ML17058B771
| ML17058B771 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 12/31/1992 |
| From: | Carrigg J NEW YORK STATE ELECTRIC & GAS CORP. |
| To: | |
| Shared Package | |
| ML17058B768 | List: |
| References | |
| NUDOCS 9305240307 | |
| Download: ML17058B771 (104) | |
Text
New York$tate Electric 6 Gas Corporation 1992 Annual Report Meeting the Competition... Together 9305240307 930520 PDR ADQCK 05000220 I
ABOUT THE COVER More than ever before, employees with diverse backgrounds and skills from throughout the NYSEG organization are working together.
They are guided by the objcwives of our five-year strategic plan:
zt to improve customer value ta to Incitme energy-eAicient sales and develop new markets a to enhance relations with regulators and elected oAicials a to enhance employees'ontributions to meeting the challenges of competition BUTCH BOUCHER GAS FITTER 1ST CLASS Butch and his coworkers fillmany impoiunt roles. As natural gas leak investigators, they are irreplaceable members of the NYSEG safety team. As high bill investigators, they perform an important customer service function.
They also set ncw meters, the final step in bringing natural gas to our new customers.
DEBBIE FENDICK MARKETINGADMINISTRATOR Employees in our field organization close natural gas sales, but their efforts arc supported by a corporate organiza-tion. Debbie is a member of the corporate team that monitors marketing programs, coordinates advertising and promotion, and analyzes information.
In 1992, the natural gas marketing group shattered their perfomunce goal.
SYBIL EDWARDS METER READER - COLLECTOR In this time of swccping change, one thing hasn't changed: meters still have to be read so that customers can be billed for thc energy they have used.
Sybil and morc than 120 of hcr colleagues across the state do their job wellmore than 95 percent of the bills we send out are based on actual meter readings and not estimates.
KEN BRONSON PLANT MAINTENANCEPLANNER Proper planning and execution of maintenance procedures at our generating stations are critical to reliable electric service. They are also important elements in electric generat-ing cAicicncy, which helps hold down production costs. The efliciency of our electric generating system stood at third in the country in 1991, the most recent year for which rankings arc complete, thanks in part to the efforts of Ken and ills colleagues.
MARK SEYMOUR LINE MECHANIC 1ST CLASS Imagine this: someone who's almost invisible except when the lights go out.
Tlut descnbn I lark and his coworkers.
Although they construct electric lines and do complex nuintenance work on energized lines, their efforts are most apparent during an electric outage.
Fortunately, outages don't occur very often-our service reliability exceeds 99.96 percent.
SANDY JOHNSON MANAGER-WORK FORCE DIVERSITY The human resources function is the oil that keeps an organization running smoothly and Sandy is an imporunt member of the human resources team at NYSEG. She plans and implements aIBrmativc action programs, ensures compliance with those programs and continually cvaluates them.
FRANK SCOLLAN TEAM LEADER-PROMOTIONAL DEVELOPMENT Frank is a member of the Electric Business Unit marketing team that has been focusing on demand-side management (DSM), a series of programs to help our customers usc electricity eIBciently. In 1992, these programs reduced our customers'lectricity use by morc than 139 million kilowatt Itours while we earned more than $ 15 million in DSM incentives.
CONTENTS Company Profile........
Financial Highlights...
Letter to Stockholders 1
2 Year in Review Meeting the Competition Hoard of Directors...........
.7 16 Printed entirely on recycled paper.
8 Printed with soy ink.
Officers 17 Financial Section Contents...........17
COMPANY PROFILE New York State Electric K Gas Corporation (NYSEG) is an investor-owned utilitythat traces its roots to the Ithaca Gas Light Company which began operations in 1852. Today our 4,888 employees serve 784,000 electric customers and 224,000 natural gas customers in suburban and rural upstate New York. High-tech firms, light industry, agriculture, colleges and universities, and recreational facilities support the area's economy.
We are composed offour business units:
a Electric (operations and marketing) a Gas (operations and marketing) a Management Services (support services) a Strategic Management (planning, research and development, and economic, organizational and corporate development)
Our total operating revenues in 1992 were approximtely $1.7 billionand total assets were approximately $5.2 billion, making us the second largest utilityin upstate New York.
We generated almost 18 billion kilowatt-hours of electricity in 1992 at seven coal-fired generating stations, several small hydroelectric generating stations and one nuclear generating station. We also delivered more than 56 million dekatherms of natural gas purchased from pipeline companies, marketers and producers.
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FINANCIAL HIGHLIGHTS 1992 1991
% CHANGE AT DECEMBER 31 Total Assets (000)
Capitalization (000)
Capital Structure (includes current maturities):
Long-term Debt Preferred Stock Common Equity
$5,176,428
$3,630,901 50.5%
7.2%
42.3%
$4,924,836
$3,463,112 52.2%
7.7%
40.1%
(3)
(6) 5 OPERATING RESULTS (000)
Total Opemting Revenues Operating Expenses Net Income Earnings for Common Stock Retail Megawatt-hour Sales Dekatherms of Natural Gas Delivered
$1,691,689
$1,367,926
$183,968
$162,973 13,294 56,366
$1,555,815
$1,234,720
$168,643
$148,313 13,107 42,404 9
11 9
10 1
33 PER COMMON SHARE Earnings Dividends Book Value (year end)
Market Value (year end)
$2.40
$2.14
$22.85
$32.50
$2.36
$2.10
$22.16
$29.00 2
2 3
12 OTHER INFORMATION Common Stock Price Range Return on Average Equity Market-to-Book Ratio Average Common Shares Outstanding (000)
Common Shareholders (year end)
$26 1/8 - 32 3/4 10.6%
142%
67,972 61,183
$24 - 29 5/8 10.7%
131%
62,906 59,593 (I) 8 DMDENDS DOLIARSPER SHARE EARNINGS DOllARS PER SHARE 321'.00 202 206 210 2.14 2.70 >>
2.43'36 2.%
1987 1988 1989 1990 1991 1992 1987 1988 1989 1990 1991 1992
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LETTER TO STOCKHOLDERS NFSEG has positioned itselfto tabePlladvantage oftbe opportunities beingpresented to us and ue have every confidence we willbe oneofthe winners.
To my fellow stockholders:
It is with a great sense of responsi-bilityand pride that I write to you.
In past years I have started this letter with a discussion of earnings.
This year I am going to break that tradition because I want to discuss three critiml issues: change, competition and challenges.
Perhaps the single most important piece of information tltat you, as an owner of NYSEG, need to know is the undeniable fact tliat the utility industry is in the midst of unprec-edented change. Gone forever are the days of a stable and predictable business climate. Utilitycompanies have to learn how to compete if they are going to succeed. Many changes are musing this new, highly competitive environment.
They include the potential for open access to our electric tmnsmission lines, the reality of non-utility generation and the Federal Energy Regulatory Commission's Order 656 which is designed to create more competition in the natural gas business. These and other emerging issues are challenging what used to be the protected domain of regu-lated energy utilities.
enormous opportunities for the companies that have the vision, skill and resources to take advan-tage of them. NYSEG willbe one of those companies.
Let me emphasize that in the mpidly changing and competitive environment we are dealing with every day, there willbe winners and losers. NYSEG has positioned itself to take full advantage of the opportunities being presented to us and we have every confidence we willbe one of the winners. But, making this happen willrequire more than just hope and good intentions. It willrequire implemen-tation ofour comprehensive strategic plan, an ability to immedi-ately respond to an ever-changing business environment and a results-oriented work force.
NYSEG had the foresight to recog-nize, early on, the enormity of the changes the industry is now experiencing. More than three years ago, we began implementing Vision 2000, the details of which I have shared with you in past communications. I am happy to report the actions we have taken are beginning to pay dividends, both tangible and intangible.
It is this infusion of competition that is the driving force behind the signifimnt challenges we face. It is this same infusion that willcreate At the core ofour strategy is a shift in our organizational structure and corporate culture. Changing to a business unit structure has
LETTER TO STOCKHOLDERS accelerated decision making, improved our ability to control costs and enabled us to become more focused. Our change in corporate culturethe way we think and work, and the environment in which we work is guided at each juncture by our shared values:
excellence, innovation, integrity, teamwork, caring and accountabil-ity. Each and every employee must focus on these values in order for us to build a firm foundation for NYSEG's future. We are already seeing results.
It's no accident that earnings have increased to $240 per share, up 4 cents from 1991. It is a direct result of the NYSEG team working together to improve shareholder return.
Three other pieces of financial information are also important to note:
im Fitch Investors Service, Inc.
upgraded its ratings of our first mortgage bonds and preferred stock and Moody's Investors Service upgraded its ratings of our first mortgage bonds and unsecured pollution control bonds. These ratings are now the highest they have been in 12 years.
a In 1992, we refinanced
$250 millionof first mortgage bonds. This willsave our customers more than $3 million a year. We have refinanced more than
$1 billion in debt since the end of 1987 and our embedded cost of debt has decreased from 9.8 percent to 7.7 percent.
il Our common equity ratio rose from 33 percent at the end of 1987 to the present level of 43 percent.
Over the same period, our long-term debt ratio decreased from 62 percent to 49 percent.
Meanwhile, our natural gas business continues to grow. In 1992, it contributed 8 cents a share to earnings, a signilicant improvement from 1991's loss of 2 cents a share.
We fullyexpect further gains in 1993 because of our emphasis on selling this abundant, clean-burning fuel and developing new markets.
The Gas Business Unit has also made us an industry leader in promoting natural gas vehicles.
We have also made significant gains in sparing our customers the financial burden of unneeded and uneconomical electricity from non-utilitygenerators (NUGs). We are required by federal law to enter into contracts with NUGs to buy electric-ity that our customers do not need.
We were required by state law to pay 6 cents a kilowatt-hour (kwh) for power from qualifying facilities, far higher than our own production cost. Fortunately, at the tenacious urging of NYSEG and other utilities in New York State, the Went law was repealed by the Legislature in June 1992 and signed into law by the Governor in August '1992.
Unfortunately, contracts signed while the Went requirement was in effect are still valid. We had signed contracts for more than 900 mega-watts (mw) of electricity by the time the law was repealed.
Had we done nothing,'these contracts would have cost our customers more than 83 billion for unneeded and over-priced electric-ity. However, we have taken a leadership role among electric utilities in fighting for our customers on three fronts:
a NUG contract requirements are strictly enforced. So far, cancella-tions have saved our customers
$240 millionand eliminated 113 mw of planned generation.
il We chose to award no contracts under a mandated bidding program for 100 mw of generation. That saved our customers approximately S80 million.
a We have aggressively negotiated the termination of two other contracts with NUG developers totaling 134 mw. We paid more than $45 millionfor these contract terminations which willsave our customers
$650 million.
Let me emphasize that our biggest concern with NUGs rested with the 6-cent law here in New York State.
We believe that, ifoperated in a true market environment, the NUG industry can increase competition to the benefit of iatepayers.
,5 LETTER TO STOCKHOLDERS At this time, we are actively en-gaged in discussions regarding a multi-year rate settlement agree-ment with the staff of the Public Service Commission and other interested parties. By working cooperatively with regulators we can eliminate much of the conten-
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tion sometimes associated with the more traditional appmach to ratemaking. At the same time, by encouraging broad involvement, win-win solutions can be devel-oped. This regulatory philosophy is absolutely essential in order to address the long-term economic challenges we face.
me tell you that the cltanges we are implementing willreduce our cost of doing business, 'make us more responsive to the marketplace and,-
build on our commitment to teamwork. In 1993, we willcontinue to reinforce the corporate culture change now underway to assure that our employees are well pre-pared to meet competition head on.
In closing, I would like to share a personal experience with you. Quite often I have the opportunity to talk with NYSEG employees from across the state, whether at an employee meeting, a Speakers Club dinner or just in the hall at the office. On those occasions, I am reminded that our employe& are the reason for our success during this time of change.
They'are the people who time and again have risen to challenges and they are truly our greatest asset.
They haven't run from competition, they have welcomed it.
For the Board of Directors,
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James A. Carrigg Chairman, President and Chief Executive Officer February 19, 1993 We also continue to believe that diversification, whether in the regulated or nonregulated arena, willplay an important role in NYSEG's future. While the strength of our core electric and natuml gas businesses remains our focus, we are actively evaluating a number of corporate development opportuni-ties for investment. Let me assure you that we willdo nothing to compromise our financial integrity.
4 Our Work Simplification program, a continuous improvement process, is well underway and has resulted in substantial changes in the way we do business. Twenty business processes were comprehensively reviewed in 1992. More information about Work Simplification is provided later in this report, but let
YEAR IN REVIEW FEBRUARY The Broome-Tioga Association for Retarded Citizens joined with us to start sorting and recycling surplus and scrap materials at our Investment Recovery Center.
MARCH We sold five million shares of common stock at $27.25 per share, a 20 percent premium to book value. Proceeds were used to repay commercial paper which was issued to pay for construction.
APRIL We received approval from the Public Service Commission (PSC) to invest in nonregulated subsidiaries in the areas of environmental services and energy-reLated businesses.
Our employee Speakers Club won the Edison Electric Institute's first DillonAward for excellence in the development and presentation of speakers bureau programs.
INVESTMENT RECOVERY CENTER JUNE We reached agreement with Indeck Energy Services of Kirkwood, Inc. to terminate the purchase power agreement for the planned 55-megawatt (mw) Indeck-Kirkwood cogenention project.
This power was unneeded and uneconomical.
JULY The PSC approved a 5 percent increase in electric rates and 4.1 percent increase in natunl gas rates effective August 1.
Our high phase order transmission line, the first of its kind in the world, was energized.
This power line, a research and develop-ment project, carries up to 73 percent more power in the same space as a tmditional tnnsmission line.
AUGUST Texas businessman Boone Pickens, OCTOBER Jennison Station became the first chairman of the Natural genemting facility in DECEMBER We sold $ 100 millionof 30-year first mortgage bonds at a coupon rate Gas Vehicle (NGV)
Coalition, was the featured speaker at our second annual Northeast NGV Conference in Binghamton. More than 400 people attended.
New York State to regularly burn tire chips to produce electricity.
of 8.30 percent. Net proceeds were used in connection with the redemption of first mortgage bonds. This refinancing willsave our customers We received permits from the New York State Department of Environmental Conser-vation for construction of an innovative pollution control system at Milliken Genemting Station.
We joined a national research effort to investigate the use of cordless electric lawn mowers to reduce urban pollution.
HIGH PHASE ORDER TRANSMISSION LINE approximately
$ 1 million a year in interest costs.
BOONE PICKENS Project SIIARE, our emergency heating fund administered by the American Red 10-year first mortgage bonds at a coupon rate of 6.75 percent. Net proceeds were used in connection with the redemption of three series of first mortgage bonds. This refinancing willsave our customers approximately
$2 million a year in interest costs.
NOVEMBER We filed requests for a 5.5 percent increase in electric rates and a 3.6 percent increase in natural gas rates to be effective in August 1993.
10th anniversary. More than $2 million has been contributed to the fund by our customers, employees, retirees and stockholders. More than 10,000 grants have been provided to needy families to help pay their utilitybills.
We reached agreement with Kamine/Besicorp Coming L.P. to terminate the purchase power agreement for the planned 79-mw South Coming cogen-eration project. This power was unneeded and uneconomical.
We sold $ 150 millionof Cross celebrated its
MEETING THE COMPETITION Change is not new to the energy industry.
Fundamental change is.
Now, for the first time since the first of NYSEG's predecessor companies began operating in Ithaca 140 years ago, we are faced with a new business environment. Public policy has changed, regulation has cl>anged and competition is a reality.
Large customers are no longer forced to buy energy from us just because they happen to be located in our service area. They can generate their own electricity or purchase their own supply of natural gas directly from the source.
Fundamental change and competition mean that we must change our ways. Only those companies that are able to adapt and meet the challenges posed by competition willprosper in the 1990s. We have adopted a new spirit and are recommitted to working together for the good of NYSEG, challenging the status quo and taking calculated risks.
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i Most importantly we willconcentrate on the strategies outlined in our five-year strategic plan. It willguide us to our goal: to be among the best utilities in the country.
The following pages highlight specific examples of some of our results to-date.
BUILDING CUSTOMER VALUE O ur customers deserve reasonable rates.
With that in mind, our goal is to maintain electric and natural gas price increases within the rate of inflation. To succeed, we must control costs.
results are from 1991 and they speak to our success. Our generat-ing system ranked first in New York State, for the eighth year in a row, and third in the country.
Kintigh Station, which provides 691 megawatts (mw) of electricity to our customers, ranked fifthin the country among individual generating units.
ALTERNATIVEFUELS:
A SUCCESS STORY Jennison and Hickling genenting stations were implemented new budgeting proce-dures. We have also set ambitious targets for capital budget-ing and investments and are continuing to pay particular attention to profit-ability and total return to stockhold-ers. However, as im-portant as control-ling direct costs is, innovation and eAiciency can also have a considenble impact on our finan-cial picture. Here are some examples.
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built in the 1940s and a second genenting unit was added to each in the 1950s. Genenting station technology has advanced markedly since then, yet their unique traveling gute design has given them new life. These tnveling gntes enable us to bum alternative fuels.
In October, Jennison Station became the first generating station in New York State to regularly bum tire chips mixed with coal. Its four boilers can consume up Wc have already saved our customers almost $1 billionby terminating pur-chase power agreements with NUG developers.
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CALLCENTER: A PLUS FOR CUSTOMER SERVICE At our new customer call center in Binghamton, we are centnlizing the telephone and account mainte-nance functions from 42 oAices scattered across our 19,000 square mile service area. This willsave customers money, but the benefits go beyond savings.
Once the call center is in full operation in November 1993, it will offer customers expanded hours. Its telephone system and computers, manned by well-tnined customer representatives, willallow us to meet our customers'hanging needs and growing expectations.
Customers willstill be able to meet with our customer representatives face-to-face at loni oAices when necessary.
GENERATING EFFICIENCY: THIRD IN THE COUNTRY In 1992, we spent more than
$262 millionfor fuel, primarily coal, to genente electricity. Ifwe are going to keep costs to a minimum, it is essential that we squeeze every kilowatt-hour out of every pound of coal.
Each year Electric Lightand Power magazine nnks the operating performance of the top 100 utilities in the country. The most recent to 4.5 million tiresor 45,000 tons of tire chips each year. Tlus saves Landfillspace and saves money for our customers because it has the potential to reduce the amount of coal we purchase by up to 65,000 tons each year.
In December, Hickling Generating Station began testing a fuel mixture of coal and coal tar soil from an inactive manufactured gas plant (MGP) site. Ifthe New York State Department of Environmental Conservation approves continua-tion of the project, it may be an NATURALGAS ENERGY MANAGEMENT:
TRACKINGSUPPLY AND DEMAND We have just installed an advanced energy management system for our natunl gas business. It provides control of natural gas flow from tnns-mission lines into our
e system and up-to-the second data on customer use around the state.
The system willhelp us better manage natural gas supply plan-ning and the purchase of natural gas. The Federal Energy Regulatory Commission's Order 636, which is designed to create more competi-tion in the natural gas business, shifts responsibility for these matters to local distribution compa-nies such as NYSEG. The energy management system willensure that we get the least expensive natural gas possible to our distribution system.
PROTECTING THE ENVIRONMENT:
AN INNOVATIVEAPPROACH Construction is about to begin on an innovative system to remove sulfur dioxide from flue gas at
. illiken Generating Station.
Itwillhelp us comply with the requirements of the Clean AirAct Amendments of 1990 and also demonstrate how we can continue to use the country's abundant supply of coal in an environmen-tally responsible manner. The project is unique in that itwilluse a German technology not currently in use in the U.S. The U.S. Depart-ment of Energy, through its Clean Coal Technology Program, and several industry research alliances willfund a portion of the
$159 million project.
Mostpeople see used tires as a disposal problem
%e see them as an opportunity. In J992 Jennison Station became thefirstgenerating facilityin the state to be licensed to regularly burn tire chips mixed with coal Some.membets ofthe tires to-energy team are: (seated, from leg) Ed Greenman, Mike Tesla and Fred Cannistra; (standing, from left)IUa Cunningham, PhilMurphy and TerryBarnard.
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10 SEARCHING OUT OPPORTUNITIES TO GROW rowth is important to our future.
It often comes with little effort during good economic times.
However, the sluggish New York State economy and the success of our demand-side management (DSM) programs have kept growth to a minimum in recent years. In 1992, retail electric sales increased just 1 percent. Retail natural gas sales increased 32 percent largely because of the acquisition of Columbia Gas of New York in April 1991.
We are responding to the chal-lyte of limited growth in several ways. First and foremost, we have reorganized our electric and natural gas marketing groups to quickly and effectively respond to tl>e.-Jteeds of our customers, as well as to concentrate on energy-efficient sales. Here are some additional examples.
NATURALGAS:
ACTIVITIESON MANYFRONTS With the Clinton Administration's new emphasis on natural gas, we are more excited than ever about the potential for our natural gas business. We are continuing to promote conversion to natural gas, extend natural gas distribu-tion lines and evaluate
11 opportunities to obtain new natural gas service franchises. We also know that these efforts alone will not allow us to realize the potential that exists for natural gas in New York State. So, we are also pursu-ing several supply and storage opportunities that would enhance our ability to deliver a reliable supply of the least expensive natural gas possible.
ELECTRICITY:BLENDING CONSERVATION AND SALES In 1992, our electric inarketing team focused on DSM programs.
While helping customers use electricity efFiciently willremain important in 1993, we willalso be actively selling electricity where it makes economic sense for custom-ers and is environmentally respon-sible. We willbe promoting efFicient technologies such as infrared drying for manufacturing processes, ground source heat pumps and security lighting.
NATURALGAS VEHICLES:
A PROMISING MARKET Our natural gas vehicle (NGV) progmm continues to gain inomentum. In August, we held the second annual Northeast NGV Conference in Hinghamton and in November, we installed a natural gas fueling station in Binghamton for sevenl NYSEG vehicles and three natural gas-fueled transit buses.
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A FRESH LOOK We received permission from the Public Service Commission in April to invest in nonregulated subsidiar-ies in the areas of environmental services and energy-related businesses.
However, after care-fullyre-evaluating the promising opportunities we had identified, we determined that any investment in those opportunities at this time would be unwise. We have now refocused our efforts on maintain-ing the financial strength of our core electric and natural gas businesses.
We continue to believe that diversification willplay an important role in our long-term success. We are actively evaluating a number of corporate development opportunites for investment.
ECONOMIC DEVELOPMENT:
HELPING SHORE UP A SLUGGISH ECONOMY Given New York State's economic climate, creating jobs is no easy task. Despite these challenging times, our economic development professionals continue to work with businesses interested in locating facilities in our service area. They are also concentrating on helping existing industrial customers expand. In 1992, their efforts resulted in the expansion or retention of 17 busi-nesses. 'Il>ey are currently working closely with 12 Canadian businesses tll'itwillbe making location decisions in 1993. The new year lliis 'ilso brought with it a renewed emphasis on working with state and local governinents to strengthen the state's econoiny.
Gathering accurate data and analyzing that data in a timely manneris at the heart ofidentifyinggrowth opportunities Representati.ves ofallfourof our business units are working together on thispr ocess on an on-going basis Some ofthe.team membets tvho have been involvedin searching out opportunities are: (clockun se, from left/'Sue Ward, Bob Rude, Rex Berntsson, Bob Irvin,Joe Vaj da, Donna Vandenberg and Tom Ryan.
12 ENHANCING RELATIONSHIPS 0
e are giving new emphasis to working together with regulators and elected ofFicials toward positions that are beneficial to our stockholders and customers.
We worked with elected officials to help shape the Clean AirAct Amendments of 1990 rather than fight against passage, and we continue to be involved in related rulemaking. At the state level, we supported the repeal of New York State's law that required us to buy electricity from qualifying NUGs for 6 cents a kilowatt-hour. The result of the repeal of this law in 1992 willsave New York State ratepayers billions of dollars. We are proud of results such as these, but there is still plenty to do.
A MULTI-YEARRATE SETTLEMENT:
DISCUSSIONS CONTINUE Since July, we have been working with the PSC staff and other interested parties toward a multi-year rate settlement agreement.
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We believe a rate settlement agreement would allow our customers to better plan their energy budgets, while sparing them the expense of frequent rate proceedings. It would help us by freeing up resources that are used during rate proceedings, allowing for better planning and allowing employees to concentrate on other critical issues such as competition.
economy which willbe to everyone's benefit. Both our electric and natural gas marketing groups now include personnel whose job it is to maintain contact with large customers and ensure that we are providing them with any services at our disposal that willhelp them be more competitive. As an off-shoot of these "key account" partnerships,
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we want to promote a common direction for economic growth in our service area.
RATES:
NOT THE SAME OLD APPROACH We know that large customers need to hold down costs to remain competitive. So, we asked the PSC for permission to negotiate electric rates with large industrial customers who meet specific requirements. InJanuary 1993, that request was approved. An interruptible service rate that will make natural gas more attractive to public authority customers, such as
'tate and federal government facilities, was also approved by the PSC inJanuary 1993.
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KEY ACCOUNTS:
BUILDINGA NEW RELATIONSHIP Our major customers will figure prominently in the actions we willhave to take to align our objectives with public policy. By building a stronger relationship with these customers, we can play an active role in strengthening the state' REGULATORY RELATIONS:
DEFINING GOALS In 1993, we willfurther formalize our regulatory relations process by defining goals and assigning specific roles and responsibilities.
We willalso use our government relations program to promote streamlining of the regulatory process and further development of incentive regulation.
Whether we are helping customers conserve electricity, selling electricity where itmakes economic sense fora customer orselling natural gas, our talented marketing representatives are on thefront line In.1992, the electric and natural gas teams each shattered their marketing goals Repr.esentatives ofthe NYSEG marketing team are: (seated, from le+3 Charlie Collins, Cathy Smith and Patricia Edwards; (standing, from left) Gary Strong, Angela Sparks and Ralph Chester.
14 MEETING COMPETITION HEAD ON O
O ur employees have the talent and skills to make NYSEG success-ful in these changing times.
Every day, our employees are dealing with the dramatic changes in the energy industry. They ltave responded very well and they now recognize tltat this is not the same old business that it has always been. They know that we must respond to a competitive environ-ment by working together, looking for new opportunities and taking more risks. Several efforts are already in place that willhelp us achieve our organizational capability challenge.
WORK SIMPLIFICATION:
REAPING BENEFITS IVork Simplification was just introduced in 1992, but its impact has been dramatic. Simply stated, this process involves carefully examining how we perform specific tasks and developing recomrnenda-tions for working more efficiently and cost-eAectively.
Twelve employee teams completed a first round of work in 1992.
Processes examined included business planning and budgeting, electric and natural gas sales management, vehicle management and employee development.
Results included implementation of our new business planning and budgeting procedures, reorganiza-tion of our marketing departments, a reduction in the number of our vehicles and streamlining our advancement opportunity program.
Eight new teams then examined processes such as requesting new electric or natural gas service and determining vehicle needs for our natural gas business.
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15 earnings goals willdetermine the size of the incentive awards.
a Our suggestion program, I', which encourages employees to submit well thought out solutions to problems. It has the potential to save money and streamline the way we operate.
a Continuation of Energy Into Action, a leadership and team building program for employees.
Brotherhood of Electrical Workers (IBE%9 convened to study the handling of grievances from IBEW employees. They reached agree-ment on an equitable way to handle future grievances and how to address a backlog of grievances awaiting arbitration.
One particularly noteworthy eflort has already come from the second round ofwork simplification. A work group composed of repre-sentatives of management and System Council U-7 International COMMUNICATIONS:
KEEPING EMPLOYEES INFORMED Our third point of emphasis is continued evaluation and enltance-ment of internal communications.
We must do our best to keep employees informed of what we are doing and why. Informed employees have the tools to be more productive and can make better decisions for the Company.
Bythe end of November, our neu call center in Binghamton willbe responsible for handling customer callsfor our entire service area. The call center willoper expanded customer service hours and will save money. Members ofthe call center team who are already on board include:
(seated, from lefty Nancy Hunt, Jim Hogan, Jean Mitchell and Sue Libous-Heenan; (standing, rom lefty Craig Hall, Hope Robinson, Rick Cerchiara and Helen Black.
WORK PLANNING:
INTEGRATING EFFORTS Proper planning of work by employees is vital to enhancing our competitive position.
In past years, each salaried employee, together with his or her supervisor, prepared annual work plans based on what they under-stood as being important to the Company's success. That process lias now changed. Business plans for each of our four business units now flow directly from the stmtegic plan, departmental plans are linked to the business unit plans and individual plans are linked to the departmental plans.
Now every employee's efforts will directly contribute to achieving the objectives ofour strategic plan.
Other efforts designed to rnakei:(is'ore competitive by making employees more accountable for results include:
C The strategic plan and our efforts thus far are only the beginning.
While we willcontinue to focus on meeting the needs and expectations ofour stockholders, customers and employees, the key stmtegies of the strategic plan willcliange as the environment in which we operate changes. In turn, each employee's energy inust be directed to reflect those changes.
One thing is clear: as our employees continue to implement our stnitegic plan and use our business planning process, our stockholders and customers will reap the benefits.
a Performance Up, an incentive award program for salaried employ-ees. Our actual performance measured against customer service and EVgjjgp 8<g ]
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16 BOARD OF DIRECTORS First year etected In tuttttthescs Wells P. Allen,Jr. (1974)
Former Chairman and Chief Exc~tive OAiccrof the Corporation Binghamton, NY James A. Carrlgg (1983)
Chairman, President and Chief Executive Officer of thc Corporation Binghamton, NY Allson P. Casarctt (1979)
Dean of thc Graduate School Cornell Vnivcrsity Ithaca, NY Everett A. Gllmour (1980)
Former Chairman of the Board and Chief Executive OAiccr The National Bank and Trust Company of Norwich Norwich, NY Paul I Giola (1991)
Senior Vice Prcsidcnt First Albany Corporation (Brokerage and Investmcnt Banking Firm)
Albany, NY John M. Kcclcr (1989)
Managing Panner Hinman, Howard 8c Kattell (Attorneys at Law)
Binghamton, NY AllenF Kintigh(1987)
Former President and Chief Operating OAicer of the Corporation Binghamton, NY Ben F Lynch (1987)
President Windtester Optical Company (hlanufacturer of Eyeglasses)
Elmita, NY Alton G. hlarsltall (1971)
Senior Fellow Nelson A. Rockefeller Institute of Government Albany, NY David R. New comb (1979)
Former President and Chief Excretive OAicer Buffalo Forge Company Q Ianufacturcr of Heating, Venti!ating and AirConditioning Equipment)
Buffalo, NY Robert A. Plane (1982)
President Wells College Aurora, NY C. WilliamStuart (1971)
Chairman and Chief Executive OAlcer C.W. Stuart Br Co., Inc.
(Interstatc Trucking Concern)
Nark, NY COMMITTEES OF THE BOARD Chairperson listed first Audlti Plane, Gioia, Kecler, Lynch Executive and Flnancc: Allen, Camgg, Gilmour, Kintigh, Marshall, Nnvcomb, Stuan Executive Compensation and Succcssloni Gilmour, Allen, Casarett, Lynch, Marshall, Ncwcomb Pensions Kcclcr, Kintigh, Plane, Stuart Public Alfalrsi Casarett, Gioia, Keeler, Lynch Mr. Carrigg is an cx oAicio member of tlte Pension and Public Alfairs committees.
r) r l
Seated, from left: Robert A. Plane, David R. Ymvcomb and Jo)m ht. Keeler.
Standing, from left: Everett A. Giimour, Paul L Gioia, Alton G. htarsltatl, Allen E. Kiniigh, James A. Camgg, Ben E. Lynch, Alison P. Casaieit, C. WilliamStuart and Wells P. Allen,Jr.
17 Ages and years of service as of December 31, 1992 in parentheses James A. Carrigg 59, 34)
Chairman, President and Chief Executive Officer Ralph R. Tedesco 89, 14)
Executive Assistant to thc Cltairman, President and Chief Executive Officer Patricia A. Orzell (50, 31)
Assistant Secretary ELECTRIC BUSINESS UNIT Jack H. Roskoz (54, 30)
Senior Vice President John J. Bodkin (47, 24)
Vice President-Electric Transmission and Distribution William G. hlcCann (45, 23)
Vice President-West Region Electric Operations Gerald E. Putman (42, 22)
Vice Prcsident-East Region Electric Operations Vincent W. Rider (61, 34)
Vice President - Electric Generation Irene M. Stillings (53, IQ Vice Prcsidcnt - Electric Marketing Michael J. Turkovic (60, 37)
Vice Presidcnt-Purchasing and Administration Denis E. Wickham (43, 20)
Vice President - Electric Resource Planning John I. Fiala (56, 34)
Assistant Vice Prcsidcnt - Plant Operations John V. Kutz (58, 3Q Assistant Vice President - Transmission and Distribution Operations GAS BUSINESS UNIT Russell Fleming Jr. (54, 2)
Senior Vice President MANAGEMENTSERVICES BUSINESS UNIT Richard P. Pagan (51, 21)
Senior Vice President Daniel W. Farley (37, 11)
Vice President and Secretary Carl E. Johnson (50, 2Q Vice President - Consumer Services and Communications Richard W. Page (57, 34)
Vice President - Human Resources Sherwood J. Raffert (45, 12)
Vice President and Treasurer (Chief Financial OAiccr)
Evcrett A. Robinson (49, 19)
Vice President and Controller (Chief Accounting OIEccr)
John D. Scott (54, 29)
Vice President - Economics Roy Hogbcn (53, 35)
Assistant Controller James M. Niefer (62, 37)
Assistant Scaetary Robcrt T. Pochily (43, 21)
Assistant Treasurer Gary J. Turton (45, 20)
Assistant Controller STRATEGIC MANAGEMENT BUSINESS UNIT Paul Komar (54, 23)
Senior Vice President MANAGEMENTCHANGES
~ Dolores R. Hix, former assistant secretary and assistant to thc chairman, president and chief executive oIEcer, passed away on September 8. The Board of Directors elected Patricia A. Otzcll, executive secretary to the chairman, prcsidcnt and chief executive offfccr, to thc position of'ssistant sccrctary on May 14.
FINANCIALSECTIONW hlanagement's Discussion &Analysis of Financial Condition and Results of Operations...................................18 Consolidated Statements of Income............25 Consolidated Balance Sheers.....
Consolidated Statements of Cash Flows......28 Notes to Consolidated Financial Statements.......
Report of hlanagement.....
Report of Independent Accountants.......... 42 Sclcctcd Financial Data.....
,43 Glossary.
43 Financial and Operating Statistics....
Financial Statistics......................
Electric Sales Statistics...............
Electric Generation Statistics.....
Natural Gas Sales Statistics....
Consolidated Statements of Changes in Common Stock Equity..................................29 Charles E. Dickson (54, 32)
Vice President - Regional Gas Operations Robert A. Paglia 65, 27)
Vice President - Gas hlarketing and Sales
~ Bcmard hl. Rider, senior vice prcsident-stratcgic growth business unit, retired effective January I, 1993.
~James A. Ackennan, vice president - East Region clcctric operations, is on disability leave. The Board of Directors elected Gerald E. Putman, executive assistant to the chairman, president and chief executive ofEccr, to succeed hlr. Ackerman and Ralph R. Tedesco, manager - corporate perfor-mance, to succeed hir. Putman.
18 MANAGEMENT'SDISCUSSION AND ANALYSISOF FINANCIALCONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS 1992 1991 over over 1991 1990 1992 1991 1990 Change Change IThousands. Except Per Share Amounts)
Operating revenues Earnings available for common stock Average shares outstanding Earnings per share Dividends r share
$ 1,691)689
$ 162,973 67,972
$z.40
$2.14
$ 1,555,815
$ 148,313 62,906
$2.36
$2.10
$ 1,496>780 9%s 4%
$ 145,351 10%
2%
58,678 8%
7%
$2.48 2%
(5%)
$2.06 2%
2%
'Ihe Company had operating revnues of approximately $ 1.7 billion in 1992, $ 1.6 billion in 1991, and $ 1.5 billion in 1990.
Operating reunues increased
$ 136 million, or 9%, in 1992, compel to 1991, primarily because of higher purchase costs of non-util-ity generation which are passed on to customers, and new electric and natural gas rates which became effective in February 1991 and August 1992. In addition, higher electric and natural gas retail sales due to an increase in retail customers, colder weather, and the April 1991 acquisition of Columbia Gas of New York, Inc. (CNY) helped boost operating revnues for 1992. In 1991, operat-ing ingenues rose $59 million, or 4%,
compared to 1990, primarily because of an increase in electric and natural gas rates effective February 1991 and the April 1991 acquisition of CNY.
Eaminy per share increasel 4 cents, or 2%%d, in 1992 compared to 1991, while eam-iny per share decreased 12 cents, or 5%, in 1991 compared to 1990. Earnings per share in 1992 were favorably affected by the growth in electric and natural gas retail sales pri-marily due to an increase in retail customers, colder mather, and the April 1991 acquisition of CNY. 'Ihe Company's efforts to control costs also contributed to the increase in 1992 eam-ings per share. Earnings per share were limited by a six-month electric rate mor-atorium that began in February 1992. In 1991, earnings per share decreased primarily because of the reduction in our allowed return on equity from 13% in 1990 to 11.7%
effective February 1991. In addition, lower electric and natural gas retail sales, which resulted from warmer mather and the weak economy, also decreased eaminy. Incentives earned on demand-side management (DSM) programs, however, had a favorable effect on 1991 earnings per share.
Average shares outstanding were 67,972,000 in 1992, 62,906,000 in 1991, and 58,678,000 in 1990. Average shares outstanding increased 8% in 1992 compared to 1991 due to the issuance of 5 million shares of common stock in March 1992, and the issuance of 1,039,000 shares of common stock through the Dividend Reinmtment and Stock Purchase Plan (Plan). In 1991, average shares outstanding i'ncreased 7% because of the issuance of 4 million shares of common stock in October 1990, and the issuance of 970,000 shans of common stock issued through the Plan.
Interest Expense Interest expense decreased 5% in 1992 and 6%%d in 1991 (before the rtxluction for allowance lor borro~txl funds used during construction). Interest on long-tenn debt decreased in 1992 and 1991 mainly due to the refinancing of certain highmupon long-term debt at lower interest rates. In 1992 and 1991, interest expense also declined due to a decrease in the average amount of commer-cial paper outstanding and lower interest rates on the Company's variable rate debt.
(See Liquidity and Capital Resources
- Financing Activities).
19 Operating Results by Business Unit Electric 1992 1991 1990 1992 1991 over over 1991 1990 Change Change iThousands)
Retail sales-kilowatt-hours (h~vh) 13,294,4GG 13,107,115 13,197,673 1%
(I%%d)
Operating revenues
$ 1,451,525
$ 1,367,936
$ 1,334,509 6%
3%
0 ratin nses
$ 1,14G,G19
$ 1,056,969
$ 1,021,669 8%
3%
The 1% growth in electric retail sales in 1992 compared to 1991 was the result of colder weather and an increase in customers.
Retail sales decreased 1% in 1991 compared to 1990 mainly due to wanner weather and the weak economy.
Flectric operating revenues increased
$84 million, or 6%, in 1992 compared to 1991.
This reflects the increases in electric rates which became effective February 1991 and August 1992. It also reflects the higher non-utility generation purchase costs and an increase in certain New York State gross receipts taxes, both of which are passed on to customers.
Also; the 1% increase in electric retail sales, due to colder weather and an rease in customers, boosted revenues.
Elec-operating revenues increased
$33 million, 3%, in 1991 comparnl to 1990, despite a
1% decrease in electric retail sales. This increase is primarily because of the increase in rates effective February 1991 and an increase in certain New York State gross receipts taxes which are passed on to cus-tomers.
Electric operating expenses increased
$90 million, or 8%, in 1992 compared to 1991, while operating expenses increased
$35 mil-lion, or 3%%d, in 1991 compared to 1990. In 1992, expenses increased primarily because of higher non-utility generation purchase costs and certain New York State gross receipts
'axes, both of which are passed on to cus-tomers. Operating expenses also increased because of higher DSM program costs and an increase in federal income taxes resulting from higher pretax book income. However, a decrease in maintenance expense reduced the increase in operating expenses.
In 1991, elec-tric operating expenses rose 3% primarily because of higher gross receipts taxes and higher federal income taxes resulting from higher pretax book income.
Natural Gas 1992 1992 1991 over over 1991 1990 1991 1990 Change Change Retail sales&katherms (dth)
Deliveries (dth)
Operating reenues 0
ratin nses tThousands) 39,357 29,874 25,515 SG,3GG 42,404 33,672
$240,1G4
$ 187,879
$ 162,271
$221,307
$ 177,751
$ 147,278 32%
17%
33%
26%
28%
16%
25%
21%
Natural gas retail sales increased 32% in 1992 compainl to 1991, and 17% in 1991 compared to 1990. 'Ihe 1992 and 1991 increases in retail sales, along with the increase in deliveries, are largely because of the April 1991 acquisition of CNY. Excluding CNY, natural gas retail sales increased 8%%d in 1992, primarily because of colder weather. In 1991, natural gas retail sales decreased 7%,
luding CNY, because of warmer winter ther and the weak economy.
Natural gas operating revenues rose $ 52 million, or 28%, in 1992 compared to 1991, and $26 million, or 16%, in 1991 compared to 1990. Those increases are principally the result of the acquisition of CNY and the increases in rates effective February 1991 and August 1992. Also, an increase in certain gross receipts taxes, which is passed on to customers, boosted 1992 revenues.
Natural gas operating expenses increased
$44 million, or 25%, in 1992 compared to 1991. This increase is primarily due to the increased quantity of natural gas purchased as a result of the CNY acquisition, and an increase in certain New York State gross receipts taxes passed on to customers.
Natural gas operating expenses increased
$30 million, or 21%, in 1991 compared to 1990, mainly because of the acquisition of CNY.
20 LIQUIDITYAND CAPITAL RESOURCES Competitive Conditions The utility industry is rapidly changing and moving towanl a competitive environ-ment. Factors contributing to this are: open access to electric transmission lines; Federal Energy Regulatory Commission (FERC) Order 636 which significantly affects the natural gas industry; and the National Energy Policy Act of 1992 (Energy Policy Act). In'ddition, the Company's desire to respond to the economic pressures on its large customers, high pur-chase costs of non-utility generation, rising health care costs, increasing taxes, weak eco-nomic conditions, conservation programs, and compliance with environmental laws and reg-ulations are factors that are placing increased pressure on our electric and natural gas rates.
The Company's five-year strategic plan addresses the competitiiv, rapidly changing utility industry. The plan positions us to meet the challenges of the future. The Company's objective is to remain competitive in its core businesses in the face of increased competition and continued deregulation.
Diversification, whether in the regulated or nonregulated arena, will play an important role in the Company's future. While the strength of the Company's core electric and natural gas businmes remains our focus, and while we will not compromise the Company's financial integrity, we are actively evaluating a number of corporate devlopment oppor-tunities for Innstment.
In April 1992, the Public Service Commis-sion of the State of New York (PSC) issued an onler allowing the Company to invest up to 5% of its consolidated capitalization (approximately $ 180 million at December 31, 1992) in one or more subsidiaries that may engage or invest in energy-related or environ-mental services businesses and provide related services. At December 31, 1992, the Company had not invested in any such businesses.
In April 1992, the FERC issued Order 636 which requires interstate natural gas pipeline companies to offer customers unbundled or separate services. With the unbundling of ser-vices, primary responsibility for reliable natural gas supply willsjiift fmm interstate pipeline companies to local distribution com-panies, such as the Company. This should result in increased direct access to low cost natural gas supplies by local distribution companies and end users. One goal of Order 636 is to provide equitable access to inteistate pipeline capacity. FERC Order 636 will sub-stantially restructure the inteistate natural gas market and intensify competition within the natural gas industry. Order 636 will allow us, subject to PSC approval, to restructure rates and provide multiple service options to our customers.
'Ihe Energy Policy Act was enacted in October 1992, and will bring major changes to the utility industry. Certain provisions of the Energy Policy Act amended the Public UtilityHolding Company Act of 1935 (PUHCA). These amendments will encourage greater competition by establishing a new cat-egory of wholesale electric generators which are exempt from PUHCA. The Energy Policy Act also enables the FERC to order utilities to provide open access to transmission systems.
The alternative fuel titles of the Act should serve to promote the use of natural gas and electric vehicles.
Recent Accounting Standards The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 106, Employers'ccounting for Postietirement Benefits Other Than Pensions (SFAS 106) in December 1990.
SFAS 106 requires that the Company accrue a liability for estimated future postretirement benefits during an employee's working career rather than recognize an expense when bene-fits are paid. SFAS 106 is elfective for fiscal yes beginning after December 15, 1992.
The Company adopted SFAS 106 in Janu-ary 1993. At the time of adoption, the accumulated benefit obligation was $225 mil-lion. The Company plans to reegnize the accumulated benefit obligation over 20 yetrs in accordance with SFAS 106. Adoption of the new standard is expected to IncreaM annual
- expenses, before deferral for ratemaking pur-poses, by about $32 million, or 7 times the 1992 expense.
In March 1992, the PSC issued a draft Statement of Policy concerning the account-ing and ratemaking treatment for post-retirement benefit costs. 'Ihis draft policy pro-vides for, among other things, recovery in rates for deferred SFAS 106 costs. In addition, the draft policy proposes that deferred SFAS 106 costs will be ielvered in rates within 10 years of the adoption of SFAS 106. The State-ment of Policy is expected to be approved by the PSC during the spring of 1993. In addi-tion, the July 1992 rate decision allows the Company to recover a portion of SFAS 106 costs in reenues from its customers and to defer the remainder of these costs for recovery in accordance mth the draft Statement of Policy. The Company anticipates that future SFAS 106 costs will be remverable through rates.
In November 1992, the FASB issued State-ment of Financial Accounting Standanls No.
112, Employers'ccounting for Postemploy-ment Benefits (SFAS 112), which is effective for fiscal years beginning after December 15, 1993. SFAS 112 will require the Company to recognize the obligation to provide post-employment benefits to former or inactive employe5 after employment but before retire-ment. The Company is evaluating the impact of SFAS 112 and intends to adopt it in 1994.
21 Financing Activities The Company remains committed to roving its financial integrity. We believe s commitment will take on added significance as competition heightens in the industry.
Capital Structure 59.5 56.3 54.2 52.2 50.5
'7.7 7.2 35.2 36.3 40.7 40.1 42.3 1988 1989 1990 1991 1992 C3 Long-term debt 0
Preferred Stock Q
Common Stock Equity In March 1992, the Company sold 5 mil-lion shares of common stock at $27.25 a 1re. After deducting underwriting fees, net of $26.54 per share, or $ 132.7 mil-on, were used to repay commercial paper.
The sale increased the Company's common stock equity ratio in March 1992 to over 43%,
the highest le~el since we became an inde-pendent utility in 1949.
The common equity ratio also impro1el in 1992 as a result of the Dividend Reinnstment and Stock Purchase Plan (Plan) and retained earnings.
We receiieI $30.3 million from the issuance of 1,039,159 shares of common stock thmugh the Plan and retained earnings increased by $ 18.3 million during 1992.
Common stock dividends paid in 1992 increased 9.7% over 1991 reflecting the incrme in common stock outstanding and an increase in the dividend paid from $2.10 to $2.14 per share.
In February 1992, we redeemed, at par, through a sinking fund provision in our Embedded Cost of Long-Term Debt 98/o 9~/o 9.1% R 0 fL4'.9/o
'l987 1988 1989 1990 1991 1992 mortgage, the remaining $20.4 million of IOs/s% Series first mortgage bonds due 2016.
In October 1992, we issued $ 150 million of 6s/A'eries first mortgage bonds due 2002.
Yel proceeds from the sale were used in con-nection with the redemption, at a premium, in October 1992 of $ 145.1 million of first mortgage bonds: $31.1 million of the 9.35%
Series due 2003; $75 million of the 93AX Series due 2005; and $39 million of the 9M'%eries due 2006.
In December 1992, we issued
$ 100 million of 8.30% Series first mortgage bonds due 2022. Net proceeds from the sale were used in connection with the redemption of $ 100 mil-lion of 10s/s% Series first mortgage bonds due 2018. In January 1993, $77.5 million of those 10s/sx bonds were redeemed, at a premium, and the remaining $22.5 million were
- redeemed, at par, in February 1993 through a sinking fund provision in our mortgage.
The refinancings will save approximately
$3.2 million in annual interest costs. Our embedded cost of long-term debt was reduced to 7.9% at the end of 1992 from 9.8% in 1987 and was further rtxluced to 7.7% in early 1993 after the redemption of $ 100 mil-lion'of 10s/s% Series first mortgage bonds due 2018. Unless interest rates fall further, it will
. be difficult to improve from the 7.7% level; hoover, all opportunities will be aggressively pursu61.
In February 1993, the Company plans to price $ 100 million of taxmempt pollution control bonds. Net proceeds from the sale, which will be delivered in April 1994, will be used to redeem, at a premium, $60 million of 12% pollution control bonds and $40 mil-lion of 12.3(% pollution control bonds.
The Company uses interim financing in the form of short-term unsecured notes, usu-ally commercial paper, to finance certain refundings and construction expenditures, and for other corporate purposes. This provides flexibilityin the timing and amounts of long-term financings. We had $64 million of com-mercial paper outstanding at December 31, 1992, at a weighted average interest rate of 4.0X. The weighted average interest rate dur-ing 1992 was 4.3%.
We also have a revolving credit agreement with certain banks which provides for borrow-ing up to $200 million to July 31, 1995. The Company did not have any outstanding loans under this agreement during 1992.
The Company's first mortgage bonds and prefened stock were upgraded by Fitch Inves-tors Services, Inc. in July 1992. Fitch stated that the higher ratings reflect signiflicantly improiei financial protection measures since 1987. Fitch also noted our efforts in lowering our embedded cost of long-tenn debt during the past snvral )ears.
Moody's Innstors Service upgraded our first mortgage bonds and unsecured pollution control bonds in August 1992. This upgrade was based on improvements in our financial, operating, and regulatory profile, as well as the likelihood that our financial condition will continue to improv
22 Capital Expenditures The Company's 1992 construction program totaled approximately $246 million. Most of the expenditures were for the extension of ser-vice and for improvements at existing facilities.
Construction Expenditures (Millionsof Dollars) 248 248 211 1988 1989 1990 1991 1992 1993 1994 1995 CD Actual ~ Forecast Construction expenditures for 1993-1995 will be primarily for the extension of service, improvements at existing facilities, and com-pliance with the Clean Air Act Amendments of 1990 (See Environmental Matters). The Com-pany has no need for additional large base-load generating capacity. tVe forecast that our current reserve margin, coupled with more efficient use of energy (See Conservation Pro-grams) and generation from non-utility generators (NUGs) will eliminate the need for additional generating capacity until well into the first decade of the 21st century.
The Company has on line and under con-tract 347 megawatts (mw) of NUG power. In addition, another 257 mw of NUG power is under construction. We are lequil61 to make payments under these contracts only for the power we receiw. During 1992, 1991, and 1990, the Company purchased approximately
$71 million, $30 million, and $8 million of NUG power. We estimate that we will pur-chase approximately $ 151 million, $251 million, and $287 million of NUG power for the years 1993, 1994, and 1995. The require-ment to purchase NUG power is expected to be a major contributor to rate increases over the next 3 years, and is expected to increase rates by approximately 8% during this time period.
In June 1992, the Company entefel into an agreement with Indeck Energy Services of Kirk~exl, Inc., Indeck Energy Services, Inc.,
and Indeck Kirhwod Limited Partnership to terminate the power purchase agreement for the 55 mw Indeck-Kirh~uod project. The ter-mination agreement will save customers an estimated
$350 million over 20 >ears. In Jan-uary 1993, the PSC approtel full recovery of the $ 11.5 million in termination costs in rates.
In December 1992, the Company entered into an agreement with Kamine/Besicofp Cor-ning L.P., Kamine South Coming Cogen Co.,
Inc., and Beta South Coming, Inc. to termi-nate the power purchase agfeement for the 79 mw South Coming cogeneration project. The termination agreement thrill save customers an estimated
$300 million over 25 )ears. The Company plans to petition the PSC in early 1993 to recover $34 million in termination costs in rates. Terminating these agreements is part of our continuing effort to minimize future rate increases associated w'th uneco-nomical power purchases from NUGs.
As a result of the PSC's competitive bid-ding program, the Company is contracting for 25 mw in conseNation projects to be avail-able by November 1994. In accordance with a PSC ruling issued in October 1992, the Company will conduct an auction for an additional 10 mw of conservation projects.
The timing of the auction has not yet been determined, but the Company does not expect that those conservation projects will be avail-able before 1995. We expect to recover the costs associated with these contracts from our customers.
The Company will utilize various methods, including competitive bidding, to minimize the economic impacts on customers of adding new resources to our sptem, while maintaining our current Ie)el of system reliability.
The following table provides information on the Company's estimated sources and uses of funds for 1993-1995. 'Ibis forecast is subject to periodic review and revision, and actual con-struction costs may vary because of revised load eslimates, imposition of additional regulatory requirements, and the availability and cost of capital.
Sources of funds Internal funds Sale of accounts receivable Long-term financing Debt and stock proceeds Debt foceeds held in trust Net nanctn roceeds Increase (decrease) in short-term debt Total Uses of funds Construction Cash expenditures AFDC Total constraetton 1993 1994 1995 Total tMlllions)
$251
$259
$262
$ 772 14
14 140 238 43 421 (56) 48 8
84 286 51 421 91 27 (2) 116
$440
$572
$311
$ 1323
$261
$296
$248
$ 805 10 13 9
32 271 309 257 837 Retirement of securities and sinking fund obligations 111 227 24 362 Working capital and deferrals 37 12 4
53 Demand-side mana ement ro m costs (net) 21 24 26 71 Total 440
$572
$311
$ 1323 As shown in the pfmding table, internal sources of funds represent 92% of construction expenditures for 1993-1995, or approximately 7'fter adjusting for working capital and defer-rals and net demand-side management (DSM) program costs.
23 Conservation Programs The Company has implemenled a number DShi programs. In 1990, we received iproval from the PSC for a plan to obtain earnings incentin5 for conducting eflicient DShi programs. Those incentin5 are currently limited to a.75% return on equity (approx-imately $ 16.1 million, before taxes, at December 31, 1992) allocated to electric oper-ations. The incentins are based on savings from 20 large-scale programs including financial and technical assistance to various customers.
In 1992, our customeis saved approx-imately 139.6 million kilowatt-hours (kwh) on an annualized basis through our DSM programs. The implementation of these pro-grams cost $40 million in 1992 and will cost approximately $34 million in 1993 with esti-mated customer savings of 158 million h&
on an annualized basis, thus producing more savings with less cost. We filed a taxi-par (1993-1994) conservation plan with the PSC in June 1992, seeking approval to continue implementation of those programs which have demonstrated cost effectiveness.
Marginal high unit-cost programs will be eliminated d the remaining DShi programs will be consolidated into five new comprehensive pro-grams which will benefit all customer classes.
The Company receiiel PSC approval for this plan in December 1992.
Environmental Matters The Company continually assesses actions that may need to be taken to ensure compli-ance with changing environmental laws and regulations. Compliance programs will very likely increase the cost of electric and natural gas service by requiring changes to our oper-ations and facilities. Historically, rate recovery has been authorized for the cost incurred for compliance with environmental laws and regulations.
Due to existing and proposed legislation and regulations, and legal proceedings com-menced by governmental bodies and others, the Company may also incur costs from the disposal of hazardous substances produced during our operations or those of our piede-cessors.
We have been notified by the U.S.
Environmental Protection Agency (EPA) and the New York State Department of Environ-mental Conservation that we are among the potentially responsible parties who may be liable to pay for costs incurred to iemediate certain hazardous substances at 9 waste sites, not including our inactive gas manufacturing sites which are discussed below. With respect to the 9 sites, I site is included on the Fed-eral National Priorities list, I site is unlisted but is the subject of an FPA administrative order, and 7 sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry). Any liability may be joint and several for certain of these sites. The ultimate cost to remediate these sites will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed, if any, to the Company. As a result, we are unable to estimate the extent of possible remediation costs. There is no clear precedent with the PSC for rate recovery of these types of remediation costs. Honorer, since lhe PSC has previously allwwl us to recover similar costs in rates (e.g., innstiga-tion and clean-up costs relating to coal tar sites), we expect to recover any remediation costs that we may incur.
A number of the Company's inactive gas manufacturing sites have been listed in the New York State Registry. We have filed peti-tions to delist the majority of the sites. Our program to investigate and initiate remedia-tion at our 38 known inactive gas manufacturing sites has been extended through 2000. Estimated expenditures over this time period are $25 million, which are reflected in our Consolidated Balance Sheets at December 31, 1992, to inmstigate and ini-tiate remediation, as necessary, at the known gas manufacturing sites. We expect to recover such expendituies in rates, as we have previ-ously been allo~el by the PSC to recover such costs in rates.
The Clean Air Act Amendments of 1990 (1990 Amendments) will result in significant future expenditures for the reduction of sulfur dioxide, nitrogen oxides, and possibly toxic emissions al several of our coal-fired generat-ing stations. Under the 1990 Amendments, we must reduce our annual sulfur dioxide emis-sions by 49X from approximately 138,000 tons in 1989 to 71,000 tons by 2000. We esti-mate that over a 25->mr period the cost to comply with the sulfur dioxide and nitrogen oxide limitations specified in the 1990 Amendments is approximately $252 million (on a present value basis) for all capital and operating and maintenance
- expenses, of which $ 17.3 million has been incurtei to date. This cost includes
$ 159 million for an innovative flue gas desulfurization (FGD) sys-tem and a nitrogen oxide nxluction system expected to be completed in 1995 at our hiilliken Generating Station (hiilliken).
In September 1991, we were selected by the Department of Fnergy (DOF) to receive fed-eral funds for these s)stems. In October 1992, the DOE approiel $45 million for these s)s-tems. In addition, the Company expects to receive funding totaling up to $ 17 million from other sources.
We estimate that a 2%
electric rate increase will be required for the cost of reiucing sulfur dioxide and nitrogen oxides emissions for both Phase I (begins January I, 1995) and Phase H (begins Januaiy I, 2000).
The cost of controlling toxic emissions, if required, cannot be estimated at this time.
Regulations may be adoptei at the state level which would limit emissions even further, at an additional cost to the Company. We antici-pate that the costs incunel to comply with the 1990 Amendments w'll be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the FPA to allocate annual emissions allowances to each of our coal-fired generating stations based on statutory emissions limits. An emissions allowance iepresents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, we esti-mate that the Company will have allowances in excess of the affected coal-flred generating stations'ctual emissions. The Company is
24 considering various methods of using, bank-ing, or selling these excess emissions allow-ances. During Phase II, we estimate that the annual tons emitted by the Company's coal-fired generating stations will equal our annual emissions allowances.
In addition to the annual emissions allowances allocated to the Company by the EPA, we may obtain extension mene allowances that the EPA will issue to com-panies electing to build scrubbers in Phase I such as the FGD sistern at Milliken. Due to the uncertainty of how many extension resene allowances will be demanded, the extent to which the demand may exceed the supply, and the method of allocating exten-sion reserve allowances, the Company entered into a pooling agreement with other utilities which are eligible to receive some of the extension reserve allowances. This agreement provides assurance that the Company will receive some of the extension reserve allowances in the cent that demand exceeds supply.
Regulatory Matters In July 1992, the PSC approiel an electric rate increase of $63.9 million annually, or 5%, and a natural gas rate increase of $ 10.4 million annually, or 4.1%, effective August I, 1992. 'Ihe electric rate increase included approximately $ 16 million of capacity charges associated with the cmt of purchasing elec-tricity from NUGs. In the event the capacity component of purchasing electricity from NUGs falls below or exceeds
$ 16 million, the difference will be deferred and passed on to customers in a future rate year. The rate decision provided for an 11.2/o return on common equity and an overall rate of return of 9.7%.
The rate decision alloviel the Company to recognize on its income statement, beginning August 1992, electric and natural gas unbilled revenues on a full accrual basis. This recog-nition did not materially affect annual revnues and earnings for common stock in 1992 and is not expected to do so in 1993, but will affect the recognition of revenues from 'quarter to quarter, on a comparative basis.
In July 1992, the Company entered into discussions with the PSC stalf and other inter-ested parties in an attempt to develop a multi-year rate plan that addresses costs and associated rate changes.
The Company con-tinues to work with the PSC staff and other parties to reach a multi-year rate settlement.
In August 1992, the Company had planned to file with the PSC for electric and natural gas rate increases to be effective in August 1993. However, since the Company was work-ing with the PSC staff and other parties to reach a multi-)mr rate settlement, the filing was dela>el until November 1992. In Novem-ber 1992, the Company filed for an electric rate increase of $77.5 million annually, or 5.5%, and a natural gas rate increase of $9.5 million annually, or 3.6%, to be effective August 1993. 'Ihe rate filing provides for an 11.4% return on common equity and an over-all rate of return of 9.6%. We cannot predict the outcome of this proceeding.
On hfay 14, 1991, the PSC issued an order approving an agreement betvimn the Com-pany and the PSC staff which settled a fuel; procurement proceeding instituted by the PSC.
The agreement, among other things, provided for a six-month electric rate moratorium beginning on February I, 1992. Eaminy for common stock decreased approximately
$ 16 million in 1992 as a result of the rate moratorium.
Federal Energy Regulatory Commission (FERC) Proceeding In August 1991 and October 1992, the FERC issued orders which revised its generic policy related to filing requirements for con-tracts determined to be subject to its jurisdiction under the Federal Power AcL Under the revised policy, FERC may require a utility to refund certain revenues collected under late-filed contracts.
In December 1992, FFRC issued a notice requesting comments from interested parties relating to its filing requirements for con-tracts. The notice solicited comments on
,. whether the obligation to file jurisdictional agreements should extend to certain termi-nated agreements as well as existing agreements.
The Company and many other utilities filed comments in January 1993 chal-lenging the filing requirements and the appropriateness of the refund obligations.
'Ihe Company continues to review its compliance with FERC contract filing requirements. In October 1992, the Company determined that it may be required to file at least four additional contracts with FERC. The Company is unable to predict what actions FERC may take as a result of its notice and is unable to estimate the amount and timing of refunds, if any, that may be requirel.
Therefore, the Company cannot predict the ultimate disposition of this matter, but belien5 that it will not have a material adverse effect on its financial position.
CONSOLIDATED STATEMENTS OF INCOME 1992 1991 1990 tThousands, except Per Share Amounts)
OPERATING REVENUES Electric Natural as TOTAL OPERATING REVENUES OPERATING EXPENSES Fuel used in electric generation Electricity purchased Natural gas purchased Other operating expenses Maintenance Depreciation and amortization (Note 1)
Federal income taxes (Notes 1 and 2)
Other taxes (Note 11)
$ 1,451,525 240,164 1,G91,689 2G2,531 95)02G 126,815 318)680 102,500 158,977 102,45G 200,941
$ 1867,936 187,879 1,555,815 274,877 45,808 99,528 279,364 110,131 152,380 94,447 178,185
$ 1/34,509 162,271 1,496,780 274,245 34,613 88,589 268,829 io6,665 147,659 89,577 158,770 TOTAL OPERATING EXPENSES 1,367,92G 1,234,720 i,168,947 OPERATING INCOME OTHER INCOME AND DEDUCTIONS INCOi41E BEFORE INTEREST CIIARGHS 323,763 12,03G 335,799 321,095 6,076 327,171 327,833 (i,508) 326,325 INTERESI'IIARGES Interest on long-term debt Other interest AFDC - borrovel (Note 1) 145,822 9,5GG 3,557 151,649 158,209 11,877 15,181 (4,998)
(5,078)
INTEREST CKNGES-NET 151,831 158,528 168312 INCOitIH
.FH K
S INGS AVAILABLEFOR COilIMONSTOCK 183,968 20 995
$ 1G2,973 158,013 12,662 168,643 20,330
$ 148,313
$ 145851 EARNINGS PHR SIIARE AVERAGE SENES OIJFSTANDING The notes on pages 30 through dt are an integral part of the financial statements.
AEC h allosiunce for funds used during construction.
82.40 67,972
$2.36 62,906
$2.48 58,678
CONSOLIDATED BALANCESHEETS December 31 ASSETS UFILm PLANF, AT ORIGINALCOST (NOTE 1)
Electric (Note 8)
Natural gas Common Less accumulated d
reciation NET UTILITYPLANT IN SERVICE Construction work in ro TOTAL UTILITYPLANT OTHER PROPERTY AND INVESXIIENTS 1992
$4,573,444 352)059 157,979 5t083,482 1,427,793 3,G55,G89 177,56G 3,833,255 59,157 tThousands) 1c
$4,421,839 317,694 156342 4,895,875 1,309,829 3,586,046 166,815 3,752,861 56,581 CURRENT ASSETS Cash and cash equivalents (Notes 1 and 6)
Special deposits (Note 6)
Accounts receivable, net (Note I)
Fuel, at average cost Materials and supplies, at average cost Prepayments Accumulated defeml federal income tax benefits (Notes I and 2)
Unfunded future federal income taxes (Notes 1 and 2)
TOTAL CURRENT ASSETS 3,968 96,432 171t683 69,077 50,G37 37,897 15,437 20,880 46G 011 18,601 11,463 133,338 66,602 51,736 37,019 16,278 22,659 35 DEFERRED CHARGES (NOTE 1)
Accumulated deferred federal income tax benefits (Notes 1 and 2)
Unfunded future federal income taxes (Notes 1 and 2)
Unamortized debt expense Other TOTAL DEFERRED CHARGES TOTAL ASSETS The notes on pages 30 thtough <t ate an inteyal patt of the finandal statements.
84,257 372,840 96,378 264,530 818,005
$5,176,428 83,718 413,586 91,850 168,544 757,698
$4. 24836
27 CONSOLIDATED BALANCESHEETS 1992 1991 GiPITALIZITIONAND LIABILITIES CAPITALIZATION Common stock equity Common stock ($6.66'/s par value, 90,000,000 and 80,000,000 shares authorized and 69,439/97 and 63,400,238 shares issued and outstanding at December 31, 1992 and 1991, respectively)
Capital in excess of par value Retained eamin Total common stock ui Prefemd stock redeemable solel at the o tion of the Com an (Note 4)
Prefemd stock sub'ect to mandato redem lion uirements (Notes 4 and 6)
Lon -term debt (Notes 3 and 6)
TOTAL CAPITALIZATION CURRENT LIABILITIES Current portion of long-term debt and preferred stock (Notes 3 and 4)
Commercial paper (Notes 5 and 6)
Accounts payable and accrued liabilities Interest accrued (Note 6)
Unfunded future federal income taxes (Notes 1 and 2)
Accumulated deferred federal income taxes (Notes 1 and 2)
Other TOTAL CURRENT LIABILITIES FERRED CREDITS ccumulated deferred inmstment tax credits (Notes 1 and 2)
Excess defemd federal income taxes (Notes 1 and 2)
Other TOTAL DEFERRED CREDITS ACCUMULATEDDEFERRED FEDERAL INCOME TAX (NOTES 1 AND 2)
Unfunded future federal income taxes Other TOTAL ACCUMULATEDDEFERRED FEDERAL INCOME TAXES CO)tIMITMENTSAND CONTINGENCIES (NOTE 9)
TOTAL CAPITALIZATIONAND LIABILITIES tThousands)
$4G2,929
$422,668 796,505 673,791 327,040 308,688 1,58G,474 1,405,147 1G0,500 160,500 106,900 108,550 1,777,027 1,788,915 3,630,901 3,463,112 115,G59 38,653 64,100 103,900 95,996 mO,847 37,G90 43,440
'20)880 22,659 24,083 16,747 6'7,499 75,483 425,907 401,729 141,729 148,078 55,762 63,778 107,160 67,961 304,G51 279,817 372)840 413,586 417,129 366,592 789,969 780,178 25,000
$ 5,176,428
$4,924.836 lhe notes on pages 30 through kl are an integral part of the financial statements.
28 CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31 1992 1991 tThouaande)
OPERATING ACTIVITIES Net Income Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization Defened fuel and purchased gas Federal income taxes and investment tax credits deferred - net Recovered (deferred) transmission wheeling charges Unbilled revenue recognition (Note I)
Demand-side management program costs Other - net Changes in certain cumnt assets and liabilities, net of effects from the purchase of Columbia Gas of New York, Inc. in 1991:
Special deposits Accounts receivable Prep ayments Inventory Accounts payable and accrued liabilities Interest accrued Olher - net 158,977 (14,G45) 50)683 (22)228)
(22,8G3)
(13,022) 152~
2,507 53,105 (86I)
(4o,i47)
(IS,>>8) 3,832 147,659 (6,225) 50,924 20,793 (43,849)
(2,051)
>>,103 (1,873)
(11,936)
(878)
(1,417)
(8,287)
(5,750) 4,4G2 (4,108)
(Is,s41)
(7,882) 4,59o s,6s6 8,6io) 2,44o (443)
(>>,123)
(2,650) 87,874)
>>,67o (4,486)
(s,42o)
$ 183)968
$ 168>643
$ 158,013 NET CASH PROVIDED BY OPERATING ACTIVITIES INVESfING ACTIVITIES Utilityplant construction expenditures, net of AFDC - other (Note I)
Pa ent for urchase of Columbia Gas of New York, Inc., net of cash uited NET CASH USED IN INVKSfINGACTIVITIES FINANCING ACTIVITIES Issuance of first mortgage bonds Sale of common stock Sale of preferred stock First mortgage bonds and prefeml stock repayments Special deposit - first mortgage bond repayments Long-term notes repayment Commercial paper - net Dividends on common and referred stock NET CASH PROVIDED BY USED IN FINANCING ACTIVITIES NET INCREASE (DECREASE) IN CASH AND CASH KQUIVALKNfS CASH AND CASH E UIVALKNfS,BEGINNING OF YEAR CASH AND CASH E UIVALENTS, END OF YEAR NOTES 1 AND 6 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFOIMATION Cash paid during the period:
Interest, net of amounts capitalized Income taxes SUPPLKllIENfALDISCLOSURE OF NONCASH INVFSfING AND FINANCING ACTIVITIES Capital lease additions The Company purchased all of the common stock of Columbia Gas of New York, Inc. In conjunction with the acquisition, liabilities were assumed as follows:
Fair value of assets acquired Cash aid Liabilities assumed 1he notes on pages 30 through 4l ate an integral patt of the financial statements.
hFDC is alb)jant>> for funds used during consttuctton.
28G,2G7 (243,051) 243,051 247,6G8 162,965 (178,289)
(83,096)
(1,593)
(39)800) 165,704 57,849 (14,G33) 18,601
$3,968
$ 149)299
$38,477
$2)970 305,886 (244,o37)
(57,096)
(301,133) 147,243 25,380 98,975 (142,715)
(2,322) 30,675 (iSo,lo6) 7,130
>>,883 6,718
$ 18,601
$ 159,927
$31,790
$9,s24
$81,982 (57,096)
$24,886 286,04I (210,540)
(21 294,316
>>5,089 (296,289)
(498)
(5,078)
(47,775)
(133,906)
(74,141) 1860 5358
$6,718
$ 171,675
$33,1>>
$ 12,192
29 CONSOLIDATED STATEMENTS OF CHANGES COMMON STOCK EQUITY tThousands, except Shares and Per Share Amounts)
Common Stock S6.66 2j3 Par Value Shares Amount Capital
, ln Excess of Par Value Retained Earnings Total BAIANCE,JANUARY I, 1990 Net income Cash dividends declatoi:
Preferred stock (at serial rates)
Redeemable - optional
- mandatory Common stock ($2.06 per share)
Issuance of stock Public Offering Dividend reinvestment and stock urchase lan BALsiNCE, DECEMBER 31, 1990 Net income Cash dividends declared:
Prefemd stock (at serial rates)
Redeemable
- optional
- mandatory Common stock ($2.10 per share)
Issuance of stock Dividend reinvestmentandstock urchase lan NCE DFCEh/BER 31 199 57,553,528
$383,690
$573,293
$268,201
$ 1,225,184 158,013 158,013 4,000,000 876,769 26,667 5,845 66990 iS,&8 (iI,484)
(11,484)
(1,178)
(1,178)
(121,302)
(121802) 93,657 2i,454 969,941 63 400238 (11 395)
(I1,395)
(8,935)
(8,935)
(131,875)
(131,875) 4365 6,466 17899 422,668 673,791 308,688 1,405,147 62,430,297 416,202 655,892 292,250 1,364,344 i68,643 i68,643 t income Cash dividends declared:
Preferred stock (at serial rates)
Redeemable
- optional
- mandatory Common stock ($2.14 per share)
Issuance of stock Public OfFering Dividend reinn5tment and stock urchase lan 5,000,000 1,039,159 183,968 183,968
(>>,IQ) oi,iQ)
(9,831)
(9,831)
(144,621)
(144,621) 33333 99,367 132,700 6,928 23,347 30,275 BAIANCE, DECEItIBER 31, 1992 6
43 7
462 2
7 505 327040 I 586 474 The notes on pages 30 through 41 are an inteyat part of the financial ttatements.
30 NOTES TO CONSOLIDATED FINANCIALSTATEMENTS
- 1. SIGNIFICANTACCOUNTING POLICIES Principles of consolidation The consolidated financial statements include the Company's wholly-owned subsid-iary, Somerset Railroad Corporation (SRC).
All significant intercompany balances and transactions are eliminated in consolidation.
Utilityplant The cost of repairs and minor replace-ments is charged to appropriate operating expense accounts. The cost of renewals and betterments, including indirect cost, is cap-italized. The original cost of utility plant retited or othenvise disposed of and the cost of removal less salvage are charged to accu-mulated depreciation.
Depreciation and amortization Depreciation expense is determined using straight-line rates, based on the average ser-vice line of groups of depreciable property in service. Depreciation accruals were equivalent to 3.3% of average depreciable property for 1992, 1991, and 1990. Depreciation expense includes the amortization of certain deferred charges authorized by the Public Service Commission of the State of New York (PSC).
Allowance for funds used during construction IAFDC)
AFDC represents the cost of funds used to finance the construction of utility plant.
Those costs are capitalized during the con-struction'period and recorded in construction work-in.progrm. AI'DC is recovered over the life of the plant through depreciation when the construction project is placei in service.
Those costs are also credited on the income statement during the construction period as an allowance for borroiiel funds used during construction, which reluces the net interest
- charges, and as an allowance for other (i.e.,
equity) funds used during construction, which is included in other income.
Revenue In 1988, the Company began accruing electric and natural gas revenues on its balanoe sheet for energy provided but not yet billed. During 1992, 1991, and
- 1990, the Company recognized approximately $22 million, $40 million, and $44 million, n5pectively, of these revenues on ttie income statement to minimize the rate increases for these >van in accordance vdth various PSC rate decisions. The July 1992 rate decision allows the Company to recognize on its income statement, beginning August 1992, electric and natural gas unbilled revenues on a full accrual basis.
The Company recognizes as revenues incentives earned as the result of conducting efficient demand-side management (DSM) programs. The Company is collecting those incentives in rates within 12 to 13 months after they are recognized. During 1992, 1991, and 1990, incentims earned were $ 15.6 mil-lion, $ 12.4 million, and $2.6 million, respectively. At December 31, 1992 and 1991, approximately $9.8 and $ 11.3 million, respec-tively, of DStI Incentins were accrued and included in accounts receivable.
Accounts receivadie 1lie Company has an agreement that expires in November 1996 to sell, with limited
- recoutse, undivided percentage interests in certain of its accounts receivable from cus-tomers. The agreement allows the Company to receive up to $ 152 million from the sale of such interests. At December 31, 1992 and 1991, accounts receivable on the Consolidated Balance Sheets is shown net of $ 138 million of interests in accounts receivable sold. All fees associated with the program are included in olher income and deductions on the Con-solidated Statements of Income and amounted to approximately $6.5 million, $9.3 million, and $ 12.5 million in 1992, 1991, and 1990, respectively. Axounts receivable on the Consolidated Balance Sheets is also shown net of an allowance for doubtful accounts which was $ 1.9 million and $.7 million at Decem-ber 31, 1992 and 1991, respectively. Bad debt expense was $ 11.5 million, $ 10.7 million, and
$8.9 million in 1992, 1991, and 1990, respectively.
Federal income taxes The Company follows the method of accounting for income taxes prescribed by Statement of Financial Accounting Standards No. 96, Accounting for Income Taxes.
The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109), in February 1992, and it is effective for fiscal >ears beginning after December 15, 1992. The Company will adopt SFAS 109 in the first quarter of 1993. The adoption of SFAS 109 will not have a mate-rial effect on the Company's results of operations or financial position because SFAS 109 does not differ materially from the State-ment of Financial Accounting Standards No. 96, Accounting for Income Taxes, which the Company adopted in 1987.
The Company files a consolidated federal income tax return with SRC. Defend income taxes are provided on all temporary differ-ences betwtx.n book and taxable income.
Innstment tax credits, which reduce federal income taxes currently pa@hie, are deferred and amortized over the book lin5 of the applicable property. 'Ihe effect of the altem.
tive minimum tax, which increases federal income taxes cumntly payable and generates a tax credit available for future use, is deferred and amortized at such times as the tax credit is used on the Company's federal income lax return.
Deferred charges The Company defers certain incurred
- expenses, when authorized by the PSC. Those expenses are recovered from customers in the future.
Consolidated Statements of Cash Flows The Company considers all highly liquid investments with a maturity or put date of three montlts or less when acquired by the Company to be cash equivalents.
These innst-ments are included in cash and cash equivalents on the Consolidated Balance Sheets.
Reclasslficatton Certain amounts have been reclassified on the consolidated financial statements to con-form with the 1992 presentation.
31
- 2. FEDERAL INCOME TAXES
~
cended December 31 Charged to operations Current Deferred - net Accelerated depreciation Unbilled revenues Tax Reform Act (TRA) 1986 Alternative minimum tax (AhiT) credit Demand management Power purchase termination agreement Miscellaneous Investment tax credit (ITC) deferred 1992
$37,237 41,492 160 (2,295) 2,123 9,324 6,800 (4,415) 12 030 1991 tThousends)
$22,991 37,409 13,644 (2,284) 5,557 8,589 (8,243) 16,784 1990
$37,804 33,704 io,i67 6,566).
(1,763) 1,985 697 10,549 Included in other income'mortization of defeml ITC Miscellaneous 102,456 (16,927) 3 747 94,447 89,577 (11,297)
(5,756)
(533) 176 TOTAL
$89,276
$82,617
$83,997 The Company's elfective tax rate differed from the statutory rate of 34% due to the following:
Year Ended December 31 1992 1991 tThousends) 1990 Tax expense at statutory rate iation not normalizel 86-net amortization Cost of removal Other - net
$92)903 16,697 (2,485)
(16,927)
(4,079) 3 167
$85,428
$82,283 16,051 14,459 (2806) 8,566)
(11,297)
(5,756)
(6,120)
(4,148) 861 725 TOTAL
$89,276
$82,617
$83,997 The Company has recorded unfunded future federal income taxes and a corres-ponding receivable from customers of approximately $393 million and $436 million as of December 31, 1992 and 1991, respec-timiy, primarily representing the cumulative amount of federal income taxes on temporary depreciation differences which were previously flo~1xi through to customers.
Those amounts, including the tax effect of the future revenue requirements, are being amortized over the life of the related depreciable assets concur-rent with their recovery in rates.
The Company has approximately $6 mil-lion of unused Investment tax crelits at December 31, 1992, which will begin to expire in 2001, and $ 12 million of AhIT credits which do not expire.
32
- 3. LONG-TERM DEBT At December 31, 1992 and 1991, long-term debt was (Thousands):
First mortgage bonds Amount Amount Series Due 1992 1991 Series Due 1992 1991
$ 100,000 50,000 25,000 25,000 30)000 50,000 150,000 8s/s%
Aug. 15, 1994 Ss/A June I, 1996 5s/sX Jan. I, 1997 6~/A Sept. I, 1997 6~/t%
Sept. I, 1998 7s/s%
Nov. I, 2001 6s/<%
OcL 15, 2002 9.35%%d July I, 2003 9s/s%
hlar. I, 2005 9s/s%%d Jan. I, 2006 7~/~%%d une I, 2006
$ 100,000 50,000 25,000 25,000 30,000 50,000 33,200 75,000 45,000 12,000 3)000 12,000 Total rst mort a e bonds 67/s%
Dec. I, 2006 8s/s%
Nov. I, 2007 10s/s%
Feb. I, 2016 9i/A Apr. I, 2016 9% hlar. I, 2017 IOs/s%
Jan. I, 2018'7/s%
Feb. I, 2020 97/s%%d May I, 2020 9~/s%
Nov. I, 2020 87/s%%d Nov. I, 2021 8.AS Dec. 15, 2022
$25,500 60,000 50,000 100,000 100,000 100,000 100,000 100,000 150,000 100,000
$25,750 60,000 20,424 50,000 100,000 100,000 100,000 100,000 100,000 150,000 1,330,500 I 251 374
'$77,500,000 loleemel in January 1993 and $22,500,000 redeemed in February 1993.
Pollution control notes Interest Rate Maturity Date Interest Rote Adjustmont Dote Letter of Credit Expiration Dote Amount 1992 1991 12%%d hiay I, 2014 12.3IS July I, 2014 3'ec.
I, 2014 3.25%%d hiar. I, 2015 2.9%
hlar. 15, 2015 3.1IS July 15, 2015 2.$S Oct. 15, 2015 2.9%
Dec. I, 2015 6.6%
July I, 2026 5.375%%d Dec. I, 2027 Dec. I, 1993 hlar. I, 1993 Mar. 15, 1993 July 15, 1993 Oct. 15, 1993 Dec. I, 1993 July I, 1993 Dec. I, 1994 Dec. 15, 1994 Mar. 15, 1994 hiar. 31, 1994 July 31, 1994 Oct. 31, 1994 Dec.
15, 1994 July 15, 1996 Dec.
15, 1994 60,000 60,NI 40,000 40,NI 74,000 74,000 37,500 37,500 60,000 60,ee 63,500 63,500 30,000 30,000 42,000 42,000 65,000 65,000 34,000 34,000 Total ollutlon control notes SRC commercial paper due December 31, 1995 Obligations under capital leases Unamortized remium and discount on debt - net 50G,000 506,000 27,707 29,300 38)804 47,260 (11,975)
(8,016)
$ 1,777,027
$ 1 788915 Total 1,891,03G 1,825,918 Les~: debt due within one ear - included in current liabilities 114,009 37003
33
- 3. LONG-TERM DEBT (Continued) t December 31, 1992, long-term debt and capital lease payments which will become due during the next five pars are:
1993 1994 1995 1996 1997 tThouaanda)
$ 114,009
$ 110,609
$36,035
$56,156
$52,196 The Company's mortgage provides for a sinking and improvement fund. This provision requires the Company to make annual cash deposits with the Trustee equivalent to IX of the principal amount of all bonds delivered and authenticated by the Trustee prior to Jan-uary I of that year (excluding any bonds issued on the basis of the retirement of bonds). The Company satisfied this require-ment in 1992 by depositing $20.4 million in cash which was used to releem the remain-ing $20.4 million of 10s/A'eries first mortgage bonds, due 2016. The Company sat-Isfied this requirement in 1993 by depositing
$22.5 million in cash which was used to m in February 1993, $22.5 million of
%%d Series first mortgage bonds, due 2018.
mandatory annual cash sinking fund requirements are $600,000 beginning June I, 2001, for the 7/A Series and $250,000 on December I in each par 1993 to 1996, for the 6~/a%%d Series. Tire amount increases to
$500,000 and $750,000 on December I, 1997 and December I, 2002, rr5pectively, for the 6N%%d Series.
The Company's first mortgage bond inden-ture constitutes a direct first mortgage lien on substantially all utility plant.
Adjustable rate pollution control notes were issued to secure like amounts of taxmempt adjustable rate pollution control revenue bonds (Revenue Bonds) issued by a govem-mental authority. The Revenue Bonds bear interest at the rate indicated through the date preceding the interest rate adjustment date.
The pollution control notes bear interest at the same rate as the Revenue Bonds. On the interest rate adjustment date and annually thereafter (every three pars thereafter in the case of the Revenue Bonds due July I, 2026 and December I, 2027), the interest rate will be adjusted, nol to exceed a rate of 15%%d, or at the option of the Company, subject to cer-tain conditions, a fixed rate of interest, not to exceed 18Ã, may become effects. In the case of the Revenue Bonds due July I, 2026 and December I, 2027, at the option of the Company, subject to certain conditions, a fixed rate of interest may become effective prior to the interest rate adjustment date or each third year thereafter.
Bond ownen may elect, subject to certain conditions, to have their Revenue Bonds purchased by ttle Trustee.
The Company has irrevocable letters of credit which expire on the letter of credit expiration dates and which the Company anticipates being able to extend if the interest rate on the related Revenue Bonds is not con-verted to a fixed interest rate. TIrose letten of credit support certain payments required to be made on the Reenue Bonds. If the Company is unable to extend the letter of credit that is related to a particular series of Retinue Bonds, that series w'll have to be redeemed unless a fixed rate of interest becomes effec-tive. Payments made under the letters of credit in connection with purchases of Reve-nue Bonds by the Trustee are repaid with the proceeds from the remarketing of the Revenue Bonds. To the extent the proceeds are not suf-ficient, the Company is required to reimburse the bank that issued the letter of credit.
34
- 4. PREFERRED STOCK At December 31, 1992 and 1991, serial cumulative prefeml stock was:
Shares Par Value Authorbied Per Redeemable a)id Series Share Prior to Per Share Outstanding(1)
Amount 1992 1991 tThousands)
Redeemable solely at the option 3.75%
$ 100 4 i/i% (1949) 100 4 15%
100 4.40%
100 4.15% (1954) 100 6.48%
100 8.80%
100 8.48%
25 Adjustable Rate (2) 25 Total of the Company:
$io4.oo 103.75 101.00 102.00 102,00 102.00 102.00 t/i/94 26.23
'Ihereafter 25.70
'/i/93 25.75 Thereafter 25.00 150,000 4o,ooo
'4o,ooo 75,000 50,000 300,000 250,000 1,000,000 1,800,000
$ 15,000 4,ooo 4,ooo 7,500 5,000 30)000 25)000 25,000
$ 15,ooo 4,ooo 4,ooo 7,500 5,000 30,000 25,000 25,000 45,ooo 45,NI
$ 160,500
$ 160,500 Subject to mandatory mlemption requirements:
9.00% (3) 100 i%/93 101.00 85 500
$8)550
$ 10 200 8.95% (4) 25
/i/94 26.94 4,000,000 100,000 100,000 Im: sinking fund requirements at par value included in current liabilities Total 108,550 110,200 1,650 1,650
$ 106,900
$ 108,550 Annual redeemable preferred stock sinking fund requirements for the next five >ears are:
1993 1994 1995 1996 1997 tThousands)
$ 1,650
$ 1,650
$ 1,650
$3,600
$5,000 (I) At December 31, 1992, there were 1,550,000 shares of $ 100 par value pre-ferrei stock, 4,000,000 shares of $25 par value preferred stock and 1,000,000 shares of $ 100 par value preference stock authorized but unissued.
(2) The payment on the Adjustable Rate Serial Preferred Stock, Series A, for April I, 1993 has been adjusted to an annual rate of 7.5% and subsequent payments can vary from an annual rate of 7.5% to 13.5%, based on a formula included in the Company's Certificate of Incorpora-tion. Dividends paid from the date of issuance (1983) through the January I, 1993 payment varied from an annual rate of 7.5/o to 12.95%.
(3) On October I, in each year 1993 through 1995, the Company must redeem 16,500 shares at par. For the years 1990 through 1992, 16,500 shares were rtxleemed and cancelled annually. This Series is redeemable at the option of the Company at $ 101.00 per share prior to October I, 1993. 'Ihe $ 101.00 price per share will be reduced annually by 50 cents. As of October I, 1994, and thereafter, the redemption price will be at par. By Sep-tember 30, 1996, the Company must set aside the amount required to redeem at par all remaining shares outstanding.
(4) On January I, in each )ear 1997 through 2016, the Company must nxleem 200,000 shares at par. This Series is redeemable at the option of the Company at $26.94 per share prior to January I, 1994. The
$26.94 price will be reduced annually by 15 cents for the )ears ending 1994 through 1999; by 14 cents for the >uar ending 2000; and by 15 cents for the
>ears ending 2001 through 2005. The Company is restricted in its ability to redeem this Series prior to January I, i996.
35
- 5. BANKLOANS AND OTHER RROWINGS e Company Itas a revolving credit agree-ment with certain banks>>1tich provides for borrowing up to $200 million to July 31, 1995. At the option of the Company, the interest rate on bormwings is related to the prime rate, the landon Interbank Offeted Rate or the interest rate applicable to certain certificates of deposit. Tlie agreement also provides for the payment of a com-mitment fee of.22%%d per annum on the unbono>>el amount.
The revolving credit agreement does not require compensating balances.
The Company did not have any outstanding loans under this agreement or a similar prior agreement at December 31, 1992 or 1991.
In order to pmvide flexibilityin the timing and amounts of long-term financings, the Company uses interim financing in the form of short-term unsecured notes, usually com-mercial paper, to finance certain refundings and construction expenditures, and for other corporate purposes.
Information relative to shoit-temi bonowings is as folio>>s:
Commercial Paper 1992 1991 1990 Ending balance Maximum amount outstanding Average amount outstanding (1)
Weighted average interest rate On ending balance Durin the riod 2
$64,ioo
$ 140,000
$3i,400 4.0/o 4.3/o tThousandsl
$ 103,900
$ 111,000
$66,700 5.3%%d 6.2X,
$73,225
$ 142,600
$98,400 8.6X 8,5%%d Calculated as the average of the sum of daily outstanding borrowings.
Calculated by dividing total interest expense by the average of the sum of daily outstanding borlo'wings.
- 6. FAIR VALUEOF FINANCIAL INSTRUMENTS The estimal61 fair values of the Company's financial instruments at December 31, 1992 are as follows (Thousands):
Carrying Amount Fair Value First mortgage bonds
$ 1,318,845
$ Q88,990 Pollution control notes
$505,680
$523,251 Prefened stock sub'ect to mandato redem tion uirements
$ 108 550 11 031 The carrying amount for the following items approximates fair value because of the short maturity of those instruments: Cash and Cash Equivalents, Commercial Paper, Special Deposits, and Interest Accrued.
The following methods and assumptions used to estimate the fair value of each of financial instruments for which it is practicable to estimate that value:
First Mortgage Bonds and Pollution Control Notes The fair value of the Company's first mortgage bonds and pollution control notes is estimated based on the quoted market prices for the same or similar issues of the same remaining maturities.
Preferred Stock Tlie fair value of the Company's prefenel stock is estimat61 based on the quoted market prices for the same or similar issues.
- 7. RETIREMENT BENEFITS The Company has noncontributory retire-ment annuity plans which cover substantially all emplo>ms. Benefits are based principally on the emplo)1x,'s length of service and com-pensation for the five highest paid >ears out of the last 10 >ears of service. It is the Company's policy to fund pension costs accrued each )var to the extent deductible for federal income tax putposes. 'Ihe net pension benefit for 1992, 1991, and 1990 totaled $ 1.5 million, $2.9 million, and
$4.9 million, respectively.
Effective January I, 1993, the retirement benefit plans for hourly and salaried emplo)es were combined into one plan.
Combining the twu plans will not affect bendit levels.
Net pension benefit for 1992, 1991, and 1990 included the following components:
1992 1991 1990 tThousands)
Service cost: Benefits earned during the >var Interest cost on projected benefit obligation Actual return on plan assets Net amortization and deferral Net enston bene t
$ 15,387
$ 13,252
$ 11,968 35,253 32,096 28,636 (60,020)
(111,749)
(6,499) 7 844 63,487 (39,017)
$ 1,536
$ (2,914)
$(4,912)
The funded status of the plans at December 31, 1992 and 1991 were:
1992 1991 Actuarial present value of accumulated benefit obligation:
Vested Non)15ted Total Fair value of plan assets Actuarial resent value of ro'ected benefit obli ation Plan assets in excess of projected benefit obligation Unrecognized net transition asset Unrecognized net (gain) loss Unreco ized rior service cost Net enston asset tThousands)
$287,504
$270,052 42,286 34,o67
$329,790
$304,119
$701,893
$659,993 (480.429)
(440,519) 221,464 219,474 (80,850)
(88,103)
(139,729)
(132,642) 5,209 5,578
$6,094
$4,3o7 Plan assets primarily consist of equity securities, corporate, U.S. agency, and Treas-ury bonds, and cash equivalents.
For 1992, 1991, and 1990, the projected benefit obligation was measured using an assumed discount rate of 7.75%%d, 7.75%, and 8N, respectively, and a long-term rate of increase in future compensation levels of 6%%d, while the net pension benefit was measured using an expected long-term rate of return on plan assets of 7.5%%d.
In addition to providing pension benefits, the Company provides certain postretirement benefits for retired emploies and their depen-dents. Substantially all of the Company's emplo>es who retire under a Company pen-sion plan may become eligible for those benefits at retirement. At December 31, 1992, 1991, and 1990, 1,905, 1,866, and 1,785 retirees and their dependents, respectively, were covered under the Company's compre-hensive health insurance plan and pnscription drug plan, vvhich the Company self-insures. The cost of providing those bene-fits to retirees was approximately $ 5 million,
$4.4 million, and $4.1 million in 1992, 1991, and 1990, respectively.
The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 106, Employers'ccounting for Postretirement Benefits Other Than Pensions (SFAS 106) in December 1990. SFAS 106 requires that the Company accrue a liability for estimated future postretirement benefits during an employe's working career rather than recognize an expense when benefits are paid. SFAS 106 is effective for fiscal >zan beginning after December 15, 1992.
The Company adopted SFAS 106 in January 1993. At the time of adoption, the actuarially determined accumulated postretire-ment benefit obligation attributable to eligible plan participants and eligible dependents was
$225 million. The Company plans to recog-nize the accumulat61 benefit obligation over 20 >ears in accordance with SFAS 106. Adop-tion of the new standard is expected to increase annual expenses, before deferral for ratemaking purposes, by about $32 million, or 7 times the 1992 expense.
In March 1992, the PSC issued a draft Statement of Policy concerning the account-ing and ratemaking treatment for postretire-ment benefit costs. This draft policy provides for, among other things, recovery in rates for deferred SFAS 106 costs. In addition, the draft policy proposes that deferred SFAS 106 costs will be recovered in rates within 10 years of the adoption of SFAS 106. The Statement of Policy is expected to be approiel by the PSC during the spring of 1993. In addition, the July 1992 rate decision allows the Company'o recover a portion of SFAS 106 costs in rei enues from its customers and to defer the remainder of these costs for recovery, in accordance vdth the draft Statement of Policy.
The Company anticipates that future SFAS 106 costs will be recoverable through rates.
37
- 8. JOINTLY-OWNED ENERATING STATIONS e Mile Point Unit 2 The Company has an undivided IS% inter-est in the output and costs of the Nine Mile Point nuclear generating unit No. 2 (NMP2) which is being operated by Niagara Mohawk Power Corporation (Niagara Mohawk). Owner-ship of NMP2 is shared with Niagara Mohawk 41'A, Ixing Island lighting Company 18K, Rochester Gas and Electric Corporation 14%,
and Central Hudson Gas Bi. Electric Corpora-tion 9X. The Company's share of the rated capability is 188,000 kilowatts. The Com-pany's net utility plant inmstment, excluding nuclear fuel, was approximately
$660 million and $679 million, at December 31, 1992 and 1991, respectively. The accumulated provision for depreciation was approximately $90 mil-lion and $72 million, at December 31, 1992 and 1991, respectively. The Company's share of opemting expenses is included in the Consolidated Statements of Income.
An interim operating agreement that pro-vided for policy, budget, and ntanagement oversight functions of NMP2 by the four non-rating cotenants expixd on December 31, Z. Effective January I, 1993, an operating agreement replaced the interim operating agreement, and its temis are substantially the same. The operating agreement, which expires December 31, 1994, provides for automatic extensions unless terminated by one or more of the cotenants after appropriate notice. The operating agreement is subject to PSC approval.
In August 1992, the Nuclear Regulatory Commission (NRC) issued a systematic assess-ment of licensee performance (SALP) review of the Nine Mile Point Station (includes both Nine Mile Point nuclear generating unit No.
I and NMP2) for the period April 1991 through May 1992. The M.P report indicated that Nh1P2 operates safely and is a good overall performer. The ratings for plant operations, engineering/technical
- support, radiological controls, saf'ety assessment/quality verification, and maintenance/surveillance remained at Category 2, representing good performance.
Emergency prepatedness and security safeguanls remained at Category I, nting superior performance.
A low level radioactive waste managemenl and contingency plan has been developed for Nh1P2 and provides assurance that it is prop-erly prepared to handle interim storage of low level radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of Energy (DOE) for disposal of high level radioactive waste (spent fuel) from NMP2. The DOE announced in early 1990 thai the schedule for start of operations of their high level radioactive waste repository had slipped from 2003 to no sooner than 2010. The Company has been advised by Niagara Mohawk that the NMP2 Spent fUel Storage Pool has a capacity for spent fuel that is adequate until 2014. If further DOE schedule slippage should occur, the recent development of pie-licensed diy storage facili-ties for use at any nuclear power plant extends the on-site storage capability for spent fuel at NMP2 beyond 2014.
NMP2's next refueling outage is antici-pated to begin in September 1993.
Nuclear Insurance Niagara Mohawk maintains public liability and property insurance for NMP2. The Com-pany reimburses Niagara Mohawk for its W share of those costs.
The Price-Andetson Amendments Act of 1988 increased the public liability limit for a nuclear incident to approximately $7.6 bil-lion. Should losses stemming from a nuclear incident exceed the commercially available public liability insurance, each licensee of a nuclear facilityveld be liable for up to a maximum of $63 million per incident, payable at a rate not to exceed
$ 10 million per >ear.
The Company's maximum liability for its IS% interest in NMP2 would be approxinuttely
$ 11 million per incident. The $63 million assessment is subject to periodic inflation indexing and a 5% surcharge should funds priv insuAicient to pay claims associated with a nuclear incident. The Price-Andenon Act also requires indemnification for precau-tionaiy evacuations whether or not a nuclear incident actually occuts.
Niagara Mohawk maintains nuclear prop-erty insurance for NMP2. Niagara Mohawk has procured property insurance aggregating approximately $2.6 billion through the Nuclear Insurance Pools and the Nuclear Electric Insurance Limited (NEIL). In addi-tion, the Company has purchased NEII.
insurance coverage for the extra expense incurred in purchasing replacement power during prolonged accidental outages.
Under NEIL programs, should losses resulting from an incident at a member facility exceed the accumulated resents of NEHeach member, including the Company, would be liable for its share of the deficiency. The Company's maximum liability under the property dam-age and replacement power coverages is approximately $2.3 million.
Nuclear Fuel Disposal and Nuclear Plant Decommissioning Costs Niagara Mohawk has contracted with the DOE for the disposal of nuclear fuel. The Company is reimbursing Niagara Mohawk for its I8% share of the cost under the contract (currently approximately $ 1 per megawatt hour of net generation).
The Company has been informed by Niagara Mohawk that its 18% share of the cost to decommission NMP2 is currently esti-mated to be $235 million in 2027, when decommissioning is expectnl to commence.
Included in the Company's current electric rates is an annualized allowance of approx-imately $ 1.6 million, based on Niagara Mohawk's estimate, which the Company expects will provide for its I8% share of decommissioning NMP2 in 2027.
In March 1990, the Company established a
Qualified Fund under applicable provisions of the federal tax law. The fund also complies with NRC regulations which require the use of an external trust fund to provide funds to decommission the contaminated portion of NMP2. The balance in this fund was approx-imately $3.9 million and $2.4 million at December 31, 1992 and 1991, respectively, and is included in other property and Inmst-ments on the Consolidated Balance Sheets.
Niagara Mohawk filed a decommissioning report for NMP2 with the NRC. The report outlined the proposed plans, which included the Company's funding plan, to provide linancial assurance to fund costs lo decom-mission NMP2 when its license expires.
Homer City The Company has an undivided 5% inter-est in the output and costs of the Homer City Generating Station, which is comprised of three genemting units. The station is owned with Pennsylvania Electric Company which operates the facility. The Company's share of the rated capability is 952,000 kilowatts and its net utility plant innstment was approx-imately $251 million and $257 million at December 31, 1992 and 1991, respectively.
The accumulated provision for depreciation was approximately $ 148 million and $ 144 million, at December 31, 1992, and 1991, respectively. The Company's share of operat-ing expense is included in the Consolidated Statements of Income.
38
- 9. COMMITMENTSAND CONTINGENCIES Construction Program The Company has made substantial com-mitments in connection with its construction program and estimates that 1993 costs will approximate $271 million. The program is subject to periodic review and revision, and actual construction costs may vary because of revised load estimates, imposition of addi-tional regulatory requirements, and the availability and cost of capital.
Environmental Matters The Company continually assesm actions that may need to be taken to ensure compli-ance with changing environmental laws and regulations. Compliance programs will very likely increase the cost of electric and natural gas service by requiring changes to its opera-tions and facilities. Historically, rate recovery has been authorized for the cost incurred for compliance with environmental laws and regulations.
Due to existing and proposed legislation and regulations, and legal proceedings com-menced by governmental bodies and others, the Company may also incur costs from the disposal of hazardous substances produced during the Company's operations or those of its predecmors.
The Company has been noti-lied by the U.S. Environmental Protection Agency (EPA) and the New York State Depart-ment of Fnvironmental Conservation that the Company is among the potentially responsible parties who may be liable to pay for costs incurred to remediate certain hazardous sub-stances at 9 waste sites, not including the Company's inactive gas manufacturing sites which are discussed below. With respect to the 9 sites, I site is included on the Federal National Priorities List, I site is unlisted but is the subject of an EPA administrative order, and 7 sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry). Any liability may be joint and several for certain of these sites. The ultimate cost to remediate these sites will be dependent on such factom as the remedial action plan selected, the extenl of site contamination, and the portion attributed, if any, to the Company. As a result, the Com-pany is unable to estimate the extent of possible remediation costs. There is no clear precedent with the PSC for rate recovery of these t)ps of remediation costs. Hogdeer, since the PSC has previously allovel the Company to tamer similar costs in rates (e.g, investigation and clean-up costs relating to coal tar sites), the Company expects to recover any remediation costs that it may incur.
A number of the Company's inactive gas manufacturing sites have been listed in the New York State Registry. The Company has filed petitions to delist the majority of the sites. The Company's program to investigate and initiate remediation at its 38 known inactive gas manufacturing sites has been extended through 2000. Fstimated expendi-tures over this time period are $25 million, which are ieflected in'the Company's Consoli-dated Balance Sheets at Decmber 31, 1992, to investigate and initiate remediation, as necessary, at the known gas manufacturing sites. The Company expects to recover such expenditures in rates, as the Company has previously been allowel by the PSC to recover such costs in rates.
The Clean Air Act Amendments of 1990 (1990 Amendments) w'll result in significant future expenditures for the reduction of sulfur dioxide, nitrogen oxides, and possibly toxic emissions at several of the Company's coal-fired generating stations.
Under the 1990 Amendments, the Company must reduce its annual sulfur dioxide emissions by 4gà from approximately 138,000 tons in 1989 to 71,000 tons by 2000. The Company estimates that over a 25->ear period the cost to comply with the sulfur dioxide and nitrogen oxide limita-tions specified in the 1990 Amendments is approximately $252 million (on a present value basis) for all capital and operating and maintenance expenses, of which $ 17.3 million has been incurred to date. This cost includes
$ 159 million for an innovative flue gas desulfurization (FGD) sistern and a nitrogen oxide reduction sistern expected to be com-pleted in 1995 at the Company's Milliken Generating Station (Milliken).
In September 1991, the Company its selected by the DOE to receive federal funds for these systems. In October 1992, the DOE approiei $45 million for these systems. In addition, the Company expects to receive funding totaling up to $ 17 million from other sources. The Company estimates that a 2% electric rate increase will be required for the cost of reducing sulfur dioxide and nitro-gen oxides emissions for both Phase I (begins January I, 1995) and Phase H (begins Janu-ary I, 2000).
The cost of controlling toxic emissions, if required, cannot be estimated at this time.
Regulations may be adopted at the state level which would limit emissions even further, at an additional cost to the Company. The Com-pany anticipates tliat the costs Incumxl to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual emissions allowances to each of the Company's coal.flred generating sta-tions based on statutory emissions limits. An emissions allowance represents an authoriza-tion to emit, during or after a specified calendar )ear, one ton of sulfur dioxide.
During Phase I, the Company estimates that it will have allowances in excess of the affected coal-fired generating stations'ctual emissions. The Company is considering var-ious methods of using, banking, or selling these excess emissions allowances. During Phase H, the Company estimates that the annual tons emitted by its coal-fired generating stations will equal its annual emissions allowances.
In addition to the annual emissions allowances allocated to the Company by the EPA, the Company may obtain extension
- 9. COMMITMENTSAND CONTINGENCIES (Continued) nu allowances that the EPA will issue to companies electing to build scrubbers in Phase I such as the FGD sistern at Milliken.
Due to the uncertainty of how many exten-sion mene allowances will be demanded, the extent to which the demand may exceed the supply, and the method of allocating exten-sion reserve allowances, the Company entered into a pooling agreement with other utilities which are eligible to receive some of the extension reserve allowances. This agreement pmvides assurance that the Company will receive some of the extension reserve allowances in the event that demand exceeds supply.
Long-Term Power Purchase Contracts The Company has on line and under con-tract 347 megawatts (mw) of NUG power. In addition, another 257 mw of NUG power is under construction. The Company is required to make payments under these contracts only for the power it recess.
During 1992,
- 1991, 1990 the Company purchased approx-ely $71 million, $30 million, and million, respectively, of NUG power. The Company estimates that it will purchase approximately $ 151 million, $251 million, and $287 million of NUG power for the pars
- 1993, 1994, and 1995, respectively. The requirement to purchase NUG power is expected to be a major contributor to rate increases over the next 3 pars, and is expected to increase rates by approximately 8% during this time period.
In June 1992, the Company enteiel into an agreement with Indeck Energy Services of Kirhvood, Inc., Indeck Energy Services, Inc.,
and Indeck Kir4md Limited Partnership to terminate the power purchase agreement for the 55 mw Indeck-Kirkwmd project. The ter-mination agreement will save ratepaprs an, estimated
$350 million over 20 pars. In Jan-uary 1993, the PSC approved full recovery of the $ 11.5 million in termination costs in rates.
In December 1992, the Company entered into an agreement with Kamine/Besicorp Coming LP., Kamine South Coming Cogen Co., Inc., and fata South Coming, Inc. to terminate the power purchase agreement for the 79 mw South Coming cogeneration proj-ect. The termination agreement will save customers an estimated
$300 million over 25 years. The Company plans to petition the PSC in early 1993 to recover $34 million in termi-nation costs in rates. Terminating these agreements is part of a continuing effort by the Company to minimize future rate increases associated with uneconomical power purchases from NUGs.
As a nuit of the PSC's competitive bid-ding program, the Company is contracting for 25 mw in conservation projects to be avail-able by November 1994. In accordance w'th a PSC ruling issued in October 1992, the Com-pany will conduct an auction for an additional 10 mw of conservation projects.
The timing of the auction has not yet been determined, but the Company does not expect that those conservation projects will be avail-able before 1995. The Company expects to recover the costs associated with these con-tracts from its customers. Tlie Company will utilize various methods, including competitive bidding, to minimize the economic impacts on customers of adding new resources to its sistern, while maintaining the Company's current Iml of system reliability.
Coal Purchasing Contracts The Company has long-term contracts with nonaffiliatel mining companies for the pur-chase of coal for the jointly-owned Homer City Generating Station. The contracts, which expire between 1995 and the end of the expectel service life of the generating station, require the purchase of either lixed or minimum amounts of the station's coal requirements.
The price of the coal under one of these contracts is based on recovery of pro-duction costs plus incentive. The remaining contracts are based on fixed price plus escala-tion provisions. lite Company's share of the cost of coal purchased under these agree-ments is expected to aggregate
$55 million for 1993.
In add,'tion, the Company has a long-term contract for the purchase of coal for the Kint-igh Generating Station. The contract, which expires in 1997, supplies the annual coal requirements of the station. One-third of the tonnage price is renegotiated annually to reflect market conditions. The delivered cost of coal purchased under this agreement is expected to be $56 million for 1993.
Federal Energy Regulatory Commission (FERCI Proceeding In August 1991 and October 1992, the FERC issued orders tvhich revised its generic policy related to filing requirements for contracts determined to be subject to its jurisdiction under the Federal Power Act.
Under the revised policy, FERC may require a utility to refund certain revenues collected under late-filed contracts.
In December 1992, FERC issued a notice requesting comments from interested parties relating to its filing requirements for con-tracts. The notice solicited comments on whether the obligation to file jurisdictional agreements should extend to certain temii-nated agieements as well as existing agreements.
The Company and many other utilities filel comments in January 1993 chal-lenging the filing requirements and the appropriateness of the refund obligations.
The Company continues to review its compliance with FERC contract filing requirements.
In October 1992, the Company determined that it may be required to file at least four additional contracts with FERC. The Company is unable to predict what actions FERC may take as a result of its notice and is unable to estimate the amount and timing of refunds, if any, that may be required.
Therefore, the Company cannot predict the ultimate disposition of this matter, but belie@5 that it will not have a material adverse effect on its financial position.
40
- 10. INDUSTRY SEGMENT INFORMATION Certain information pertaining to the electric and natural gas operations of the Company is:
1992 1991 1990 Operating Revenues Fspenses Income Depreciation and amortization'onstruction expenditures Identifiable assets" Electric
$ 1,451,525
$ 1,146,619
$304,906
$ 150,549
$210,185
$4,49o,436 Natural Gas
$240,164
$221,307
$ 18,857
$8,428
$35,433
$373,269 Electric tThousands)
$ g67,936
$ 1,056,969
$310,967
$ 145,700
$210,127
$4,42o,i66 Natural Gas
$ 187,879
$ 177,75I
$ 10,128
$6,68o
$35,756
$33o,7S4 Electric
$ 1+34,509
$ 1,021,669
$312,840
$ i42,286
$ 187,66o
$4,355,218 Natural Gas
$ 162,271
$ 147,278
$ 14,993
$5373
$23,065
$236828
'lndudal in operaiing epernar.
"keels used in borh eiedfric and nalural gas operaiions rNI Induded abeam'cre S3I2,723, SI73916 arul SI45,885 al December 31, 1992, l99I, and 1990, reyedicrly.
rbey etna&I primarily ofcash and cash cluing alenls, yodal delnnirc preingrnenls, and unamoriired debl etlnrue.
- 11. SUPPLEMENTARY INCOME STATEMENT INFORMATION Charges for maintenance, repairs, and depreciation and amortization, other than those set forth in the Consolidated Statements of Income, Nere not significant in amount. Taxes, other than federal income taxes, are:
1992 1991 1990 tThousands)
Pmperty Franchise and gross receipts Payroll Miscellaneous Tolal OCker Ta.dies
$81,640 92,153 17,096 10,052
$76,s89 76,721 is,467 9,408
$200,941
$ 178 185
$73,495 62,849 14,179 8,247
$ 158,770
41
- 12. QUARTERLY FINANCIAL NFORMATION(UNAUDITED)
M h31 June 30 Sept.30 Dec.31 tThousends, Except Per Share Amounts) 1992 Operating revenues Operating income Net income Flemings for common stock Fzminy per share Dividends per share Average shares outstanding Common stock price'igh IBw 1997 Operating reunues Operating income Nel income Earnings for common stock Faminy per share Dividends per share Average shares outstanding Common stock price'igh IA)w
$489,847
$ 111,373
$76,4i6
$71,iG7
$ 1.10
$.53 64,682
$29.G3
$26.i3
$443,5sl
$ 105,695
$73,208(1)
$68,909
$ 1.iO
$.52 62,54z
$z6.75
$2438
$401,934
$82,755
$46,772
$4i,488
$.Go
$.53 68,800
$29.38
$26.75
$373,362
$81,992
$43,087
$37,722
$.60
$.52 62,775
$27
$24
$367,833
$60,109
$2G,581
$21,320
$.54 69,o63
$32
$29.25
$349,6z6
$66,oos
$29,374
$23,997
$.38
$.53 63,oz4
$27.63
$24.63
$432,075
$69,52G
$34)199
$28,998
$.42
$ 54 69,318
$32.75
$30.38
$3s9,246
$67,4oo
$22,974(2)
$'17,685
$.28
$.53 63,273
$29.63
$26.63 First quarter 1991 results reflect the stockhoMeis'hare of proceeds from the settleinent of lawsuits relating to the design and construction of Nh1P2 which increased net income and earnings for common stock by $3.9 million, and increased eaminy per share by 6.2 cents.
(2) Fourth quarter 1991 results reflect an adjustment to the Homer City Coal Cleaning Plant, which decreased net income and eaminy for common stock by $3.5 million, and decreased eaminy per share by 5.6 cents, and the stockholders'hare of a settlement of an antitrust lawsuit which decreased net income and earnings for common stock by $ 1.9 million, and decreased eaminy per sltare by 3 cents.
- The Company's common stock is listnl on the New York Stock Exchange. The number of stockhoMers of record at December 31, 1992 was 61,183.
Dividend limitations: After dividends on all outstanding preferred stock have been paid, or
- declared, and funds set apart for their pay-ment, the common stock is entitled to cash diyidends as may be declared by the Board of Directors out of retained eaminy accumu-lated since December 31, 1946. Common Stock dividends are limited if Common Stock Equity (43.7X at December 31, 1992) falls bellv 25% of total capitalization, as defined in the Company's Certificate of Incorporation.
Dividends on common stock cannot be paid unless sinking fund requirements of the pre-ferred stock are met. The Company has not been restricted in the payment of dividends on common stock by these provisions. The retained earnings balances of $327,040 and
$308,688 million as of December 31, 1992 and 1991, respectiwly, have been accumu-lated since December 31, 1946.
42 REPORT OF MANAGEMENT The Company's management is responsible for the preparation, integrity, and objectivity of the consolidated flnancial statements, notes, and other information in this Annual Report. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles and include estimates which are basel upon manage-ment's judgment and the best available information. Other financial information contained in this report was prepared on a basis consistent with that of the consolidated financial statements.
In recognition of its responsibility for the consolidated financial statements, management maintains a system of internal accounting controls which is designed to provide reasonable assurance as to the integrity and reliability of the financial statements, the protec-tion of assets from unauthorized use or disposition, and the prevention and detection of fraudulent financial reporting. hianage-ment continually moniton its system of internal controls for compliance. The Company maintains an internal audit department which independently assesm the effectiveness of the internal con-trols. In addition, the Company's independent accountants, Coopers
& Lybrand, have considered the Company's internal control struc-ture to the extent they considered necemry in expressing an opinion on the consolidated financial statements.
hlanagement is responsive to the nxmmmendatfons of its internal audit department and Coopers & Lybrand concerning internal controls and corrective measures are taken when considered appropriate. Management hellene that as of December 31, 1992, the Company's system of internal controls provicles reasonable assurance as to the integrity and reliability of the consolidated financial statements.
The Board of Directors oversees the Company's financial report-ing through its Audit Committee. This Committee, which is comprised entirely of outside directors, meets regularly with man-
- agement, the internal auditor, and Coopers & I.ybrand to discuss auditing, internal control, and financial reporting matters. To ensure their independence both the internal auditor and indepen-dent accountants have free access to the Audit Committee, without management's presence.
REPORT OF INDEPENDENT ACCOUNTANTS Coopers 8 Lybrand To the Stockholders and Board of Directors, New York State Electric & Gas Corporation and Subsidiary Ithaca, New York We have audited the accompanying consolidated balance sheets of New York State Electric & Gas Corporation and Subsidiary as of December 31, 1992 and 1991, and the related consolidated state-ments of income, changes in common stock equity, and cash flows for each of the three pm in the period ended December 31, 1992.
~ These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standmls. Those standanls require that we plan and per-form the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
We believe tliat our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above pre-sent fairly, in all material respects, the consolidated financial position of New York State Electric & Gas Corporation and Subsid-iary at December 31, 1992 and 1991, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1992, in conformity with generally accepted accounting principles.
James A. Garrigg Cbairnran, Presidenl and Chief Eveculirv; Ogicer New York, New York January 29, 1993 Sherwood J. Rafferty Vice Presidenl and yyeasurer (CbiefFinancial Ogicer)
Everett A. Robinson Vice Presidenl and Conlroiier (ChiefAmunling Opiner)
43 SELECTED FINANCIALDATA ousands - Except Per Share Amounts) tmg revenues income Earnings per share Dividends declatel and paid per share Average shares outstanding Book value per share of common stock ()oar end)
Intemt charges AFDC and non<ash return Depreciation and amortization Other taxes Construction expenditures Total assets
)xnan -term obli ations, c ital leases, and redeemable 1992
$ 1,691)G89
$ 183,968
$2.40
$2.14 67,972
$22.85
$ 155,388
$6,482
$ 158,977
$200,941
$245)G18
$5,176,428 refened stock
$ 1,883,927 1991
$ 1,555,S)5
$ 168,643
$2.36
$2.10 62,906
$22.16
$ 163,526
$7,54i
$ 152/80
$ 178,185
$245,883
$4,924,s36
$ 1,897,465 1990
$ 1,496,780
$ 158,013
$z.48
$2.06 58,678
$21.85
$ 173390
$5,776
$ 147,659
$ 158,770
$210,725
$4,737,43)
$ 1,766,457 1989
$ 1,427,745
$ 157,779*
2.53'2.O2 57,)38
$21.29
$ )so,o6s
$6@7
$ 148,375
$ i46,6o5
$ 192,022
$4,670,283
$ 1,799,800 1988
$ 1,340,169
$ 171,467'2.814.
$2.00 56,239
$20,71
$ 199,730
$28,788
$ )34,037
$ )36,706
$228,223
$4,693,277
$ 1,837,648
'iVet inconre and earnings per sbare for 1988 anrl 1989 indnde lbe egects ofadj nslmenls recorrled in rtpril 1988 anrl December 1989 lo lbe 1987 tVine i(file Poinl nndear generaling rmit Ão.2 write-ojj. 8xdrrding those arjlrrstments nel inconre and earnings per sl~re for 1988 and 1989 uere f165377 and $2.70 and gl51,998 and g2.43, repedively.
GLOSSARY Allowance for funds used during construction (AFDC): the cost of money to finance a project v hich is added to truction costs and recovered over the life he asset Allowed return on common equity:
the cost of common equity as determined by the PSC Book value per share: common stock equity divided by the number of common shares outstanding for the period Btu (British thermal unit): the quan-tity of heat required to raise the temperature of one pound of water by one degree fahren-heit at sea level Common equity: the value of common stockholders'nvestment in a company along with retained eaminy Competitive bidding: a mandated prem by which utilities must seek bids for additional generation or demand-side management projects Dekatherm:
a measure of heating value equal to one million Btu (1,000 cubic feet of natural gas (one mco equals approximately one dekathenn)
Demand-side management (DSM):
planning and implementation of pro-designed to help midential, commer-
, and industrial electric customers consent'nergy Earnings for common stock: eam-iny after all expenses are recognized and prefenel dividends have been paid Earnings per share:
earnings for com-mon stock for a given period dividel by the average number of shares outstanding for the period Embedded cost of long-term debt:
the average interest rate on long-term debt outstanding at the end of the >oar Heat rate: a measure of generating sta-tion efficiency often expressed as the number of Btu needed to generate one kilowatt-hour of electricity Load factor: the average load of an electric or natural gas distribution s)stem compared to its maximum load capability for a certain period of time, expressed as a percentage Market-to-book ratio: an indication of the market's perception of a stock's value (a ratio of over 100 indicates that the market believe the stock is ivorth more than its book value)
Net income: earnings after all expenses are recognized, but before preferred dividends are paid Non-utilitygenerator (NUG): a non-traditional pomr generator that is also known as an independent power producer or energy service company Peak load: the point of highest cus-tomer demand for electricity (the Company is a w'nter peaking utility; its record peak is 2,597 megawatts)
Price/earnings (P/E) ratio: a mea-surement of the market's petoeption of a company's youth potential (the higher the P/E ratio, the more potential the market be)i@15 there is for yore)
Retained earnings:
the portion of eaminy that is reimt5ted in the business and not paid out as dividends Return on common equity: the rate of return earned on common equity calcu-lated by dividing earnings for common stock by average common equity Total shareholder return: the increase in the value of a shareholder's iniostment including dividends received and changes in the market price per common share Transportation gas: natural gas pur-chased directly from a supplier by an end user and transported, for a fee, by a local dis-tribution company such as the Company Unbilled revenues:
the estimated revo-nues attributable to energy which has been delivered to the Company's customers but for which the metered amount has not been billed to the customers Watt: one ampere of electric current under one volt of pressure (one kilowatt is 1,000 watts; one kilowatt-hour is one kilowatt usel for one hour, and one megawatt is 1,000 kilowatts or one million watts)
Ytetd: the return which dividends provide a shareholder calculated by dividing the cur-rent annualized dividend per share by the cunent market price per share
44 FINANCIALAND OPERATING STATISTICS 1992 1991 1990 1989 1988 1987 198 OPERATING REVENUES Electric Natural as tThousands, except Per Share Amounts)
$ 1>451>525
$ 1,367,936
$ 1/34,509
$ 1,26o,668
$ 1,191,806
$ 1,136,799 240,164 187,879 162,271 161,077 148363 152.839
$768,717 TOTAL 1,G91,G89 1,555,815 1,496,780 1,427,745 1340,169 1,289,638 953,714 OPERATING EXPENSES Fuel used in electric generation Electricity purchased Natural gas purchased Other operating expenses Maintenance Depteciation and amortixation Federal income taxes Other taxes 262>531 95,026 12G,815 318,G80 102,500 158,977 102,45G 200,941 274,877 45,808 99,528 279g64 110,131 152,380 94,447 178,185 274,245 34,6i3 88,589 268,829 io6,665 147,659 89,577 158,770 279,075 26,019 101,598 238,804 97,420 148,375 Q,4S9 146,605 253,326 19,432 82,822 2i3,959 90,097 134,037 81,689 136.706 249,520 29,638 90,974 195,204 93,274 iio,679 110,355 128,776 200,895 68,781 132,300 125,044 6o,54i 53,174 53,6o6 82,877 TOTAL OPERATING INCOillE OTIIER INCOME AND DEDUCTIONS 1,3G7,926 323,763 12,03G 1,234,720 321,095 6.o76 328,101 327,833 325,360 (1,508) 7,474 28350 1,168,947 1,102385 1,012,068 i,oos,4zo 281,218 (73,876) 777.218 176,496 66,346 INCOME BEFORE INfEREST CHARGES INTEREST CHARGES Interest on long-term debt Other interest Allowance for borrovttxi funds used durin construction INIXRESI'IIARGES-NEf INCOilIE BEFORE CUMULATIVEEFFECT OF ACCOUNTING CHANGES Cumulative effect for )eats prior to 1987 of accounting change for disallow~el project costs (less applicable taxes of $95,434)
Cumulative effect for )ears prior to 1987 of accounting chan e for income taxes NET INCOME (LOSS)
PREFERRED STOCK DIVIDENDS EARNINGS (LOSS)
AVAILABLEFOR COibIMON STOCK COMMON STOCK DIVIDENDS RETAINED EARNINGS INCREASE DECREASE Average number of shares of common stock outstanding Earnings (ix5s) per share Dividends aid r share 335,799 145,822 9,5GG (3,557) 151,831 183,968 183,968 20,995 162,973 144,621
$ 18,352 67,972
$Z.40
$2.14 327,171 151,649 11,877 (4,998) 158,528 168,Q3 168,643 20,330 148,313 131,875
$ i6,43S 62,9o6
$2.36
$2.10 326325 158,209 15,181 (5,078) 168312 158,013 158,013 12,662 145,351 121,302
$z4,049 58,678
$2.48
$z.o6 33z.s34 164,573 15,495 (5,013) 175,055 157,779 157,779 12,975 i44,so4 115,224
$29,580 57,138
$2.53
$z.oz 356,451 187,304 12,426 (i4,746) 184,984 171,467 i7i,467 13,492 157,975 112,252
$45,723 56,239
$2,81
$z.oo 207,342 195,264 7,057 (47,312) 155.009 52333 (210,914)
(19,156)
(177,737) 13.662 (191899) 145.794
($337,193) 55318
($346)
$2.64 24z,s4z io4,oso 5,186 (11,5 97,74>
145,095 145,095 22,610 122,485 75.484
$47,001 36,41
$3..
FINANCIALSTATISTICS 1992 1991 1990 1989 1988 1987 1982
. ANCIALSTATISTICS Return on average common stock equity. percent Percentage of.AFDC and non~h return to total earnings Mortgage bond interest-times earned Interest charges and prefemd dividends-times earned Book value per share of common stock ()car end) liarket value per share of common stock ()car end)
Dividend payout ratio (percent)
Price earnings ratio ()car end)
PROPERTY, PLANT AND EQUIPhIENT (INCLUDES COiVSTRUCTION WORK IN PROGRESS)
Electric Natural gas Common TOTAL ACCUMULATEDDEPRECIATIOiV CAPITALIZATION(INCLUDES URRENT hIATURITIES) x)ng-term debt Preferred stock Common stock uit 10.G 4.0 3.1 10.7 11.4 11.5*
13.2'2.2'.1 4.0 4.6 15.5 50.3 3.0 2.9 2.9 2.6 1.6 15.2 445 2.7 1.8 1.8 1.8 1.7 1.2 1.9
$22.85
$22.16
$21.85
$21.29
$20.71
$ 19.85
$22.39
$32.50 89.2 13.5
$'29.00
$26.00
$28.88
$22.75
$20.88 89.0 83.1 79.8 71.2 82.2**
12.3 10.5 11.4 8.1 6.54*
$2i.63 62.5 6.4 tThousands)
$4>G94)073
$4,537/56
$4,367,913
$4,217,920
$4,089,485
$3,885,989 3G1,G30 336,199 222,125 201,942 189,580 176,019 205,345 189,135 175,703 155/40 129,860 100.252
$2,616,720 137,788 50,432 tThousands)
$ 1>891>03G
$ 1,825,918
$ 1,815,686
$ 1,801,762
$ 1,985,276
$2,091,678 269,050 270,700 172,350 174,000 178,650 183,320 1,58G,474 1,405,147 1,364,344 1,225,184 1,174,028 1,106,518
$ 1,123,789 236,075 888,594
$ 5,2G1,048
$5,062,690
$4,765,741
$4,575,202
$4,408,925
$4,162,260
$2,804,940
$ 1>427>793
$1/09,829
$ 1,174,651
$ 1,063,630
$956,415
$855,198
$526,471 TOTAL CAPITALIZATIOiV
$3,746,5GO
$3,501,765
$3,352,380
$3,200,946
$3,337,954
$3,381,516
$2,248,458 CAPITALIZATIONRATIOS (PERCENT)
Long-term debt Preferred stock Common stock equity NUMBER OF STOCKIIOLDERS Common stock G1,183 Preferred stock 3,829 PAYROLL (INCLUDINGPENSIONS, ETC.)
Charged to operations
$ 181>245 Charged to construction and other accounts 89,463 52.2 54.2 56.3 7.7 5.1 5 4 40.1 40.7 38.3 59.5 53 35.2 61.9 54 32.7 50.0 10.5 39.5 59,593 60,585 62,552 3,943 4,o6s 4,238 (Thousands)
$ 163,421
$ 148,007
$ 140,415 66,6S9 4 444 7o,44i 4,583 76,o73 6,669
$ 132,617
$ 134,484
$94,219 51,015 82,455 72,761 64,890 61,808.
54,276 TOTAL Number of em lo ees ( car end)
$270,708
$245,876
$220,768
$205,305
$ 194,425
$ 188,760
$'145,234 4,888 4,842 4,599 4,558 4,494 4,498 4,426
'Return on average common stock equity for 1987 excludes the effects of the writewffof Nine Mile Point nuclear generating unit No.2 (Nh)P2) and Jamesport disalloij)el costs and the accounting change for income taxes.
The return on equity for 1988 and 1989 excludes tlie NhtP2 witewff adjustments.
"Excludes the 1987 witewffs and accounting diange.
KILOWATr-HOUR(KWH) SALES (MILLIONS)
Residential Commercial Industrial Other 5,472 3,283 3,082 1,457 ELECTRIC SALES STATISTICS 1992 1991 5,297 3,285 3,068 i,457 1990 UI9 3,235 3,175 i,46s 1989 5,233 3,181 3,210 1,431 1988 5,148 3,069 3,159 1,400 1987 4,9o5 2,882 3,018 1,372 198 4,4i2 2,492 2,621 1,201 TOTAL RETAIL Other electric utilities TOTAL 13,294 6,003 19,297 13.107 5,o66 18,173 13,197 4,750 17,947 13,055 4,461 17.516 12.776 3,896 i6,672 12,177 4,295 16,472 10,726 1,827 12,553 OPERATING REVENUES (THOUSANDS)
Residential
$6OI,O42 Commercial 314,272 Industrial 225)832 Other 133,819
$553,056 293,197 207,933 124.575
$521,688 267,598 196,016 116.352
$510,941 26i,6o6 196,701 114364
$ 507,428 257,707 198+44 113,576
$483,531 244,4i6 190,806 iio.s46
$325,124 163,755 128,633 72357 TOTAL RETAIL 1,274,965 I.I78.761 i,ioi,654 1,083,612 1,077,055 1,029,599 689,869 Other electric utilities 143,414 131,412 Unbilled menue mognitlon - net (427) 35333 Other o ratin revenues 33,573 22,430 145,104 42,995 44,756 134,108 48,948 89,784 24,967 109,453 (2,253) 64,780 14,068 TOTAL OPERATING REVENUES
$ 1,451,525
$ 1,367,936
$ 1,334,509
$ 1,266,668
$ 1,191,806
$ 1,136,799
$76s,7i7 OPERATING REVENUES PER mVH (CENTS)
Residential Commercial Industrial Other Total Retail Other electric utilities NUMBER OF CUSTOMERS (YEAR Residential Commercial Industrial Other TOTAL ANNUALAVERAGE USE (IOVH)>>
Residential Commercial Industrial (thousands)
ANiiUALAVERAGE BILL>>
Residential Commercial Industrial 10.98 9.57 7.33 9.18 959 2.39 END) 699,387 72,463 1,508 11,073 784,431 7,843 45,258 2,O47
$s61 4,333 149,955 10.44 893 6.7s 8.55 899 2.59 692,922 7i,463 i,so6 10,907 776,798 7,672 45,s64 2,047
$soi 4,093 138714 9.81 8.27 6.17 7.93 8.35 3.05 685,898 70,802 1,498 10,825 769,023 7,796 45,826 2,i42
$765 3,791 132 265 9.76 8.22 6.13 799 8.30 3.01 676,590 69,230 i,465 io,694 757,979 7,7s6 46,095 2,200
$76o 3,791 134 81 9.86 8.40 6.28 8.11 s.43 2.30 665,296 67,4ss 1,437 io,556 744,777 7,791 45,6oo 2,226
$768 3,829 13 777 9.86 8.48 6.32 8.08 8.46 2.55 653,398 65,923 i,4ii 10,363 731,095 7,569 43,787 2,134
$746 3,713 I34 7.37 6
4 6.o 643 3.55 6o4,936 59,413 1,338 9,843 675,530 7,306 41,895 1,956
$538 2,753 5
5
'Computed using the vjeighted average number of customers for the lear.
47 ELECTRIC GENERATION STATISTICS 1992 1991 1990 1989 1988 1987 1982
'THM CAPABILm (MEGAWATfS)
Coal Nuclear Hplro internal Combustion TOTAL GENERATING CAPABILITY Purchased*Pomr Authority
-Other less: Firm Sales TOTAL SYSTHhI CAPABILITY SYSTEhI CAPABILITY(PERCENT)
Coal Nuclear 11 1lro TOTAL GENERATING CAPABILITY Purchased.Poaer Authority
-Other Less: Firm Sales TOTAL SYSfEM CAPABILITY PRODUCTION STATISTICS Annual load factor (percent)
Coal burned (thousands of net tons)
Coal heat value (Btu per lb.)
tu per kwh generated (net)
WATf-HOUR (KWH) PRODUCTION-NET (MILLIONS)
Generated:
Coal Nuclear H dro TOTAL GENERATED Purchased-Pov er Authority
-Other TOTAL PRODUCTION EXPENSES (THOUSANDS)
Generated Purchased-Pomr Authority
-NUG*
-Other TOTAL COSI'HR KWH (hIILLS)
Generated Puxhased-Pomr Authority
-NUGAE
-Other 0
ratin nse (excludin mduction)
TOTAL ELECTRIC OPERATION AND hlAINfHNANCE HNSES (THOUSANDS) uction Transmission s"
Distribution Customer accounting Customer service Administrative and eneral TOTAL
'Non.utility generator 2,415 188 70 8
2,681 489 347 8
3,509 69 5
2 76 14 10 2,41z 196 70 8
2,686 488 110 3,284 74 6
2 15 3
100 74.6 6,478 12,668 9,902 68.9 6,310 12,610 9,898 16,709 922 301 17,932 1,G35 1,250 20,817 i6,is7 1,180 258 17,595 i,667 343 19,605
$375i209
$391,393 15,GG1 14,668 71,260 30,028 8,105 1,112
$470,235
$437,201 20.92 9.58 5G.SG 21.39 12.15 34.74 22.24 8.80 63.48 21.67 11.34 33.64
$470,235 31,623 64,428 31,180 31,390 94,349
$437,201 3o,46z 62,763 28,861 24845 75,812
$723,205
$659444 z,414 194 68 7
2,683 487 53 3,223 z,4i4 193 66 7
2,680 487 9
(115) 3,061 2,405 67 7
2,673 510 (125) 3,058 68 7
2,461 2,970 75 6
2 83 15 2
6 2
16 (4) 79 6
2 87 17 (4) 81 2
83 17 69.4 6395 12,510 9,936 64.7 6,47z 12,477 9,931 63.5 6,io6 12,572 9,881 6s.s 5,956 12,487 9,897 16,211 743 356 17310 i,6o7 347 i9,264 16845 773 292 17,410 i,667 102 19,179 15,589 639 245 16,473 1,743 45 18,261 15,025 60 280 15365 1,911 583 17,859
$391,977
$381,371
$351,963
$332,250 13,534 12,012 11,360 14,729 7,700 1,905 1,393 1/41 13379 12,102 6,679 13,568
$426,590
$407,390
$371,395
$361,888 22.64 8.4z 62.10 30.41 11.70 33.84 21.91 7.21 56.03 4o.47 10.57 31.81 21.37 6.sz 55.72 26.61 9.6z 29.96 21.62 7.71 55.88 18.84 979 30.05
$426,S9o 30,118 58,876 26,861 27,625 81,815
$407,390
$371,395
$361,888 22,196 49,737 21,031 20,527 62,258 24,3i4 55,673 20,158 12,047 62,66o 29,239 54,420 23,242 23,426 72,405
$651,885
$610 122
$ 547 144
$536,740 1,731 38 11 1,780 768 350 2,898 6i 27 12 6s.i 4,803 11,937 io,67o 10,748 197 10,945 2,104 663 13,712
$248,278 27,511 731 40.539
$317,059 zz.68 13.08 52.21 5299 8.39 31.51
$317,059 13,023 36,495 i6,s68 4,457 44,476
$'432 078
48 NATURALGAS SALES STATISTICS 1990 1989 1992 1991 DHKATHERM (DTH) SALES (THOUSANDS)*
Residential Commercial Industrial Other 24,913 10,796 1,G89 1,959 i4,86 6,532 2,023 2,151 15331 6,9z6 z,i67 2,071 18,115 8,054 1,788 1,917 26,495 29,874 25,515 39,357 TOTAL RETAIL Trans rtation of customer-owned natural as 17,009 12,530 8,157 8,853 56,3GG 35,348 42,404 33,672 TOTAL OPERATING REVENUES (THOUSANDS)*
Residential Commercial Industrial Other
$94,531 37,852 10,267 ii,574
$93,873 38,726 10,437 io,776
$ 152,325
$ 111,106 59,939 43,969 8)092 8,640 10,762 10,243 i54,224 153,812 231,118 173,958 TOTAL RETAIL 7,169 853 25 6,7zi 544 11,G39 (3,626) 1,033 Tmnsportation of customer-owned natural gas Unbilled revenue recognition - net Other natural as revenue 9,571 3,770 580 7,265 8047 13,921 SUBTOTAL TOTAL OPERATING REVENUES
$240,1G4
$ 187,879
$ 162,271
$ 161,077 OPERATING REVENUES PER DTII Residential Commercial Industrial Other Total Retail Transportation NUMBER OF CUSTOMERS (YEAR END)>>
Residential with house heating Residential without house heating Commercial vdth space heating Commercial vdthout space heating Industrial Transportation of customer-owned natural gas Other
$6.38 5.79 5.08 5.38 6.o4 0.88
$6.13 5.46 4.83 H4 5.82 o.76
$6.11 5.55 4.79 5.49 5.87 0.GS
$6.iz 5.59 4.8z 5.20 5.83 o.76 178,625 12,906 23,023 2,24i 342 1,557 117,429 8860 i6,843 i,548 334 277 1,246 II4,497 8,079 i6,6z6 i,476 343 228 i,154 182,795 13,181 23,165 2,282 390 389 1,657 142,4o3 146,037 223,859 TOTAL 219,080 ANNUALAVERAGE USH (DTH)>>>>
Residential Commercial Industrial ANNUALAVERAGE BILL>>>>
Residential Commercial Industrial COST OF NATURALGAS PURCHASED Amount (thousands)
Per dth NATURALGAS OPERATION AND MAIPfKNANCEEXPENSES (THOUSANDS)
Production Transmission and distribution Customer accounting Customer service Administrative and eneral 105 345 4,781 129 42S 4,387 126 386 6,246 119 358 6,0o3
$786 2)377 21)018
$763 2,076 3o,466
$641 1,882 23,102
$774 2,158 30,079
$ 12G)815
$3.22
$88,589
$ 101,598
$3.64
$3.57
$99,528
$3.30
$ 126,984 19)938 9)233 8,152 18,040
$88,901
$ 102,014 13,982 13,247 5,765 4,99o 5,942 3,972 6,464 8,571
$ io1,458 18,491 8,046 6,533 15,735
$ 182,347 150263 121054 127 TOTAL
'The inc)ease in 1991 is primarily due to the acquisition of Columbia Gas of New York, lnc.
"Computed using the weighted average number of customers for the >ear.
1988 14,818 7,055 3,121 2,242 27,236 7,825 35,061
$83,115 35,680 12,821 10,738 142354 5,523 486 6,009
$ 148863
$5.61 5.o6 4.ii 4.79 5.24 0.71 111,543 8+0 16,419 i,444 343 zi4 1,133 139,436 125 398 8,694
$703 2,012 35,713
$82,822
$3.02
$83,155 11,712 4,516 3,352 9,758 1124 3
1987 13,897 6,803 3,038 2,499 26,237 5,959 32,196
$85,242 37,620 13,909 12,620 149,391 2,931 517 3,448
$ 152.839
$6.13 5.53 4.58 5.05 5.71 0.49 108,515 8,220 16,265 i,4o8 149 1,202 136,159 120 387 7,6i4
$738 2,139 34,86o
$90,974
$3.43
$91,369 11,570 4,656 2/74 11,901
$ 121.870 i5,688 8,123 9,804 4,3i4 37,929 37,929
$83,167 38,192 43,383 20,255 184,997
$ 184,997
$5.30 4.7o 443 103,033 9,057 14,980 1,383 386 1,141 129,980 14o 5i4 25,531
$742 2,417 112,977
$ 132/00
$3.49
$ 132
(
3,-
I,I41 8,66i 155483
VESTOR INFORMATION Binghamton Executive Offices 4500 Vestal Parkway East P.O. Box 3607 Binghamton, NY 13902-3607 (607) 729-2551 Ithaca Executive Offices Ithaca-Dryden Road P.O. Box 3287 Ithaca, NY 14852-3287 (607) 3474131 General Counsel Independent Accountants Huber Lawrence K Abell Coopers 8c Lybrand 605 Third Avenue 1301 Avenue of the Americas New York, NY 10158 New York, NY 10019 To present certificates for transfer write to:
Chemical Bank Attention: Stock Transfer Administration P.O. Box 24935 Church Street Station New York, NY 10249 (Certified or registered mail is recommended.)
For stock transfer instructions, write to:
Chemical Bank Attention: Legal Transfer 450 West 33rd Street New York, NY 10001 ase contact NYSEG shareholder services with stions regarding:
dividend payments or lost dividend checks a direct deposit of dividends a our dividend reinvestment and stock purchase plan a replacement of lost certificates a a change of address a report requests a our annual meeting of stockholders We are available between 8 a.m. and 4:30 p.m.
(Eastern Time) on regular business days at
'I-800-225-5643. Or you may write to:
New York State Electric 8c Gas Corporation Attention: Shareholder Services P.O. Box 3200 Ithaca, NY 14852-3200 You may also obtain a free copy of Form 10-K, which is filed each year with the Securities and Exchange Commission, by contacting shareholder services at the telephone number or address above.
Securities Listed on the New York Stock Exchange a Common Stock D 3.75% Preferred Stock D 8.89Y0 Preferred Stock a
8.480/0 Preferred Stock ($25 par value) a Adjustable Rate Preferred Stock ($25 par value) a 7 5/80/o First Mortgage Bonds (Due 2001) a 8 5/80/o First Mortgage Bonds (Due 2007)
Trading Symbol The trading symbol for our common stock which is listed on the New York Stock Exchange is NGE.
Annual Meeting Friday, May 14, 1993 at 11 a.m.
Ithaca Executive Offices Ithaca-Dryden Road Dryden, NY Formal notice of the meeting, a proxy statement and form of proxy willbe mailed to stockholders in early April.
New York State Electric'& Gas Corporation Ithaca-Dryden Road P.O. Box 3287 Ithaca, NY 14852-3287 BULK U
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New Tork Ct Territory served by Long Island Lighting Company Meeting the challenge...
The Long Island Lighting Company's 6,500 employees provide electric and gas service to more than 1 millioncustomers in Nassau and SuffolkCounties and the Rockaway Peninsula in Queens County.
LILCO's service territory covers 1,230 square miles with a population of approximately 2.7 million people.
l992 Highlights Public Service Commission approved common stock dividend reinvestment plan First mortgage and general and refunding bonds upgraded one notch above investment grade
~
Common stock trading at a 21-year high Common stock quarterly dividend increased to 43.5 cents On tho cover: Long Island's 1,180 milos ofcoastline offer some oftho world's best recreation to swimmers, bootors and water sports enthusiasts.
ltLCO's mission is to provide unparalleled service to our more thon 1 mt%I'on customers.
To Our Shareowners In 1992, LILCOcontinued its trend of improving its financial performance. Earnings for the year were $238 million, or $2.14 per common share, with quarterly stock dividends increasing to 43.5 cents per share on October 1, 1992.
LILCO's improved financial position resulted in favorable actions by the rating agencies.
In 1992, the Company's principal securities were upgraded for the third consecutive year, a show of confidence that allowed LILCOto refinance higher cost securities, saving the Company and our customers more than $ 17 million a year in interest expense.
In November, 1992, the Public Service Commission (PSC) approved a 4.1 percent increase in LILCO's electric rates, consistent with the 1989 Shoreham settlement. The Commission also approved a separate 7.1 percent increase in the Company's natural gas rates, that will allow us to expand natural gas service to more customers.
Both increases became effective December 1, 1992.
Reshaping LILCO For the past several years, LILCOhas been examining its business to prepare the Company for success in the 1990s and beyond. A blueprint forthe future was developed and, in 1992, LILCO moved forward with a three-year reorganization designed to position the Company to meet the challenges of the changing marketplace.
LILCO is committed to becoming a premier service organization, and has embarked on a
gram to change its corporate culture. More t an just moving boxes around on an organiza-tional chart, we are seeking to fundamentally change the way we do business.
Business Units The reorganization divides the Company's activities into three business units Electric, Natural Gas and Energy Conservation allowing each to concentrate on the energy service they are providing. In July, 1992, the Electric Business Unitwas formed, with the Natural Gas and Conservation Units scheduled to be formed by the end of 1993.
torner Service In addition to dividing the Company into key competitive units, LILCO's reorganization incorporates two vital customer service elements.
Later this year, we willbe opening a "one-call center" in Melville, providing a single point of contact for customers conducting any type of business with LILCO.We willalso be regionalizing the electric and gas businesses into four geographic locations to bring these services closer to the customer. Both steps are designed to improve LILCO's abilityto respond to customer needs more efficiently and effectively.
Company does business.
Decreases in defense spending and a nationwide recession have slowed local economic growth, but there are pockets of growth in Long Island's emerging technology industries. LILCO, along with Long Island's government and business communities, introduced an economic development campaign to help boost the region's economy.
In addition to targeting new and growing businesses, the campaign also promotes higher education and tourism on Long Island. These efforts have yielded significant results, with LILCOeconomic development specialists helping more than 175 businesses start up, expand or relocate to Long Island.
Meeting the Challenge Facing both a changing industry and business environment, LILCOhas worked throughout 1992 to position itself to meet the challenges of a more competitive marketplace. We seek a future in which LILCObecomes a model of service excellence and efficiency.
On behalf of LILCO's Board of Directors and Officers, I would like to thank you foryour continued confidence in our leadership.
Sincerely, rowing Long Island In 1992, we not only developed a blueprint for LILCO's future, we helped map out Long Island's economic future. As the utilityindustry
- changes, so does the environment in which our WilliamJ. Catacosinos Chairman and Chief Executive Officer Oe
Meeting the challenge...
To meet new challenges, utilities nationwide are altering the way they do business. Rapidly changing technology, more sophisticated customer demands, non-utility generating facilities, and increasing environmental regulations all point to a new era in the utilityindustry.
In 1992, the Long Island Lighting Company examined and discarded old utilityparadigms and began to implement new strategies for success. While still in its infancy, the framework goes beyond simple changes in business practice to a new ideology for each and every employee an understanding of LILCO's role in providing services to Long Island and the importance of each employee in the Company's success.
In short, a blueprint for the future.
Meeting the Competition The driving force behind changes at LILCO, and at utilities nationwide, is competition. Despite lingering public perception of the monopolistic power company, non-utilitygeneration has grown tremendously in the last decade.
A recent industry study indicated that non-utility generators are currently contributing 43,114 megawatts of installed capacity to the U.S. electric supply, which represents eight percent ofcurrent U.S. electric capacity.
In addition, non-utilitygenerators have 65,690 megawatts in the pipeline and the numbers are
Almost 50 percent of New York's nursery crops, such as shade trees, are produced on long Island.
Meeting the challenge...
increasing each year. These new generating facilities are beginning to present some formidable competi-tion. In 1992, 9.8 percent of the electricity delivered by LILCOwas produced by non-utility generators.
LILCO's natural gas business is also functioning in an increasingly competitive market. With the northeast region the last national stronghold for home heating oil companies, natural gas'ecent in-roads into this market have caused a multi-milliondollar advertising campaign from a coalition of oil heat dealers.
How then can traditional utilities survive? The answer lies in looking at ourselves in a non-traditional way as a competitive business.
Through a reorganization into distinct business units Electric, Natural Gas and Energy Conservation-LILCO has begun to restructure itself to meet the competitive challenge. More importantly, however, the Company is changing its attitudes and perceptions, recognizing that future success is dependent upon cost-conscious management and close attention to increasingly sophisticated customer demands.
Adapting and Evolving Containing costs and providing unparalleled customer service are not mutually exclusive. In 1992, LILCO began to implement "cost-management" as opposed to simple cost-cutting. Bytaking an integrated approach to business planning, the Company is
lacrosse is one ofthe many competitive sports thol have a iong history on long Island.
Meeting the challenge...
eliminating costs that do not contribute to the value of services provided to our customers.
A key element of this new approach is integrated resource planning, which considers all available options to meet Long Island's long-term energy needs, includ-ing demand-side management, independent power producers and co-generation facilities, energy purchases from other utilities, and fuel substitution in our own plants. LILCO's plan combines these elements to provide cost-effective service in an environmentally acceptable manner.
Equally important in building the Company's competitive edge is an investment in our human resources.
To enhance employee effectiveness, LILCO worked over the last year to bring each employee "on board" in terms of the Company's strategic plan.
Employees participated in empowerment workshops to prepare them to become part of the Company's future. Employee views were also sought on ways to improve service and increase productivity.
With this change taking place in corporate culture, employees are adopting a service orientation that includes personal involvement and responsibility for achieving corporate objectives.
Looking Outside While internal improvements were an important part of LILCO's growth in 1992, external forces
Long Island's agricultural heritage ranges from livestock ond grain in colonial times to potatoes, sod and vineyards today.
Meeting the challenge...
played an equally vital role. The passage of the Clean AirActAmendments and the National Energy Security Act have brought environmental concerns to the forefront of utilityplanning.
Airquality in particular was a key environmental concern in 1992, with motor vehicle emissions a primary focus of the new legislation. Since electricity and natural gas are currently the two leading alternative fuels for motor vehicles, LILCO is in a unique position to help Long Islanders respond to emissions concerns.
In 1992, LILCOwas active in pursuing both alternative fuel options. With natural gas vehicles (NGVs) a more immediate clean air solution, the Company began adding NGVs to our own fleet, as well as providing information and assistance to other Long Island businesses.
In December, 1992, we completed construction of the Island's first company-owned natural gas refueling station, commissioned by the Metropolitan Suburban Bus Authority.
LILCO is also supporting further developments in battery technology for electric vehicles, to make these zero-emission vehicles widely usable in the future. In October, 1992, we held a joint forum with represen-tatives'of major U.S. car manufacturers to discuss technology issues, production challenges, and local and national legislation.
t< 3!t kg, viJL a i ft Old Bethpage Village Restoration is a living museum olLong Island it%in the 1800s.
LILCO's commitment to energy conservation expanded in 1992 as well, taking a more compre-hensive approach to decreasing residential energy use through programs such as the New York State Energy-Star (NYSE-Star) program. As a NYSE-Star participant, LILCO provides incentives to residential developers who build homes that far exceed the state energy construction code.
Meeting the challenge...
Involvement and Innovation In 1992, LILCOencouraged economic growth by spearheading an economic development campaign depicting Long Island's innovative business atmosphere, excellent colleges and universities, and diverse cultural and tourism options. The Company's efforts were part of the New Long Island Partnership, a coalition of businesses and government agencies, working to attract, retain and expand businesses on the Island.
The effort has been successful. Since its inception, more than 70 companies have been involved with the economic development program, helping Long Island add or retain more than 7,000 jobs and $2 billion in annual sales.
Encouraging innovation is another method for generating economic growth. In the case of LILCO's Long Island Research and Development Initiative
Nore than 80 biotechnology companies comprise Long Island's newest, most rapidly growing industry.
there was an additional benefit developing technologies that improve LILCOservice.
In February, 1992, LILCOawarded more than
$3.5 millionin funding to Long Island institutions for 27 winning research and development projects, ranging from expert computer systems to gas leak detection devices to robotics. These projects, currently in various stages of development, represent approximately
$ 5 millionworth ofwork that willbe performed locally.
Meeting the challenge...
Direction forthe Future Change, particularly change of ingrained beliefs and behaviors, takes time. The progress made in altering both LILCO's organization and culture will continue in 1993 and beyond. But the groundwork has been laid for forging a new, competitive business from the old utilitymodel.
LILCOwillremain focused on providing unparalleled service to all Long Islanders. In 1993, that willinclude the completion of our "one-call center," a single point of contact for all LILCO customer transactions.
And we willcontinue to seek innovation and improvement in technology and service as we grow and evolve to meet the challenge of the future.
Long Island olfers a wealth ofeducational opportunities with 19 colleges and universities.
Financial Review Overview The year 1992 represents the fourth consecutive year of continued improvement in the Company's financial health.
The financial viabilityof the Company had been jeopardized in the past by the controversy concerning the Shoreham Nuclear Power Station (Shoreham) and the federal Racketeer Influenced and Corrupt Organizations Act (RICO Act) litigation. The 1989 Settlement between the Company and the State of New York (State) was designed to eliminate the controversy over Shoreham by providing for, among other matters, the transfer of Shoreham to an agency of the State and reciting the intention to return the Company to investment grade financial condition by providing rate increases in each year from 1989 through 1998. The Company's financial recovery began in 1989 following the 1989 Settlement and a class action settlement (Class Settlement) entered into between the Company and its ratepayers to resolve the RICO Act litigation.
The improvement in the Company's financial condition is evidenced, in part, by the elevation of the Company's First Mortgage Bonds and General and Refunding Bonds (G8 R Bonds) to one notch above "minimum investment grade" and the elevation of the Company's unsecured debt and preferred stock to "minimum investment grade."
Other significant events in 1992 included:
~ The transfer of ownership of Shoreham to an agency of the State on February 29, 1992.
4 Approval, by the New YorkState Public Service Commission (PSC), of the second annual electric rate increase of 4.1% effective December 1, 1992, under the three-year electric rate plan approved in 1991.
This three-year rate plan follows the receipt of electric rate increases in each of the years 1989 through 1991.
~ The reinstatement of the Company's Automatic Dividend Reinvestment Plan beginning with the October 1, 1992 common stock dividend payment.
~ An increase in the Company's common stock quarterly dividend from 42'/~ cents per quarter to 43'/2 cents per quarter.
Earnings for common stock in 1992 were $2.14 per common share compared to $2.15 per common share in 1991. The 1992 results reflect a significant improve-ment in the Company's gas business earnings. The Company's electric business earnings were lower in 1992 as a result of the lower allowed rate of return which is prescribed by the PSC.
~ The common stock traded on average at a twenty-one year high.
e The refinancing of a significant amount of the Company's securities as a result of very favorable long-term interest rates.
The refinancing of approximately $ 1.5 billionof higher-cost securities which significantly lowered the Company's cost of debt and preferred stock. These 1992 refinancings willresult in more than $ 17 million in annual cash savings through lower interest and preferred stock dividend expenses.
Since the 1989 Settlement became effective, the Company's aggressive refinancing program has resulted in annual cash savings of approximately
$70 millionthrough lower interest and preferred stock dividend expenses.
The elimination of all of the Company's outstanding bank debt of approximately $446 million.
The conversion of $400 millionof variable rate tax-exempt securities to a 30-year fixed annual rate of 7.15%.
~ The issuance of $200 millionof low-cost tax-exempt securities resulting in substantial savings for the Company's ratepayers since these securities carry significantly lower interest rates than taxable bonds.
4 The addition of approximately 10,000 new gas space heating customers for the third consecutive year.,
~ An increase in gas rates of 7.1% effective Decembe 1, 1992.
Investment Rating First Mortgage Bonds G8 R Bonds Debentures Preferred Stock Baa2 BBB BBB BBB Baa2 BBB BBB BBB Baa3 BBB-BBB-BBB-baa3 BBB-BBB-BB+
Minimum Investment Grade Baa3 BBB-BBB-BB The Company's securities are rated by Moody's Investors Service, Inc. (Moody's), Standard and Poor's Corporation (S8 P), Fitch Investors Service, Inc. (Fitch) and Duffand Phelps (D8 P).
Since 1989, the rating agencies have significantly upgraded their ratings on the Company's First Mortgage Bonds and G8cR Bonds to one level above "minimum investment grade" and the Company's debentures and preferred stock to "minimum investment grade."
The chart below indicates the current ratings for each of the Company's principal securities and the minimum investment grade ratings used by each agency.
Moody's S8P Fitch D&P
e Matters ectric Pursuant to the 1989 Settlement, the Company received electric rate increases contemplated by the Rate Moderation Agreement (RMA), a constituent document of the 1989 Settlement discussed below, for each of the three rate years in the period ended November 30, 1991. In response to the Company's rate filingin December 1990, the PSC approved the Long Island Lighting Company Rate-making and Performance Plan (LRPP) in November 1991, which provides for annual electric rate increases of 4.15%,
4.1% and 4.0% effective December 1, 1991, 1992 and 1993, respectively. Effective December 1, 1992, the Company began receiving the second of the three annual electric rate increases provided forwithin the LRPP. The LRPP provides for an allowed return on common equity from electric operations of 11.6%.
One principal objective of the LRPP is to reassign risk so that the Company assumes the responsibility for risks within the control of management, whereas risks largely beyond the control of management would be assumed by the ratepayers.
One of the major components of the LRPP provides for a revenue reconciliation mechanism that reduces the impact on earnings ofexperiencing electric sales that are above or below the LRPP forecast by providing a fixed annual net margin I (defined as sales revenues, net of fuel and gross receipts
) that the Company willreceive over the three rate years er the LRPP. Another component of the LRPP allows the Company to earn for each rate year up to 60 additional basis points, or forfeit up to 38 basis points, of the allowed return on common equity as a result of its performance within certain incentive and/or penalty programs. The LRPP also contains a mechanism whereby earnings in excess of the allowed rate of return on common equity, excluding the impacts of the various incentive and/or penalty programs, are shared equally between ratepayers and shareowners.
In conjunction with the 1989 Settlement, the PSC authorized the recognition of a regulatory asset known as the Financial Resource Asset (FRA). The FRA consists of two components, the Base Financial Component (BFC) and the Rate Moderation Component (RMC). The RMAprovides forthe fullrecovery of the FRA. The RMA, by its terms, specifies that the FRA is being created to provide the Company adequate financial indicia for the period 1989 through 1999 and to restore the Company's debt securities to investment grade levels as determined by independent rating agencies.
The BFC, as initiallyestablished, represents the present value of the future net-after-tax cash flows which the RMAprovided the Company for its financial recovery. The BFC was granted rate base treatment under the terms of the RMAand is uded in the Company's revenue requirements through an tization included in rates over fortyyears on a straight-l asis beginning July 1, 1989.
The RMC reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation of the rate moderation plan provided for in the RMA. The RMC has provided the Company with a substantial amount of non-cash earnings since the 1989 Settlement became effective.
The RMAwas designed to provide rate increases sufficient to recover the RMC within a ten-year period. The RMC balance has increased as the difference between revenues resulting from the implementation of the rate moderation plan provided for in the RMAand revenue requirements under conventional ratemaking, together with a carrying charge equal to the allowed rate of return on rate base, has been deferred. The RMC balance willsubsequently decrease and is expected to be fullyamortized by November 30, 1999, as deferred revenue requirements are recovered.
The LRPP was designed to be consistent with the RMA's long-term goals including: (i) the recovery of the BFC; (ii) the recovery of the RMC in approximately ten years; (iii)the Company's return to investment grade ffnancial condition and (iv) the Company's receipt of adequate and timely rate relief. Although the LRPP provides for slightly lower annual electric rote increases than originally anticipated in the 1989 Settlement, the Company believes that itwillstill fullyrecover the RMC within a ten-year period principally as a result of changes in the original assumptions. The revenues assumed by the LRPP are adequate to provide the Company with recovery of its revenue requirements under conventional ratemaking and recovery of the RMC balance over the remainder of the ten-year period. However, actual revenues may differfrom those assumed for this period. The original assumptions underlying the RMAincluded projections of future revenues, operating expenses and required rates of return. Since then, the Company has experienced interest rates, operations and maintenance expenses, non-Shoreham property taxes and fuel expenses that are lower than those originally anticipated. As a result, amounts deferred in the RMC have been less than expected.
For a further discussion of the 1989 Settlement and Rate Matters, see Notes 2 and 3 of Notes to Financial Statements.
Gas In November 1992, the PSC approved a gas rate increase of 7.1%, or $35.7 millionannually, effective December 1, 1992, with an allowed return on common equity from gas operations of 11.0%. In November 1991, the Company received a gas rate increase of 4.1% effective December 1, 1991.
On December 31, 1992, the Company filed an application with the PSC seeking gas rate relief for the three rate years beginning December 1, 1993. The Company has requested a gas rate increase of 6.7%, or $37.7 millionin additional revenues to become effective for the first rate year under this filing.The Company's filingalso includes a proposed methodology for determining rate increases, not to exceed approximately $30 millionannually, for the subsequent second and third rate years. This filing reflects the Company's latest projections of capital expenditures, operations and maintenance expense< and the continued expansion of its gas business.
Results of Operations Earnings Summary results of earnings for the years 1992, 1991 and 1990 were as follows:
(In millions ofdollars ond shares except earnings per share) 1992 1991 19900 Net Income Earnings for Common Stock Earnings per Common Share Average Shares Outstanding AFC 8 RMC Included in Net Income AFC8 RMC %of Net Income
$ 302 306
$ 319 238 239 251
$ 2.14
$ 2.15
$ 2.26 111.4 111.3 111.3 60 183
$ 214 20%
60%
67%
'Excludes the effect ofan accounting change forunbilled gas revenues.
For all periods, net income, earnings for common stock and earnings per common share include non-cash allowance for funds used during construction (AFC) and the RMC.
The earnings in the electric business were lower in 1992 when compared to 1991. This lower level of earnings in the electric business was offset by the significant increase in the gas business earnings in 1992.
The increase in the gas business earnings was the result of higher revenues and continued cost containment programs.
The higher gas revenues were due to the 1992 gas rate increase and the Company's aggressive gas expansion program, which has resulted in an increase in the number of gas space heating customers.
The electric business earnings for 1992 were lower as a result of the lower allowed rate of return of 11.6% in 1992 when compared to the allowed rate of return of 12.75% in 1991.
The allowed rate of return is prescribed by the PSC.
Incentives earned for electric operations provided 6 cents per share in 1992 and 12 cents per share in 1991. In addition, for the rate year ended November 30, 1992, the Company earned $ 16.2 million, net of tax effects, in excess of its allowed rate ofreturn on common equity which, in accordance with the LRPP, was shared equally between ratepayers and shareowners.
These excess earnings were generated as a result of a reduction in operations and maintenance expenses and the effect of a decrease in capital expenditures included in rate base.
The decrease in earnings for common stock for 1991 of approximately $ 12 million, or 11 cents per share, compared with 1990, was primarily attributable to increases in non-fuel operations and maintenance expenses, operating taxes and interest expense, partially offset by higher electric revenues.
For the rate year ended November 30, 1991, the Company earned $ 10.1 million, net oftax effects, in excess of its allowed rate of return, which was applied as a reduction to the RMC.
Revenues Total revenues in 1992, including revenues from recovery of fuel costs, were $2.6 billion, which represents an increase of $74 millionor 2.9% over 1991 revenues. Total revenues for the Company's electric and gas operations for the years 1992, 1991 and 1990 were as follows:
Electric Gas (In mi%l'ons ofdollars) 1992 1991 1990
$ 2,195
$ 2,197
$ 2,096 427 351 361 Total Revenues
$ 2,622
$ 2,548
$ 2,457 E/ectrIc In 1992, electric revenues decreased
$2 million when compared to 1991. Revenues in 1991 had increased
$ 101 millionor 4.8% over 1990. The changes in the leve revenues when compared to the prior year resulted fram following factors:
Rate Increases Sales Volumes Fuel Cost Recoveries Total (In millionsofdollars)
'92/'91
'91/'90 85
$ 114 (74)
(7)
(13)
(6)
(2)
$ 101 Rate Increases The Company received electric rate increases of 4.1% effective December 1, 1992, and 4.15% effective December 1, 1991. These rate increases provided $85 millionin additional revenues for 1992 when compared to 1991. A 5.0% rate increase effective December 1, 1990, provided $ 114 millionin additional revenues for 1991 when compared to 1990.
Sa(es Vo(umes The decrease in revenue from sales volumes was primarily attributable to cooler weather experienced in the summer of 1992 when compared to the same period in 1991. The Company's current electric rate structure, discussed above under the heading "Rate Matters," provides for a revenue reconciliation mechanism which reduces the impact on earnings of experiencing electric sales that are above or below the levels reflected in rates. As a result of lower th adjudicated electric sales, the Company recorded non-c income whichis included in "Other Regulatory Amortizatio of $78.5 millionand $0.4 million in 1992 and 1991, respectively.
Earnings for 1990 included 10 cents per common share ~
attributable to a change in the Company's method of recognizing gas revenues.
Effective January 1, 1990, the Company's revenues included estimated consumption of gas delivered to customers, but not yet billed at month end, resulting in the full accrual of all unbilled gas revenues. The cumulative effect of this accounting change increased 1990 earnings by nearly $ 12 million, net of tax effects. The Company did not earn in excess of its allowed rate of return for the rate year ended November 30, 1990.
att Hour Sales Summary ofelectric kilowatt hour (kWh) for the years 1992, 1991 and 1990 were as follows:
(In millionsofkWh) 1992 1991 1990 Residential Commercial/Industrial System Sale's Power Pool Sales Total Sales 6,788 7,023 7,022 8,652 8,791 8,832 15,440 15,814 15,854 227 598 532 15,667 16,412 16,386 The decrease in residential and commercial/industrial sales in 1992 was largely due to the cooler weather experienced during the summer months. Residential sales, which comprised 44% of system sales, were down by 3.3% when compared with 1991, while commercial/industrial sales, which accounted for 53% of system sales, declined by 1.7%.
Power pool sales fluctuate with relative costs and power pool system availabilities.
The average number of electric customers served in 1992 and 1991 was approximately 1,009,000 and 1,005,000, respectively. The 4,000 customer increase in 1992 is similar to the increase experienced in 1991 when compared to 1990.
s ary of average use per customer for the years 1992,
', and 1990 was as follows:
1992 1991 1990 Space Heating Non-Space Heating 48,751 7,541 41,323 41,081 7,366 7,800 Total Firm Interruptible 56,292 48,689 5,090 4,538 48,881 6,347 Total System 61,382 53,227 55,228 Summary of average use per customer for the years 1992, 1991 and 1990 was as follows:
(In dth per customer)
Rate Increases The Company received gas rate increases of 7.1% effective December 1, 1992, and 4.1% effective December 1, 1991. These rate increases provided $ 17 million in additional revenues in 1992 when compared to 1991. A gas increase of 1.3% in January 1990 provided $2 millionin additional revenues for 1991 when compared to 1990.
Sa/es Vo/umes The increase in 1992 revenues due to sales volumes was primarilydue to customer additions and conversions resulting from the Company's gas expansion program, aided by a colder heating season in 1992. The Company added approximately 10,000 new gas space heating customers to its system for the third consecutive year.
Summary of gas decatherm (dth) sales for the years 1992, 1991 and 1990 were as follows:
(In thousands ofdth) 1992 1991 1990 Residential Commercial/Industrial System (In kWh per customer) 1992 1991 1990 7,518 7,812 7,844 80,346 81,797 82,304 15,297 15,731 15,832 Fuel Cost Recoveries Total electric fuel cost recoveries for 1992 were down $ 13 millioncompared with 1991, primarily as a result of lower sales volumes, partially offset by an increase in the average cost of fuel. In 1991, fuel cost recoveries decreased by $6 millioncompared with 1990, principally due to a lower average cost of fuel.
Gas In 1992, gas revenues increased by $76 million, or 21.7%, when compared to 1991. Revenues in 1991 decreased by $ 10 million, or 2.8%, when compared to 1990.
The changes in the level of revenues when compared to the prior year resulted from the followingfactors:
(In thousands ofdollars)
'92/'91
'91/'90 Space Heating Non-Space Heating Interruptible System 188 165 171 42 40 41 9,568 9,614 15,480 140 123 129 Fuel Cost Recoveries Recoveries of fuel expenses in 1992 revenues increased by $9 millioncompared with 1991, primarilydue to higher sales volumes. In 1991, fuel recovery revenues had decreased by $5 million, primarilydue to lower sales volumes.
Fuel and Purchased Power Expenses for fuel and purchased power for electric operations and for gas delivered to customers decreased by $27 million in 1992 compared with 1991, and decreased by $ 18 million in 1991 compared with 1990. Summary of fuel and purchased power expenses for the years 1992, 1991, and 1990 were as follows:
(In mi%I'ons ofdollars) 1992 1991 1990 Rate Increases
.s Volumes ost Recoveries 17 50 (7)
(5)
Electric Fuel Purchased Power Gas
$ 279 381 441 281 213 170 182 175 176 76
$ (10)
Total
$ 742
$ 769
$ 787
The Company has substantially reduced its dependence on foreign oil for electric generation, substituting gas and purchased power whenever economical. Summary of electric fuel and purchased power mix for the years 1992, 1991 and 1990 were as follows:
Oil Gas Purchased Power Nuclear Fuel Total (Percent ofsystem energy requirements) l992 199I t990 37%
50%
56%
19 18 20 38 25 20 6
7 4
100%
100%
100%
Operations and Maintenance Expenses Total operations and maintenance expenses, excluding fuel and purchased power, for 1992, 1991 and 1990 were $498 million, $523 million and $476 million, respectively. The $25 million, or 4.8%, decrease in 1992 was primarily due to lower electric operations expenses which resulted from the Company's aggressive expense reduction and cost containment programs. The Company also instituted and has pursued more aggressive collection practices as evidenced by a lower provision for doubtful accounts in 1992. Partially offsetting these decreases were certain higher expenses, including expenses related to the Company's share in the Nine Mile Point Nuclear Power Station, Unit 2 (NMP2) and employee related benefits.
The $47 million, or 9.9%, increase in 1991 was primarily attributable to increases in employee wages and benefits, electric production and gas distribution costs, and provision for doubtful accounts.
Other Items In 1992, federal income taxes were approximately $ 161 million, compared with $ 182 million in 1991. In 1990, these taxes amounted to $ 183 million, excluding the effect of the accounting change for unbilled gas revenues.
Interest expenses for 1992, 1991 and 1990 were $512 million, $524 millionand $508 million, respectively. The decrease in 1992 was the result of lower interest rates, primarily achieved through refinancings.
In 1992, the Company recorded non-cash charges to income of approximately $23 millionwhich represents the increase in the present value of the Class Settlement liability.These charges amounted to $25 million and
$23 millionfor 1991 and 1990, respectively. For a further discussion of the Class Settlement see Note 4 of Notes to Financial Statements.
For the years 1992, 1991 and 1990, the Company recorded non-cash credits to income of $73 million, $269 millionand
$313 million, respectively, reflecting the RMC and related carrying charges. For a further discussion of the RMC and RMA, see Notes 2 and 3 of Notes to Financial Statements.
For the years 1992, 1991 and 1990, the Company reco~
non-cash charges to income of approximately $ 101 mill~i reflecting the continuing amortization of the BFC, which is afforded rate base treatment under the RMA. For a further discussion of the BFC and 1989 Settlement, see Notes 1 and 2 of Notes to Financial Statements.
Securities Issued
$ 56 millionG&R Bonds 7.85% Series Due 1999
$ 75 millionG8 R Bonds 8.50% Series Due 2006
$ 80 millionG8 R Bonds 7.90% Series Due 2008
$397 million Debentures 7.30% Series Due 1999
$420 million Debentures 8.90% Series Due 2019
$451 million Debentures 9% Series Due 2002
$363 million Preferred Stock 7.95% Series AA
$ 57 million Preferred Stock 7.66% Series CC
$400 milliontax-exempt securities, 7.15%, 30-year Axed annual rate Securities Redeemed
$ 53 millionG8 R Bonds 9.75% Series Due 1999
$ 70 millionG&R Bonds 9.625% Series Due 2006
$ 75 millionG8 R Bonds 9.20% Series Due 2008
$319 million Debentures 10.875% Series Due 1999
$346 million Debentures 11.375% Series Due 2019
$ 25 million First Mortgage Bonds 9.125% Series Due 2000
$446 millionunder the 1989 Term Loan Agreement
$320 million Preferred Stock 10.60% Series Y
$ 55 million Preferred Stock 9.80% Series S '.
$400 milliontax-exempt securities vanable weekly rate In addition to the above refinancings, the Company utili'200 millionof tax-exempt securities in 1992. The net proceeds from the sale of these tax-exempt securities were used to reimburse the Company's treasury for previously incurred capital expenditures.
Uquidity Cash and Revolving Credit At December 31, 1992, the Company's cash and cash equivalents amounted to approximately $309 million, compared to $298 millionat December 31, 1991.
In addition, the Company has approximately $251 million available under its revolving line of credit through October 1, 1993, provided by its 1989 Revolving Credit Agreement (1989 RCA). At December 31, 1992, no amounts were outstanding under the 1989 RCA. For a further discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements.
Financing Programs During 1992, the Company issued
$211 millionaggregate principal amount of GER Bonds, approximately $ 1.3 billion aggregate principal amount of debentures and $420 millionof preferred stock. The net proceeds from the sale of these securities were used to eliminate all bank debt, redeem higher-cost debt and preferred stock and to pay any related redemption cost The details respecting the Company's $2.3 billionof refinancing activities in 1992 were as follows:
ddition to the conversion of $400 millionof tax-exempt rities in June 1992, the Company converted $ 100 million of tax-exempt securities in January 1993 from a variable weekly interest rate to a 30-year fixed annual rate of 6.90%.
In January 1993, the Company issued $36 millionprincipal amount of Debentures, 7.30% Series Due 2000, the net proceeds ofwhich willbe used in February 1993 to redeem, at the applicable redemption price, $35 millionprincipal amount of First Mortgage Bonds, 8.20% Series R Due 1999.
In February 1993, the Company sold $ 142 millionprincipal amount of Debentures, 7.50% Series Due 2007, the net proceeds ofwhich willbe used in March 1993 to redeem, at the applicable redemption prices, the following series of G8 R Bonds: $50 million, 8/e% Series Due 2006 and $85 million, 8/e% Series Due 2007.
The Company has been able to utilize $ 100 millionof tax-exempt securities in each of the years 1989 through 1992. In 1990, the Company was able to utilize an additional $ 100 millionof tax-exempt securities (1991 Series A Electric Facilities Revenue Bonds) allocated for its benefit.
During the period January 1, 1993 to December 31, 1995, the Company has estimated that itwillbe required to seek external financing of approximately $ 1.4 billion, principally to refund maturing debt and secondarily to meet its operating d capital requirements.
In addition, the Company intends ontinue to access the capital markets to refund higher-cost t and preferred stock, when market conditions permit.
The Company currently has debt and equity securities regis-tered with the Securities and Exchange Commission on shelf registration statements. The sale of $615 millionofthese secur-ities willbe used to refund the following securities maturing in 1993: $40 millionof First Mortgage Bonds, 4.40% Series M Due April 1, 1993, $375 millionof Debentures, 11 3/8%
Series Due April 1, 1993 and $ 175 millionof Debentures, 11.70% Series Due November 15, 1993. The Company may also sell an additional $ 146 millionof previously registered securities, which willbe used, when market conditions permit, to refund higher-cost debt or preferred stock.
For a further discussion on the Company's capital stock and long-term debt, see Notes 6 and 7 of Notes to Financial Statements.
Capltallzatlon The Company's capitalization (defined as the total oflong-term debt, preferred stock and common shareowners'quity) at December 31, 1992, was approximately $8.2 billion, as compared to $7.8 billionat December 31, 1991. This increase in capitalization of approximately $420 million principally reflects an increase in long-term debt and preferred stock ociated with the Company's financing activities in 1992 an increase in common shareowners'quity comprising 2 net income of approximately $302 million reduced by common and preferred stock dividends of $254 million.
At December 31, 1991, capitalization increased by approxi-mately $492 millionfrom the December 31, 1990, balance of
$7.3 billion. This increase in capitalization primarily reflects an increase in long-term debt associated with the Company's financing activities in 1991 and an increase in common shareowners'quity comprising 1991 net income of $306 million reduced by common and preferred stock dividends of $245 million.
At December 31, 1992 and 1991, the components of the Company's capitalization ratios were as follows:
Long-Term Debt Preferred Stock Common Shareowners' ui Total 1992 1991 64.7%
63.9%
8.8 8.8 26.5 27.3 100.0%
100.0%
Capital Requirements Construction Electric Gas Common Total Construction Refundings and Dividends Long-term debt Preferred stock Preferred stock dividends Common stock dividends Redem tion costs Total Refundin s and Dividends Shoreham ost settlement costs Total Ca ital Re uirements Capital Provided (Increase) in cash Long-term debt Preferred stock Financing costs Other financing activities Internal cash generation from o erations Total Capital Provided 137 104 90 27 18 268 235 1,344 1,129 389 71 70 66 191 173 159 68 2,153 1,507 228 158
$ 2,649
$ 1,900 (11)
(195) 1,660 1,532 411 63 (7)
(20) 6 590 520
$ 2,649
$ 1,900 For further information, see the Statement ofCash Flows.
For 1993, total capital requirements (excluding common stock dividends) are estimated at $ 1.2 billion, of which construction requirements are estimated to be $320 million, mandatory redemptions are $590 million, preferred stock sinking fund requirements are $8 million, preferred stock dividends are $57 million, and Shoreham post settlement costs are estimated at approximately $ 189 million. The Company intends to satisfy these capital requirements through external financing, as discussed above, and internal cash generation from operations.
O Capital Requirements and Capital provided Capital requirements and capital provided for 1992 and 1991 were as follows:
In millions ofdollars 1992 1991
Other Matters Electric Competition, Conservation and Supply The Company is experiencing competition from cogenerators and other independent power producers located within the Company's service territory. These facilities supply electric energy to existing or new industrial and commercial customers and excess electricity is sold to the Company pursuant to the purchase requirements of the Public Utility Regulatory Policy Act of 1978 (PURPA). The Company has contracts with owners of these facilities which willprovide for a total of approximately 340 megawatts (MW)of capacity by 1994, which includes the New York Power Authority's 136 MW Holtsville facility.The Company has also entered into contracts for approximately 450 MWof power from various projects on an energy-only basis.
The Company has implemented conservation and load management programs to meet Long Island's energy needs in the future. In 1992, the Company met its targeted reductions in its revised 1992 Electric Conservation and Load Management Plan, which called for a 235 MW reduction in coincident peak demand by December 31, 1992, and annualized energy savings of 454 gigawatt hours, at a budgeted cost of approximately $45.3 million.The Company anticipates that the Conservation and Load Management Plan willcontinue in future years to gain further reductions in system peak and energy usage.
The Company's current electric load forecasts indicate that, with continued implementation of its aggressive conser-vation and load management programs and with electricity provided by independent power producers and cogenerators, the Company's existing generating facilities, the Company's portion of nuclear energy generated at NMP2 and contracts for purchased power are adequate to meet the energy demands on Long Island beyond the end of the century.
Gas Competition In 1987, the Federal Energy Regulatory Commission (FERC) issued an order allowing gas pipeline companies and producers access to certain of the Company's customers for the purpose of supplying competing gas service. As of December 31, 1992, approximately 104 of the Company's former large gas customers were purchasing gas directly from gas pipeline companies and producers and arranging for its transportation through the Company's gas mains. The Company receives a fee for this transportation service which accounted for approximately $6.7 million, or 1.6%, of total gas revenues for 1992.
Clean AirAct In late 1990, significant amendments to the federal Clean AirAct were adopted. A number of electric utilities anticipate substantial increases in operating costs and capital expenditures as a result of the amendments.
The Company does not expect to incur any costs to satisfy these amendments with respect to the reduction of sulfur dioxide emissions, since the Company already uses fuel with acceptably low levels of sulfur. However, the Company expects that itwillincur costs to comply with additional continuous emission monitoring (CEM) requirements and or future nitrogen oxide reduction requirements that may be imposed under federal or state regulations. The Company estimates that the cost of installing CEM and nitrogen oxide control equipment, which the Company willseek to recover through rates, willbe approximately $ 15 millionand $ 100 million, respectively.
Accounting Pronouncements The Company will adopt the provisions of Statement of Financial Accounting Standards (SFAS) No. 106, Employers'ccounting for Postretirement Benefits Other Than Pensions, during the first quarter of 1993. SFAS No. 106 requires the Company to recognize the expected cost of providing postretirement benefits when employee services are rendered rather than on a pay-as-you-go method. The Company willrecord an accumulated postretirement benefit obligation and corresponding regulatory asset of approximately $376 millionwhich represents the transition obligation at December 31, 1992. Additionally, as a result of adopting SFAS No. 106, the Company's annual postretirement benefit expense willincrease by approximately $44 millionabove the amount previously recorded under the pay-as-you-go method. This additional $44 millionof non-cash post-retirement benefit expense willalso be accounted for as a regulatory asset. The Company believes that the PSC'ermit recovery of these regulatory assets through rates.
For a further discussion of SFAS No. 106, including the recoverability of these regulatory assets, see Note 8 of Notes to Financial Statements.
The Company willadopt SFAS No. 109, Accounting for Income Taxes, during the first quarter of 1993. SFAS No. 109 prohibits net of tax accounting and reporting and requires recognition ofa deferred tax liabilityfor the tax benefits which are flowed through to its customers and the equity component of AFC. A regulatory asset or liabilitywillbe recognized relating to such items ifit is probable that the future increase or decrease in taxes payable thereon shall be recovered from or returned to customers through future rates. The Company estimates that had it adopted SFAS No. 109 at December 31, 1992, the Company would have recorded an accumulated deferred tax liabilityand a corresponding regulatory asset of approximately $ 1.2 billion.The impact of SFAS No. 109 on the Statement of Income is not expected to be material. For a further discussion of SFAS No. 109, see Note 1 of Notes to Financial Statements.
Selected Financial Data Additional financial information for the last five years is provided in Tables 1 through 11 of Selected Financial Information with regard to the Company's business seg for the last three years is provided in Note 11 of Notes to Financial Statements.
Financial Statements I
tement of Income year ended December 31 (tn thousands ofdollars except per share amounts I 1992 1991 1990 Revenues Electric Gas Total Revenues Expenses Operations fuel and purchased power Operations other Maintenance Depreciation and amortization Base financial component amortization Regulatory liabilitycomponent amortization Other regulatory amortizations Rate moderation component Operating taxes Federal income tax current Federal income tax deferred and other Total Expenses Operating Income Other Income and (Deductions)
Allowance for other funds used during construction Rate moderation component carrying charges Other income and deductions, net ss Settlement leral income tax (charge) deferred and other otal Other Income and (Deductions)
Income Before Interest Charges and Cumulative Effect of Accounting Change Interest Charges and (Credits)
Interest on long-term debt Other interest Allowance for borrowed funds used during construction Total Interest Charges and (Credits)
Income Before Cumulative Effect ofAcc'ounting Change Cumulative Effect ofAccounting Change forUnbllled Gas Revenues (net ofapplicable taxes of $6,017)
Net Income Preferred stock dividend requirements Earnings forCommon Stock Average Common Shares Outstanding (000)
Earnings per Common Share Before cumulative effect of accounting change Cumulative effect of accounting change Earnings per Common Share Dlvldends Declared per Common Share Notes to Financial Statements.
$ 2,194,632 427,207 2,621,839 741,784 372,209 125,736 119,137 100,971 (88,573)
(22,072)
(30,444) 388,988 530 172,468 1,880,734 741,105 4,725 42,837 28,832 (22,541) 12,036 65,889 806,994 450,621 61,785 (7,386) 505,020 301,974 301,974 63,954 238,020 111,439 2.14 1.72
$ 2,196,568 351,161 2,547,729 768,702 375,267 147,492 118,955 100,971 (88,573) 8,666 (228,572) 388,380 515 168,937 1,760,740 786,989 2,202 40,456 33,783 (25,467)
(12,201) 38,773 825,762 472,974 50,842 (3,592) 520,224 305,538 305,538 66,394 239,144 111,348 2.15 2.15 1.60
$ 2,095,660 361,242 2,456,902 786,999 340,518 135,291 110,884 100,971 (88,573) 14,427 (297,214) 370,317 3,638 177,014 1,654,272 802,630 2,940 15,683 27,218 (22,574)
(2,629) 20,638 823,268 467,700 40,559 (4,628) 503,631 319,637 11,680 331,317 68,161 263,156 111,290 2.26
.10 2.36 1.25
Balance Sheet A
AtDecember 3 l UtilityPlant Electric Gas Common Construction work in progress Nuclear fuel in rocess and in reactor Less Accumulated depreciation and amortization Total Net Utilit Plant Regulatory Asset Base financial component (less accumulated amortization of $353 398 and $252 427 NonutilityProperty and Other Investments Current Assets Cash and cash equivalents Special deposits Customer accounts receivable (less allowance for doubtful accounts of $24,375 and $26,935)
Other accounts receivable Accrued unbilled revenues Materials and supplies at average cost Fuel oil at average cost Gas in storage at average cost Pre a ments and other current assets Total Current Assets Deferred Charges Rate moderation component Shoreharn post settlement costs Unamortized cost of issuing securities Shoreham nuclear fuel Accumulated deferred income taxes Other Total Deferred Char es Total Assets See Notes to Financial Statements.
l992 3,429,803 760,635 172,703 161,663 19,216 4,544,020 1,382,872 3,161,148 3,685,432 20,730 309,485 23,683 208,049 6,937 143,172 86,482 51,702 47,002 40,402 916,914 651,657 586,045 380,267 77,629 511,898 256,904 2,464,400
$ 10,248,624 In thousands ofdella
$ 3,323,008 666,904 157,495 157,511 29 818 4,334,736 1 332 003 3 002 733 3 786 403 9 788 298,098 23,207 210,525 6,515 136,565 86,863 44, 43, 34, 884,017 602,053 378,386 227,713 79,760 439,235 133,213 1,860,360
$ 9,543,301
pltallzatlon and Liabilities ce ber31 apltallzatl on Long-term debt Unamortized remium and discount on debt Preferred stock redemption required Preferred stack no redemption re uired Total Preferred Stock Common stock Premium on capital stock Capital stock expense Retained earnin s
Total Common Shareowners' uit Total Ca italization Current Liabilities Current maturities of long-term debt Current redemption requirements of preferred stock Accounts payable and accrued expenses Accrued taxes (including federal income taxes of $27,100 and $27,693)
Accrued interest Dividends payable ass Settlement tamer de osits al Current Liabilities Deferred Credits 1989 Settlement credits Class Settlement Accumulated deferred income taxes Other Total Deferred Credits Reserves for Claims, Damages, Pensions and Benefits Commitments and Contingencies Total Capitalization and Liabilities See Notes to Financial Statements.
1992
$ 4,755,733 (14,731 4,741,002 557,900 154,276 712,176 558,002 998,089 (39,304) 667,988 2,184,775 7,637,953 590,000 8,200 286,102 67,525 131,179 53,966 30,000 24,815 1,191,787 164,294 167,066 970,373 110,341 1,412,074 6,810
$ 10,248,624 (In thousands ofdollars) 1991
$ 5,001,016 14,850 4,986,166 524,912 154,371 679,283 556,825 993,509 (40,216) 620,373 2,130,491 7,795,940 10,000 10,616 223,589 60,174 85,565 60,287 20,000 22,664 492,895 173,507 173,564 816,053 84,035 1,247,159 7,307
$ 9,543,301
Shareowners'quity Statement of Retained Earnings 1992 (In thousands ofdolla 1991 Balance at January 1
Net income for the ear Deductions Cash dividends declared on preferred stock Cash dividends declared on common stock Ca ital stockex ense 620,373 301,974 922,347 62,387 191,693 279 560,405 305,538 865,943 67,261 178,169 140 436,6 331,317 768,007 68,218 139,128 256 Balance at December 31 Preferred Stock AtDecember 31 Call Price Per Share December 31 1992 Final 667,988 1992 620,373 560,405 (In thousands ofdollars) 1991 1990 Par Value $100 per Share, Cumulative Shares authorized Shares issued and outstandin 5.00% Series B 4.25% Series D 4.35% Series E 4.35% Series F 5 1/8%Series H 5 3/4%Series I Convertible 8.12% Series J 8.30% Series K 7.40% Series L*
8.40% Series M*
8.50% Series R'.80%
Series S*
7.66% Series CC*
$ 101.00 102.00 102.00 102.00 102.00 100.00 101.00 103.29 103.22 103.36 101.00
$101.00 102.00 102.00 102.00 102.00 100.00 101.00 103.29 100.00 100.00 100.00 100.00 7,000,000 2,353,757 10,000 7,000 20,000 5,000 20,000 2,276 25,000 30,000 20,300 23,800 15,000 57,000 7,000,000 2,438,993 10,000 7,000 20,000 5,000 20,000 2,371 25,000 30,000 21,350 25,200 22,500 55,478 7,000,000 2,528,400 10,000 7,000 20,000 5,000 20,000 2,674 25,000 30,000 22.
26, 26,2 57,916 Total Par Value $ 100 Par Value $25 per Share, Cumulative Shares authorized Shares issued and outstandin
$2.47 Series 0*
$2.43 Series P
$3.31 Series T*
$2.65 Series Y*
$2.35 Series Z*
7.95% Series AA*
Total Par Value $25 Less Sinkin fund re uirements Total Preferred Stock
$ 25.25 27.75 27.35 235,376 25.00 25.00 65,000 363,000 485,000 8,200 712,176 30,000,000 19,400,000
$ 25.25 22,000 27.75 35,000 243,899 30,000,000 17,840,000 26,000 35,000 320,000 65,000 446,000 10,616 679,283 252,840 30,000,000 17,720,000 28,000 35,000 60,000 320,000 443,000 13,616 682,224 Common Stock (In thousands ofdollars)
AtDecember 31 Par Value $5 per Share Shares authorized Shares issued and outstanding Increase in shares outstandin Increase in $5 par value Increase in premium on capital stock Decrease in capital stock expense 1992 150,000,000 111,600,376 235,320 1,177 4,493 912 1991 150,000,000 111,365,056 40,975 205 614 2,460 1990 150,000,000 111,324,081 74,613
'Redemption required, see Note 6.
"Notcallable at December 31, 1992.
The aggregate fairvalue ofredeemable preferred stock at December 31, 1992 amounted to $581,984 compared toits carryfng amount of$566,100.
See Notes to Financial Statements.
Statement of Cash Flows l991 (In thousands ofdollars) l990 Operating Activities Net Income Adjustments to reconcile net income to net cash provided by operating activities Cumulative effect of accounting change for unbilled gas revenues Depreciation and amortization Fuel moderation component Provision for doubtful accounts Base financial component amortization Regulatory liabilitycomponent amortization Other regulatory amortizations Rate moderation component Rate moderation component carrying charges Class Settlement Amortization of cost of issuing and redeeming securities Federal income taxes deferred and other Allowance for other funds used during construction Other Changes in operating assets and liabilities Accounts receivable Accrued unbilled revenues Materials and supplies, fuel oil and gas in storage Prepayments and other current assets Accounts payable and accrued expenses ass Settlement
.crued taxes ther Net Cash Provided by Operating Activities Investing Activities Construction and nuclear fuel expenditures Shoreham post settlement costs Other Net Cash Used in Investing Activities Financing Activities Proceeds from issuance of Iong-term debt Redemption of long-term debt Proceeds from sale of preferred stock Redemption of preferred stock Preferred stock dividends paid Common stock dividends paid Cost of issuing and redeeming securities Other Net Cash (Used in) Provided by Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and cash equivalents at beginning of year Net increase (decrease) in cash and cash equivalents Cash and Cash Equivalents at End of Year nterest paid, before reduction for the allowance r borrowed funds used during construction eral income taxes paid ederal income taxes refunded See Notes to Financial Statements.
301,974 119,137 16,329 100,971 88,573) 22,072) 30,444) 42,837 22,541 41,204 160,432 (4,725) 699 (14,275)
(6,607)
(10,933)
(5,548) 62,513 7,351 (17,073) 590,064 (268,179)
(227,658)
(1,484 (497,321 1,659,928 (1,344,283) 411,373 (389,428)
(69,923)
(190,477)
(166,066) 7,520 (81,356) 11,387 298,098 11,387 309,485 424,842 2,100 1,566 305,538 118,955 34,025 35,431 100,971 (88,573) 8,666 (228,572)
(40,456) 25,467 27,456 181,138 (2,202) 38,068 (26,045) 2,352 28,217 (1,035) 34,560 3,926 (37,459) 520,428 (235,349)
(158,432)
(3,923)
(397,704) 1,532,247 (1,129,000) 63,130 (70,638)
(65,838)
(172,584)
(88,586) 3,707 72,438 195,162 102,936 195,162 298,098 477,240 1,650 642 331,317 (11,680) 110,884 3,804 30,097 100,971 (88,573) 14,427 (297,214)
(1 5,683) 22,574 23,648 179,643 (2,940) 15,234 (22,463) 30,748 (48,040) 23,752 2,345 (20,129)
(42,187)
(19,477) 321,058 (229,525)
(152,675) 81 (382,119) 112,319 (82,000)
(13,659)
(68,046)
(125,192)
(1,327) 1,598 (176,307)
$ (237,368) 340,304 (237,368) 102,936 479,278 900 23,588
Notes to Financial Statements Note 1. Summary ofSignificant Accounting Policies Regulation The Company's accounting policies conform to generally accepted accounting principles (GAAP) as they apply to a regulated enterprise.
Its accounting records are maintained in accordance with the Uniform Systems of Accounts prescribed by the Public Service Commission of the State of New York (PSC) and the Federal Energy Regulatory Commission (FERC).
UtilityPlant Additions to and replacements of utilityplant are capitalized at original cost, which includes material, labor, overhead and an allowance for the cost of funds used during construction. The cost of renewals and betterments relating to units of property is added to utilityplant. The cost of property replaced, retired or otherwise disposed of is deducted from utilityplant and, generally, together with dismantling costs less any salvage, is charged to accumulated depreciation. The cost of repairs and minor renewals is charged to maintenance expense. Mass properties (such as poles, wire and meters) are accounted for on an average unit cost basis by year of installation.
Allowance for Funds Used During Construction The Uniform Systems of Accounts deAnes the allowance for funds used during construction (AFC) as the net cost of borrowed funds for construction purposes and a reasonable rate of return upon the utility's equity when so used. AFC is not an item of current cash income. AFC is computed monthly using a rate permitted by FERC on that portion of construc-tion work in progress which is not included in the Company's rate base. The average annual AFC rate, without giving effect to compounding, was 9.98%, 10.74% and 11.03% for the years 1992, 1991 and 1990, respectively.
DePreciation The provisions for depreciation result from the application of straight-line rates to the original cost, by groups, of depreciable properties in service. The rates are determined by age-life studies performed annually on depreciable properties. Depreciation for electric properties was equivalent to approximately 3.2%, 3.3% and 3.2% of respective average depreciable plant costs for the years 1992, 1991 and 1990. Depreciation for gas properties was equivalent to approximately 2.6%, 2.9% and 2.8% of respective average depreciable plant costs for the years 1992, 1991 and 1990.
Financial Resource Asset GAAP authorizes recogniti of the existence of a regulatory asset when it is probable th a regulator willpermit fullrecovery of a previously incurred cost. Pursuant to the 1989 Settlement, the Company recorded a regulatory asset known as the Financial Resource Asset (FRA), to provide the Company with sufficient cash flows to assure its financial recovery. The FRA has two components, the Base Financial Component (BFC) and the Rate Moderation Component (RMC). The Rate Moderation Agreement (RMA),one of the constituent documents of the 1989 Settlement, provides for the full recovery of the FRA.
For a further discussion of the 1989 Settlement and the FRA, see Note 2.
Cash and Cash Equivalents Cash equivalents are highly liquid investments with maturities of three months or less when purchased. The carrying amount approximates fair value because of the short maturity of these investments.
Unbilied Revenues The Company accrues electric revenues for services rendered to customers but not billed at month-end.
Effective January 1, 1990, the Company adopted the full accrual method for unbilled gas revenues. Previously, unbilled gas revenues were recognized only for customers billed on a bi-monthly cycle basis forthe month in which th were normally not billed. This change better matches revenues and expenses and provides consistency with the Campany's revenue recognition method forelectric revenues. The cumulative effect of this change at January 1, 1990 was $ 11.7 million, net of tax effects, or $.10 per share and had been included in net income for the year ended December 31, 1990. The effect of this change on income before the cumulative effect of accounting change and on earnings for common stock for the year ended December 31, 1990 was not material.
Fuel Cost Adjustments The Company's electric and gas tariffs include fuel cost adjustment (FCA) clauses which provide for the difference between actual fuel costs and the fuel costs allowed in the Company's base tariffrates (base fuel costs). The Company defers these adjustments, net of tax effects, to future periods in which they willbe billed or credited to customers, except for base electric fuel costs in excess of actual electric fuel costs, which are currently credited to the RMC as incurred. The Company collects the higher of actual electric fuel costs or base electric fuel costs, pursuant to the RMA.
ctive December 1, 1991, the electric rate order discussed ote 3 authorized the adoption of a partial pass-through fuel cost incentive plan which includes a mechanism that compares, on a monthly basis, the Company's actual cost to produce electric energy against a targeted fuel value. The incentive measures the Company's abilityto purchase fuel at the lowest possible cost, to purchase energy economically from other power suppliers and to operate its generating plants at optimum efficiency. The shareowners are allocated 40% of the impact between actual fuel costs and targeted fuel values up to a maximum benefit or penalty of 20 basis points of the allowed return on common equity. The shareowners'ortion of these impacts are being deferred on a monthly basis. The accumulated net deferral willbe recovered or returned, through the FCA, over a twelve-month period in the following rate year. For a further discussion of the partial pass-through fuel cost incentive, see Note 3.
Fair Values of Financial Instruments The fairvalues for the Company's long-term debt and redeemable preferred stock are based on quoted market prices, where available.
The fair values for all other long-term debt and redeemable preferred stock are estimated using a discounted cash flow analyses which is based upon the Company's current remental borrowing rate for similar types of securities.
italization-premiums, Discounts and Expenses Premiums or discounts and expenses related to the issuance of long-term debt are amortized over the lifeof each issue.
Unamortized premiums or discounts and expenses related to issues of long-term debt that are refinanced are amortized and recovered through rates over the shorter life of the redeemed or new issues. Capital stock expense related to that portion of preferred stock that is required to be redeemed is written-offas an adjustment to retained earnings upon redemption unless the preferred stock is redeemed below par value. In that case, any resulting gain, net of the related capital stock expense, is recorded as additional premium on capital stock. Capital stock expense and redemption costs related to certain issues of preferred stock that have been refinanced as well as the cost of issuance ofthe preferred stock issued are recorded as deferred charges. These amounts are being amortized and recovered through rates over the shorter lifeofthe redeemed or new issues.
Federal Income Taxes The Company provides deferred federal income taxes with respect to certain differences between net income before income taxes and taxable income in certain instances when approved by the PSC, as disclosed in Note 10. The Company defers the benefit of 60% of pre-1982 gas and pre-1983 electric and 100% of all other investment tax credits, with respect to regulated properties, when realized on its tax returns.
For ratemaking purposes, certain accumulated deferred federal income taxes are deducted from rate base and amortized or otherwise applied as a reduction (increase) in federal income tax expense in future years. Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties.
The tax effects of other differences between income for financial statement purposes and forfederal income tax purposes are accounted for as current adjustments in federal income tax provisions.
The Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes requires, among other matters, recognition of the amount of current and deferred taxes payable or refundable at the date of the financial statements as a result of all events that have been recognized in the financial statements and adjustment of deferred income taxes for an enacted change in tax laws. For regulated enterprises, SFAS No. 109 prohibits net of tax accounting and reporting and requires recognition of a deferred tax liabilityfor the tax beneAts which are flowed through to its customers and the equity component ofAFC. A regulatory asset or liabilitywill be recognized relating to such items ifit is probable that the future increase or decrease in taxes payable thereon shall be recovered from or returned to customers through future rates. The Company estimates that had itadopted SFAS No. 109 at December 31, 1992, the Company would have recorded an accumulated deferred tax liabilityand a corresponding regulatory asset of approximately $ 1.2 billion. The Company willadopt SFAS No. 109 during the first quarter of 1993 and does not expect a material impact on the Statement of Income.
Reserves for Claims, Damages, Pensions and Benefits Losses arising from claims against the Company are partially self-insured. Extraordinary storm losses are partially self-insured up to $5 million until March 1, 1993, at which time the Company willbear a greater portion of these costs. Amounts provided are credited to the reserves based upon experience, risk of loss, actuarial estimates and/or specific orders of the PSC.
Reclasslfications Certain prior year amounts have been reclassified in the financial statements to be consistent with the current year's presentation.
Note 2. The 1989 Settlement On February 28, 1989, the Company and the State of New York (by its Governor) entered into the 1989 Settlement resolving certain issues relating to the Company and providing, among other matters, for the transfer of the Shoreham Nuclear Power Station (Shoreham) and its subsequent decommissioning. On February 29, 1992, the Company transferred ownership of Shoreham to the Long Island Power Authority (LIPA), an agency of the State of New York. Pursuant to the 1989 Settlement, LIPAis responsible for the decommissioning of Shoreham and has estimated that the decommissioning, in which Company employees are participating, willbe completed in 1994.
The 1989 Settlement recites the intention of the parties that the Company shall be returned to investment grade financial condition and that the Company and the State of New York anticipate that the PSC shall ensure that the future impacts on rates are to be minimized to the maximum extent practicable.
It is the Company's position that these objectives willcontinue to be achieved, in part, through the continued receipt of adequate and timely rate relief.
Upon the effectiveness of the 1989 Settlement, the Company simultaneously recorded on its Balance Sheet the retirement of its investment of approximately $4.2 billion in Shoreham and Bokum Resources Corporation (Bokum) and the establishment of the FRA.
The BFC, a component of the FRA, as initiallyestablished, represents the present value of the future net-after-tax cash flows which the RMAprovided the Company for its financial recovery. The BFC was granted rate base treatment under the terms of the RMAand is included in the Company's revenue requirements through an amortization included in rates over fortyyears on a straight-line basis beginning July 1, 1989. At December 31, 1992 and 1991, the unamortized balance of the BFC was approximately $3.7 billionand $3.8 billion, respectively.
The RMC, a component ofthe FRA, reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation of the rate moderation plan provided for in the RMA.The RMC, which has provided the Company with a substantial amount of non-cash earnings over the last several years, is based upon forecasted data filed in connection with the RMA. The RMAwas designed to provide rate increases sufficient to recover the RMC within a ten-year period. The RMC is currently adjusted, on a monthly basis, for the Company's share of certain Nine Mile Point Nuclear Power Station, Unit 2 (NMP2) operations and maintenance
- expenses, fuel credits resulting from the Company's electric fuel cost adjustment clause discussed in Note 1 and state gross receipts tax adjustments related to the FRA. Prior to December 1, 1991, the RMC was adjusted to reflect actual property taxes, cost of asbestos removal, interest expense, energy conservation and load management program costs, costs to provide added electric system reliability and inflation.
The RMC balance, which was $652 millionand $602 million at December 31, 1992 and 1991, respectively, has increased as the difference between revenues resulting from the implementation of the rate moderation plan provided for in the RMAand revenue requirements under conventional ratemaking, together with a carrying charge equal to the allowed rate of return on rate base, has been deferred. The RMC balance willsubsequently decrease and is expected to be fullyamortized by November 30, 1999, as deferred revenue requirements are recovered.
The PSC opproved the Long Island Lighting Company Ratemaking and Performance Plan (LRPP), discussed in Note 3, effective for each of the three rate years in the period beginning December 1, 1991. Although the LRPP provides for slightly lower annual electric rate increases than originally anticipated in the 1989 Settlement, the Company believes that itwillstill fullyrecover the RMC over the ten-year period principally as a result of changes in the original assumptions. The revenues assumed by the LRPP are adequate to provide the Company with recovery of its revenue requirements under conventional ratemaking and recovery of the RMC balance over the remainder of the ten-year period. However, actual revenues may differfro those assumed for this period. The original assumptions underlying the RMAincluded projections of future revenues, operating expenses and required rates of return. Since then, the Company has experienced interest rates, non-Shoreham property taxes and fuel expenses that are lower than those originally anticipated. As a result, amounts deferred in the RMC have been less than expected. In addition, as a result of the Company's improved credit ratings and an overall decline in the cost of money in the Rnancial marketplace, the PSC provided the Company in the LRPP with a lower rate of return on common equity than that initiallyprovided for in the RMA.This lower rate of return, which willbe in effect for the three years associated with the LRPP, results in a lower RMC balance than had been anticipated in the 1989 Settlement.
Under the 1989 Settlement, certain tax benefits attributable to the Shoreham abandonment are to be shared between ratepayers and shareowners. A regulatory liabilityof approximately $794 millionwas recorded in June 1989 to preserve an amount equivalent to the ratepayer tax benefits attributable to the Shoreham abandonment.
This amount is being amortized over a ten-year period an a straight-line basis from the effective date of the 1989 Settlement. The tax beneAt arising from the abandonment loss deduction has been offset against the corresponding regulatory liability~
the Company's Balance Sheet. This tax benefit could not~
have been fullyrecognized under GAAP were it not for the fact that its recovery is assured under the 1989 Settlement through the regulatory liabilityoffset.
oreham post settlement costs (decommissioning, payments in lieu of property taxes and other costs as incurred) are being capitalized and amortized and recovered through rates over a forty-year period on a straight-line remaining life basis.
Upon the effectiveness of the 1989 Settlement, Shoreham nuclear fuel was reclassified to deferred charges and is being amortized and recovered through rates over a forty-year period on a straight-line remaining life basis.
The 1989 Settlement credits on the Balance Sheet of approximately $ 164 million, net of amortization, reflect an adjustment of the book write-offto the negotiated 1989 Settlement amount. A portion of this amount is being amortized over a ten-year period. The remaining portion is not currently being recognized for ratemaking purposes under the 1989 Settlement.
Note 3. Rate Matters Electric Pursuant to the 1989 Settlement, discussed in Note 2, the Company received electric rate increases contemplated by the RMAfor each of the three rate years in the period ended November 30, 1991. The RMA ontemplates that the Company willapply to the PSC for geted annual rate increases of 4.5% to 5.0% in each year r an eight-year period beginning December 1, 1991. In response to the Company's rate filing, the PSC approved the LRPP in November 1991, which provides that the Company receive, for each of the three rate years in the period beginning December 1, 1991, annual electric rate increases of 4.15%, 4.1% and 4.0%, respectively, with an allowed return on common equity from electric operations of 11.6%
for each of the three rate years. Aftergiving effect to the reductions required by the Class Settlement discussed in Note 4, the Company's annual electric rote increases are approximately 4.15%, 3.9% and 3.9%, with an allowed return on common equity from electric operations of 10.92%, 10.72% and 10.58%, for the rate years beginning December 1, 1991, 1992 and 1993, respectively.
The LRPP was designed to be consistent with the RMA's long-term goals including: (a) the recovery of the BFC; (b) the recovery ofthe RMC in approximately ten years; (c) the Company's return to investment grade financial condition; and (d) the Company's receipt of adequate and timely rate relief. One principal objective of the LRPP is to reassign risk so that the Company assumes the responsibility for risks within the control of management, whereas risks largely beyond the control of management would be assumed by the ratepayers. The LRPP reflects an update of the long-range ecast of the Company's revenue requirements, which was basis of the RMA's initialthree rate increases. The LRPP ntains three major components revenue reconciliation, expense attrition and reconciliation, and performance incentives.
Revenue reconciliation is provided through a mechanism that reduces the impact of experiencing electric sales that are above or below the LRPP forecast by providing a fixed annual net margin level (defined as sales revenues, net of fuel and gross receipts taxes) that the Company willreceive over the three rate years under the LRPP. The differences between the actual electric net revenues and the annual net margin level are deferred on a monthly basis during the rate year.
The expense attrition and reconciliation component permits the Company to make adjustments for certain expenses recognizing that certain cost increases are unavoidable due to inflation and changes in the business. The LRPP includes the annual reconciliation of certain expenses for wage rates, property taxes, interest charges and demand side management (DSM) costs, the deferral and amortization of certain costs for enhanced reliabilityand operations and maintenance expenses, and the application of an inflation index to other expenses for the rate years beginning December 1, 1992 and 1993.
The deferred balances resulting from the net margin, property taxes, interest expense and wage rates willbe netted at the end of each rate year. The LRPP established a band whereby the first $ 15 millionof the total net deferrals willbe used to increase or decrease the RMC balance. The LRPP provides for the disposition of the total net deferrals in excess of the $ 15 millionband. The total net deferrals in excess of $ 15 millionwillbe refunded to or recovered from the ratepayers in the following twelve-month period beginning in the second quarter of each year. For the rate year ended November 30, 1992, the total net deferrals in excess of $ 15 million, to be recovered from the ratepayers, amounted to approximately $29.5 million.
Under the performance incentive component of the LRPP, the Company is allowed to earn for each rate year up to 60 additional basis points, or forfeit up to 38 basis points, of the allowed return on common equity as a result of its performance within certain incentive and/or penalty programs. These programs consist of a customer service performance plan, a DSM program, a time-of-use program and a partial pass-through fuel cost incentive plan, discussed in Note 1. The incentives and/or penalties related to the customer service performance plan and the time-of-use program are determined an a monthly basis during the rate year. The total amounts deferred at the end of each rate year willbe refunded to or recovered from the ratepayers through the FCA in the followingtwelve-month period beginning in the second quarter of each year. The incentives earned from the DSM program are collected in rates, on a monthly basis, through the FCA. For the rate year ended November 30, 1992, the Company earned a total of approximately 23 basis points, or $4.3 million, net of tax effects, based upon its performance within these programs.
For the rate year ended November 30, 1992, the Company earned $ 16.2 million, net of tax effects, in excess of its allowed rate of return on common equity which, in accordance with the LRPP, was shared equally between ratepayers (by a reduction to the RMC) and shareowners.
These excess earnings were generated as a result of a reduction in operating expenses and the effect of a decrease in capital expenditures included in rate base. Prior to December 1, 1991, the RMA provided that earned returns on common equity in excess of targeted allowed rates of return, as adjusted, were to be applied to reduce the RMC ar mitigate rates, as determined by the PSC, at the end of eachrate year. For the rate year ended November 30, 1991, the Company earned $ 10.1 million, net of tax effects, in excess of its allowed rate of return, which was applied as a reduction to the RMC. The Company did not earn in excess of its allowed rate of return for the rate year ended November 30, 1990.
To assist in recovering the RMC within a ten-year period under the rates provided by the LRPP, the Company, in accordance with the LRPP, has credited the RMC with several deferred ratepayer benefits. In December 1992, the Company applied a total of approximately $22.5 millionof various deferred ratepayer benefits to the RMC including the ratepayers portion of the excess earnings for the rate year ended November 30, 1992. In December 1991, the Company applied approximately $57.6 millionof previously deferred credits and related carrying charges for amounts collected in excess of actual fuel costs and other miscellaneous deferred credits as a reduction to the RMC.
Gas In November 1992, the PSC approved a gas rate increase of 7.1%, or $35.7 millionannually, which became effective on December 1, 1992. The gas rate decision provides for an 11.0% allowed return on common equity for the rate year beginning December 1, 1992.
On December 31, 1992, the Company filed an application with the PSC seeking gas rate relief for the three rate years in the period beginning December 1, 1993. The Company has requested a gas rate increase of 6.7%, or $37.7 millionin additional revenues to become effective for the first rate year under this filing.The Company's filingalso includes a proposed methodology for determining rate increases, not to exceed approximately $30 millionannually, for the subsequent second and third rate years. This filingreflects the Company's latest prajections of capital expenditures, operations and maintenance expenses and the continued expansion of its gas business.
Note 4. The Class Settlement The Class Settlement, which became effective on June 28, 1989, resolved a civillawsuit against the Company brought under the federal Racketeer Influenced and Corrupt Organizations Act (RICO Act). The lawsuit which the Class Settlement resolved had alleged that the Company made inadequate disclosures before the PSC concerning the construction and completion of nuclear generating facilities.
The Class Settlement provides the Company's ratepayers with reductions, aggregating $390 million, that are to be reflected as adjustments to their monthly electric bills over a ten-year period beginning June 1, 1990. The reductions required for the ffrst three years have already been reflected in rates. The reductions in each subsequent twelve-month period are as follows:
June 1993
$30 million June 1994
$30 million June 1995
$40 million June 1996
$50 million June 1997
$60 million June 1998
$60 million June 1999
$60 million Upon its effectiveness, the Company recorded its liabilityfor the Class Settlement on a present value basis at $ 170 milli and simultaneously recorded a charge to income (net of ta effects of $57 million) of approximately $ 113 million. Each month the Company records the changes in the present value of such liabilitythat result from the passage of time and from monthly reductions. Because the reductions of the liabilityare greater in the later years, the current present value calculations result in an increase in total liabilitydespite the reductions in the total amount due. Beginning sometime in 1993, the amount of the total remaining Class Settlement liabilitywillbegin to decrease as the monthly reductions of the liabilityexceed the incremental increases in the present value. The Company expects the Class Settlement liabilitywill be fullysatisfied by May 31, 2000.
As a result ofthe Class Settlement, the Company's electric rate increases on average willbe approximately.2% to.3%
per year lower than they would otherwise have been during the balance ofthe Class Settlement period. The amounts recorded on the Statement of Income for 1992, 1991 and 1990 of approximately $23 million, $25 millionand $23 million, respectively, represent the increase in present value of the Class Settlement liability.
te 5. Nine MilePoint Nuclear Power Station, nit 2 The Company has an 18% undivided interest in NMP2 which is operated by Niagara Mohawk Power Corporation (NMPC) near Oswego, New York. Ownership of NMP2 is shared by five cotenants: the Company (18%), NMPC (41%), New York State Electric Sc Gas Corporation (18%),
Rochester Gas and Electric Corporation (14%) and Central Hudson Gas 8 Electric Corporation (9%). At December 31, 1992, the Company's net utilityplant investment in NMP2 was $776 million, net of accumulated depreciation of $97 million,which is included in the Company's rate base. Output of NMP2, which had an operating capability of 1,080 megawatts in 1992, is shared in the same proportions as the cotenants'espective ownership interests. NMPC has determined that the operating capability of NMP2, effective January 1, 1993, is 1,047 megawatts. The operating expenses of NMP2 are also allocated to the cotenants in the same proportions as their respective ownership interests. The Company's share of these expenses is included in the appropriate operating expenses on the Statement of Income.
The Company is required to provide its respective share of financing for any capital additions to NMP2. Nuclear fuel osts associated with NMP2 are being amortized on the basis the quantity of heat produced for the generation of ctricity.
NMPC has contracted with the United States Department of Energy for the disposal of nuclear fuel. The Company reimburses NMPC for its 18% share of the cost under the contract at a rate of $ 1.00 per megawatt hour of net genera-tion less a factor to account for transmission line losses.
Based upon a study performed by NMPC, the Company's share of the decommissioning costs for NMP2 is estimated to be $37 million (in 1989 dollars) assuming that decom-missioning willcommence in 2027 or $237 million (in 2027 dollars). The Company's share of estimated decommissioning costs are being provided for in electric rates and are being charged to operations as depreciation expense. The amount of accumulated decommissioning costs collected from the Company's ratepayers through December 31, 1992 was
$5.4 million. Amounts collected by the Company for the decommissioning of the contaminated portion ofthe NMP2 plant, which approximate 84% of total decommissioning costs, are held in an independent decommissioning trust fund. This fund complies with regulations issued by the Nuclear Regulatory Commission (NRC) governing the funding of nuclear plant decommissioning costs. The Company's funding plan for its share of decommissioning costs willprovide reasonable assurance that, at the time ermination of operation, adequate funds for the ommissioning of the Company's share ofthe contaminated portion of NMP2 plant willbe available.
The Internal Revenue Service (IRS) has ruled that the Company's decommissioning trust meets the requirements of a qualified fund under applicable provisions of the federal income tax law. This IRS ruling allows the Company's contributions to the decommissioning trust to be deductible for income tax purposes for the tax year in which they are made.
Note 6. Capital Stock Preferred Stock Redemption of certain series of preferred stock is effected through the operation of various sinking fund provisions. The aggregate par value of preferred stock required to be redeemed in each ofthe years 1993 through 1996 is $8.2 million and in 1997 is $4.5 million.
Dividends on preferred stock are paid in preference to dividends on common stock or any other stock ranking junior to preferred stock.
Preference Stock None ofthe authorized 7,500,000 shares of nonparticipating preference stock, par value $ 1 per share, which ranks junior to preferred stock, are outstanding.
Common Stock Of the 150,000,000 shares of authorized common stock at December 31, 1992, 1,834,289 shares were reserved for sale through the Company's Employee Stock Purchase Plan, 6,620,755 shares were committed to the Automatic Dividend Reinvestment Plan (ADRP) and 132,694 shares were reserved forconversion of the Series I
Convertible Preferred Stock at a rate of $ 17.15 per share. In June 1992, the Company reinstated the ADRP which had been suspended since February 1984. Common and preferred stock dividend limitations in the mortgage securing the Company's First Mortgage Bonds are not material. There are no dividend limitations contained in the Company's other debt instruments.
Note 7. Long-Term Debt Each of the Company's outstanding mortgages is a lien on substantially all of the Company's properties.
First Mortgage Allof the bonds issued under the First Mortgage, including those issued after June 1, 1975 and pledged with the Trustee of the G8 R Mortgage (G8 R Trustee) as additional security for General and Refunding Bonds (G8cR Bonds), are secured by the lien of the First Mortgage. First Mortgage Bonds pledged with the G8 R Trustee do not represent outstanding indebtedness of the Company. Amounts of such pledged bonds outstanding were
$ 1.03 billionand $957 millionat December 31, 1992 and 1991, respectively. The annual First Mortgage depreciation fund and sinking fund requirements for 1992, due not later than June 30, 1993, are estimated at $ 194 millionand $ 18 million, respectively. The Company expects to meet these requirements with property additions and retired First Mortgage Bonds.
G&RMortgage The lien of the G8 R Mortgage is subordinate to the lien of the First Mortgage. The annual G8 R Mortgage sinking fund requirement for 1992, due not later than June 30, 1993, is estimated at $27 million.
The Company expects to satisfy this requirement with retired G8 R Bonds.
Third Mortgagel1989 Term Loan Agreement In November 1992, the Company used the net proceeds from the issuance of $451 millionprincipal amount of debentures to repay the then outstanding 1989 Term Loan Agreement which had been secured by the Third Mortgage. The Third Mortgage has been discharged as a result of the repayinent of the 1989 Term Loan Agreement.
Fourth Mortgage In December 1992, the Company satisfied the Fourth Mortgage which had secured $85 million of the Company's obligations under the letters of credit then supporting the 1985 Pollution Control Revenue Bonds (1985 PCRBs). The 1985 PCRBs are presently supported by unsecured letters ofcredit discussed below under the heading Authority Financing Notes.
1989 Revolving Credit Agreement The Company has an estimated $251 millionavailable to itthrough October 1, 1993, under its $300 million 1989 Revolving Credit Agree-ment (1989 RCA). This line of credit is secured by a Arst lien upon the Company's accounts receivable and fuel oil inventories.
The Company has, with the approval of the NRC, dedicated
$49 millionof the 1989 RCA sufficient to cover estimated, not yet incurred, costs attributable to the decommissioning of Shoreham. As of December 31, 1992, LIPAwas projecting, based on current information, that the Shoreham decommis-sioning costs would total $ 160 million.The Company has provided LIPAwith funds aggregating approximately
$ 111 millionfor decommissioning costs incurred to date and for decommissioning costs expected to be incurred during the first quarter of 1993. Actual decommissioning costs may differfrom LIPA's current estimate. The amount of credit available to the Company under the 1989 RCA willincrease as decommissioning costs are funded by the Company.
At December 31, 1992, no amounts were outstanding under the 1989 RCA. The Company has the option, when amounts are outstanding, to commit to one of three interest rates including: (a) the Adjusted Certificate of Deposit Rate which is a rate based on the certificate of deposit rates of certain of the lending banks, (b) the Base Rate which is generally a rate based on Citibank, N.A.'s prime rate and (c) the Eurodallar Rate which is a rate based on the London Interbank Offering Rate (LIBOR). The Company has agreed to pay a fee of one quarter ofone percent per annum on the unused portion.
The termination date of the 1989 RCA may be extended for one-year periods upon the acceptance by the lending ba'f the Company's request delivered to the lending banks prior to April 1 in each year.
Debentures On January19, 1993, the Company issued
$36 millionprincipal amount of Debentures, 7.30% Series Due 2000. The net proceeds from the issuance of these debentures willbe used in February 1993 to redeem, at the applicable redemption price, $35 millionprincipal amount of First Mortgage Bonds, 8.20% Series R Due 1999.
Authority Financing Notes Authority Financing Notes are issued by the Company to the New YorkState Energy Research and Development Authority (NYSERDA) to secure certain tax-exempt Pollution Control Revenue Bonds, Electric Facilities Revenue Bonds (EFRBs) and Industrial Development Revenue Bonds issued by NYSERDA. Certain ofthese bonds are subject to periodic tender at which time their interest rates are subject to redetermination.
The Company has $400 millionof EFRBs that were converted in June 1992 from a variable weekly interest rate to a Axed annual rate of 7.15% and $ 100 millionof EFRBs that were converted in January 1993 from a variable weekly interest rate to a Axed annual rate of 6.90%. Letters of credit supporting these EFRBs, by their terms, were terminated upon the conversion to a fixed interest rate.
The 1985 PCRBs are supported by letters of credit pursuant to which the letter of credit bank has agreed to pay the principal, interest and premium on the tendered 1985 PCRBs, in the aggregate, up to approximately $ 163 millionin the event of default. The obligation of the Company to reimburse the letter of credit bank is unsecured. These letters of credit expire on March 16, 1996, at which time the Company is required to obtain either an extension of the letters of credit or substitute credit backup. Ifneither can be obtained, the 1985 PCRBs must be redeemed unless the Company purchases the 1985 PCRBs in lieu af redemption and subsequently remarkets them. Prior to December 16, 1992, the letters of credit supporting the 1985 PCRBs were partially secured by the Fourth Mortgage in the amount of $85 million.
Fair Valve Car~ing Amount First Mortgage Bonds General and Refunding Bonds Debentures Authority Financing Notes 397,971 400,000 1,891,842 1,801, 2,523,721 2,428, 729,61 0
- 716, Total Long-Term Debt
$ 5,543,144
$ 5,345,733 Fair Values of Long-Term Debt The carrying amounts and fair values of the Company's long-term debt consisted of the followingat December 31, 1992:
(In thousands ofdollars)
gT Dbt b
31 Maturity First Mortgage Bonds (excludes Pledged Bonds)
April 1, 1993 June 1, 1994 u
June 1, 1995
, March 1, 1996 April 1, 1997 September 1, 1999 September 1, 2000
'pril 1, 2001 December 1, 2001 September 1, 2002 December 1, 2003 t
TotalFirstMort a e Bonds General and Refunding Bonds May 1, 1996 February 15, 1997 March 1, 1999 May 15, 1999 May 15, 2006 June 1, 2006 December 1, 2006 May 1, 2007 April 1, 2008 July 15, 2008 May 1, 2021 Jul 1,2024 Interest Rate 4.40%
4 5/8%
4.55%
5 1/4%
5 1/2%
8.20%
9 1/8%
7 1/4%
7 1/2%
7 5/8%
8 1/8%
8 3/4%
8 3/4%
9.75%
7 85%
8.50%
9 5/8%
8 5/8%
8 5/8%
9.20%
7.90%
9 3/4%
9 5/8%
Series M
N0 P
Q R
S U
V W
X 1992 40,000 25,000 25,000 40,000 35,000 35,000 40,000 50,000 50,000 60,000 400,000 415,000 250,000 56,000 75,000 50,000 85,000 80,000 415,000 375,000 (In thousands ofdollars) 1991 40,000 25,000 25,000 40,000.
35,000 35,000 25,000 40,000 50,000 50,000 60,000 425,000 415,000 250,000 63,000 70,000 50,000 85,000 75,000 415,000 375,000 Third Mortgage/1989 Term Loan Agreement Debentures 1,801,000 1,798,000 446,341 April 1, 1993 November 15, 1993 June 15, 1994 November 15, 1994 June 15, 1999 July 15, 1999 June 15, 2019 July 15, 2019 November 1, 2022 Total Debentures Authority Financing Notes Pollution Control Revenue Bonds December 1, 2006 December 1, 2009 October 1, 2012 March 1, 2016 Electric Facilities Revenue Bonds September 1, 2019 June 1, 2020 December 1, 2020 February 1, 2022 August 1, 2022 August 1, 2022 ustrial Development Revenue Bonds December 1, 2006 tal Authority Financin Notes Total Long-Term Debt Less Current maturities Total Long-Term Debt Less Current Maturities 11 3/8%
11.70%
10.25%
11.75%
10.875%
7.30%
11.375%
8.90%
9%
7.5%
7.8%
8 1/4%'p/
7.15%
7.15%
7.15%
7.15%
3 95P/ 44 4 4p/ 44 4 7.5%
1976A 1979 B 1982 1985A,B 1989A,B 1990A 1991 A 1992 A,B 1992 C 1992 D 1976A,B 375,000 175,000 400,000 175,000 30,545 397,000 4,513 420,000 451,000 2,428,058 28,375 19,100 17,200 150,000 100,000 100,000 100,000 100,000 50,000 50,000 2,000 716,675 5,345,733 590,000
$4,755,733 375,000 175,000 400,000 175,000 350,000 350,000 1,825,000 28,375 19,100 17,200 150,000 100,000 100,000 100,000 2,000 516,675 5,011,016 10,000 S5,001,016
'Tendered every throe years, next tondor October 1994.
"Tendorod annually an March 1.
"'Converted ta a fixed annual rate af 6.90% from a variable weekly rate an January 21, 1993.
Long-term debt duoin tho next five yoarsis $590,000 (1993), $600,000 (1994), $25,000 (1995), $455,000 (1996) and $2B6,000 (1997).
Note 8. Retirement Benefit Plans fin thousands ofdollaa) 1992 1991 Actuarial present value of benefit obligation Vested benefits Nonvested benefits
$ 453,201
$ 375,326 4,326 5,315 Accumulated benefit obligation
$ 457,527
$ 380,641 Plan assets at fair value Actuarial present value of projected benefit obligation Projected benefit obligation less than plan assets Unrecognized January 1, net obligations Unrecognized net gain Net accrued pension cost
$ 556,399
$ 519,816 536,818 446,718 19,581 73,098 98,147 33,113 (128,218 (114,389)
$ (10,490 (8,178)
Pension Plans The Company maintains a primary defined benefit pension plan (Primary Plan) which covers substantially all employees, a supplemental plan (Supplemental Plan) which covers officers and certain key executives and a retirement plan which covers the Board of Directors (Directors'lan).
Primary Plan The Company's funding policy is to contribute annually to the Primary Plan a minimum amount consistent with the requirements of the Employee Retirement Income Security Actof 1974 (ERISA) plus such additional amounts, if any, as the Company may determine to be appropriate from time to time.
For service before January 1, 1992, pension benefits are determined based on the greater of an accrued benefit as of December 31, 1991, or applying a moving five-year average to a certain percentage per year of service. For service after January 1, 1992, pension benefits are established by crediting the employee with an amount determined using the base salary for each year the employee is a participant in the plan. This change in the pension benefits calculation resulted in an increase of approximately
$70 millionin the actuarial present value of projected benefit obligation. Employees are vested in the pension plan after five years of service with the Company.
The Primary Plan's funded status and amounts recognized on the Balance Sheet at December 31, 1992 and 1991 were as follows:
Discount rate Rate of future compensation increases Long-term rate of return on assets 1992 1991 1990 7.75%
7.75%
7.25%
5.5%
5.5%
6.0%
75%
7Q%
7Q%
The Primary Plan assets at fair value primarily include cash, cash equivalents, group annuity contracts, bonds and listed equity securities.,
Supplemental Plan The Supplemental Plan, the cost of which is borne by the Company's shareowners, provides supplemental death and retirement benefits for officers and other key executives without contribution from such employees. The Supplemental Plan is a non-qualified plan under the Internal Revenue Code. Death benefits are currently provided by insurance. The provision for retirement benefits, which is unfunded, totaled approximately $685,000,
$675,000 and $561,000 and was recognized as an expense in 1992, 1991 and 1990, respectively.
Directors'lan The Directors'lan, adopted in February 1990, provides benefits to directors who are not officers of the Company. Directors who have served in that capacity for more than five years qualify as participants under the plan.
The Directors'lan is a non-qualified plan under the Internal Revenue Code. The provision for retirement benefits, which is unfunded, totaled approximately $ 133,000, $ 101,000 and $99,000 and was recognized as an expense in 1992, 1991 and 1990, respectively.
Periodic pension cost for 1992, 1991 and 1990 forthe Primary Plan included the following components:
Itn thousands ofdollaa) 1992 1991 1990 Service costbenefits earned during the period
$ 13,661
$ 14,323
$ 12,720 Interest cost on projected benefit obligation and service cost 39,574 33,698, 32,264 Actual return on plan assets (47,156)
(63,875)
(23,121)
Net amortization and deferral 12,849 33,569 (5,449)
Net eriodic pension cost
$ 18,928
$ 17,715
$ 16,414 Assumptions used in accounting for the Primary Plan were:
0
tretlrement Benefits Other Than Pensions In dition to providing pension benefits, the Company provides certain medical and life insurance benefits for retired employ-ees. Substantially all ofthe Company's employees may become eligible for these beneRts ifthey reach retirement age after working forthe Company for a minimum of five years.
These and similar beneRts for active employees are provided by the Company or by insurance companies whose premiums are based on the benefits paid during the year. The cost of providing these benefits on a pay-as-you-go method was
$38,044,000, $37,312,000 and $29,410,000 for 1992, 1991 and 1990, respectively, and were recognized as an expense as beneRts and premiums were paid. The cost of providing these benefits for approximately 2,200 retirees is not separable from the cost of providing benefits. for approximately 6,200 active employees forthe years 1990 through 1992.
In December 1990, the FASB issued SFAS No. 106, Employers'ccounting for Postretirement Benefits Other Than Pensions which requires the Company to recognize the expected cost of providing postretirement benefits when employee services are rendered rather than on a pay-as-you-go method.
The Company willadopt the provisions of SFAS No. 106
'ng the first quarter of 1993 and record an accumulated retirement benefitobligation and a corresponding regula-ry asset of approximately $376 million. This regulatory asset willbe amortized and recovered in rates over a twenty-year period. Additionally, as a result of adopting SFAS No.
106, the Company's annual postretirement benefit expense willincrease approximately $44 millionabove the amount previously recorded under the pay-as-you-go method.
In 1992, the PSC staff issued a proposed generic accounting order which proposes that the effects of implementing SFAS No. 106 be phased into rates. The PSC proposes that the difference between the postretirement beneRt expense recorded for accounting purposes in accordance with SFAS No. 106 and the postretirement beneRt expense reflected in rates willbe deferred and accumulated as a regulatory asset.
The ongoing annual postretirement benefit expense willbe phased into and fullyreflected in rates within a Rve-year period with the accumulated postretirement obligation being recovered in rates over a twenty-year period.
In November 1992, the FASB issued SFAS No. 112, Employer's Accounting for Postemployment Benefits. SFAS No. 112 establishes accounting standards for employers who provide benefits to former or inactive employees after employment but before retirement. SFAS No. 112 requires employers to recognize the obligation to provide employment benefits ifthe followingconditions are met:
bligation is attributable to employees services already ndered, employee rights to those benefits are accumulated or vested, payment is probable and the amount of the benefit is reasonably estimated. The Company has not yet evaluated the effect of implementing SFAS No. 112 on its financial condition and results of operations. The Company believes it willbe permitted to recover these costs through rates. The Company must adopt SFAS No. 112 by January 1, 1994, and does not expect to do so prior to that date.
Note 9. Commitments and Contingencies Litigation On February 11, 1988, the Company began a lawsuit in Suffolk County Supreme Court against Suffolk County, seeking the recovery of approximately $54 million in damages for Suffolk County's breach of a contract to prepare an offsite emergency response plan for Shoreham (Long Island Lighting Company v. County ofSuffolk). In addition, the complaint alleges that, because of the delays that have resulted, the Company has been damaged in an additional amount of $706 million. On October 30, 1992, the court granted in part and denied in part Suffolk County's motion to amend its answer to assert additional defenses and counterclaims. Two proposed counterclaims were allowed seeking approximately $ 16 millionin damages as well as
$700 million in alleged punitive damages. The outcome of these counterclaims, ifadverse, could have a material effect on the financial condition of the Company. The Company has argued that there is no basis for punitive damages and intends to vigorously prosecute its claim against Suffolk County and to defend against these counterclaims.
Commitments The Company has entered into substantial commitments for fossil fuel, gas supply, purchased power and transmission facilities. The costs associated with these commitments are normally recovered from ratepayers through provisions in the Company's rate schedules.
Nuclear Plant Insurance The Company has property damage insurance and third-party bodily injury and property liabilityinsurance for its 18% share in NMP2 and for Shoreham. The premiums for this coverage are not material.
The policies for this coverage provide for retroactive premium assessments under certain circumstances. Maximum retroactive premium assessments could be as much as approximately $4.7 million. For property damage at each nuclear generating site, the NRC requires a minimum of
$ 1.06 billionof coverage. The NRC has provided Shoreham with a partial exemption from these requirements for Shoreham.
Under certain circumstances, the Company may be assessed additional amounts in the event of a nuclear incident. Under agreements established pursuant to the Price Anderson Act, the Company could be assessed up to approximately $74 millionper nuclear incident in any one year at any nuclear unit, but not in excess of approximately $ 12 millionin payments per year for each incident. The Price Anderson Act also limits liabilityfor third-party bodily injury and third-party property damage arising out of a nuclear occurrence at each unit to $7.4 billion.
Note 10. Federal Income Taxes On April 17, 1989, the Company received a private letter ruling from the IRS which stated that the Company would be entitled, for federal income tax purposes, to an abandon-ment loss deduction in connection with Shoreham, upon effectiveness of the 1989 Settlement. The Company claimed an abandonment loss deduction on its 1989 federal income tax return of approximately $ 1.8 billion. The Company's net operating loss carryforward is estimated to be approximately
$2.3 billion at December 31, 1992.
On January 8, 1990 and October 10, 1992, the Company received Revenue Agents'eports disallowing certain deductions claimed by the Company on its tax returns for the audit cycle years 1984-1987 and 1988-1989, respectively.
The Revenue Agents'eports reflects proposed adjustments to the Company's federal income tax returns for 1984 through 1989 which, ifsustained, would give rise to tax deficiencies totaling approximately $220 million. The Company is protesting some of the adjustments and seeks an administrative and, ifnecessary, a judicial review of the conclusions reached in the Revenue Agents'eports.
The Company cannot predict either the timing or the manner in which this matter willbe resolved. If, however, the ultimate disposition of any or all matters raised in the Revenue Agents'eports are adverse to the Company, the Company expects that any deficiencies that may arise willbe substantially offset by the net operating loss carrybacks associated with the Shoreham abandonment loss deduction and thus any impact would not have a material effect on the Company's financial condition ar cash flows.
The amount of investment tax credit (ITC) carryforward fo financial statement purposes after 1992 is approximately
$206 million.The Revenue Agents have proposed ITC adjustments which, ifsustained, would reduce the Company's carryforward by approximately $96 million. These credits expire by the year 2002. In accordance with the Tax Reform Act of 1986 (TRA 86), ITC allowable as credits to tax returns for years after 1987 must be reduced by 35%. The amount of the reduction willnot be allowed as a credit for any other taxable year.
The Company has not provided deferred taxes on approxi-mately $500 millionof various other deductions and depreciation method differences'for property placed in service prior to 1981 which, in conformity with the ratemaking 'practices of the PSC, have been flowed through.
These various other flow-through tax deductions, which were deductible currently for tax purposes but capitalized for accounting and ratemaking purposes, include certain taxes, a portion of AFC, pensions and certain other employee benefits. See Note 1 with respect to a change in the method of accounting for income taxes which the Company will adopt during the first quarter of 1993.
e federal income tax amounts included in the Statement of Income differ from the amounts which result from lying the statutory federal income tax rate to net income before income taxes. The table below sets forth the reasons for such differences.
(In thousands ofdollars) 1992 1991 1990 Federal income tax, per Statement of Income Current Deferred and other (see Note 1) 1989 Settlement Shoreham property Bokum Resources Corporation Rate moderation component Other 1989 Settlement items Shoreham post settlement costs Contractor litigation settlement Class Settlement Interest capitalized Mortgage recording tax Accelerated tax depreciation Call premiums Fuel cost adjustments Capitalized overheads tired debt costs temaking and performance plan ien date property taxes Other items, net Total Deferred and Other Total federal income tax expense Income before cumulative effect of accounting change Income Before Cumulative Effect of Accounting Change and Income Taxes
%of Pre-tox Amount Income 530 3,806 10,351 (5,499) 60,125 (1,190)
(2,100)
(222) 35,951 35,441 8,747 2,645 17,680 (6,161) 858 160,432 160,962 301,974
$ 462,936 Amount 515 10,677 20,400 77,715 (13,638) 50,375 (18,758)
(2,038)
(2,562) 4,653 30,447 18,496 (3,289) 180 9,185 (371)
(334) 181,138 181,653 305,538
$ 487,191
%of Pre.tax Income
%of Pre-tax Amount Income 3,638 3,239 101,053 (13,577) 61,475 (534)
(3,220)
(589) 33,342 (3,111) 4,879 2,287 (5,601 179,643 183,281 319,637
$ 502,918 Statutory federal income tax Additions (reductions) in federal income tax resulting from:
1989 Settlement Shoreham property Allowance for funds used during construction Lien date property taxes Tax credits Excess of book depreciation over tax depreciation Interest capitalized Other items, net Total Federal Income Tax Expense 4,003 4,003 0.9 (4,118)
(0.9)
(6,586)
(1.4)
(1,310) 277 (2,980) 12,193 2.6 2,947 0.6 4,875)
(1.0 13,108 4,232 1,322
$ 160,962 34.8%
$ 181,653
$ 157,398 34.0%
$ 165,645 0.8 (0.3) 0.1 (0.6) 2.7 0.9 (0.3 4,035 0.8 (2,573)
(0.5)
(8,757)
(1.8) 1,537 0.3 11,987 2.4 6,031 1.2 29 00 37.3%
$ 183,281 36.4%
34.0%
$ 170,992 34.0%
Note 11. Segments of Business The Company is a public utilityoperating company engaged in the generation, distribution and sale of electric energy and the purchase, distribution and sale of natural gas to residential and commercial customers in Nassau and Suffolk Counties and the Rockaway Peninsula in Queens County, all on Long Island, New York. Identifiable assets by segment include net utilityplant, financial resource asset, materials and supplies (excluding cotnmon), accrued unbilled revenues, gas in storage, fuel and deferred charges (excluding common). Assets utilized for overall Company operations consist of other property and investments, cash, temporary cash investments, special deposits, accounts receivable, prepayments and other current assets, unamortized debt expense and other deferred charges.
(In thousands ofdollars)
For year ended December 31 Operating revenues Electric Gas Total Operating expenses (excludes federalincomo taxes)
Electric Gas Total Operating income (before federalincome taxes)
Electric Gas Total AFC Other income and deductions Interest charges Federalincome taxes operating Federal income taxes non o eratin Income before cumulative effect of accounting change Cumulative effect of accounting change (net of a licable taxes Net Income Depreciation and amortization Electric Gas Total Construction and nuclear fuel expenditures'lectric Gas Total 1992 2,194,632 427,207 2,621,839 1,354,959 352,777 1,707,736 839,673 74,430 914,103 (12,111)
(49,128) 512,406 172,998 (12,036) 301,974 301,974 104,034 15,103 119,137 163,609 109,295 272,904 1991
$ 2,196,568 351,161
$ 2,547,729
$ 1,252,993 338,295
$ 1,591,288 943,575 12,866 956,441 (5,794)
(48,772) 523,816 169,452 12,201 305,538 305,538 104,172 14,783 118,955 144,356 93,195 237,551 1990
$ 2,095,660 361,242
$ 2,456,902
$ 1,151,105 322,515
$ 1,473,620 944,555 38,727 983,282 (7,
(20,'08,2 180,652 2,629 319,637 11,680 331,317 98,022 12,862 110,884 151,425 81,040 232,465
'Includes non-cash allowance forother funds used during construction and excludes Shoreham post settlement costs.
(In thousands ofdollars)
AtDecember 31 Identifiable assets Electric Gas Total Assets utilized for overall Com an o erations Total Assets 1992 8,351,370 767,444 9,118,814 1,129,810
$ 10,248,624 1991
$ 7,986,887 621,570 8,608,457 934,844
$ 9,543,301 1990
$ 7,643,963 540,3 8,184, 658,36
$ 8,842,684
te 12. Quarterly Financial information uditedJ In thousands of dollars exce t earnin s
er common share Operating revenues For the quarter ended March 31 June 30 September 30 December 31 Operating income For the quarter ended March 31 June 30 September 30 December 31 Net income For the quarter ended March 31 June 30 September 30 December 31 Earnings forcommon stock For the quarter ended March 31 June 30 September 30 December 31 s nings per common share For the quarter ended March 31 June 30 September 30 December 31 1992
$ 697,761 580,498 747,729 595,851
$ 179,741 166,954 256,800 137,610 66,7O6 59,285 141,388 34,595 50,553 41,040 126,295 20,132
.45
.37 1.14
.18 1991
$ 657,921 543,250 773,706 572,852
$ 207,830 166,830 268,041 144,288 86,4O4 50,089 144,449 24,596 69,567 33,013 128,175 8,389
.30 1.15
.08 Report of Ernst &'Young, independent Auditors To the Shareowners and Board of Directors of Long Island Lighting Company We have audited the accompanying balance sheet of Long Island Lighting Company as of December 31, 1992 and 1991 and the related statements of income, shareowners'quity and cash flows for each of the three years in the period ended December 31, 1992. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial osition of Long Island Lighting Company at December 31, 1992 and 1991, and the results of its operations its cash flows for each of the three years in the period ended December 31, 1992 in conformity with rally accepted accounting principles.
Melville, New York February 5, 1993
Selected Financial Data Summary of Operations(See Notes to Financial Statements) 1992 1991 1990 1989
- Tab, Total revenues (000)
Total operating income (loss) (000)
Before federal income taxes Afterfederal income taxes Income (loss) before cumulative effect of accounting changes (000)
Cumulative effect of accounting change for unbilled gas revenues (net of taxes) (000)
Cumulative effect of accounting change for disallowed costs (net of taxes) (000)
Earnings (loss) for common stock (000)
Average common shares outstanding (000)
Earnings (loss) per common share Before cumulative effect of accounting changes Cumulative effect of accountin chan es Earnin s loss ercommonshare Pro forma earnings with accounting changes for unbilled gas revenues and disallowed project costs applied retroactively Earnings (loss) for common stock (000)
Earnin s loss er common share Common stock dividends declared per share Common stock dividends paid per share Book value per common share at year end Common shareowners at ear end Ratio of earnings to fixed charges Ratio of earnings to combined fixed charges and preferred stock dividends Ratio of earnings to fixed charges (excluding AFC and RMC)
Ratio of earnings to combined fixed charges and preferred stock dividends (excluding AFC and RMC)
'The Company had no earnings to cover fixedcharges.
$ 2,621,839
$ 2,547,729
$ 2,456,902
$ 2,347,614
$ 2,137,834 914,103 956,441 741,105 786,989 S
983,282 S
802,630 (93,997) 701,049 S
620,423 500,938 238,020 111,439 239,144 111,348 263,156 111,290
$(1,345,110)
(175,035)
$(1,121,128) 111,215 111,177 2.14 2.15 2.26 (1.57) 2.02
.10 12.10 S
2.14 S
2.15 S
2.36 S
(1.57 S
(10.08 251,476 S
(173,251)
S 223,712 S
2.26 S
1.56 S
2.01 S
1.72 S
1.60 S
1.25 S
.50 S
171 S
155 S
1125 S
.25 S
1958 S
1913 S
1857 S
1745 S
1 86,111 90,435 82,903 85,142 93, 1.90 1.93 1.98 1.95 1.59 1.73 1.60 1.40 1.64 1.36 1.58 1.60 1.46 1.17 1.12 1.30 S
301,974 S
305,538 S
319,637 S
(95,803)
S 298,490 S
11,680 Operations and Maintenance Expense Details In thousands ofdollars Table 2 Total payroll and employee benefits 413,817 398,000 357,689 329,694 S
314,341 Less Char ed to construction and other 124,076 123,838 97,650 117,761 129 990 Payroll and employee benefits charged to o erations Fuels electric operations Fuels gas operations Purchased power costs Fuel cost ad'ustments deferred Total Fuel and Purchased Power Allother 289,741 274,162 260,039 211,933 184,351 282,138 354,859 444,458 461,576 410,174 182,201 175,046 175,877 188,139 172,431 280,914 197,154 168,749 128,368 88,465 (3,469) 41,643 2,085 5,631 3,359 741,784 768,702 786,999 772,452 674,429 208,204 248,597 215,770 215,373
- 173, Total Operations and Maintenance Expense
$ 1,239,729 1 291 461 1 262 808 1 199,7 8
$ 1,032 Employees at December 31 6,502 6,605 6,630 6,239 6,2 1
(In thousands ofdollars) ectric Operating Income Revenues Residential Commercial and industrial Other s stem revenues Total system revenues Sales to other utilities Other revenues Total Revenues Expenses Operations fuel and purchased power Operations other Maintenance Depreciation and amortization Base financial component amortization Regulatory liabilitycomponent amortization Other regulatory amortizations Rate moderation component Regulatory liabilitycomponent Jamesport amortization Operating taxes Federal income tax current Federal income tax deferred and other al Ex enses ctric Operating Income 1992
$ 1,045,799 1,076,302 49,395 2,171,496 9,997 13,139 2,194,632 559,583 294,909 105,341 104,034 100,971 (88,573)
(21,984)
(30,444) 331,122 530 158,908 1,514,397 680,235 1991
$ 1,047,490 1,070,098 47,838 2,165,426 23,040 8,102 2,196,568 593,656 296,798 127,446 104,172 100,971 (88,573) 8,666 (228,572) 338,429 515 173,259 1,426,767 769,801 1990 997,868 1,017,387 46,673 2,061,928 24,140 9,592 2,095,660 611,122 271,608 118,545 98,022 100,971 (88,573) 14,427 (297,214) 322,197 3,138 169,274 1,323,517 772,143 1989 915,644 981,740 42,232 1,939,616 42,880 792 1,983,288 584,313 237,931 115,502 91,759 50,485 (44,286) 1,248 (131,167) 793,592 104,160 312,456 14,612 738,500 1,392,105 591,183 1988 Table 3 835,584 883,267 40,518 1,759,369 24,152 3,412 1,786,933 501,998 195,283 96,599 82,811 262,644 18,394 166,557 1,324,286 462,647 Gas Operating Income (In thousands ofdollars Table 4 Revenues Residential space heating other Non-residential space heating other Total firm revenues Interru tible revenues Total system revenues Other revenues Total Revenues Expenses Operations fuel Operations other Maintenance Depreciation and amortization Regulatory amortizations Operating taxes Federal income tax current Federal income tax deferred and other tal Ex enses s Operating Income 243,950 33,035 90,363 29,094 396,442 19,658 416,100 11,107 427,207 182,201 77,300 20,395 15,103 (88) 57,866 13,560 366,337 60,870 190,976 29,383 70,938 25,515 316,812 21,686 338,498 12,663 351,161 175,046 78,469 20,046 14,783 49,951 4,322 333,973 17,188 198,734 30,854 68,441 26,501 324,530 30,515 355,045 6,197 361,242 175,877 68,910 16,746 12,862 48,120 500 7,740 330,755 30,487 209,192 31,692 72,351 28,674 341,909 19,226 361,135 3,191 364,326 188,139 59,587 14,286 11,671 51,935 9,468 335,086 29,240 201,312 31,803 68,114 28,078 329,307 18,821 348,128 2,773 350,901 172,431 53,415 12,599 10,785 48,220 15,160 312,610 38,291
Electric Sales and Customers Sales millions of kWh Residential Commercial and industrial Other System sales Sales to other utilities Total Sales Customers monthly average Residential Commercial and industrial Other Customers total monthly average Customers total at ear end 1992 6,788 8,181 471 15,440 227 15,667 902,885 101,838 4,593 1,009,316 1,009,028
)991 7,022 8,322 469 15,813 598 16,411 898,974 101,740 4 540 1,005,254 1 005 363 1990 7,022 8,359 472 15,853 532 16,385 895,294 101,562 4 504 1,001,360 1 001 441 1989 7,063 8,636 470 16,169 633 16,802 890,406 100,481 4 452 995,339 996 488 6,979 8,566 483 16,028 445
- 16,473 882,962 98,450 4 436 985,848 989 097 Residential kWh per customer Revenue er kWh 7,518 7,812 15.41'4.92 7,844 14.21 7,932 7,905 12.96'1.97'ommercial and Industrial kWh per customer Revenue er kWh 80,346 81,797 82,304 13.16'2.86'2.17'5,943 87,005 11.37'0.31'ystem kWh per customer Revenue per kWh 15,297 15,731 15,832 16,245 14.06'3.69<
13.01'2.00'6,258 10.
Gas Sales and Customers Sales thousands of dth Residential space heating other Non-residential space heating other Total firm sales Interru tible sales Total Sales Customers monthly average Residential space heating other Non-residential space heating other Total firm customers Interruptible customers Customers total monthly average Customers total at ear end Residential dth per customer Revenue per dth Non-residential dth per customer Revenue per dth System dth per customer Revenue per dth 35,089 3,203 13,662 4,338 56,292 5,090 61,382 227,834 169,189 31,666 10,777 439,466 531 439,997 442,117 96.4 7.23 424.1 664 139.5 6.78 29,687 3,195 11,636 4,171 48,689 4,538 53,227 220,562 171,581 30,453 11,003 433,599 472 434,071 436,853 83.9 67O 381.3 6.10 122.6 6.36 29,810 3,448 11,271 4,352 48,881 6,347 55,228 211,400 176,000 29,072 11,310 427,782 410 428,192 430,571 85.8 6.90 386.9 6O8 128.9 6.43 32,024 3,491 11,548 4,539 51,602 5,300 56,902 204,982 179,415 27,733 11,517 423,647 359 424,006 426,060 92.4 6.78 409.9 628 134.2 6.35 31,276 3,589 11,054 4,580 50,499 5,078 55,577 198,949 181,926 25,979 11,725 418,579 325 418,904 421,429 91.5 6.69 41 132.7 6.26 O
ctric Operations Energy millions of kWh Net generation Power purchased net Total system requirements Company use and unaccounted for System sales Sales to other utilities Total Energy Available Peak Demand mW Station coincident demand Power purchased net System Peak Demand System Capability mW LILCOstations Nine Mile Point 2 (LILCO's 18% share)
Firm purchases net Total Capability Fuel Consumed for Electric Operations Oilthousands of barrels Gas thousands of dth Nuclear thousands of mW days tal billions of Btu lars per million Btu ts per kWh of net generation Heat rate Btu per net kWh Fuel Mix (f'ereentage ofsystem requirements)
Oil Gas Purchased Power Nuclear Fuel Total 1992 10,592 6,211 16,803 (1,363 15,440 227 15,667 2,975 636 3,611 4,091 188 170 4,449 10,656 34,475 124 102,126 2.76<
10,558 37%
19 38 6
100%
1991 13,570 3,638 17,208 (1,395) 15,813 598 16,411 3,085 819 3,904 4,078 194 244 4,516 15,314 32,924 154 129,937 2.61 2.73/
10,484 50%
18 25 7
100%
1990 13,981 2,989 16,970 (1,117) 15,853 532 16,385 3,260 426 3,686 4,077 194 300 4,571 16,401 36,477 108 139,874 307 3.24<
10,564 56%
20 20 4
100 1989 15,220 2,087 17,307 (1,138) 16,169 633 16,802 3,178 510 3,688 4,066 194 400 4,660 20,480 26,490 105 154,669 2.86 3.06'0,704 67%
13 16 100%
1988 Table 7 15,228 1,940 17,168 (1,128) 16,040 433 16,473 3,347 475 3,822 3,834 194 482 4,510 19,927 29,126 87 153,828 2.53 2.67<
10,545 68%
15 13 4
100%
Gas Operations Energy thousands of dth Natural gas Manufactured gas and change in storage Total Natural and Manufactured Gas Total system requirements Company use and unaccounted for Total Energy Available Maximum Day Sendout dth System Capability dth per day Natural gas LNG manufactured or LP gas Total Capability endar Degree Days
-year average 5,028) 64,911 48 64,959 64,959 3,577 61,382 448,726 561,584 120,700 682,284 5,066 55,579 60 55,639 55,639 (2,412) 53,227 435,050 507,344 128,200 635,544 4,378 55,407 (15) 55,392 55,392 (164) 55,228 406,177 507,344 128,200 635,544 4,139 60,359 53 60,412 60,412 (3,510) 56,902 462,610 461,788 145,600 607,388 5,169 Table 8 58,743 (18) 58,725 58,725 (3,148) 55,577 431,940 411,596 145,600 557,196 5,162
Construction Expenditures'992 1991 1990 fin thousands ofdolla 1989 Tab Electric Production Transmission Distribution General (includes nuclear fuel)
Electric Total Gas Total Common Total 46,217 15,535 74,951 5,049 141,752 104,028 27,124 32,541 12,452 74,770 9,880 129,643 89,950 17,958 141,028 78,766 12,671 139,196 49,847 11,007 S
36,400 S
59,880 23,418 9,022 82,975 66,679 (1,765) 3,615 S
419,028 13,379 64,653 17,227 514,287 37,518 9,352 Total Construction Expenditures 272,904 S
237,551 S
232,465
'Includes noncash allowance forother funds used during construction and excludes Shoreham post settlement costs.
Balance Sheet S
200,050 561,157 (In thousands ofdollars)
Table 10 Assets Utilityplant Less Accumulated depreciation and amortization Total Net UtilityPlant Regulatory asset Nonutilityproperty and other investments Current assets Deferred charges Rate moderation component Shoreham post settlement costs Unamortized cost of issuing securities Shoreham nuclear fuel Accumulated deferred income taxes Other Total Deferred Charges Total Assets 4,544,020 1,382,872 3,161,148 3,685,432 20,730 916,914 651,657 586,045 380,267 77,629 511,898 256,904 2,464,400
$ 10,248,624
$ 4,334,736 1,332,003 3,002,733 3,786,403 9,788 884,017 602,053 378,386 227,713 79,760 439,235 133,213 1,860,360 S 9,543,301
$ 4,150,822 1,262,743 2,888,079 3,887,373 6,381 726,060 411,443 225,818 132,875 92,069 359,768 112,818 1,334,791 S 8,842,684
$ 3,939,410 1,158,253 2,781,157 3,988,344 6,050 982,032 102,971 75,044 150,610 97,925 262,298 73,607 762,455 S 8,520,038
$ 8,017,047 1,071,923 6,945,124 69,271 571,934 s2, 525,029 162,290 740,008 S 8,326,337 Capitalization and Liabilities Capitalization Long-term debt Unamortized premium and (discount) on debt Preferred stock redemption required Preferred stock no redemption required Treasury stock, at cost Retained earnings restricted for preferred stock dividend requirements Common stock and premium Capital stock expense Retained earnings 4,755,733 (14,731) 557,900 154,276 1,556,091 (39,304) 667,988
( 14,850) 524,912 154,371 1,550,334 (40,216) 620,373 (23,125) 527,550 154,674 1,549,505 (42,676) 560,405 (28,587) 541,187 155,592 1,547,971 (42,916) 436,690 (25,011) 513,924 221,050 (58,430) 341,008 1,557,293 (56,151) 679,579 S 5,001,016 S 4,556,016 S 4,560,016 S 3,449,821 Total Capitalization Current Liabilities Deferred Credits 1989 Settlement credits Class Settlement Accumulated deferred income taxes Other Total Deferred Credits Reserves for Claims, Damages, Pensions and Benefits Total Capitalization and Liabilities I
7,637,953 1,191,787 164,294 167,066 970,373 110,341 1,412,074 6,810
$ 10,248,624 7,795,940 492,895 173,507 173,564 816,053 84,035 1,247,159 7,307
$ 9,543,301 7,282,349 449,830 182,720 167,569 634,704 117,172 1,102,165 8,340
$ 8,842,684 7,169,953 470,885 191,933 164,040 430,933 81,443 868,349 10,851
$ 8,520,038 6,623,083 583,017 963,97
- 144, 1,107, 12,247 S 8,326,337
pitalization Ratios'ong-term debt Preferred stock Common equity Total Capitalization 1992 65%
9 26 100%
1991 64%
9 27 100%
1990 62%
10 28 100%
1989 63%
10 27 100%
1988 Table 11 53%
15 32 100%
'Includes current motunties oflong-term debt and current redemption requirements ofpreferred stock.
Common and Preferred Stock Prices Table 12 The common stock of the Company is traded on the New York Stock Exchange and the Pacific Stock Exchange. The Preferred Stock $ 100 par value, Series B, E, I, J, K and CC and the Preferred Stock $25 par value, Series 0, P, Z and AAof the Company are, and Series S, T and Y were traded on the New York Stock Exchange. The table below indicates the high and low prices on the New York Stock Exchange listing of composite transactions for the years 1992 and 1991.
1992 Quarter First Second Third Fourth 1991 Quarter First Second Third Fourth Common Stock High Low 24'/e 24'/4 22'/e 22/e 25s/e 25r/a 23'/e 23'/e 23'/s 23/e 24'/~
25 19 21'/~
22'/e 23'/
Preferred Stock Series B
5.00%
Series E
4.35%
Series l
5 /4%
Series J 8.12%
Series K 8.30%
Series 0
$2.47 Series P
$2.43 Series S 9.80%
High Low High Low High Low High Low High Low High Low High Low High Low 138 133 146'/2 136 131 '36 141 /e 143'/e 125 131 134 139 96'/~
96'/4 100 /s 101 92 92'/~
94'/2 96 98'/2 98 102 101 94 1/2 94 96 1/4 97 1/2 85'/2 86 91 94 78 82s/4 83 88'/e 85 88 91 97 78 83'h 85 91 28 28 29'/
27'/~
25s/4 26'/2 27 27s/e 26'/e 26 26 25'/z 24'/4 24%
25 26 27/e 28'/~
29'/e 28'/s 25 /s 27'/~
27s/e 28 26%
27'/4 27/e 27/s 24th 24%
25>/s 26/e 105s/s 105 102 102'/2 99/e 101 102'/z 105 96'h 100 101 102 61 66 70 67 53'/~
54 5 6s/4 58 56'/z 57 65 62 48 51'/2 53 '2 52'/4 59'/2 62 60 47 46'/4 49 52 49 491/2 55 54 431/2 441/2 45 471/g Series T
$3.31 High 273/4 27'/4 Low 26 26'/e Series Y
$2.65 High Low 29 28'/e 27s/a 27'/4 27 27'li 28 28'/z 25 25~/a 26s/s 26'/e Series Z
$2.35 High Low 28 /4 28 29 29
25'/2 26/e 28/e 27 26'/s 27 27'/e
25'/e 24/e 26 Series AA 7.95%
High 26s/4 27 Low 25'/4 25'/2 Series CC 7.66%
High Low 102 103 100s/e 100 referred Stock $ 100 par value, Series D425% is traded in the over thewoun ter market and no price data is availoble. The Preferred Stock $ 100 par value, Series
, M and R are held privately.
trades reported during this period.
Corporate information Executive Offices 175 East Old Country Road Hicksville, New York 11801 Common Stock Usted New York Stock Exchange Pacific Stock Exchange Ticker Symbol: LIL Transfer Agent and Registrar Common Stock and Preferred Stock The Bank of New York Shareholder Services Department 11th Floor 101 Barclay Street New York, NY 10286-1258 1-800-524-4458 Annual Meeting The Annual Meeting of Shareowners willbe held on Tuesday, April20, 1993 at 3:00 p.m. In connection with this meeting, proxies willbe solicited by the Company.
Form 10-KAnnual Report The Company willfurnish, without charge, a copy of the Company's Annual Report, Form 10-K, as filed with the Securities and Exchange Commission, upon written request to: Investor Relations, Long Island Lighting Company, 175 East Old Country Road, Hicksville, New York 11801.
Shareowners'Agent forAutomatic Dividend Reinvestment Plan The Bank of New York Dividend Reinvestment Department 11th Floor 101 Barclay Street New York, NY 10286-1258 1-800-524-4458
Directors am J. Catacosinos rman of the Board and Chief Executive Officer Long Island Lighting Company A. James Barnes Dean School of Public and Environmental Affairs Indiana University George Bugliarello President Polytechnic University Renso L. Caporali Chairman of the Board and Chief Executive Officer Grumman Corporation Peter O. Crisp President Venrock, Inc.
Venture Capital Investments Anthony F. Earley, Jr.
President and Chief Operating Officer Long Island Lighting Company Winfield E. Fromm Retired Vice President Eaton Corporation Electrical Engineering Basil A. Paterson Partner Meyer, Suozzi, English 8 Klein, PC Law Eben W. Pyne Corporate Director and Consultant W.R. Grace and Company Retired Senior Vice President Citibank, N.A.
Richard L. Schmalensee Director Center for Energy and Environmental Policy Research Massachusetts Institute ofTechnology George J. Sideris Retired Senior Vice President Finance Long Island Lighting Company John H. Talmage Partner H.R. Talmage 8 Son Agriculture Phyllis S. Vineyard Director Long Island Community Foundation icers WilliamJ. Catacosinos Chairman of the Board and Chief Executive Officer Anthony F. Earley, Jr.
President and Chief Operating Officer James T. Flynn Executive Vice President Edward C. Dietz Senior Vice President Electric Business Unit Ralph T. Brandifino Vice President Finance and Chief Financial Officer WilliamN. Dimoulas Vice President Information Systems and Technology rt X. Kelleher
- President Human Resources John D. Leonard, Jr.
Vice President Corporate Services and Nuclear Operations Adam M. Madsen Vice President Corporate Planning Arthur C. Marquardt Vice President Gas Operations Brian R. McCaffrey Vice President Administration Joseph W. McDonnell Vice President External Affairs WilliamG. Schiffmacher Vice President Electric Operations Robert B. Steger Vice President Fossil Production WilliamE. Steiger, Jr.
Vice President Engineering and Construction Christian G. Wilding Vice President Conservation and Load Management Walter F. Wilm,Jr.
Vice President Edward J. Youngling Vice President Customer Relations Robert J. Grey General Counsel Kathleen A. Marion Corporate Secretary and Assistant to the Chairman Anthony Nozzolillo Treasurer Thomas J. Vallely, III Controller Herbert M. Leiman Assistant General Counsel and Assistant Corporate Secretary
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