Page 1642 – RTO Insider

March 11, 2014

Artificial Island Price Tag Rising?

Artificial Island Proposals - Southern Delaware Crossings (Source: PJM Interconnection, LLC) — Artificial Island Proposals – Southern Delaware Crossings (Source: PJM Interconnection, LLC)

The solution to the Artificial Island transmission stability problem may be more costly than originally estimated, PJM officials said last week.

PJM planners, who received 26 proposed solutions with costs as high as $1.5 billion, have been concentrating their review on several proposals with estimated costs of $110 million to $270 million.

Vice President for Planning Steve Herling told the Transmission Expansion Advisory Committee Thursday that addressing technical concerns stakeholders have raised about the proposals “could drive costs up.”

PJM’s Paul McGlynn said costs could be increased, for example, due to “the complexity that comes from working in a substation outside a nuke plant.” Artificial Island is home to the Salem and Hope Creek nuclear plants.

Officials gave TEAC members a briefing on the preliminary findings of the constructability review by the RTO’s engineering consultant.

Right of Way Concerns

The review found that the availability of land that Transource Energy proposed using in New Jersey “is in question.”

Proposals by LS Power and Virginia Electric and Power Co., in contrast, would require no additional land for expansion of the existing Salem substation. LS Power has acquired an option on a site for its proposed new switching station in Delaware.

The consultant also raised concerns about proposals that would cross or parallel Delaware Route 9, which is designated as a “Scenic and Historic” highway. Sharon Segner, of LS Power, said her company has obtained a legal opinion that Delaware law does not prohibit transmission lines near scenic highways.

Some proposals also could impact a wildlife refuge in New Jersey.

Artificial Island is PJM’s first competitive transmission project under FERC Order 1000.

McGlynn said planners are doing their best to conduct an “apples to apples” comparison of the proposals. “It’s proving to be more of a challenge than I originally thought,” he said, adding that planners still hope to recommend a solution to the PJM board by summer.

March 4, 2014

PSEG Employees Hurt in Gas Explosion

By David Jwanier

At least seven people were injured, including five PSE&G workers, Tuesday afternoon when a gas explosion ripped through a Ewing Township, N.J. condo complex. The blast destroyed at least one home and others were damaged by what witnesses described as a fireball.

Two hours after the explosion, firefighters from West Trenton Fire Co. and surrounding communities in Mercer County and beyond were still dousing the flames.

PSE&G said crews were working on repairs to a gas line that was reported damaged by a contractor when “there was an ignition.” The cause was under investigation.

According to news reports, the accident occurred about 1 p.m. in the South Fork development when witnesses said they heard what sounded “like a thunderbolt hitting” the area. One witness described diving to avoid a fireball.

Details were still unclear late Tuesday afternoon.

Ewing Police Lieutenant Ron Lunetta said five PSE&G workers were injured in the explosion, in addition to two employees of utility contractor Henkels and McCoy. PSE&G said two of its employees were hospitalized.

One of the injured was undergoing emergency surgery for lower body fractures at Capital Health Regional Medical Center in Trenton, according to Chief of Surgery Louis D’Amelio. None of the injuries were considered life threatening.

It did not appear that any residents were injured.

Dozens of homes were evacuated and affected residents were taken to the fire company and a local golf course in the immediate aftermath.

News reports said homeowners whose homes weren’t directly affected by the blaze would have to wait until late evening to return to their homes.

March 4, 2014

Stakeholders Reject Pay Hike for Black Start Units

By David Jwanier

Black start generators anticipating increased compensation came away empty handed Thursday as stakeholders rejected two proposals that would have boosted payments to existing units by at least 40%.

The Markets and Reliability Committee split along supply-load fault lines in rejecting the proposals.

Proposals Described

The Minimum Incentive proposal, which would have increased total payments to existing black start units by an estimated $3.4 million, won only 60% support in a sector-weighted MRC vote, short of the two-thirds needed to clear. While every Transmission Owners sector member and most members of the Generation Owners sector voted in favor, the proposal failed to win a single vote from End Use Consumers and got about half of Other Suppliers and Electric Distributors votes.

An alternative proposal, the Proxy for Base Formula Replacement, which would have more than doubled costs for existing black start units, also fell short with only 45% support and no support from the EUC and ED sectors.

The proposals had garnered 65% and 63% support, respectively, in unweighted votes in the System Restoration Strategy Senior Task Force.

Existing black start units are paid a base formula rate plus an incentive. The Minimum Incentive proposal would have increased the incentive factor from 10% of the base to the greatest of 10% or $25,000. This would raise the annual payment for a 20 MW black start unit from approximately $51,000 to nearly $72,000.

The same 20 MW unit would have received $312,000 under the proxy proposal. (See Black Start Units to See More Green?)

Bowring: No Need for Increase

Market Monitor Joe Bowring and stakeholders representing load questioned the need for the increase, noting that PJM said it had received a good response to its recent solicitation for new resources.

After the Minimum Incentive proposal failed, NRG Energy’s Neal Fitch made a statement endorsing the Proxy proposal, which he said was similar to compensation methods in New England.

Dave Weaver, representing Exelon, said generators in the PECO zone “are receiving revenues that are nowhere near the proxy.”

“What’s the benefit?” asked the Delaware Public Service Commission’s John Farber.

“I would say the benefit is you don’t lose these resources,” responded Weaver.

Bowring opposed both options, eschewing the “idea of some minimum payment that isn’t based on costs.”

“We support paying black start units full costs,” he said. “This is not what this is about. This is about an artificial cost based on what other units are getting. There is no basis for the assertion that these units will go away” without an increase.

PJM’s Chantal Hendrzak said although some operating generators have stopped offering black start service recently, “we’re finding sufficient black start to meet these critical load needs” as a result of the solicitation.

After the second proposal failed, Gloria Godson, representing Pepco Holdings, called for a renewed effort to create a “back-stop” solution for zones that fail to attract sufficient black start resources. “Generators are not in the business of just breaking even,” she said.

The issue will be returned to the task force for further consideration.

March 4, 2014

Pepco Earnings Up, FE Down

By Ted Caddell

Pepco Holding Inc.’s quarterly earnings shot up to 23 cents a share on $58 million for the final quarter of 2013, compared to 15 cents a share on $34 million for the same quarter a year ago.

Year-end results were $1.14 per share on $280, compared to 98 cents a share on $225 million a year ago.

The company attributed the increase to higher electric distribution revenues — primarily from higher rates from infrastructure investments — and lower operating expenses.

“Over the past three years, decreases in the duration and number of power outages have been dramatic, reflecting the significant investments we have made in the electric system,” CEO Joseph Rigby said during a conference call Friday. “The increase in adjusted earnings in 2013 reflects the impact of these investments.”

As with many utilities announcing year-end financial results, Pepco’s regulated delivery service posted an annual increase in revenue (4 %) while its non-regulated business posted a decrease (3.4 %) for the year.

Rigby said that the company’s improvements in system reliability helped drive its improved results. Having announced his retirement in January, he’ll have little time to enjoy the upswing, however. (See Pepco CEO to Retire.)

FirstEnergy Posts Lower Q4, Year-End Results

FirstEnergy reported a decrease in both quarterly and year-end earnings for 2013, a tough announcement in a year that already saw the company cut its dividend.

The company reported fourth-quarter earnings of 75 cents per share, compared to 80 cents for the same quarter a year ago, and $3.04 for the year, compared to $3.34 the year before.

Its 2014 guidance numbers show that it’s not out of the woods, either, with first-quarter earnings estimates of 35 cents to 45 cents per share, and year-end earnings at $2.45 to $2.85 per share.

The company said increased regulated delivery revenue helped make up for lower power prices coming from its aging generation fleet.

In January, it announced it was reducing its quarterly dividend to 36 cents a share from 55 cents, the first dividend cut in the company’s 17-year history, and said it will concentrate on its regulated delivery businesses going forward. (See Reboot for FirstEnergy.)

FirstEnergy CEO Anthony J. Alexander said the company’s actions “were intended to strengthen our financial position and reposition the company to focus on more predictable and stable growth initiatives in our regulated businesses.”

The company plans to invest $4.2 billion on its transmission business over the next four years.

March 4, 2014

RPS Targets’ Cost: $13.7B in Tx Upgrades

Renewable Portfolio Standards in PJM States (Source: DESIRE)

PJM could get 30% of its energy from wind and solar power without reliability problems, but it will require as much as $13.7 billion in transmission upgrades and 1,500 MW in additional regulation reserves, according to a long-awaited study.

The results of the study, which PJM commissioned in 2011, were presented to stakeholders yesterday by a study team headed by GE Energy.

Stakeholders had asked PJM to assess the impact on grid operations of state renewable portfolio standards. PJM states have targets calling for at least 10% of their electricity from renewables by the middle of the next decade, with most states setting targets between 20% and 25%. In total, the state targets anticipate the addition of 33 GW of wind and 9.2 GW of solar by 2029 (see chart).

Ten Scenarios

The study considered 10 scenarios, ranging from a business-as-usual case based on 2011 levels of wind and solar generation to a high-end case in which nearly one-third of the region’s power was generated by those renewables.

The study looked at the impact on regulating and operating reserves, transmission upgrades, PJM markets and operations, power plant emissions and the impact of cycling duty on variable operation and maintenance (VOM) costs.

Findings

Wind and Solar Requirements in PJM (MW) By 2029 - 33 GW of Wind 9.2 GW of Solar (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

It found that PJM could adapt to the 30% renewable scenario without significant reliability problems by adding transmission and regulation reserves. “PJM has long held that ISOs and RTOs are better able to integrate variable energy resources because of their organized markets and regional infrastructure planning processes,” PJM said in its summary of the study. “… The study found that PJM’s large geographic footprint also provides significant benefit for integrating wind and solar generation because it greatly reduces the magnitude of variability-related challenges.”

All 10 of the scenarios predicted lower average Locational Marginal Prices and reduced revenues for conventional generators.

Although renewable generation increased the amount of cycling on existing generators, the increased VOM costs were small relative to the reduction in spending on fuel.

Recommendations

The study recommends that PJM:

Develop a method for determining reserve requirements based on forecasted levels of wind and solar production.
Consider intra-day unit commitments that would allow use of more efficient combined cycle units rather than combustion turbines to balance renewables’ variability. The study’s authors said that four-hour wind and solar forecasts have half the error rate of day-ahead projections.
Identify the reasons for ramping constraints on individual generators (i.e., technical, contractual, or otherwise) and seek methods for improving the flexibility of those that have traditionally operated as baseload units.

The study suggested PJM consider further study on how conventional generators can remain economically viable despite reduced energy market revenues.

It also recommended the RTO investigate how wind and solar plants could contribute to frequency response. Current wind and solar generators have the ability to respond to frequency response and down-regulation.

PJM’s Ken Schuyler, who introduced the study team yesterday, said PJM management has not taken a position on the study’s recommendations and plans to consult with members to “see which ones stakeholders think we should pursue.”

March 4, 2014

Company Briefs

American Municipal Power issued a request for proposal for carbon offset projects its six-state territory. Offsets may be from existing or new projects, including forest management, coal mine methane, landfill methane, wastewater treatment and anaerobic digestion. AMP has developed forestry offset projects and continues to pursue them, but says “carbon offset diversification is desired as well.”

More: AMP

Former Southern Exec Joins AEP Board

American Electric Power elected J. Barnie Beasley Jr. to its board of directors. Beasley, former chairman, president and CEO of Southern Nuclear Operating, is an adviser to the board of the Tennessee Valley Authority. His “nuclear operations expertise and insights into our industry will be valuable contributions to our board,” said AEP Chairman and chief executive Nick Akins.

More: AEP

— Compiled by Kathy Larsen

March 4, 2014

TOs Will Disclose Calculation Methodologies

Transmission owners will publicly post the calculations they use to allocate energy, capacity and transmission costs under a plan outlined to the Markets and Reliability Committee.

The Transmission Owners Agreement-Administrative Committee’s plan is intended to promote greater transparency, addressing a problem statement approved by the MRC last year. (See MRC Backs Industrials’ Call for Transparency in Transmission Owner Calculations.)

The proposal would add a page to the PJM website containing the methodologies transmission owners use to calculate total hourly energy obligations (THEO), peak load contributions (PLC) and network service peak loads (NSPL). The calculations are used to allocate cost responsibility among load-serving entities.

The issue arose because some TOs have not filed tariffs disclosing the methodology they use. Some members complained that the lack of transparency made it difficult to ensure they were being properly charged.

March 4, 2014

PJM Proposes Change to CONE Schedule

PJM officials told members last week they want to accelerate the schedule of the quadrennial review of the Cost of New Entry (CONE) by two months.

The proposed change would move the deadline for staff recommendations to May 15 from July 15 and the projected FERC filing to Oct. 1 from Dec. 1.

Executive Vice President for Markets Andy Ott noted that CONE calculations — which set the floor price for new generation resources looking to enter the capacity market — have been highly contentious in past years.

The two-month acceleration is “to give enough time for it to be litigated at FERC” before the capacity auction, he told the Markets and Reliability Committee.

The proposed change will be brought to a vote at the next MRC meeting.

March 4, 2014

Tariff Changes Prepare for CTS

Preparing for a new scheduling product, the Markets and Reliability Committee last week approved collateral rules for export transactions.

The changes to Attachment Q of the Open Access Transmission Tariff will apply to Coordinated Transaction Schedules, which are designed to reduce uneconomic power flows between PJM and NYISO.

Under CTS, traders would be able to submit “price differential” bids that would clear when the price difference between New York and PJM exceed a threshold set by the bidder. CTS were conditionally approved by FERC on Feb. 20 and will not be available to traders until at least November.

March 4, 2014

January Cold Almost Off the Charts

PJM’s frigid January was almost off the charts — literally.

PJM Load-Weighted LMPs (Source: PJM Interconnection, LLC)

The record-setting cold pushed PJM’s load-weighted LMP to $126.80, more than three times the price in January 2012, officials told stakeholders last week.

The RTO’s gross billings for the month were $11.2 billion — about one third of the total for all of 2013. Collateral calls for the month totaled $2.6 billion, more than six times the total for all of 2013. (See charts.)

PJM officials told the Members Committee that they are combing through data in preparation for an April 1 technical conference called by the Federal Energy Regulatory Commission.

January 2014 Billing & Collateral Activity (Source: PJM Interconnection, LLC)

Acting FERC Chair Cheryl LaFleur announced the conference Feb. 27, saying it would focus in part on the experience in PJM, which called on demand response, a voltage reduction and voluntary appeals for conservation to avoid rolling blackouts in the face of record demand and large numbers of generator outages.

Investigations Sought

Consumer advocates from the PJM states on Feb. 14 asked FERC to investigate the causes of the high prices.

“It is becoming apparent that the unprecedented energy and ancillary service prices that occurred in January were not reflective of smoothly operating market fundamentals, but were, instead, reflective of significant and systemic inefficiencies,” the advocates wrote. “For example, we know that more than 40,000 MW of generation was unavailable during critical periods in January due to forced outages. This is the same generation for which consumers in the PJM region are paying billions of dollars in capacity payments each year.”

The American Public Gas Association, which represents publicly owned local distribution companies, asked the Commodity Futures Trading Commission (CFTC) Feb. 20 to examine the cause of a 10% jump in the February 2014 New York Mercantile Exchange (NYMEX) Henry Hub contract.

The association said natural gas for February delivery jumped 52 cents to $5.557 per MMBtu, the highest closing price in more than three years, during the final hours of trading on Jan. 29.

While he said the association had no evidence of manipulation, APGA President Bert Kalisch said “We are more concerned about the pervasive pricing impact of NYMEX and want to be certain that the market is liquid and operating correctly.”

Gerald Ballinger, chairman of the group’s Gas Supply Committee, noted that most public gas companies purchase gas under contracts priced off of a price index.

Inside FERC’s Gas Market Report calculated the February price at Texas Gas Zone 1 based on a survey of 18 trades, 17 of which were basic transactions priced off of NYMEX, he said. The price rose to $5.54/MMBtu in February, compared up from $4.34/MMBtu in January.