similar products offered by the RTOs in the future also will be exempt (p. 22-23).

PJM and the other regional system operators said the transactions should be exempt because they are “subject to pervasive regulatory oversight” by FERC and PUCT. The regions said they made the request “in an abundance of caution” to forestall future legal challenges that could cause market “uncertainty.”

The definition of exempted transactions was expanded in the final order to include “Virtual and Convergence Bids and Offers,” because they enable market participants to trade energy without physically producing or consuming it.  “Although there is an apparent financial settlement nature of virtual and convergence bids and offers … they are inextricably linked to the physical delivery of electric energy due to their being subject to the same aggregate physical capabilities of the electric energy transmission grid as other physical Energy Transactions,” the commission wrote (p. 31-32).

Not exempted are financial transactions that are “not tied to the allocation of the physical capabilities” of the electric grid “because such activity would not be inextricably linked to the physical delivery” of electricity (p. 16).

Exempt Parties

The transactions are only exempt if conducted among “appropriate persons,” a definition that includes banks, broker-dealers regulated by the Securities Exchange Act, futures traders regulated under the CEA and other companies with a net worth exceeding $1 million or total assets exceeding $5 million.

The commission expanded the definition to include a “person who actively participates in the generation, transmission, or distribution of electric energy” but declined to extend the exemption to all those participating in RTO and ISO markets (p. 77-78).

The only parties not exempt in RTOs, the commission said, are “market participants that can demonstrate neither the financial wherewithal nor the requisite business activities and congruent expertise to qualify as appropriate persons under” the Commodity Exchange Act (p. 78).

“The Commission is concerned that a person or entity that is engaged in purely financial transactions in the RTO or ISO markets, but that does not meet [the] … appropriate person criteria may be operating on inadequate resources and may pose inappropriate risks to itself and other market participants.” (p. 70-71)

RTO Interpretation

In comments filed Dec. 20, PJM requested that the commission rule that all PJM market participants are “appropriate persons.” Of 588 participants with transaction rights in PJM markets, PJM said, it was unable to confirm that 246 would qualify as Appropriate Persons. In the final order, the commission indicated that 55 PJM participants — an apparent reference to financial traders listed by PJM — would not be covered by the rule (footnote 412, p. 108).

Carol Smoots, counsel to the Financial Marketers Coalition, said the number of market participants excluded from the exemption will be determined largely by how the ISOs and RTOs interpret the CFTC order. “If a participant is trading in three markets do they need to have $1 million net worth in each?” she asked.

A PJM spokeswoman said yesterday the RTO “is reviewing the order and will discuss the implications for members in the near future.”

CFTC-FERC Conflicts

Smoots said the CFTC’s retention of its authority to take action against electric market participants for fraud or market manipulation means that the agency could find itself at odds with FERC in the future.

“It continues to be a pretty troubled relationship,” she said. “Hopefully, this order removes uncertainty in a lot of areas, but there’s a lot of uncertainty that remains.”

The two agencies recently squared off in federal court over FERC’s prosecution of former Amaranth Advisors trader Brian Hunter for market manipulation. Hunter was accused of selling natural gas futures contracts at the end of the trading day to drive down the closing price — benefitting swap positions held by Amaranth.

FERC argued that it shared jurisdiction with CFTC in the case because Hunter’s actions impacted natural gas physical markets, over which FERC has clear jurisdiction. The CFTC insisted it had exclusive jurisdiction over the futures markets, a position the U.S. Court of Appeals for the D.C. Circuit backed in a ruling March 15.

Conditions

The CFTC conditioned its exemption on the regions’ compliance with FERC Order 741 on credit practices and a legal opinion from outside counsel that the region’s netting arrangements give it the right to seize a trader’s assets in a bankruptcy (p. 17).

The commission also required that that information sharing arrangements with FERC remain in effect and that the regions agree not to notify a member prior to providing the commission information about it in response to a subpoena (p. 18).

Recreating Market Prices

The CFTC dropped a proposed condition that the regions be able to re-create Day Ahead and Real Time prices — an aid to investigators seeking to determine the magnitude of losses caused by manipulative trading schemes. The commission said it dropped the requirement because of “the potentially significant costs” involved although it encouraged FERC and PUCT to issue the requirement. (p. 92)

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PJM, Monitor in Stalemate on FTR Forfeiture Rule

WILMINGTON (April 2, 2013) — PJM officials were left scratching their heads Thursday after stakeholders rejected the RTO’s tariff changes for determining when to issue forfeitures against Financial Transmission Rights.

“We’ll have to take it back and see what we’re going to do,” said Stu Bresler, PJM vice president of market operations, after the changes won only a 2.29 vote from the Markets and Reliability Committee, far below the two-thirds (3.34) threshold required. “We have no manual language.”

Bresler said he was surprised by the vote because the PJM proposal had won about 90% support at the Market Implementation Committee on March 6, besting an alternative proposed by Market Monitor Joseph Bowring.

At issue are the criteria for applying the FTR forfeiture rule, which is intended to prevent participants from submitting virtual bids that boost the value of their FTRs.  Forfeiture rules would apply when those transactions result in a higher LMP spread in the day-ahead market than in the real-time market.

Recently Discovered

Bresler said PJM discovered only recently that it disagreed with the criteria by which the monitor has been determining whether a company’s virtual bid is “at or near” the delivery or receipt buses of its FTR. PJM does the billing for forfeitures and has the authority to use its own determination if it disagrees with the monitor’s.

Under the PJM plan, companies would lose any profit for an FTR if 75% or more of the energy injected or withdrawn by a virtual bid is reflected in a constrained path between FTR source and sink points.

The monitor has been applying the penalty based on the net impact of virtual bids, triggering application of the rule in less than one-tenth of 1% of transactions. In December, PJM penalized 65 companies a total of about $75,000; PJM’s load-weighted reference bus method would have resulted in penalties on a single company for only $1,500, a 98% reduction, Bowring said.

“This is a very dramatic change to a rule that’s worked well” for 10 years, Bowring told the MRC Thursday. “It makes the rule ineffective and meaningless.” Bowring said any changes in the criteria should be made after issuance of a problem statement and a full stakeholder review.

Bresler said it wasn’t until PJM attempted to create documentation explaining how the rule is applied that the RTO realized it disagreed with the monitor’s criteria. Bresler said the monitor finds the worst case increment or decrement on a path, which is inappropriate because “we don’t know where energy is being injected or withdrawn.”

Carol Smoots, counsel to the Financial Marketers Coalition, supported PJM’s change, which she said would make the criteria more transparent and reduce the triggering through false positives. “There are a lot of transactions that just weren’t done for fear of the rule being applied,” she said. “Many of my clients see the rule as definitely not clear.”

Testing the Limits

David Pratzon, representing Calpine, said he opposed the PJM proposal because he fears it would lead to traders testing the limits of the new criteria. The infrequent triggering of the rule under Bowring’s interpretation “indicated that people know how to do INCs and DECs away from FTRs,” he said.

Pat Sunseri, of Twin Cities Power, LLC, said PJM should consider the volume of transactions in its application of the rule. “It shouldn’t ever come up as a false positive for people who want to hedge their portfolio.” Bowring agreed that the rule should take trading volume into account.

Bowring said the monitor will continue to interpret the rule the way it has been doing, whether or not PJM issues penalties as a result. If it sees evidence of market manipulation that PJM does not police, he said, “we have no other recourse” but to notify the Federal Energy Regulatory Commission.

The lengthy debate ended on a conciliatory note from Ed Tatum of Old Dominion Electric Cooperative: “Let’s work this out.”

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Cool Reception for DR “Fatigue” Study

WILMINGTON — A proposal to study potential “fatigue” among demand response resources met strong opposition Thursday, March 28, with curtailment service providers suggesting anticompetitive motives by the sponsor.

Ken Carretta, of PSEG, told the Markets and Reliability Committee that stakeholders should explore whether PJM has sufficient safeguards to ensure that Emergency Demand Response resources will perform as needed if they are increasingly called upon in the future, as PJM expects.

Carretta said the proposed problem statement, presented to the committee on first reading, is a response to a recommendation by the Brattle Group that PJM should “confirm that [DR] Resources can respond as often and as seasonably as claimed.”

Representatives of demand response companies, including Dan Griffiths of Comverge and Bruce Campbell of EnergyConnect, said new rules could increase their record-keeping costs and were unnecessary because providers already face high penalties if they fail to perform. “This appears to be an anticompetitive” move, said Aaron Breidenbaugh, of EnerNOC. “… A solution in search of a problem.”

Bob Weishaar, who represents industrial customers, also was skeptical. “We normally don’t oppose problem statements but we have no evidence that there’s been any demand response fatigue,” he said.

Carretta denied the proposal was motivated by competitive concerns. Current PJM rules, he said, don’t require CSPs to demonstrate that their portfolios are capable of meeting frequency obligations. Potential reporting requirements for DR resources would be no more onerous than those for generators, which track their outages, he said.

PJM Concerned

Michael Kormos, PJM senior vice president for operations, declined to take a position on the problem statement or any potential solutions but said the RTO “absolutely” is concerned about its increasing reliance on DR.

PJM expects the importance of demand response to increase because its Installed Generation Reserve Margin (IGRM) is projected to fall from the current 13% to 9% after 2013/14. The RTO projects DR resources will be called upon from five to nine times annually beginning in 2014/15, up from one to five calls in 2013/14.

“It’s not a problem — we’re still reliable — but we’ll probably have to call on demand response more in the future,” Kormos said.

Annual Limits

Limited DR resources can be called upon 10 times annually for up to six hours each over the summer.  Annual DR resources can be called upon for up to 10 hours a day with no limit on the number of days they are called.

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Task Force to Study Gas-Electric Coordination

The Markets and Reliability Committee approved the creation of a task force to study potential reliability problems resulting from PJM’s increasing reliability on gas-fired generation. The Gas Electric Senior Task Force (GESTF), which will report to the MRC, will prioritize gas-electric coordination issues for potential solutions.

Natural gas’ share of PJM’s generation has nearly tripled since 2007, rising to almost 20% of electric production in 2012. Gas is expected to replace most of the coal-fired generation scheduled to retire through 2015.

Michael Kormos, PJM senior vice president for operations, said although PJM does not face any immediate reliability problems it could take five years to respond to potential shortages through the capacity markets. “We probably should start talking about it now,” he said.

Because natural gas generation relies on “just-in-time” fuel supplies, the Federal Energy Regulatory Commission has warned that some plants may not be able to operate on the coldest days when gas demand for heating is at its peak.

In late January, the operator of Transco Zone 6 — which supplies generators in northern New Jersey and heating and electric demand in New England and New York — briefly limited supplies with an operational flow order.

“Doing nothing is not an option here,” said PJM CEO Terry Boston. He said although PJM has increased its communication with the gas industry there is room for improvement. “We are talking more to each other but we still talk past each other.”

Boston noted that the gas pipelines supplying generators are radial systems giving them less flexibility than PJM’s networked electric transmission system.

FERC held five technical conferences on the relationship between the natural gas and electricity markets last year (docket #AD12-12-000). The commission will hold another conference April 25 in Washington on coordinating gas and electric scheduling.

The issue is most acute for New England. ISO-NE is seeking FERC approval for tariff changes to allow earlier clearing of its Day Ahead energy market (Docket # ER13-895) and sharing of generator information with pipelines (ER13-356). The commission last month approved ISO-NE’s proposal to increase its procurement of ten-minute non-spinning forward reserves (ER13-465).

To date, PJM has been working to improve coordination with gas pipelines through information sharing and cross training of dispatch personnel.

PJM also is working with ISO-NE, NYISO, MISO and TVA to conduct an analysis of the infrastructure serving the Eastern Interconnection. The study, for which the regions are seeking federal funding, will evaluate the ability of gas systems to supply gas-fired generation into the next decade.

PJM Contact: Gary Helm

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Delmarva Power Seeks $65 Million in Rate Increases

Delmarva Power & Light Co. filed rate hike requests totaling almost $65 million in Delaware and Maryland, saying its revenues have not kept pace with growing capital spending.

Delmarva asked for a $42 million annual increase in its electric distribution rates in Delaware, where it serves 300,000 customers, and $22.7 million in Maryland, where it serves 200,000.

Delaware Filing

Delmarva’s March 22 filing with the Delaware Public Service Commission said its current return on equity is only 6.6%, below the 9.75% ROE approved by the commission in its 2011 rate case, which boosted revenues by $22 million annually. The company is seeking a 10.25% ROE and a 7.38% increase in total revenue.

The company said the biggest driver in its rising costs is its capital spending. It expects to spend about $397 million on capital projects in 2013 through 2017, much of it for reliability upgrades. “Delmarva is not realizing sufficient growth in the number of customers and load served to offset this pace of investment,” the company said. It requested new rates take effect May 21. DE PSC Docket No. 13-115

Maryland Filing

In its March 29 filing with the Maryland Public Service Commission, the company requested a 10.25% ROE, saying it was currently earning only 7%.

The company said it spent almost $54 million on reliability improvements in 2012, with plans for an additional $115 million in 2013 and 2014. The spending helped reduced the frequency of outages by 9% and their duration by 17% since 2010, the company said.

The requested base rate increase would boost the monthly bill for a residential customer using 1,000 kWh by $7.74.

Resiliency Surcharge

In addition, Delmarva asked Maryland regulators for a three-year “grid resiliency” surcharge that would add another $1.06 to the typical customer’s bill in 2014 and allow the company to accelerate its infrastructure spending. The proposed surcharge would provide the company incentives for reaching reliability benchmarks and penalties if it failed to do so, as recommended by a September 2012 task force report prepared for Gov. Martin O’Malley. MD PSC Case # 9317

Delmarva is a subsidiary of Pepco Holdings Inc., which is also seeking a $60 million rate increase in Maryland and a $52.1 million boost in Washington, D.C. and. (See story “Pepco Goes Back to the Well“.)