State Briefs

Pepco Gets About Half Of Requested Rate Increase

The Public Service Commission approved a $23.4 million distribution rate increase for Pepco, about half of the $44.8 million the utility had requested. The PSC also approved an overall 7.65% rate of return, which includes a 9.4% return on common equity, less than the 10.25% ROE Pepco sought.
The decision means most residential customer rates will rise about $3.75 per month. The commission said that for most residential customers, who buy their supply through Pepco’s standard offer service, the increase would be offset by a lower Standard Offer Service that will effectively lower monthly bills by around $6.

More: DC Public Service Commission

ILLINOIS

ComEd 2013 Reliability Highest in Utility’s History

Commonwealth Edison said its system reliability in 2013 was the best in company history, with 300,000 fewer customer interruptions than previously. The utility credits the performance to the $2.6 billion of investments it is making over 10 years by authority of the state’s Energy Infrastructure and Modernization Act. The investments include smart grid technology and infrastructure upgrades. ComEd said its reliability and Illinois’ competitive power supply market are key reasons that businesses like Airgas and others have committed to building new facilities in the utility’s territory.

More: Commonwealth Edison

FirstEnergy to Impose Polar Vortex Surcharge

FirstEnergy will impose a one-time charge of between $5 and $15 on customer bills in June to cover unexpected costs incurred during January’s polar vortex.
A company spokeswoman said the surcharge will affect 220,000 of its 670,000 Illinois customers living in Rockford and 97 other municipalities in northern Illinois.
Constellation, owned by Exelon, and Integrys Energy Services, which supplies the city of Chicago, said they don’t intend to impose a similar charge on customers.

More: Crain’s Chicago Business

INDIANA

Efficiency Program Killed; Pence Orders a Redesign

Gov. Mike Pence signed legislation killing the state’s two-year-old energy efficiency program, Energizing Indiana, but ordered the Indiana Utility Regulatory Commission to give him plans for a redesigned program that he could introduce next year.

The bill started as a measure to let large industrial users opt out of the program — which is paid for by a fee on utility bills — but quickly became a complete de-funding of the program. Pence said he supported energy-efficiency efforts and was unhappy that lawmakers had not worked out a compromise to let it continue with changes.

More: Indianapolis Star

MARYLAND

Bill to Let Green Energy On Farmland Advances

Pinnacle Wind Farm (Source: White Construction, Inc.)

The state Senate approved a bill allowing some green-energy equipment on land set aside in Maryland’s agricultural land preservation program. Farmers could contract with wind, solar or other companies for revenue in addition to their payments for keeping the land in the preservation program.

The House has passed a similar bill. Both versions prohibit placement of wind turbines where lawmakers fear they would interfere with radar at Patuxent Naval Air Station.

More: The Baltimore Sun

NEW JERSEY

Lawmakers Try for RGGI Again After Court Decision

Lawmakers have renewed efforts to force the state to rejoin a multistate greenhouse gas reduction pact just two days after an appellate court found that Gov. Chris Christie’s administration was not allowed to scrap related cap-and-trade regulations without proper rulemaking.

The Senate Environment and Energy Committee voted 3-1 to send a bill that would require the state’s participation in the Regional Greenhouse Gas Initiative (RGGI) to the full Senate for consideration.

Christie, who announced in May 2011 that the state would back out of RGGI, has shot down previous legislative attempts to reverse that decision.

More: NJSpotlight

NORTH CAROLINA

Investor Funds Pressure Duke; Ash Woes Continue

Large institutional investors demanded that Duke Energy’s board of directors launch independent investigations of the Feb. 2 coal ash spill at Duke’s Dan River plant and the questions that have arisen since about other ash facilities.

“These events, and Duke’s response to them, have shaken investors’ confidence in Duke and its board,” the investors, which include public funds in California, Connecticut, Illinois, Oregon and Pennsylvania, said in a letter to the board.

Duke CEO Lynn Good said an internal task force and outside experts are reviewing all sites and are scheduled to report by the end of May. She said Duke would move ash from three plants and speed up closure of another basin.

Meanwhile, the state Department of Environment and Natural Resources (DENR) issued a citation to Duke for a crack in an earthen ash pond dam at the Cape Fear River, where the company was cited March 20 for illegal dumping of ash.

More: ABC News; Triad Business Journal; Reuters; Los Angeles Times

Appeals Court Rejects Duke Merger Challenges

The North Carolina Court of Appeals upheld the Utilities Commission approval of Duke Energy’s 2012 acquisition of Progress Energy. Rejecting challenges from activist group NC WARN and the city of Orangeburg, S.C., the court said it was not its “role to second-guess the determination of the commission” where its decision was supported by evidence.

NC WARN had argued that the merger would not be good for residents, particularly the poor, and that the companies did not address the merger’s risks. The group said it would appeal the ruling to the state Supreme Court.

More: News & Observer

OHIO

Cracks in Davis-Besse Getting NRC Scrutiny

Davis-Besse Nuclear Power Station (Source: FirstEnergy)

Engineers are examining concrete samples from the Davis-Besse nuclear plant’s shield building to see if it is still strong enough to protect the reactor. Some tiny cracks in the building have been found since the first “laminar” cracks were found in 2011. Owner FirstEnergy will report on the matter to the Nuclear Regulatory Commission by late spring or early summer. The matter was discussed at NRC public hearings last week to talk about potential environmental impacts from a 20-year operating license extension.

More: The Blade

AEP Goes to High Court To Keep Fuel Overcharges

Recovery of overpayments, or retroactive ratemaking? That’s the question before the state Supreme Court in American Electric Power-Ohio’s challenge to an order to credit customers for $35 million in excess coal costs. The company was able to impose charges under a fuel adjustment clause before the Public Utilities Commission conducted a review of the charges’ reasonableness and prudence. The PUC ultimately determined that the utility had charged too much and ordered it to credit the overpayments against current fuel charges.

AEP’s arguments, together with a state Supreme Court decision in February that allowed the company to keep $368 million in past overcharges, show that “regulation is out of balance in the utilities’ favor and to the customers’ disfavor,” the Ohio Consumers Counsel office said.

FirstEnergy is mounting a similar challenge over a 2013 PUC ruling that FirstEnergy companies overcharged $43 million for renewable energy credits.

More: Midwest Energy News

Efficiency Debate Begins; FirstEnergy Urges Changes

As Republicans plan a bid to freeze state mandates for renewable energy and energy efficiency, FirstEnergy is urging customers to lobby lawmakers to amend the efficiency rules.

Proponents of energy efficiency, however, have been circulating American Electric Power’s case studies showing how its 2013 voluntary program has saved Ohio industrial customers millions of dollars.

The dueling scenarios argue either that the mandated efficiency programs over the coming decade will save billions of dollars or that they will increase electric rates by billions of dollars.

Republicans were poised to propose a bill that would freeze for up to three years a 2008 bill in support of energy efficiency and against new coal production while the law’s merits are studied. Opponents argue the freeze would ultimately become permanent.

More: The Plain Dealer

Car Dealers Say Tesla May Have Three Direct Outlets

Tesla Car (Source: Tesla) — (Source: Tesla)

Tesla Motors has made a deal with the Ohio Automobile Dealers Association to keep the electric car company’s two existing direct-sales locations open, as well as to open one more. Assuming the legislature approves the agreement, Tesla will have won a significant victory in Ohio over an argument it is having in other states. Under the agreement, however, no other carmaker could avoid going through auto dealerships.

The company is barred from direct sales in New Jersey, Texas and Arizona, and is fighting dealer-protective legislation in New York.

More: The Wall Street Journal

PUC Maintains Status Quo On Regulated Pricing

State regulators concluded their investigation into Ohio’s electricity market without recommending major changes to the system. The Public Utilities Commission looked at a number of issues in the 15-month probe, including whether to eliminate regulated pricing.

Alternative suppliers, including IGS Energy and Direct Energy, had argued that regulated pricing is an impediment to a competitive market and customers should be nudged to engage with the market. If there was no standard price, customers would need to shop for a plan or be automatically assigned to one.

Consumer advocates urged the PUCO to retain the current pricing system, which they said is an essential protection for customers.

The most visible change for consumers is that the logo of alternative suppliers will soon appear on the electricity bill.

The opinion may be Todd Snitchler’s last act as chairman. He chose not to seek reappointment after three years on the job; his term ends April 10.

More: The Columbus Dispatch

VIRGINIA

State Awards Aim to Help Offshore Wind Progress

Four businesses in the state have been selected for awards totaling $860,000 for research aimed at accelerating development of offshore wind power and associated industries. Dominion Virginia Power, which offered $2 million in cost-share contribution, is to receive a $310,000 award to advance geotechnical studies, including deep borings. Alstom Power offered $10,000 in cost-share and is to get $40,000 to develop advanced controls that adjust ocean wind turbines to ocean conditions. Other awards are going to CoastalObsTechServices and Timmons Group.

More: Virginia.gov

— Compiled by Kathy Larsen and David Jwanier

April 1, 2014

Conflict Ahead for States, TOs over ‘Multi-Driver’?

By Rich Heidorn Jr.

State regulators and PJM transmission owners will talk later this week in an attempt to narrow their differences over rules for approving and allocating the costs of “multi-driver” transmission projects.

Such projects would allow the expansion of reliability or market-efficiency upgrades to accommodate public policy initiatives.

The rules being drafted by the Transmission Owners Agreement Administrative Committee (TOs), however, differ from those proposed by PJM in the fall — and that has some state officials concerned.

“Last summer, PJM was prepared to let states come in with public policy [projects] and combine them with reliability projects that were approved but not started,” Walter Hall, of the Maryland Public Service Commission, told the Markets and Reliability Committee Thursday during a first read of proposed Tariff and Operating Agreement changes.

The transmission owners now “want to block that,” Hall said. “They want to prevent the states from coming in … once a project has been approved by the Board” of Managers.

“I don’t think it was quite that complete of an exclusion,” PJM Vice President for Planning Steve Herling responded. Herling said he would have to review the TOs’ language in detail before making a definitive conclusion.

Hall also said the transmission owners are seeking to increase the state cost allocation for multi-driver projects.

Hall said he and officials of several other states plan to talk with the TOs in a conference call later this week. If the conflict is not resolved, state officials could challenge the TOs’ proposal before the Federal Energy Regulatory Commission.

Two-track Process

In a survey last month, the Regional Planning Process Task Force (RPPTF) expressed overwhelming support for the Tariff and OA changes that will be brought to a formal vote at the MRC’s next meeting April 24.

PJM’s Fran Barrett told the MRC last week that the task force’s work on the Tariff and OA changes was being conducted in parallel with the TOs’ proposed cost allocation methodology. “Our job is to bring both of these trains into the station at the same time,” for filings with FERC, Barrett said.

A multi-driver project could mean replacing a 230 kV line planned to relieve congestion with a 500 kV line that also addresses public policy needs — such as the import of wind power to meet state renewable portfolio standards.

TOs’ Proposed Approval Process

A working group of the Transmission Owners Agreement Administrative Committee adopted a “principles” document March 7 outlining the TOs’ proposed rules for approving and paying for multi-driver projects.

It states that “PJM shall include only those projects that have been proposed to fulfill needs within a current cycle planning year as the basis for a new multi-driver project.” [Emphasis added.]

The principles also would bar modification of multi-driver projects “to consider transmission needs not previously considered within the planning cycle after the project has been submitted for board approval.”

It explained: “The TO Group believes this provision will prohibit `gaming’ of the process, where certain beneficiaries may seek to introduce out-of-planning-cycle projects, or modifications to other projects, to meet transmission needs in an attempt to pay only incremental costs for a specific need and thus reduce their cost allocation.”

The TOs would allow the following exception to the prohibition on modifying multi-driver projects: “During the subsequent planning cycle, or for out-of-cycle projects that specifically result from unanticipated reliability needs, a new transmission system need can be determined that is solved with an upgrade to an existing or proposed RTEP project.”

Such a proposal would “be reassessed as if it were a new project for purposes of cost allocation.”

Cost Allocation

In its Order 1000 compliance filing in October 2012, PJM told FERC it was committed to developing a multi-driver approach. Last fall the RTO proposed two methodologies for apportioning the costs of such projects.

The “incremental” method would be used when the multi-driver project was developed as a result of a single driver but was modified to satisfy one or more other goals and becomes a more cost effective solution to all of the drivers.

The “proportional” method would be used when the multi-driver project is developed in parallel with individual solutions to different drivers. It would allocate costs in using percentages based on the relative costs of the individual projects that would have been required to address each driver alone.

Increased Costs for States?

Hall said the TOs “dropped PJM’s language” and would increase the cost allocation assigned “to the state public policy bucket.”

Herling said although the TOs “may have dropped some of our language I think they are still generally following the same approach.”

The TOs are working to convert the principles into amendments to Schedule 12 of the PJM Tariff. The Schedule 12 changes — which require FERC approval but no stakeholder vote — are expected to be completed by mid-April, according to Randall Palmer of FirstEnergy. The RPPTF may discuss the provisions at its April 29 meeting.

April 1, 2014

Company Briefs

Transmission Spending by Investor-Owned Utilities 2007-2016 (Source: Edison Electric Institute)

Investor-owned utilities spent $17.5 billion on transmission projects in 2013 and will spend at least $43 billion more through 2024, according to an annual report by the Edison Electric Institute. Of the projects featured in the report, 43% are large interstate projects; 75% support renewables integration; 49% are member-company collaborations with others; and 75% are high-voltage projects 345 kV and above.

More: EEI

NextEra ‘Most Admired’ Utility in Forbes List

NextEra Energy has been named No. 1 among electric and gas utilities on Fortune magazine’s 2014 list of the “World’s Most Admired Companies.” The company, with principal subsidiaries Florida Power & Light and NextEra Energy Resources, said this is the eighth straight year it was named tops in its industry.

NextEra was followed closely in the rankings by Dominion Resources, while Duke Energy, American Electric Power and PPL also made the list.

More: Forbes

NRG Buys a Top-10 Solar Roof Installation Business

NRG Energy has acquired Roof Diagnostics Solar, the eighth-largest solar installer in the U.S. Terms of the transaction were not disclosed.

The 475-employee Roof Diagnostics has offices in New Jersey, New York, Massachusetts and Connecticut, and expansion plans for California. NRG is one of the larger solar developers (through NRG Solar) and retail providers of green energy (through Green Mountain).

More: Greentech Media

PPL Reconnects Reactor Following Valve Repair

PPL restarted the Unit 2 reactor at the Susquehanna nuclear power plant last week after a five-day outage for a valve repair. The reactor was being brought online after a planned shutdown for routine maintenance when operators discovered a leak in what the company said was a non-safety-related water supply pump.

Unit 2 has been under increased scrutiny by the U.S. Nuclear Regulatory Commission after four unplanned shutdowns, two with complications, since December 2012. The reactor is one of six in the nation in the NRC’s most serious category, “degraded cornerstone.” PPL is implementing a plan to address the issues under NRC oversight.

More: Citizens Voice

Exelon, Dynegy Called Vulnerable in New Era

Morningstar analysts named Exelon, Dynegy and Pinnacle West as three companies most vulnerable to “a solar-powered ‘death spiral’ roiling the electric industry.” Companies like Exelon and Dynegy will suffer most, the analysts said in a Utilities Observer report, as centralized generation loses value to competitive solar at customers’ homes.

At the same time, the analysts said NRG Energy, Edison International and SunPower are three companies poised to do well in the new environment.

More: Forbes

— Compiled by Kathy Larsen and David Jwanier

April 1, 2014

Stakeholders Preview Offer-Cap Debate

By Ted Caddell

Stakeholders representing load said Thursday they may oppose efforts to change PJM’s $1,000/MWh offer cap, despite a frigid winter in which high gas prices forced the RTO to obtain temporary waivers from the limit.

“We’re not convinced that last winter proves the need to change the cap,” Walter Hall, of the Maryland Public Service Commission, said after PJM officials gave the Markets and Reliability Committee a first read on a problem statement to consider raising or eliminating the cap.

John Farber, of the Delaware Public Service Commission, said he fears costs will quickly rise if PJM raises the cap. “We need fact gathering to determine if there’s a long-term issue here,” he said.

Exelon’s Jason Barker responded that the issue is one of simple math. “There’s no question in our mind that this issue is ripe for consideration,” he said. “PJM’s pricing must be correct so we have an adequate response from generators next winter.”

FERC Actions

On Jan. 24 the Federal Energy Regulatory Commission granted PJM’s request for a waiver allowing make-whole payments for generators with operating costs above the $1,000 cap. PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked to $140/mmBtu.

The January order allowed PJM to fund the make-whole payments through uplift charges. On Feb. 11, FERC granted a second waiver eliminating the cap through March 31, allowing high-cost generators to set locational marginal prices.

FERC lifted the cap over the objections of consumer advocates, state regulators and others, who said allowing the RTO’s most inefficient generators to set clearing prices would provide a windfall to the vast majority of generators with costs well less than $1,000.

Moderating temperatures and gas prices rendered the second waiver moot. But Thursday’s discussion — and a surprising report filed by the Market Monitor the day before — suggested the cap’s long-term future will be hotly debated in the coming months.

Problem Statement

PJM’s proposed problem statement says stakeholders should consider lifting the cap because this winter’s extreme conditions had for the first time put the limit at odds with rules requiring capacity resources to offer their output into the day-ahead energy market.

“A large amount of generation was offered into, and cleared, PJM’s energy market at prices likely below the generators’ costs of producing that energy,” PJM said. “The Operating Agreement’s `must-offer’ and `offer-cap’ provisions mean that the sellers were required to offer the available capacity of their generation resources below their marginal costs.”

Most stakeholders agree that it is improper to force generators to sell below cost. But a report that Market Monitor Joe Bowring filed with FERC on Wednesday may further stoke concerns about the risk that raising or eliminating the cap will lead to price gouging.

Monitor’s Review

The Monitor’s report (ER14-1144) covered the period between Jan. 24, when the first waiver took effect, and Feb. 11, when it was superseded by the second.

The only day during that period that resulted in waivers was Jan. 28, when seven generators owned by three companies sought relief.

The Monitor reviewed the requests at FERC’s direction and concluded that all but $9,118 of the nearly $584,000 in requested make-whole payments should be rejected.

The Monitor rejected requests to include the 10% “adder,” which is typically included in offers based on the uncertainty of calculating operating costs for combustion turbines under changing ambient conditions. “It is not appropriate to include the 10% adder in make-whole payments to generation owners in this situation because it is not an actual cost and the generation owners did not pay it,” the report said.

The report said all seven of the units requesting waivers purchased gas for less than the estimated price on which their cost-based offers were based and that five of the seven had better heat rates than what was reflected in their requests. Three of the generators withdrew their requests in response to the Monitor’s challenges.

The report said one generator purchased gas at a price 45% less than the estimate on which it based its waiver request. “When combined with an actual heat rate 4% better than included in the waiver request and removal of the 10% adder, the actual cost of the unit was about 52% lower than the cost included in the waiver request, lower than the $1,000/MWh offer cap,” the Monitor said.

The Monitor is conducting a broader review of all price offers by gas units in January to identify any evidence of overcharging. That review could result in recommendations that PJM seek refunds, Bowring said.

Lengthy Debate Predicted

PJM’s Adrien Ford, who presented the problem statement, said PJM agreed with the Monitor’s calculations on the waiver requests.

Ford said she hoped the Market Implementation Committee could complete work on the problem statement within three months, a timeline she acknowledged was “optimistic.”

Load representatives predicted a longer debate.

“I think this is going to be a tough issue from the customer perspective,” said Susan Bruce, of the PJM Industrial Customer Coalition. “We are still digesting what happened” over the winter.

“From the perspective of the consumer advocates this is a very touchy issue,” agreed Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS).

Bowring, too, cautioned that three months might be too ambitious a time frame for a full review. He said that it might be too early to say if any substantive change is necessary. “If it turns out our investigation shows this is a one-off, you don’t want a permanent solution,” he said. “You want a one-off waiver.”

The issue would be assigned to the MIC under PJM’s proposed Issue Charge. The proposals are expected to be brought to a vote at the MRC’s next meeting.

April 1, 2014

Federal Briefs

Former Federal Energy Regulatory Commission Chairman Jon Wellinghoff responded to criticism of his role in publicizing information about potential for attacks on the power grid Friday, telling Politico he had done nothing wrong.

Wellinghoff came under attack over a Wall Street Journal article describing an internal FERC report that described possible grid attack scenarios. Wellinghoff was not named in the Journal article as the source of the report, but he discussed it for an earlier Journal article on the subject. (See FERC Criticism of Ex-Chair Mounts.)

The former chairman told Politico that the information in the Journal article was no secret. “There was no classified information,” he said. “There was no secret information and nothing was shared with anybody that was in any way part of some unpublished report.” He and another FERC official had briefed hundreds of people about the study, Wellinghoff said.

Sens. Mary Landrieu, D-La., chairwoman of the Energy and Natural Resources Committee, and Lisa Murkowski of Alaska, the committee’s top Republican, sent the Department of Energy’s inspector general a letter last week asking for an investigation into the leak. Murkowski also named Wellinghoff on the Senate floor, criticizing him for participating in the Wall Street Journal story with “sensational,” possibly “reckless” comments.

More: Politico Morning Energy; Senate Energy Committee

GRID Act Gives FERC More Power to Deal With Threats

Sen. Ed Markey, D-Mass., and Rep. Henry Waxman, D-Calif., reintroduced legislation that would give FERC more authority to protect the transmission system from security threats. FERC last month ordered the North American Electric Reliability Corp. to identify critical facilities and propose standards to protect them. But spurred by ongoing concern about attacks on the power grid and recent publicity about the potential threats, some in Congress want to go further.

The Grid Reliability and Infrastructure Defense (GRID) Act would empower FERC to issue emergency orders if an imminent security threat is identified. It also allows FERC to issue protective orders on its own if it determines that NERC has not adequately addressed an identified vulnerability. Under current law, FERC must only act on reliability standards that NERC submits to it.

The bill would also allow FERC to ensure there are enough spare large transformers available to “promptly replace” any that are damaged in an attack. The measure also requires the president to identify up to 100 defense-critical facilities vulnerable to disruption of power supply provided by an external provider. If FERC determines a vulnerability that is not adequately addressed, it may issue a rule to protect it. The bill is similar to one that passed the House of Representatives in 2010 but did not succeed in the Senate.

More: Energy and Commerce Committee

PTC May See Senate Panel Action Starting This Week

Windmills (Image credit:123RF Stock Photo)

Senate Finance Committee Chairman Ron Wyden, D-Ore., hopes to start action Wednesday on a package of measures to extend energy tax incentives, including the production tax credit (PTC) for wind power. Wyden, who became chairman of the committee in February, is a strong supporter of the PTC.

It is unclear whether tax extenders would win full Senate approval, particularly in this election year. If the measures must be part of a full package of tax code rewrites, the negotiations will be complex. In the House of Representatives, Ways and Means Committee Chairman Dave Camp, R-Mich., may be open to discussing tax extenders but said he still wanted to keep pressing toward comprehensive tax reform. The PTC for wind, one of a number of tax incentives for the energy sector, expired at the end of last year.

More: E&E Daily

GOP Polls PJM, Others About EPA Rule Impacts

Republicans on the House Energy and Commerce Committee, who oppose the Environmental Protection Agency’s upcoming regulations limiting greenhouse gas emissions from power plants, are surveying grid operators about the role coal plants play in their markets and reliability.

In a letter to PJM and other transmission operators, the lawmakers said they want to know what could happen if coal plants produced less or closed because of the EPA’s rules. Their concern was sparked by the gas and electricity price spikes this winter, they said.

More: Governors’ Wind Energy Coalition

Chu: ‘Don’t Get FedExed,’ Get Into Rooftop Business

Former Energy Secretary Steven Chu has advice for utilities: Instead of looking for protective rules and rates, they should get into the rooftop-solar business themselves. Utilities are in danger of being pushed out, he said, “like the Post Office got FedExed.”

Chu said utilities should consider leasing rooftop installations to homeowners. “This is not a radical model. This is the old telephone system model,” he said.

More: Forbes

— Compiled by Kathy Larsen and David Jwanier

April 1, 2014

PJM Considers Easing Sharing of Real-Time Generator Data

PJM is considering ways to simplify the sharing of real-time generator data to improve situational awareness and help transmission operators respond more quickly in emergencies.

AEP’s Dana Horton urged the Markets and Reliability Committee Thursday to consider changing the current rules on data access, which he said are cumbersome and time consuming.

Horton said transmission operators would “like to be able to see real-time megawatt hour output from all generators in the PJM footprint, like PJM control operations folks do. They’re dealing with a lot of transmission overload issues. If they could see more output data, for more of the region that impacts their area, they are better able to give feedback.”

Horton said the current procedure for obtaining data access, spelled out in Manual 14D, “looks like it was written in the 1950s. It refers to making copies in triplicate.”

Phil Hoffer, an AEP transmission operations manager, said the data would be used as an input to AEP’s state estimator. “Some units may be outside of our control area but have significant impact on our operations,” Hoffer explained.

PJM officials said the RTO supports the effort. “We should be as transparent as we can,” said Executive Vice President for Operations Mike Kormos.

CEO Terry Boston noted that PJM found other transmission operators’ state estimators helpful during the September heat wave, particularly for understanding conditions on lower voltage systems.

PJM Market Monitor Joe Bowring said he would support streamlining the sharing rules if it were done in a way to preserve confidential information. Existing confidentiality agreements and codes of conduct should satisfy any confidentiality concerns, AEP said.

The MRC will be asked to vote on AEP’s issue charge and problem statement at its next meeting. If approved as is, the issue would be assigned to the Operating Committee.

April 1, 2014

MRC/MC Voting Summary

The Markets and Reliability and Members committees approved the following measures with little or no discussion last week:

Markets and Reliability Committee

Changes to Manual 14A: Generation and Transmission Interconnection Process, which updated Attachments F & G. These attachments list wind turbine models that do not need to be reviewed by PJM prior to submission of system impact and generation interconnection feasibility studies. Units listed reflect those PJM has modeled in the past.
Revisions to PJM’s Tariff and Operating Agreement to update the list of agreements and transmission service transactions to which PJM Settlement, Inc. is not a part.
Operating Agreement and Tariff revisions in preparation for eSuite application name changes. These revisions include changing eSchedule and Enhanced Energy Schedule (EES) to InSchedule and ExSchedule, respectively, in the documents. This is part of a larger refresh of eSuite tools, which will occur in stages through the end of the year. (See PJM Updating eSuite Apps.)
Updates to the Regional Transmission and Energy Scheduling Practices for the deployment of ExSchedule. The changes remove ramp reservation and tag timing requirements based on schedule duration. These changes were requested in part due to the new Coordinated Transaction Scheduling (CTS) between PJM and NYISO, which aims to reduce uneconomic flows between the RTOs. (See NYISO Scheduling Product Wins FERC OK.)
Changes to accelerate the schedule of the triennial review of the Cost of New Entry (CONE) by two months. The change, which was also approved by the Members Committee, will move the deadline for staff recommendations to May 15 from July 15 and the projected FERC filing to Oct. 1 from Dec. 1. The CONE review will be conducted every four years beginning with the 2018/2019 Delivery Year.

Members Committee

Tariff revisions associated with CTS and export transactions. The key change is the addition of a provision stating that export transaction screening will not apply to emergency transactions between PJM and neighboring balancing authorities.
Tariff changes to add a transition mechanism to protect generators whose installed capacity ratings are reduced by seasonal verification tests. (See Transition Period OKd for Seasonal Verification Rules.)

April 1, 2014

PJM Proposes Generic Transition Rule for Capacity Market Changes

Members reacted warily Thursday to PJM’s proposal to develop a generic transition mechanism that would hold capacity providers harmless for future rule changes.

PJM’s Adrien Ford told the Markets and Reliability Committee that the proposal was prompted by the transition mechanism approved by members to protect generators whose installed capacity ratings are reduced by seasonal verification tests. (See Transition Period OKd for Seasonal Verification Rules.)

Bruce Campbell, of demand response provider EnergyConnect, said the proposed solution, based on the Manual 21 fix for generators, may not provide protection for DR.

“This mechanism is really impractical” because it assumes the impact of the changes can be predicted, Campbell said. “We often don’t know what the impact of the changes will be.”

Susan Bruce, of the PJM Industrial Customer Coalition, said she prefers “stability” in capacity market rules. “It might make rule changes too easy to contemplate,” she said.

Exelon’s Jason Barker said his company had “reservations about a `one size fits all’ solution.”

Barker said “it would certainly be helpful to have a default” transition mechanism. But he said it should be spelled out in manuals and not the Tariff or Operating Agreement, where changes would require Federal Energy Regulatory Commission approval.

Katie Guerry, of DR provider EnerNOC, agreed, suggesting the mechanism not be a “defined solution but a set of parameters that must be abided by.”

Ford said PJM officials attempted to address DR in drafting the problem statement. “We wanted to make sure it works for all types of capacity resources,” she said.

The MRC will be asked to vote on the proposed problem statement and issue charge at its next meeting.

April 1, 2014

FTR Holders Seek Shortfall Fix

Financial Transmission Rights holders asked PJM and Market Monitor Joe Bowring last week to take action to address the continuing shortfall in FTR funding. They received sympathy but no commitments.

In June, the Federal Energy Regulatory Commission rejected a complaint (EL13-47) by FirstEnergy Solutions Corp. that sought to bill all transmission users to make up the shortfalls. While PJM largely supported FirstEnergy’s proposed solution, the Monitor rejected it as “simplistic” and unfair to load.

The commission urged PJM and its stakeholders to reach a consensus solution and to work with its neighbors to reduce congestion on the RTO’s borders. In August, the commission granted rehearing in the case, keeping the docket open but offering no timetable for further action.

$1.1 Billion

In the interim, market participants say, the problem has only gotten worse. Cumulative shortfalls have grown to more than $1.1 billion (see chart). DC Energy’s Bruce Bleiweis told the Members Committee Thursday that March “could be the worst ever.”

“It’s a problem that hasn’t gone away,” said Bleiweis. “We’re still looking for action.”

PJM introduced FTRs in 1999, intending them to provide a financial hedge against the costs of day-ahead transmission congestion.

The value of an FTR is based upon the difference between the day-ahead congestion price between a specific source and sink. The quantity of FTRs to be auctioned is supposed to be limited by transmission capacity.

But a PJM stakeholder report found that revenues were falling short because pre-auction modeling failed to capture some transmission outages and deratings. The modeling also could not account for market-to-market flowgates added in the middle of a planning period.

Consensus Elusive

Since the report, PJM officials have worked with MISO to reduce congestion resulting from cross-border flows.

Last spring, stakeholders also approved two modeling changes recommended by the Financial Transmission Rights Task Force that were expected to provide modest improvements. But members were unable to reach consensus on others, including several proposed by the Monitor. (See MIC Rejects Change to FTR Long-Term Auction Modeling.) The task force was disbanded in December.

With no solutions coming from the stakeholder process and no action from FERC, Goldman Sachs’ J. Aron & Co. seized upon PJM’s ad hoc creation of a pricing interface in the ATSI region during the Sept. 10-11 heat wave. PJM’s action, intended to make demand response set prices in the area, exacerbated underfunding by $23 million over the two days, J. Aron said in a filing in the FirstEnergy docket in December.

Top Binding Constraints in FTR Auctions and ARR Allocations (Source: State of the Market 2013, fig. 13-1)

FTR holders found a new opportunity to bring the issue up when Bowring gave members a presentation on the 2013 State of the Market report, which also criticized the creation of such interfaces.

Harry Singh, of Goldman Sachs, said market participants used to be able to buy 1.2 or 1.3 FTRs for a path they were looking to hedge, but that the technique no longer works because the level of underfunding varies significantly from day to day. On Feb. 14, for example, the funding was only 30%; on Sept. 10 and 11 it approached zero.

In 2010, load serving entities converted almost 63% of their Auction Revenue Rights (ARRs) to FTRs, Singh said. In 2013, only 31% did so. “That tells you people think it doesn’t work as a hedge,” Singh said. Instead, he said, the market has become a way to speculate on uplift and the level of underfunding.

Sympathy, No Commitments

Bowring and PJM CEO Terry Boston acknowledged the problem but were noncommittal about pursuing solutions.

“I’m almost certain the stakeholder process is not going to come to a resolution on this issue,” Boston said. “But we need to keep it on the table.”

The State of the Market report declared the FTR market performance competitive. But it said the market design was flawed because it “incorporates widespread cross subsidies which are not consistent with an efficient market design and over sells FTRs.”

The Monitor noted that the market has responded to the shortfalls by reducing bid prices and increasing bid volumes.

Clearing prices for FTR obligations averaged $0.30/MW in planning year 2013/14, down from $0.71/MW in 2010-11. FTR obligation sell offers dropped to $0.05/MW down from $0.22/MW over the same period.

The report reiterates eight recommendations Bowring made in an April 2013 filing in response to the FirstEnergy complaint.

Bowring said the eight recommendations could increase the FTR payout ratio to almost 96% from the current rate in the mid-70s. The recommendations included a reduction in the allocation of ARRs, the elimination of portfolio “netting” and using probabilistic analysis to improve transmission outage modeling.

In response to a question from Bleiweis, Bowring said he had considered making a Section 206 filing to win FERC approval for his proposed changes. “It’s really a question of timing,” Bowring said, adding that he’d like “to see if others will join us” in support.

April 1, 2014

Missing Zero Produces Illusory Locational Marginal Prices

PJM’s day-ahead prices for last Thursday turned out to be far more modest than they initially appeared.

The RTO reposted the day-ahead results for March 27 after officials identified an error in the input data used to clear the market. A value of 350 MW was used for the West Interface instead of 3,500 MW for hours 8 through 23, causing incorrect prices and quantities in the day-ahead market solution.

A glum Stu Bresler, vice president of market operations, informed stakeholders of the error at the end of Thursday’s Members Committee meeting. In reposting the results, Bresler said PJM was invoking a provision put in the Tariff “with the hope that we’d never have to use it.”

The changes reduced prices by as much as $37/MWh, with the biggest changes seen in the AECO, BGE, JCPL, METED, PECO, PPL and PSEG zones. In the PPL zone, for example, the LMP for hour 20 — originally posted at $89.41 — was reduced to $52.16.

Bresler said yesterday that the error resulted in higher day-ahead dispatch orders for some generators east of the West Interface and lower orders for those to the west, but that the actual dispatch of the units in real time was unaffected.

Bresler said the apparent constraint at the West Interface “didn’t bind that hard, so it wasn’t enough to raise a red flag” before the day-ahead results were initially posted.

He said officials are investigating whether they can add an automated check to prevent such errors in the future. “We certainly don’t want the market to think this is going to be a regular occurrence,” he said.