Duke Energy told analysts Feb. 28 that it expects adjusted diluted earnings per share of $4.20 to $4.45 in 2013 and has set a target EPS growth of 4% to 6% percent through 2015. The company said its 2013 results, the first full year of operation since Duke’s merger with Progress Energy, will serve as the base year for the company’s long-term EPS growth projections.
John T. Herron, CEO, president and chief nuclear officer of Entergy Nuclear, joined Duke Energy’s board of directors effective March 1, 2013. Herron will retire from Entergy on March 31.
Duke announced the appointment of Dhiaa Jamil as president of Duke Energy Nuclear, which operated 12 nuclear units in the Carolinas and Florida. Jamil previously served as Duke Energy’s executive vice president and chief nuclear officer. Bill Pitesa, senior vice president of Duke Energy’s nuclear operations for the Brunswick and Robinson nuclear plants, will become chief nuclear officer reporting to Jamil.
Dominion Resources, Inc.
Dominion Resources will hold its annual shareholders meeting May 3, 2013, at 9:30 a.m. ET.
Dominion appointed Pamela J. Royal, M.D., to its board of directors effective March 1. Dr. Royal, 50, is a board-certified dermatologist and the owner and president of Richmond skin care company.
The Market Implementation Committee voted overwhelmingly March 6 to endorse PJM’s proposals for applying forfeiture rules to virtual transactions, rejecting the Market Monitor’s alternatives.
The PJM proposals create criteria for applying the existing forfeiture rule for increment offers and decrement bids and extends application of the rule to Up to Congestion (UTCs) transactions, previously not covered.
PJM’s package was backed by about 90% support of MIC members voting and will be forwarded to the Markets and Reliability Committee. Market Monitor Joseph Bowring’s alternative proposals won support from only a quarter of the members.
The rules address companies (including affiliates) that submit virtual bids that affect the value of the companies’ Financial Transmission Rights (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.
Radical Change
Bowring called the PJM proposals “a radical change” that should have been subjected to more discussion through issuance of a problem statement. Bowring said PJM’s load-weighted reference bus method would inappropriately penalize some transactions and fail to apply the forfeiture in others when it should apply.
In December 2012, for example, PJM penalized 65 companies a total of about $75,000. The new method would have issued penalties on a single company for only $1,500, a 98% reduction, Bowring said.
Stu Bresler, PJM vice president of market operations, acknowledged that PJM’s changes would reduce the triggering of the rule — which is now applied in less than one-tenth of 1% of transactions — but said the RTO has not quantified the impact.
‘At or Near’
Bresler said PJM’s proposal simply clarifies how the RTO determines whether a company’s virtual bid is “at or near” the delivery or receipt buses of its FTR.
Under the PJM plan, companies will lose any profit for an FTR if 75% or more of the energy injected or withdrawn is reflected in a constrained path between FTR source and sink points. “We don’t believe this is a radical change,” he said.
PJM proposed using a similar test for UTCs. Bowring’s proposal would have applied the penalty on UTCs based on their net impact. He said the full impact of UTCs are not captured by the PJM proposal.
Net Impact
PJM’s Tim Horger, who presented the RTO’s proposal, said it is not appropriate to use the same “net” impact rule for UTCs because increment and decrement transactions don’t involve a second bus. Increment officers have only a source, and decrement bids have only sinks. UTC transactions include both source and sink.
David Mabry, consultant to the PJM Industrial Customers Coalition, said his group fears the PJM proposal weakens preventions against abuse.
Legitimate Hedging
Pat Sunseri, of Twin Cities Power, LLC, countered: “We don’t want to see more forfeitures when the activity might not be market manipulation but legitimate hedging.” Sunseri said the FTR forfeiture rule was created to stop participants from making small virtual transactions as low-cost leverage to impact much larger FTR positions.
Carol Smoots, counsel to the Financial Marketers Coalition, said that the PJM proposal was more reasonable than Bowring’s because it reflects the differences between UTCs and increments and decrements. “It’s very troubling to have this guilty-until-proven-innocent always come up when it comes to these transactions,” she said of Bowring’s proposal.
PJM’s proposed new criteria will be in a new section (8.6) of Manual 6: Financial Transmission Rights. It will also amend Section 5.2.1 of Appendix K to the PJM Tariff and require changes to the Operating Agreement.
Demand response (DR) providers will face increased scrutiny and be required to provide additional documentation under changes approved by the Market Implementation Committee March 6.
The new rules require Curtailment Service Providers (CSPs) bidding into the capacity auction to have a company officer sign a certification attesting to the company’s intent to physically deliver MWs. Bids will be made through an offer template to increase the consistency of information supplied. PJM also will increase its scrutiny of delivery zones in which CSPs’ bids exceed DR penetration thresholds.
Not Specific Enough
PJM’s transmission planners said the information currently provided by CSPs is not specific enough to allow modeling of the quantity and location of DR in reliability planning.
PJM staff also found that DR offered in the 2015/16 Base Residual Auction (BRA) exceeded 20% of the Preliminary Zonal Peak Load Forecast for some zones, raising concerns that DR providers’ bids are overly optimistic.
The MIC considered four proposals and voted to send two to the Markets and Reliability Committee for further consideration.
Zonal Screens
PJM staff’s proposal, which was endorsed by 81% of MIC voters, would “flag” a zone for increased scrutiny based on the higher of the following screens:
maximum zonal DR penetration (percentage of zonal peak) as determined based on the “Expanded Business as Usual” scenario in a 2009 FERC study, or the
maximum zonal registered DR from past delivery years (expressed as a percentage of zonal peak).
A zone will be flagged if the projected DR resources exceeds the screen. Once identified, zones will remain flagged for at least three years. CSPs bidding in a flagged zone will be required to provide additional information for their end-use customers. (For commercial and industrial customers: name and address, business segment, and electric distribution company account number if known. For residential customers: estimated number of customers, estimated nominated per customer capacity value.)
Overlapping MWs
Overlapping MWs — those offered by more than one CSP — will not clear in the auction unless supported by evidence, such as a letter from the customer.
The other three proposals considered by the MIC differed from PJM’s only on the application of the screen used to flag zones. Two proposals received less than 25% support.
The fourth, by Market Monitor Joseph Bowring, won support from 73% percent of voters and will be a secondary proposal before the MRC. Bowring’s proposal would calculate penetration levels net of megawatts bought back by CSPs or other participants, as determined based on previous auction results. “The idea is to determine megawatts which need to be documented more clearly,” Bowring explained. Megawatts that are bought back “are not going to physical.”
Bowring had offered his proposal as a “friendly” amendment to the PJM plan. PJM rejected the amendment, saying it could make it difficult for CSPs to fulfill their obligations through long term contracts.
PJM will suspend its Day Ahead market if it loses Internet service under the outlines of a contingency plan approved by the Market Implementation Committee March 6.
PJM’s Tariff and Operating Agreement do not specify procedures for responding to an extraordinary event, such as an Internet failure, that disables the RTO’s eMKT application. Under the problem statement approved by the MIC, all market settlements would be done in real time in such circumstances.
The plan assumes that PJM’s internal processes are working but that eMKT and other Internet-based services are not functioning, said Stu Bresler, PJM vice president of market operations. Generator dispatch may be based on the most recent offers received by PJM before the loss of the web, Bresler said.
The problem statement will be considered next by the Markets and Reliability and Members committees. Changes to the Tariff and Operating Agreement are expected to be completed by July.
The Planning Committee approved the following manual changes by acclimation March 7. The changes move next to the Markets and Reliability Committee. For more information, contact PJM Member Relations.
Manual 14B: PJM Region Transmission Planning Process
Reason for Change: PJM needed to revise the manual to comply with upcoming changes to NERC Reliability Standard TPL-001-4.
Impacts:Changes affect the following sections of the manual:
R 2.4.1 – Dynamic behavior of loads
R 5 – Transient voltage response
R 4.3.1.3 – Transient swings cause protection system operation
R 4.3.1.1 – High speed reclosing into a fault
R 4.1.2 – Tripping of transmission elements due to generator out of step event
The Planning Committee voted March 7 to require new generators to pay for the installation of phasor measurement units (PMUs), rejecting an alternate proposal to have PJM cover the cost.
Reason for change: PMU data can enhance grid reliability for both real-time operations and planning applications (e.g., generation dynamic model calibration and validation, primary frequency response, oscillation monitoring and detection). PJM expects to receive PMU data from 82 substations by the end of 2013 but has none located at generation stations.
Impact: The Interconnection Service Agreement will be changed to require installation of PMUs at new interconnections for generators with nameplate ratings of 100MVA or larger. Data collected by the PMU must be transmitted to PJM continuously and stored locally for 30 days.
A proposal to bill generators for the capital costs was approved 87-27 with eight abstentions. The alternate proposal — for PJM to recover the cost through the administrative fee paid by members using PJM market or reliability services — was rejected 26-86-11.
PJM will cover the cost of the communication links in the system.
The proposal moves next to the Markets and Reliability Committee.
The following PJM manual changes were approved by the Operating Committee on March 5, 2013. There were approved by the Markets and Reliability Committee on March 28. For more information, contact PJM Member Relations.
Manual 3: Transmission Operations
Reason for Change: Creates procedure for generation operators seeking exemptions from following a voltage schedule.
Impacts: The changes will be included with the next update of Manual 03.
PJM Contact: David Schweizer, manager, generation department
Manual 14D: Generator Operational Requirements
Reason for Changes: Changes were made to reflect new names of several PJM departments, address wind power generation and ensure clarity and consistency with other manuals. Several utilities, including AEP, Dominion and Pepco, abstained from the vote to endorse the changes. Additional revisions to M14D are planned in 2013 to update various other sections of the manual.
PJM Contact: David Schweizer, manager, generation department
Manual 37: Reliability Coordination
Reason for Change: The manual is being updated to reflect the integration of the East Kentucky Power Cooperative, the elimination of an out of date section and the addition of a reactive transfer interface.
Impacts:
Updated the PJM Reliability Plan in Attachment A for the East Kentucky Power Cooperative integration effective June 1, 2013.
Removed Attachment C: Change Control Review Board description, which is out of date. PJM’s change management procedure can be found in PJM DOCs #596201. Attachment D was renamed Attachment C.
The ComEd Reactive Transfer Interface was added to a table in Section 3.1, SOL and IROL Limit Determination.
PJM Contact: Chris Pilong, manager, reliability engineering
Changes to two PJM manuals were approved by the Market Implementation Committee on March 6, 2013. The changes will be considered next by the Markets and Reliability Committee. For more information, contact PJM Member Relations.
Reason for Change: Changes were made to comply with a FERC order regarding allocation of costs for PJM’s joint operating agreement with the New York ISO.
Impacts:
M28, Section 5 (identical changes in M11, Section 2.13): Day-ahead operating reserve credits for resources scheduled to provide reactive services or transfer interface control will be allocated to PJM members in proportion to their total real-time load in the applicable transmission zone(s). These credits were previously included in the allocation of day ahead operating reserves.
Manual 28, Section 8 and 14: Revenues paid to or received from NYISO for market-to-market (M2M) congestion relief will be incorporated in the total transmission congestion charges allocated to FTR holders. This is identical to how M2M charges are treated with the Midwest ISO.
Manual 28, Section 4: Footnote added to clarify that diesel generators are treated like combustion turbines based on their similar operating characteristics.
Two unplanned generator outages and high natural gas demand resulted in unusually high Balancing Operating Reserve (BOR) payments in the eastern half of PJM’s footprint in January and February.
BOR payments averaged more than $1 million daily in January and $2 million per day in February, Adam Keech, PJM director of dispatch, told the Market Implementation Committee March 6. That is the higher than any period in recent memory, PJM said.
Balancing Operating Reserves are paid to generators dispatched out-of-merit by PJM that require uplift payments to cover their costs.
The impact of the spike was exacerbated because average daily deviations (in MWh) have declined by almost half in the east over the last three years. We have to spread the costs over fewer MWh,” Keech said.
Discouraging Imports
Member David Pratzon told the Operating Committee that the high BOR charges are discouraging generators outside PJM from exporting power into the RTO.
Keech said a major reason for the increase was the delay in a planned outage as a result of Hurricane Sandy and an equipment failure that shut down a second generator in February.
5-Year High
In addition, spot natural gas prices in Transco Zone 6 were extremely volatile in January and February, spiking far above prices elsewhere in PJM and exceeding $10 per mmBtu for much of the period. Prices hit a five-year high in late January, when the pipeline operator limited supplies with an operational flow order.
Transco Zone 6 supplies not only generators in northern New Jersey but also heating and electric demand in New England and New York. Most of the replacement generators dispatched by PJM were gas-fired units with minimum run times that limit their flexibility.
“If we didn’t have the outages we wouldn’t have needed all the generation …” Keech said. “Maybe the spikes are still there but they’re shorter spikes.”
Other contributing factors are congestion on the Readington-Roseland 230 kV tie line between the Jersey Central Power and Light and Public Service Electric and Gas (PSEG) zones and maintaining the “wheel” between PSEG in northern New Jersey and Consolidated Edison Co. in New York City.
Real-Time Commitments
The additional generation is usually committed in real time as a result of reliability analyses, meaning most of the charges have been allocated to the BOR. Make-whole payments are allocated to day ahead load and exports RTO-wide if the units are committed day ahead.
Keech said the costs fall sharply with a return to normal gas prices. The generator down for maintenance is expected back online in June. Spectra Energy’s New Jersey-New York pipeline expansion will add new supply when it becomes operational as soon as November.
PJM members may consider changing the rules of the PJM capacity market to eliminate arbitrage opportunities between the Base Residual and Incremental auctions.
The Market Implementation Committee voted March 6 to endorse a problem statement, sponsored by David Pratzon on behalf of Calpine and LS Power, to consider changes.
Because clearing prices in Incremental Auctions (IAs) are usually lower than those in the Base Residual Auction (BRA), participants can profit by over-committing in the BRA and buying out their commitments in the IAs.
Monitor’s Report
The Market Monitor reported in December a substantial level of buy outs of BRA positions through IAs and other replacement mechanisms. The monitor said such buyouts could undermine system reliability and suppress the price of other capacity resources – a particular concern of the PJM Power Providers (P3), a group of generation owners that requested that the Monitor study the issue. Although the P3 group asked for a study of only Demand Response (DR) providers’ behavior, the Monitor broadened the study to include all capacity resources.
(Source: Monitoring Analytics)
Since the 2009/2010 delivery year, the Monitor found, DR resources were far more likely than generators to replace BRA capacity. DR replacements jumped in 2009, when the formula for computing penalties was changed and reduced deficiency charges. It fell in 2012 with the elimination of the interruptible load product. (See chart.)
FERC Order
About 40% of DR replacement megawatts for the 2012/2013 Delivery Year came from the selling company’s portfolio, suggesting that it was a result of a 2012 FERC order changing measurement and verification methods. Excluding that, replacement capacity represented about 27% of cleared DR capacity, still much higher than that for generation.
In 2012, only seven generation companies, 7% of the total, replaced 50% or more of their commitments. Six DR companies, 13% of the total, replaced half or more of their commitments. In all years studied, more than half of DR replacement capacity came from incremental auctions.
No Evidence
Although the Monitor reported that two DR providers replaced 100% of their BRA capacity in each of the last three years, it said it had no evidence that any CSPs are “are purely financial entities … with no intention of providing a physical resource.”
Capacity market rules do not require sellers to identify the reasons for purchasing replacement capacity. The Monitor noted that while generation has a lead time about equal to the three-year horizon of RPM auctions, DR providers do not receive commitments from new customers until much closer to the delivery year.
Premature
John Farber, public utilities analyst for the Delaware Public Service Commission, said the problem statement “is at best premature” given other changes PJM is considering through its DR Plan Enhancements initiative to address potential abuse.
James Wilson, an economist who represents consumer advocates in several states, said PJM should not make changes that could hurt market efficiency. The Monitor’s report “identified a phenomenon not a problem,” he said.
Scope Too Narrow
Others said the scope of the inquiry was too narrow and should be broadened to include possible market design flaws. “Why are generators willing to accept much lower prices in the IA than BRA? Why is that?” asked Bruce Campbell, director of regulatory affairs for
EnergyConnect, Inc.
Pratzon said the inquiry will not focus on bidders’ intent but on the economic consequences of the buybacks. Although buy outs have not resulted in reliability deficiencies to date, Pratzon said the current capacity surplus could disappear as a result of generator retirements and load growth.
The problem statement was approved with nine objections and 36 abstentions.
