Generators would be permitted to sell frequency response services at market-based rates under a rule proposed by the Federal Energy Regulatory Commission last week.
“While most balancing authorities should be able to meet the new reliability standard using their own resources, some may nevertheless be interested in purchasing primary frequency response service from others if doing so would be economically beneficial,” the commission wrote, concluding “there could be interest in the near future in voluntary purchases of a primary frequency response product.”
FERC would allow entities with market-based rate authority for energy and capacity to also sell frequency response at market-based rates.
The NOPR applies to generators providing primary frequency response — the ability to automatically change their output within seconds when the grid’s frequency strays above or below 60 Hz.
It is distinguished from regulation — also known as secondary frequency response — which involves manual or automated dispatch from a centralized control system.
The requirements of the reliability standard will be phased in over a year beginning April 1. The commission expects to finalize the rule after a 60-day comment period.
Public Service Enterprise Group reported fourth-quarter net income of $476 million ($0.94/share), more than double the $200 million ($0.39/share) for the same quarter in 2013. The company posted net income of $1.518 billion ($2.99/share) for 2014, compared to $1.243 billion ($2.45/share) a year earlier.
CEO Ralph Izzo attributed the increased earnings to its investments in its regulated business, Public Service Electric & Gas. “As a result of an extended capital program, earnings from our regulated company grew to represent 52% of our consolidated operating earnings, as PSE&G’s investment in transmission has grown to represent 39% of its $11.4 billon rate base.”
Izzo highlighted several aspects of the investment in the regulated business, much of it in response to the pounding New Jersey, and PSE&G in particular, took during Hurricane Sandy. “We received approval to invest $1.2 billion in Energy Strong, a program that will improve the resiliency of our electric and gas distribution systems,” he said during a conference call.
The company is updating and replacing about 250 miles of its natural gas lines, as well as making upgrades to its electric transmission network. “We completed construction of two, 230-kV transmission lines during the year, as well as the New Jersey portion of the 500-kV Susquehanna-Roseland line,” he said.
Izzo acknowledged that PSEG Power’s bid to build a new 475-MW combined-cycle plant in Connecticut didn’t clear ISO-NE’s recent capacity auction, but he said “we haven’t abandoned this work and we’ll invest when the markets support its development.” (See Exelon, LS Power Join CPV in Adding New England Capacity.)
Calpine is building a 345-MW, gas-fired combined-cycle unit at the site of its 375-MW Mankato plant in Minnesota to meet the rising demand of Xcel Energy’s Northern States Power-Minnesota utility.
The Minnesota Public Utilities Commission approved a 20-year power purchase agreement between Calpine and Northern States Power. The new unit is expected to start operations by mid-2018.
Navigant Predicts Smart Grid Market to Reach $29 Billion by 2023
A Navigant Research report said the market for smart grid technology will expand to $29 billion a year by 2020.
“The smart grid continues to mature, and communications technologies are also evolving in response,” said Navigant Senior Research Analyst Richelle Elberg. “Whereas five years ago vendors and utilities were consumed with simply enabling grid communications, today they are focused on technology that is anticipated to enable a truly integrated system that links existing legacy technology with new technology from a variety of vendors.”
The report also predicted that as smart grid technology is implemented, security needs will rise as well.
Oops: PECO Customer Overpays Bill by $33K, Awaits Refund
A PECO Energy customer is waiting — somewhat impatiently — for a refund after his wife accidentally overpaid the couple’s electric bill by more than $33,000.
Steve Onufrey, 71, of suburban Philadelphia, said his wife misplaced a decimal point when paying their $339.38 bill online, and paid the utility company $33,938 instead. Luckily, he had that much in the account because of a real estate transaction. He said it took him about a week to convince the company to issue a refund.
PECO Spokesman Ben Armstrong said the company is sending a paper check in the mail, as part of standard refund practice to prevent fraud.
NextEra Energy, which is completing its $4.3 billion purchase of Hawaiian Electric, is planning to build a 120-MW wind farm on state land on Maui.
The planned facility will be on about 500 acres on the southern slopes of Haleakala, and be built, owned and operated by NextEra Energy Resources.
The NextEra project is the latest wind-generation facility to sprout in Hawaii. Boston-based First Wind operates four wind farms on Maui and Oahu with a capacity of about 120 MW, and Sempra U.S. Gas & Power owns a 21-MW wind facility on Maui. Champlin Hawaii Holdings is in the planning stages of a 24-MW wind farm on Oahu.
Dynegy Lobbying Against AEP’s Guaranteed Income Plan
Flexon
Dynegy CEO Bob Flexon spent an hour with Ohio Gov. John Kasich recently to argue against a competitor’s plan to seek guaranteed income for some of its coal-fired plants.
Flexon told Columbus Business First that a proposal by rival AEP to seek long-term power purchase agreements for plants it says cannot compete would stifle incentives to build more efficient merchant generation plants in the region, at the expense of system reliability.
“When you want to create subsidies for a plant, you go into the huddle and pull out a playbook and have three plays: the reliability play, the jobs play and the local community play,” Flexon said. Merchant generator Dynegy is near closing on a $2.8 billion deal to buy 11 Duke Energy plants in the region, including nine in Ohio.
Tom Raga, who has headed up Dayton Power and Light’s communications and government relations departments since 2010, was named the company’s new president and CEO. He replaces Derek Porter, who held the position since 2013.
“Tom brings the business experience and proven leadership skills with a clear strategic vision to the role of president and CEO,” said Ken Zagzebski, president of AES’ U.S. strategic business unit, in a statement. AES is the parent company of DPL.
Robert C. Braun, PSEG Nuclear’s chief operating officer, has been named chief nuclear officer, replacing Thomas P. Joyce, who is retiring in March after 40 years in the industry.
Braun has been chief operating officer for 10 years and has 30 years of experience in nuclear operations. PSEG Nuclear operates the nuclear complex on Artificial Island in New Jersey.
NRG Can Be Sued over Coal Ash, Ill. Pollution Board Rules
The Illinois Pollution Control Board has ruled that environmental organizations can pursue a lawsuit against NRG Energy that alleges the Princeton, N.J., company has done nothing to keep harmful chemicals from coal ash dumps at four power plants it bought last year from Midwest Generation.
“The decision by the Illinois Pollution Control Board to allow an expanded lawsuit and investigation into NRG’s coal ash disposal methods brings us one step closer to making sure local communities and bodies of water around these plants are adequately protected,” said Holly Bender of the Sierra Club Beyond Coal Campaign.
Environmentalists allege that ash dumps at the Waukegan, Joliet, Romeoville and Pekin plants are leaking into the ground and into water supplies.
Darn that Reply-All Button: Ameren Shares Negotiating Position Before Hearings
Ameren Missouri has filed for a $264 million rate increase with the Missouri Public Service Commission, but it inadvertently disclosed that it would be willing accept about $100 million less.
Ameren told its investors in a Securities and Exchange Commission filing that it had accidentally shared its proposed settlement position with all of the parties in a series of electronic document transfers meant to go only to the PSC staff. Ameren said it had “inadvertently” disclosed the proposed settlement to all the parties but made no further comment.
PPL Transferring Nuke Engineering Staff to Susquehanna Station Amidst Acquisition Rumors
PPL is transferring 88 engineer and technical support staff members associated with its nuclear operations from its Allentown, Pa., headquarters to its Susquehanna nuclear generating station in Berwick, Pa.
The announcement came amid market speculation that PPL might be looking to sell more generation assets. It is currently spinning off most of its power generation assets, along with those owned by Riverstone Holdings, into a new company called Talen Energy.
A company spokesman said engineering and support for the plants under the Talen name will remain in Allentown. The Morning Call reported that rumors are circulating that Talen may already be looking to buy more generation assets, but the company declined to comment on the rumors. The Talen spinoff has yet to achieve approval from the Federal Energy Regulatory Commission.
Exelon Expects Illinois Legislation Benefiting Nukes to be Introduced
Exelon, which has been lobbying hard for legislation to favor its six nuclear reactors in Illinois, said it expects a bill to be introduced in the Illinois General Assembly as soon as March. William Von Hoene Jr., the company’s chief strategy officer, said during an earnings conference call that it expects bi-partisan support for the measure.
Details of the bill haven’t been released, but Exelon has long complained that its nuclear fleet doesn’t get credit for being a carbon-free generation source, making it hard to compete against subsidized renewable energy. It has warned that without some sort of relief, it may have to shut down some or all of its nuclear sites in the state.
The Federal Energy Regulatory Commission last week approved a new risk-based approach to reliability compliance monitoring and enforcement, saying it will allow regulators to focus resources on the most serious issues (RR15-2).
The Reliability Assurance Initiative (RAI), a collaboration among NERC, the Regional Entities, and industry, is intended to streamline what reliability violations come under enforcement of the North American Electric Reliability Corp., with “minimal”-level risk issues subject to less oversight.
The new approach allows qualified facilities to self-log minor issues that they have identified and solved, instead of reporting them immediately to NERC. These logs will be periodically reviewed by NERC’s Regional Entities, FERC said.
The initiative also includes a compliance monitoring program, which provides definitions of risk levels and violations, among other guidelines.
“A risk-based approach is necessary for a proper allocation of resources and to encourage registered entities to enhance internal controls, including those focused on the self-identification of noncompliance,” NERC said in describing the new approach.
The minimal risk issues will not be subject to NERC penalties. Instead they will be treated as “compliance exceptions.” While RAI received broad support, some stakeholders disagreed with NERC’s decision not to make these exceptions public. NERC had proposed to submit them monthly to FERC for review.
“Greater transparency, particularly in the first two transitional years as [NERC] gains experience with implementation of RAI, is essential to educating [the] industry to avoid and mitigate noncompliance with reliability standards and to maintain the credibility of NERC’s compliance and enforcement regime,” a group of stakeholders, including the American Public Power Association and the National Rural Electric Cooperative Association, said in a joint filing.
FERC agreed, requiring NERC to post exceptions similar to how it files Find, Fix and Track reports.
“We find arguments that publicly posting compliance exceptions is unnecessary or will discourage entities from taking advantage of the efficiencies of RAI unpersuasive,” FERC said, alluding to comments by the Edison Electric Institute and the Electric Power Supply Association. “Public disclosure of compliance exceptions would appear to require only minimal additional resources since information will be compiled monthly in a spreadsheet and provided to the commission.”
FERC directed NERC to submit a compliance filing within 90 days of the order outlining revisions to its rules and procedures incorporating RAI.
New Reliability Standard
In a separate order, FERC also approved a new NERC reliability standard, MOD-031-1, which allows planning authorities and coordinators to collect demand data to support reliability assessments (RM14-12). Transmission planners, balancing authorities and load-serving entities are required to provide data such as total internal demand, net energy for load and demand-side management.
FERC said the standard will improve consistency and efficiency as well as help identify where grid improvements are needed.
Duke Energy contractors and engineers survey the site of the coal ash spill on the Dan River in North Carolina.
Duke Energy said Friday that it had reached a $102.2 million settlement with the federal government to end the investigation into the Dan River ash spill and the company’s ash basin operations at other North Carolina plants.
News of the proposed settlement, which must still be approved by a U.S. District Court judge, came hours after federal prosecutors filed misdemeanor criminal charges against the company for illegal ash pond discharges throughout the state.
The investigation began following the February 2014 spill of up to 39 million tons of ash into the Dan River.
‘We are Accountable’
“We are accountable for what happened at Dan River and have learned from this event,” said CEO Lynn Good in a prepared statement Friday. Good mentioned the pending settlement during an earnings call on Wednesday.
Under the terms of the settlement, Duke will pay $68.2 million in fines and restitution and $34 million for community service and mitigation. The settlement calls for the $102.2 million to be borne by company shareholders, not ratepayers. The company’s fourth-quarter results included a charge of 14 cents per share to cover the settlement.
The full terms of the settlement will be released if it is approved by the court.
Good said the investigation was a catalyst to strengthen Duke’s ash management practices and to speed up its ash basin closures.
She also said the company expects to spend $1.3 billion to excavate and close five sites: Asheville, Dan River, Riverbend and Sutton in North Carolina, and W.S. Lee in South Carolina.
The Duke incident led North Carolina legislators to impose stricter rules on how coal ash storage sites can be operated.
In December, the Environmental Protection Agency issued the first-ever federal regulations governing the storage and use of coal ash, a byproduct of burning coal. There are an estimated 1,000 coal ash storage sites in the U.S., primarily under the control of electric generating companies. The industry produces about 140 million tons of coal ash per year.
Earnings Down
On Wednesday, the Charlotte, N.C.-based company reported fourth-quarter earnings of $97 million ($0.14/ share), compared with $688 million ($0.97/share) a year earlier. Year-end earnings were $1.88 billion ($2.66/share), down from $2.67 billion ($3.76/share) in 2013.
Duke said the results for its regulated utility business were affected by higher operation and maintenance costs due to a change in the accounting treatment of nuclear plant outages in the Carolinas. Meanwhile, its nonregulated businesses were impacted by Duke Energy International’s lower earnings, which resulted from a widespread drought in Brazil.
International Operations to Remain
Duke said Wednesday that it has decided to retain the international affiliate, which it had said last year it was considering selling.
The company said it plans to repatriate $2.7 billion in DEI earnings to the U.S. through 2022 through a taxable dividend.
DEI owns, operates or has substantial interests in approximately 4,900 MW of electric generation outside the U.S., primarily in Latin America.
Fourth-quarter earnings of Northern Indiana Public Service Co. parent NiSource rose to $154.2 million ($0.49/share), up nearly 2% from $151.8 million ($0.48/share) a year ago. Fourth-quarter revenues rose 8% to $1.129 billion.
For all of 2014, net income was $530 million, down from $532 million in 2013 despite a 10% jump in revenues to $4.23 billion.
Highlights for the year included a record $2.2 billion capital investment program.
Pipeline Spinoff
Earlier this month NiSource completed the initial public offering of Columbia Pipeline Partners, the spinoff of its natural gas pipeline business.
NiSource remains on-track to complete the Columbia transition in mid-2015, said president and CEO Robert Skaggs Jr.
Columbia will issue its own long-term debt prior to the separation to fund a one-time cash distribution to NiSource, reducing the latter’s debt. NiSource shareholders will receive a one-time cash distribution in the form of a pro-rata dividend of shares in Columbia stock.
Because of the pending separation, NiSource did not provide full-year earnings guidance.
Electric Revenues Up 2%
NiSource’s electricity segment during the fourth quarter generated revenues of $392 million, compared with $386 million during the fourth quarter of 2013.
For the full year, electricity revenues were $1.68 billion, up from $1.56 billion in 2013. Increased environmental cost recovery and two transmission projects authorized by MISO boosted revenue by $5.1 million.
NIPSCO recently filed with the Indiana Utility Regulatory Commission an electric and natural gas capital expansion plan totaling $2 billion over seven years. Among the major projects in the plan is the 70-mile, 765-kV Greentown-Reynolds transmission line, to be completed by 2018.
Consolidated Edison reported lower fourth-quarter earnings for 2014, but its $0.58/share showing for ongoing operations beat analysts’ consensus by 2 cents.
The company said warm weather pinched its steam-delivery revenues service while operations and maintenance expenses were higher.
The New York City-based utility said earnings for the quarter were $81 million ($0.28/share) versus $234 million ($0.80/share) a year earlier. Earnings from ongoing operations — which exclude mark-to-market accounting for its competitive energy businesses among other items — were $171 million ($0.58/share), compared with $202 million ($0.69/share) for the final three months of 2013.
For all of 2014, earnings were $1.09 billion ($3.73/share) compared with $1.06 billion ($3.62/share) in 2013.
Ongoing operations for the year were $1.14 billion ($3.89/share) compared with $1.11 billion ($3.80/share) in 2013.
“We are preparing our energy grid to adopt many new technologies and new ways of delivering power, including more customer-sited generation resources,” CEO John McAvoy said in a statement accompanying the earnings. “This effort reinforces our commitment to the environment with our business operations, promoting renewable resources, oil-to-gas conversions and new energy efficiency solutions for homes and businesses.”
PJM set a new winter record for electricity use Friday, with demand hitting about 143,800 MW at 8 a.m., according to preliminary data.
Real-time prices peaked at 7 a.m., with prices hitting $564/MWh in the Dominion zone and almost $419/MWh RTO-wide.
The record came as at least two dozen cities in the RTO broke low temperature records, including D.C., Wilmington, Del., Detroit, Cleveland, Cincinnati and Pittsburgh.
PJM had forecast a morning peak of 144,330 MW at 7 a.m. with available economic capacity of 160,958 MW.
(Click to Zoom)
The RTO noted that although it was able to meet the load about 12,000 MW of generation will retire this year “making high performance essential from the rest of the generation fleet.”
The previous peak was 141,846 MW on Jan. 7, 2014, (142,573 MW with demand response contributions added back in), when forced outages reached as high as 21%.
PJM CEO Terry Boston (Source: PJM Interconnection LLC)
By Suzanne Herel
PJM President and CEO Terry Boston announced Wednesday that he plans to retire effective Dec. 31 after seven years at the helm of the RTO.
“Thanks to the outstanding talent of PJM employees, I leave knowing that PJM today is a true leader in the industry — the gold standard for reliable electric service, fair and efficient markets and infrastructure planning,” Boston, who joined PJM in February 2008, said in a letter to the board.
“I am especially proud that the PJM team has successfully managed three ‘one-in-a-hundred-years’ weather events within the past four years,” said Boston, 64, who plans to use this year consolidating improvements PJM has made and serving as chairman of the ISO/RTO Council.
Board of Managers Chairman Howard Schneider, speaking for the board, praised the 43-year electric utility industry veteran for his “strong leadership and extraordinary vision.”
“Terry’s outstanding leadership has been important not only to PJM and the customers it serves but to the development of the grid and markets across the country,” Federal Energy Regulatory Commission Chairman Cheryl LaFleur said in a statement.
The announcement has been in the works for some time. PJM said in a press release that a “rigorous succession process by the PJM board has been underway.”
“Candidates to succeed Boston will be considered based on demonstrated leadership abilities, industry expertise and reputation, as well as commitment to electric system reliability and fair, efficient electricity markets,” PJM said.
Boston came to PJM after serving as executive vice president for the Tennessee Valley Authority.
PJM rejected most of the criticism of its Capacity Performance proposal in comments filed late Friday, but dropped its proposed change in the method for determining the capacity obligations of load-serving entities.
“Based on the comments received … PJM proposes instead to discuss that issue further with stakeholders and report back to the commission in one year on the results of those discussions,” PJM wrote in a filing with the Federal Energy Regulatory Commission (EL15-29). PJM noted that the allocation of LSEs’ capacity obligations does not need to be resolved before the May 2015 RPM Base Residual Auction.
PJM also conceded merit to an assertion by the PJM Utilities Coalition (American Electric Power, Dayton Power and Light Co. , FirstEnergy and East Kentucky Power Cooperative) that there is a problem with a “one-year price” for a multi-year investment in generation.
“PJM did not propose any Tariff changes in the Dec. 12 filing on this issue and does not propose any now. However, given the additional costs of serving as a Capacity Performance resource, the possibility for new environmental rules to require even more investment in existing generation facilities and the commission’s recent approval of an expansion for the new entry pricing available in ISO-New England, the time may be ripe to revisit this issue,” it said.
PJM asked FERC to respond to the coalition’s concerns by directing PJM to explore with stakeholders the subject of new entry pricing and multi-year pricing. PJM would report back to FERC on the issue no later than December.
More than 60 entities filed comments and protests in response to PJM’s proposal, which would increase the reliability expectations of capacity resources with a “no excuses” policy. It is expected to result in both larger capacity payments and higher penalties for non-performance. (See States, LSEs Skeptical, Utilities Split Over Capacity Performance.)
In their comments and protests, states and LSEs were skeptical about the need for a major overhaul, while generators were split over elements they liked and others they said must be changed.
PJM defended its changes to force majeure provisions, which some generators described as unduly punitive.
“Strong performance incentives are a vital part of the solution to poor resource performance,” it said.
“The governing principle of this new approach is very simple and very conducive to innovation and efficiency: resources that exceed expectations will receive higher compensation; those that fall short of expectations will relinquish revenue and face a threat of net payments.”
PJM noted that FERC received equally strong arguments that the proposed charge levels are too high and too low.
“As shown in the Dec. 12 filing, this part of PJM’s proposal closely tracks the structure, and much of the details, of the approach recently approved for ISO-New England,” it said.
PJM also responded to a number of public interest groups who said that renewable, energy efficiency and demand response resources would be disadvantaged in the new structure, saying “the actual suppliers of renewable and energy storage resources recognize that PJM’s proposal to permit intermittent storage, demand response and energy efficiency resources (‘Intermittent/Storage/DR/EE’) to combine their capabilities offers a workable pathway for these resources to qualify as Capacity Performance resources. Parties also recognize that the ability of these resources to receive revenues for superior performance provides a new revenue stream that does not exist under today’s capacity construct.”
As for those who objected to the proposal as a reaction only to last year’s polar vortex, PJM pointed to “deficiencies and disincentives” in the current Tariff relating to resource performance, including a “very weak” non-performance charge.
“The polar vortex provided a dramatic demonstration of these adverse effects. But the shortcomings in the current resource performance rules would still be there, and would still require correction, even if there had been no polar vortex,” it said.
PJM requested that FERC approve the changes by April 1.
Generators would be permitted to sell frequency response services at market-based rates under a rule proposed by the Federal Energy Regulatory Commission last week.
