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 PDR
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 MARK SEYMOUR GAS FITTER 1ST CLASS LINE MECHANIC 1ST CLASS Butch and his coworkers fill many Imagine this: someone who's almost impoiunt roles. As natural gas leak invisible except when the lights go out.
investigators, they are irreplaceable Tlut descnbn I lark and his coworkers.
members of the NYSEG safety team. As Although they construct electric lines high bill investigators, they perform an and do complex nuintenance work on important customer service function. energized lines, their efforts are most They also set ncw meters, the final step apparent during an electric outage.
in bringing natural gas to our new Fortunately, outages don't occur very customers. often-our service reliability exceeds 99.96 percent.
DEBBIE FENDICK MARKETING ADMINISTRATOR SANDY JOHNSON Employees in our field organization MANAGER-close natural gas sales, but their efforts WORK FORCE DIVERSITY arc supported by a corporate organiza- The human resources function is the oil tion. Debbie is a member of the that keeps an organization running corporate team that monitors marketing smoothly and Sandy is an imporunt programs, coordinates advertising and member of the human resources team promotion, and analyzes information. at NYSEG. She plans and implements In 1992, the natural gas marketing aIBrmativc action programs, ensures group shattered their perfomunce goal. compliance with those programs and continually cvaluates them.
SYBIL EDWARDS METER READER - COLLECTOR FRANK SCOLLAN In this time of swccping change, one TEAM LEADER-thing hasn't changed: meters still have PROMOTIONAL DEVELOPMENT to be read so that customers can be Frank is a member of the Electric billed for thc energy they have used. Business Unit marketing team that has Sybil and morc than 120 of hcr been focusing on demand-side colleagues across the state do their job management (DSM), a series of well more than 95 percent of the bills programs to help our customers usc we send out are based on actual meter electricity eIBciently. In 1992, these readings and not estimates. programs reduced our use by morc than 139 million customers'lectricity KEN BRONSON kilowatt Itours while we earned more PLANT MAINTENANCE PLANNER than $ 15 million in DSM incentives.
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.
CONTENTS Company Profile........ 1 Financial Highlights... 2 Letter to Stockholders Year in Review Meeting the Competition .7 Hoard of Directors........... 16 8 Printed entirely on recycled paper.
Printed with soy ink.
Officers 17 Financial Section Contents...........17
COMPANY PROFILE New York State Electric K Gas Corporation Our total operating revenues in 1992 were (NYSEG) is an investor-owned utility that traces its approximtely $ 1.7 billion and total assets were roots to the Ithaca Gas Light Company which began approximately $ 5.2 billion, making us the second operations in 1852. Today our 4,888 employees largest utility in upstate New York.
serve 784,000 electric customers and 224,000 natural We generated almost 18 billion kilowatt-hours of gas customers in suburban and rural upstate New electricity in 1992 at seven coal-fired generating York. High-tech firms, light industry, agriculture, stations, several small hydroelectric generating stations colleges and universities, and recreational facilities and one nuclear generating station. We also delivered support the area's economy.
more than 56 million dekatherms of natural gas We are composed of four business units: purchased from pipeline companies, marketers a Electric (operations and marketing) and producers.
a Gas (operations and marketing) a Management Services (support services) a Strategic Management (planning, research and development, and economic, organizational tA S URGH~
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FINANCIAL HIGHLIGHTS 1992 1991 % CHANGE AT DECEMBER 31 Total Assets (000) $ 5,176,428 $ 4,924,836 Capitalization (000) $ 3,630,901 $ 3,463,112 Capital Structure (includes current maturities):
Long-term Debt 50.5% 52.2% (3)
Preferred Stock 7.2% 7.7% (6)
Common Equity 42.3% 40.1% 5 OPERATING RESULTS (000)
Total Opemting Revenues $ 1,691,689 $ 1,555,815 9 Operating Expenses $ 1,367,926 $ 1,234,720 11 Net Income $ 183,968 $ 168,643 9 Earnings for Common Stock $ 162,973 $ 148,313 10 Retail Megawatt-hour Sales 13,294 13,107 1 Dekatherms of Natural Gas Delivered 56,366 42,404 33 PER COMMON SHARE Earnings $ 2.40 $ 2.36 2 Dividends $ 2.14 $ 2.10 2 Book Value (year end) $ 22.85 $ 22.16 3 Market Value (year end) $ 32.50 $ 29.00 12 OTHER INFORMATION Common Stock Price Range $ 26 1/8 - 32 3/4 $ 24 - 29 5/8 Return on Average Equity 10.6% 10.7% (I)
Market-to-Book Ratio 142% 131% 8 Average Common Shares Outstanding (000) 67,972 62,906 Common Shareholders (year end) 61,183 59,593 DMDENDS EARNINGS DOLIARS PER SHARE DOllARS PER SHARE 321'.00 210 2.14 2.70 >>
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LETTER TO STOCKHOLDERS To my fellow stockholders: enormous opportunities for the companies that have the vision, It is with a great sense of responsi- skill and resources to take advan-bility and pride that I write to you. tage of them. NYSEG will be one of those companies.
In past years I have started this letter with a discussion of earnings. Let me emphasize that in the This year I am going to break that mpidly changing and competitive tradition because I want to discuss environment we are dealing with three critiml issues: change, every day, there will be winners competition and challenges. and losers. NYSEG has positioned itself to take full advantage of the Perhaps the single most important opportunities being presented to us piece of information tltat you, as an and we have every confidence we owner of NYSEG, need to know is will be one of the winners. But, NFSEG has the undeniable fact tliat the utility making this happen will require industry is in the midst of unprec-more than just hope and good positioned itselfto edented change. Gone forever are intentions. It will require implemen-the days of a stable and predictable tation of our comprehensive business climate. Utility companies tabePlladvantage strategic plan, an ability to immedi-have to learn how to compete if ately respond to an ever-changing they are going to succeed. Many oftbe opportunities changes are musing this new, business environment and a results-oriented work force.
being presented to us highly competitive environment.
They include the potential for open NYSEG had the foresight to recog-and ue have every access to our electric tmnsmission nize, early on, the enormity of the lines, the reality of non-utility changes the industry is now generation and the Federal Energy confidence we willbe experiencing. More than three years Regulatory Commission's Order 656 ago, we began implementing which is designed to create more oneof the winners. Vision 2000, the details of which I competition in the natural gas have shared with you in past business. These and other emerging communications. I am happy to issues are challenging what used to report the actions we have taken be the protected domain of regu- are beginning to pay dividends, lated energy utilities. both tangible and intangible.
It is this infusion of competition that At the core of our strategy is a shift is the driving force behind the in our organizational structure and signifimnt challenges we face. It is corporate culture. Changing to a this same infusion that will create business unit structure has
LETTER TO STOCKHOLDERS accelerated decision making, 1987 and our embedded cost of Unfortunately, contracts signed improved our ability to control costs debt has decreased from while the Went requirement was in and enabled us to become more 9.8 percent to 7.7 percent. effect are still valid. We had signed focused. Our change in corporate il Our common equity ratio rose contracts for more than 900 mega-culture the way we think and from 33 percent at the end of 1987 watts (mw) of electricity by the time work, and the environment in to the present level of 43 percent. the law was repealed.
which we work is guided at each Over the same period, our long-juncture by our shared values: term debt ratio decreased from Had we done nothing,'these excellence, innovation, integrity, 62 percent to 49 percent.
contracts would have cost our teamwork, caring and accountabil- customers more than 83 billion for Meanwhile, our natural gas business unneeded and over-priced electric-ity. Each and every employee must focus on these values in order for continues to grow. In 1992, it ity. However, we have taken a us to build a firm foundation for contributed 8 cents a share to leadership role among electric NYSEG's future. We are already earnings, a signilicant improvement utilities in fighting for our customers seeing results.
from 1991's loss of 2 cents a share. on three fronts:
We fully expect further gains in a NUG contract requirements are It's no accident that earnings have 1993 because of our emphasis on strictly enforced. So far, cancella-increased to $ 240 per share, up selling this abundant, clean-burning tions have saved our customers 4 cents from 1991. It is a direct fuel and developing new markets. $ 240 million and eliminated result of the NYSEG team The Gas Business Unit has also 113 mw of planned generation.
working together to improve made us an industry leader in il We chose to award no contracts shareholder return. promoting natural gas vehicles. under a mandated bidding program for 100 mw of generation. That Three other pieces of financial We have also made significant gains saved our customers approximately information are also important in sparing our customers the S80 million.
to note: financial burden of unneeded and a We have aggressively negotiated im Fitch Investors Service, Inc. uneconomical electricity from non-the termination of two other upgraded its ratings of our first utility generators (NUGs). We are contracts with NUG developers mortgage bonds and preferred required by federal law to enter into totaling 134 mw. We paid more stock and Moody's Investors Service contracts with NUGs to buy electric-than $ 45 million for these contract upgraded its ratings of our first ity that our customers do not need. terminations which will save our mortgage bonds and unsecured We were required by state law to customers $ 650 million.
pollution control bonds. These pay 6 cents a kilowatt-hour (kwh) ratings are now the highest they for power from qualifying facilities, Let me emphasize that our biggest have been in 12 years. far higher than our own production concern with NUGs rested with the a In 1992, we refinanced cost. Fortunately, at the tenacious 6-cent law here in New York State.
$ 250 million of first mortgage urging of NYSEG and other utilities We believe that, if operated in a bonds. This will save our customers in New York State, the Went law true market environment, the NUG more than $ 3 million a year. We was repealed by the Legislature in industry can increase competition to have refinanced more than June 1992 and signed into law by the benefit of iatepayers.
$1 billion in debt since the end of the Governor in August '1992.
,5 LETTER TO STOCKHOLDERS At this time, we are actively en- me tell you that the cltanges we are just in the hall at the office. On those gaged in discussions regarding a implementing will reduce our cost occasions, I am reminded that our multi-year rate settlement agree- of doing business, 'make us more employe& are the reason for our ment with the staff of the Public responsive to the marketplace and,- success during this time of change.
Service Commission and other build on our commitment to They'are the people who time and interested parties. By working teamwork. In 1993, we will continue again have risen to challenges and cooperatively with regulators we to reinforce the corporate culture they are truly our greatest asset.
can eliminate much of the conten- ~
change now underway to assure They haven't run from competition, tion sometimes associated with the that our employees are well pre- they have welcomed it.
more traditional appmach to pared to meet competition head on.
For the Board of Directors, ratemaking. At the same time, by encouraging broad involvement, win-win solutions can be devel-In closing, I would like to share a personal experience with you. Quite often I have the opportunity to talk
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oped. This regulatory philosophy is with NYSEG employees from across James A. Carrigg absolutely essential in order to Chairman, President and address the long-term economic the state, whether at an employee Chief Executive Officer challenges we face.
meeting, a Speakers Club dinner or February 19, 1993 We also continue to believe that diversification, whether in the regulated or nonregulated arena, will play an important role in 4 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 will do nothing to compromise our financial integrity.
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 AUGUST OCTOBER DECEMBER The Broome-Tioga Texas businessman Jennison Station We sold $ 100 million of Association for Retarded Boone Pickens, became the first 30-year first mortgage Citizens joined with us chairman of the Natural genemting facility in bonds at a coupon rate to start sorting and Gas Vehicle (NGV) New York State to of 8.30 percent. Net recycling surplus and Coalition, was the regularly burn tire proceeds were used in scrap materials at our featured speaker at our chips to produce connection with the Investment Recovery INVESTMENT RECOVERY second annual Northeast electricity. redemption of first CENTER Center. NGV Conference in mortgage bonds. This JUNE Binghamton. More than refinancing will save MARCH We reached agreement We sold five million 400 people attended. our customers with Indeck Energy shares of common stock approximately Services of Kirkwood, We received permits at $ 27.25 per share, a $1 million a year in Inc. to terminate the from the New York 20 percent premium to interest costs.
purchase power State Department of book value. Proceeds agreement for the Environmental Conser- Project SIIARE, our were used to repay planned 55-megawatt vation for construction emergency heating commercial paper which (mw) Indeck-Kirkwood of an innovative BOONE PICKENS fund administered by was issued to pay for cogenention project. pollution control the American Red construction. We sold $ 150 million of This power was system at Milliken Cross celebrated its APRIL unneeded and Genemting Station. 10-year first mortgage 10th anniversary. More We received approval uneconomical. bonds at a coupon rate than $ 2 million has from the Public Service We joined a national of 6.75 percent. Net JULY been contributed to the Commission (PSC) to research effort to proceeds were used in The PSC approved a fund by our customers, invest in nonregulated investigate the use of connection with the 5 percent increase in employees, retirees and subsidiaries in the areas cordless electric lawn redemption of three electric rates and stockholders. More than of environmental mowers to reduce series of first mortgage 10,000 grants have been 4.1 percent increase in services and energy- urban pollution. bonds. This refinancing natunl gas rates provided to needy reLated businesses. will save our customers effective August 1. families to help pay approximately their utility bills.
Our employee Speakers Our high phase order $2 million a year in Club won the Edison We reached agreement transmission line, the interest costs.
Electric Institute's first with Kamine/Besicorp first of its kind in the Dillon Award for NOVEMBER world, was energized. We filed requests for a Coming L.P. to excellence in the This power line, a terminate the purchase 5.5 percent increase in development and research and develop- power agreement for electric rates and a presentation of the planned 79-mw ment project, carries up 3.6 percent increase speakers bureau South Coming cogen-to 73 percent more in natural gas rates to programs. HIGH PHASE ORDER eration project. This power in the same TRANSMISSION LINE be effective in space as a tmditional power was unneeded August 1993.
tnnsmission line. and uneconomical.
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 will prosper 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.
Most importantly we will concentrate on the strategies outlined in our five-year strategic plan. It will guide us to our goal: to be among the best utilities in the country.
Vjp The following pages highlight specific examples of some of our results to-date.
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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 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 IKEY ~
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our customers, ranked fifth in the control costs.
country among individual environmentally responsible and generating units. economical way of disposing of Wc have already saved our customers almost $ 1 billion by terminating pur- coal tar byproducts from MGP sites.
ALTERNATIVEFUELS:
chase power agreements with NUG A SUCCESS STORY CALL CENTER: A PLUS FOR developers. We Jennison and Hickling CUSTOMER SERVICE have developed and genenting stations were At our new customer call center in implemented new built in the 1940s and a Binghamton, we are centnlizing budgeting proce- second genenting unit the telephone and account mainte-dures. We have also was added to each in nance functions from 42 oAices set ambitious targets the 1950s. Genenting scattered across our 19,000 square for capital budget- station technology has mile service area. This will save ing and investments advanced markedly customers money, but the benefits and are continuing since then, yet their go beyond savings.
to pay particular unique traveling gute attention to profit- design has given them Once the call center is in full ability and total new life. These tnveling operation in November 1993, it will return to stockhold- gntes enable us to bum offer customers expanded hours. Its ers. However, as im- alternative fuels. telephone system and computers, portant as control- manned by well-tnined customer ling direct costs is, In October, Jennison representatives, will allow us to innovation and Station became the first meet our customers'hanging eAiciency can also generating station in needs and growing expectations.
have a considenble New York State to Customers will still be able to meet ii i impact on our finan- X i regularly bum tire chips with our customer representatives i
cial picture. Here are mixed with coal. Its four face-to-face at loni oAices when some examples. boilers can consume up necessary.
to 4.5 million tires or 45,000 tons GENERATING EFFICIENCY: THIRD IN THE COUNTRY of tire chips each year. Tlus saves NATURALGAS ENERGY MANAGEMENT:
Landfill space and saves money for TRACKING SUPPLY AND DEMAND In 1992, we spent more than our customers because it has the We have just installed an advanced
$ 262 million for fuel, primarily coal, potential to reduce the amount energy management system for our to genente electricity. Ifwe are of coal we purchase by up to natunl gas going to keep costs to a minimum, 65,000 tons each year. business. It it is essential that we squeeze every kilowatt-hour out of every provides In December, Hickling Generating control pound of coal.
Station began testing a fuel mixture of of coal and coal tar soil from an natural Each year Electric Light and Power inactive manufactured gas plant gas flow magazine nnks the operating (MGP) site. If the New York State from tnns-performance of the top 100 utilities Department of Environmental mission lines in the country. The most recent Conservation approves continua- into our tion of the project, it may be an
e system and up-to-the second data on customer use around the state.
requirements of the Clean Air Act Amendments of 1990 and also a German technology not currently in use in the U.S. The U.S. Depart-The system will help us better demonstrate how we can continue ment of Energy, through its Clean manage natural gas supply plan- to use the country's abundant Coal Technology Program, and ning and the purchase of natural supply of coal in an environmen- several industry research alliances gas. The Federal Energy Regulatory tally responsible manner. The will fund a portion of the Commission's Order 636, which is project is unique in that it will use $ 159 million project.
designed to create more competi-tion in the natural gas business, shifts responsibility for these Mostpeople see used tires as a disposal problem matters to local distribution compa- %e see them as an opportunity. In J992 Jennison Station became the firstgenerating facilityin the nies such as NYSEG. The energy management system will ensure state to be licensed to regularly burn tire chips that we get the least expensive natural gas possible to our distribution system. mixed with coal Some.membets ofthe tires to-energy team are: (seated, from leg) Ed Greenman, PROTECTING THE ENVIRONMENT:
AN INNOVATIVEAPPROACH Mike Tesla and Fred Cannistra; (standing, from Construction is about to begin on an innovative system to remove left)IUa Cunningham, sulfur dioxide from flue gas at Phil Murphy and
. illiken Generating Station.
It will help us comply with the Terry Barnard.
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10 SEARCHING OUT OPPORTUNITIES TO GROW rowth is important to largely because of the acquisition well as to concentrate on energy-our future. of Columbia Gas of New York efficient sales. Here are some in April 1991. additional examples.
It often comes with little effort during good economic times. We are responding to the chal- NATURALGAS:
However, the sluggish New York ACTIVITIES ON MANY FRONTS State economy and the success of lyte of limited growth in several With the Clinton Administration's ways. First and foremost, we have new emphasis on natural gas, we our demand-side management reorganized our electric and are more excited than ever about (DSM) programs have kept growth natural gas marketing groups to the potential for our natural gas to a minimum in recent years. In quickly and effectively respond to business. We are continuing to 1992, retail electric sales increased tl>e.-Jteeds of our customers, as promote conversion to natural just 1 percent. Retail natural gas sales increased 32 percent 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 BZ4~ Tih>> RrzceB important role in our long-term success. We are actively evaluating a number of corporate not allow us to realize the potential development opportunites that exists for natural gas in New elks for investment.
York State. So, we are also pursu- amQ dLmclbqp ing several supply and storage ECONOMIC DEVELOPMENT:
opportunities that would enhance 6MKiH586L HELPING SHORE UP A SLUGGISH ECONOMY our ability to deliver a reliable Given New York State's economic supply of the least expensive climate, creating jobs is no easy natural gas possible. task. Despite these challenging times, our economic development ELECTRICITY: BLENDING professionals continue to work CONSERVATION AND SALES In 1992, our electric inarketing with businesses interested in team focused on DSM programs. locating facilities in our service While helping customers use area. They are also concentrating electricity efFiciently will remain on helping existing industrial important in 1993, we will also be customers expand. In 1992, their actively selling electricity where it efforts resulted in the expansion or makes economic sense for custom- retention of ers and is environmentally respon- 17 busi-sible. We will be promoting NONREGULATED SUBSIDIARIES: nesses. 'Il>ey A FRESH LOOK are currently efFicient technologies such as We received permission from the infrared drying for manufacturing working Public Service Commission in April processes, ground source heat closely with to invest in nonregulated subsidiar-12 Canadian pumps and security lighting. ies in the areas of environmental businesses services and energy-related NATURALGAS VEHICLES: tll'itwill be A PROMISING MARKET businesses. However, after care-making Our natural gas vehicle (NGV) fully re-evaluating the promising location progmm continues to gain opportunities we had identified, decisions in inomentum. In August, we held we determined that any investment 1993. The the second annual Northeast in those opportunities at this time new year NGV Conference in Hinghamton would be unwise. We have now lliis 'ilso and in November, we installed a refocused our efforts on maintain-brought with it a renewed natural gas fueling station in ing the financial strength of our emphasis on working with state Binghamton for sevenl NYSEG core electric and natural gas and local governinents to vehicles and three natural businesses. We continue to believe strengthen the state's econoiny.
gas-fueled transit buses. that diversification will play an Gathering accurate data and analyzing that data in a timely manneris at the heart ofidentifying growth opportunities Representati.ves ofallfour of our business units are working together on thispr ocess on an on-going basis Some ofthe.team membets tvho have been involved in searching out opportunities are: (clockun se, from left/'Sue Ward, Bob Rude, Rex Berntsson, Bob Irvin, Joe Vaj da, Donna Vandenberg and Tom Ryan.
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12 ENHANCING RELATIONSHIPS 0
e are giving new emphasis to lBH economy which will be to working together with regulators Krafta cd everyone's benefit. Both our and elected ofFicials toward ~ ~
ER83 electric and natural gas marketing positions that are beneficial to our groups now include personnel (gCKRB gcSR9p stockholders and customers. whose job it is to maintain ClliEEQ cGxxBQKP contact with large customers and We worked with elected officials to ~ ~
E8i8) ensure that we are providing them help shape the Clean Air Act ~ ~ ~
QKK6 with any services at our disposal Amendments of 1990 rather than fight against passage, and we dkaeRaN dKtLL, that will help them be more competitive. As an off-shoot of continue to be involved in related these "key account" partnerships, =
rulemaking. At the state level, we we want to promote a common supported the repeal of New York Tliis process has been unique in direction for economic growth in State's law that required us to buy that it has been less formal than our service area.
electricity from qualifying NUGs for usual rate proceedings. Everyone 6 cents a kilowatt-hour. The result involved has had an equal voice RATES:
of the repeal of this law in 1992 and the process has been facili- NOT THE SAME OLD APPROACH will save New York State tated by a NYSEG employee using We know that large customers ratepayers billions of dollars. We problem-solving techniques. need to hold down costs to remain are proud of results such as these, competitive. So, we asked the PSC but there is still plenty to do. We believe a rate settlement for permission to negotiate electric agreement would allow our rates with large industrial A MULTI-YEARRATE customers to better plan their customers who meet specific SETTLEMENT: energy budgets, while sparing requirements. In January 1993, that DISCUSSIONS CONTINUE them the expense of frequent rate request was approved. An Since July, we have been working proceedings. It would help us by interruptible service rate that will with the PSC staff and other freeing up resources that are used make natural gas more attractive to interested parties toward a multi-during rate proceedings, allowing public authority customers, such as year rate settlement agreement. 'tate and federal government for better planning and allowing employees to concentrate on other facilities, was also approved by the critical issues such as competition. PSC in January 1993.
Rate settlement discussions, which REGULATORY RELATIONS:
DEFINING GOALS are continuing, have con-In 1993, we will further formalize H(gp I tributed to improved relations with the PSC.
KEY ACCOUNTS:
BUILDINGA NEW our regulatory relations process by defining goals and assigning specific roles and responsibilities.
We will also use our government Ogg RELATIONSHIP relations program to promote Our major customers will streamlining of the regulatory figure prominently in the process and further development actions we will have to take of incentive regulation.
08ER ERROR to align our objectives with Cg public policy. By building a stronger relationship with these customers, we can play an active role in strengthening the state'
Whether we are helping customers conserve electricity, selling electricity where it makes economic sense for a customer or selling natural gas, our talented marketing representatives are on the front 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 WORK SIMPLIFICATION:
REAPING BENEFITS business planning and budgeting, and skills to make NYSEG success- electric and natural gas sales ful in these changing times. IVork Simplification was just management, vehicle management introduced in 1992, but its impact and employee development.
has been dramatic. Simply stated, Every day, our employees are Results included implementation of this process involves carefully dealing with the dramatic changes our new business planning and in the energy industry. They ltave examining how we perform specific budgeting procedures, reorganiza-tasks and developing recomrnenda-responded very well and they now tion of our marketing departments, recognize tltat this is not the same tions for working more efficiently a reduction in the number of our old business that it has always and cost-eAectively. vehicles and streamlining our been. They know that we must advancement opportunity program.
Twelve employee teams completed respond to a competitive environ-a first round of work in 1992.
ment by working together, looking Eight new teams then examined Processes examined included for new opportunities and taking processes such as requesting new more risks. Several efforts are electric or natural gas service and already in place that will help us determining vehicle needs for our achieve our organizational natural gas business.
capability challenge.
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15 earnings goals will determine the ggg size of the incentive awards.
Qi) QQii)Q(eig e o g(ojiP +o a Our suggestion program, I', which geKSi@guilhwo encourages employees to submit well thought out solutions to One particularly noteworthy eflort Brotherhood of Electrical Workers problems. It has the potential to (IBE%9 convened to study the save money and streamline the has already come from the second round of work simplification. A handling of grievances from IBEW way we operate.
a Continuation of Energy Into work group composed of repre- employees. They reached agree-sentatives of management and ment on an equitable way to Action, a leadership and team System Council U-7 International handle future grievances and how building program for employees.
to address a backlog of grievances COMMUNICATIONS:
awaiting arbitration. KEEPING EMPLOYEES INFORMED By the end of WORK PLANNING:
INTEGRATING EFFORTS Our third point of emphasis is continued evaluation and enltance-November, our neu Proper planning of work by ment of internal communications.
call center in employees is vital to enhancing We must do our best to keep our competitive position. employees informed of what we Binghamton willbe are doing and why. Informed responsible for In past years, each salaried employees have the tools to be employee, together with his or her more productive and can make handling customer supervisor, prepared annual work better decisions for the Company.
callsfor our entire plans based on what they under-stood as being important to the The strategic plan and our efforts service area. The call Company's success. That process thus far are only the beginning.
center willoper lias now changed. Business plans While we will continue to focus on for each of our four business units meeting the needs and expectations expanded customer now flow directly from the of our stockholders, customers and service hours and will stmtegic plan, departmental plans employees, the key stmtegies of the are linked to the business unit strategic plan will cliange as the save money. Members plans and individual plans are environment in which we operate changes. In turn, each employee's ofthe call center team linked to the departmental plans.
energy inust be directed to reflect Now every employee's efforts will who are already on directly contribute to achieving the those changes.
board include: objectives of our strategic plan.
One thing is clear: as our (seated, from lefty Other efforts designed to rnakei:(is'ore employees continue to implement Nancy Hunt, Jim competitive by making our stnitegic plan and use our employees more accountable for business planning process, our Hogan, Jean Mitchell results include: stockholders and customers will and Sue Libous- C reap the benefits.
a Performance Up, Heenan; (standing, an incentive award rom lefty Craig Hall, program for salaried employ-Hope Robinson, ees. Our actual EVgjjgp Rick Cerchiara performance measured against 8<g ]4$ Py and Helen Black. customer service and
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16 BOARD OF DIRECTORS First year etected In tuttttthescs Allen F Kintigh (1987) Robert A. Plane (1982)
Wells P. Allen, Jr. (1974) Former President and President Former Chairman and Chief Operating OAicer of the Corporation Wells College Chief Exc~tive OAiccr of the Corporation Binghamton, NY Aurora, NY Binghamton, NY Ben F Lynch (1987) C. William Stuart (1971)
James A. Carrlgg (1983) President Chairman and Chief Executive OAlcer Chairman, President and Windtester Optical Company C.W. Stuart Br Co., Inc.
Chief Executive Officer of thc Corporation (hlanufacturer of Eyeglasses) (Interstatc Trucking Concern)
Binghamton, NY Elmita, NY Nark, NY Allson P. Casarctt (1979) Alton G. hlarsltall (1971) COMMITTEES OF THE BOARD Dean of thc Graduate School Senior Fellow Chairperson listed first Cornell Vnivcrsity Nelson A. Rockefeller Ithaca, NY Institute of Government Audlti Plane, Gioia, Kecler, Lynch Albany, NY Executive and Flnancc: Allen, Camgg, Everett A. Gllmour (1980) Gilmour, Kintigh, Marshall, Nnvcomb, Former Chairman of the Board and David R. New comb (1979) Stuan Chief Executive OAiccr Former President and Executive Compensation and The National Bank and Trust Company Chief Excretive OAicer Succcssloni Gilmour, Allen, Casarett, of Norwich Buffalo Forge Company Lynch, Marshall, Ncwcomb Norwich, NY Q Ianufacturcr of Heating, Venti!ating Pensions Kcclcr, Kintigh, Plane, Stuart and Air Conditioning Equipment) Public Alfalrsi Casarett, Gioia, Keeler, Paul I Giola (1991) Buffalo, NY Lynch Senior Vice Prcsidcnt First Albany Corporation Mr. Carrigg is an cx oAicio member of (Brokerage and Investmcnt Banking Firm) tlte Pension and Public Alfairs Albany, NY committees.
John M. Kcclcr (1989)
Managing Panner Hinman, Howard 8c Kattell (Attorneys at Law)
Binghamton, NY 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. William Stuart and Wells P. Allen, Jr.
17 Ages and years of service as of MANAGEMENTSERVICES December 31, 1992 in parentheses BUSINESS UNIT Richard P. Pagan (51, 21)
James A. Carrigg 59, 34) Senior Vice President Chairman, President and Chief Executive Officer Daniel W. Farley (37, 11)
Vice President and Secretary Ralph R. Tedesco 89, 14)
Executive Assistant to thc Cltairman, Carl E. Johnson (50, 2Q President and Chief Executive Officer Vice President - Consumer Services and Communications Patricia A. Orzell (50, 31)
Assistant Secretary Richard W. Page (57, 34)
Vice President - Human Resources FINANCIALSECTIONW ELECTRIC BUSINESS UNIT Sherwood J. Raffert (45, 12)
Jack H. Roskoz (54, 30) Vice President and Treasurer hlanagement's Discussion & Analysis Senior Vice President (Chief Financial OAiccr) of Financial Condition and Results of Operations...................................18 John J. Bodkin (47, 24) Evcrett A. Robinson (49, 19)
Vice President- Vice President and Controller Consolidated Statements of Income............25 Electric Transmission and Distribution (Chief Accounting OIEccr)
Consolidated Balance Sheers.....
William G. hlcCann (45, 23) John D. Scott (54, 29)
Vice President- Vice President - Economics West Region Electric Operations Consolidated Statements of Cash Flows......28 Roy Hogbcn (53, 35)
Gerald E. Putman (42, 22) Assistant Controller Consolidated Statements of Changes in Vice Prcsident- Common Stock Equity..................................29 East Region Electric Operations James M. Niefer (62, 37)
Assistant Scaetary Notes to Consolidated Vincent W. Rider (61, 34) Financial Statements.......
Vice President - Electric Generation Robcrt T. Pochily (43, 21)
Assistant Treasurer Report of hlanagement.....
Irene M. Stillings (53, IQ Vice Prcsidcnt - Electric Marketing Gary J. Turton (45, 20) Report of Independent Accountants .......... 42 Assistant Controller Michael J. Turkovic (60, 37)
Vice Presidcnt- Sclcctcd Financial Data..... ,43 Purchasing and Administration STRATEGIC MANAGEMENT BUSINESS UNIT Glossary. 43 Denis E. Wickham (43, 20)
Vice President - Electric Resource Planning Paul Komar (54, 23)
Senior Vice President Financial and Operating Statistics....
John I. Fiala (56, 34)
Assistant Vice Prcsidcnt - Plant Operations Financial Statistics......................
MANAGEMENTCHANGES
~ Dolores R. Hix, former assistant secretary Electric Sales Statistics ...............
John V. Kutz (58, 3Q Assistant Vice President - Transmission and and assistant to thc chairman, president and Distribution Operations chief executive oIEcer, passed away on Electric Generation Statistics.....
September 8. The Board of Directors elected Patricia A. Otzcll, executive secretary to the chairman, prcsidcnt and Natural Gas Sales Statistics ....
GAS BUSINESS UNIT Russell Fleming Jr. (54, 2) chief executive offfccr, to thc position Senior Vice President sccrctary on May 14. of'ssistant Charles E. Dickson (54, 32) ~ Bcmard hl. Rider, senior vice prcsident-Vice President - Regional Gas Operations stratcgic growth business unit, retired effective January I, 1993.
Robert A. Paglia 65, 27)
Vice President - Gas hlarketing and Sales ~ 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'S DISCUSSION AND ANALYSIS OF 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 $ 1,691)689 $ 1,555,815 $ 1,496>780 9%s 4%
Earnings available for common stock $ 162,973 $ 148,313 $ 145,351 10% 2%
Average shares outstanding 67,972 62,906 58,678 8% 7%
Earnings per share $ z.40 $ 2.36 $ 2.48 2% (5%)
Dividends r share $ 2.14 $ 2.10 $ 2.06 2% 2%
'Ihe Company had operating revnues of effective February 1991. In addition, lower approximately $ 1.7 billion in 1992, $ 1.6 electric and natural gas retail sales, which billion in 1991, and $ 1.5 billion in 1990. resulted from warmer mather and the weak Operating reunues increased $ 136 million, or economy, also decreased eaminy. Incentives 9%, in 1992, compel to 1991, primarily earned on demand-side management (DSM) because of higher purchase costs of non-util- programs, however, had a favorable effect on ity generation which are passed on to 1991 earnings per share.
customers, and new electric and natural gas Average shares outstanding were 67,972,000 rates which became effective in February 1991 in 1992, 62,906,000 in 1991, and 58,678,000 and August 1992. In addition, higher electric in 1990. Average shares outstanding increased and natural gas retail sales due to an 8% in 1992 compared to 1991 due to the increase in retail customers, colder weather, issuance of 5 million shares of common stock and the April 1991 acquisition of Columbia in March 1992, and the issuance of 1,039,000 Gas of New York, Inc. (CNY) helped boost shares of common stock through the Dividend operating revnues for 1992. In 1991, operat- Reinmtment and Stock Purchase Plan ing ingenues rose $ 59 million, or 4%, (Plan). In 1991, average shares outstanding compared to 1990, primarily because of an i'ncreased 7% because of the issuance of 4 increase in electric and natural gas rates million shares of common stock in October effective February 1991 and the April 1991 1990, and the issuance of 970,000 shans of acquisition of CNY. common stock issued through the Plan.
Eaminy per share increasel 4 cents, or 2%%d, in 1992 compared to 1991, while eam- Interest Expense iny per share decreased 12 cents, or 5%, in Interest expense decreased 5% in 1992 and 1991 compared to 1990. Earnings per share 6%%d in 1991 (before the rtxluction for in 1992 were favorably affected by the growth allowance lor borro~txl funds used during in electric and natural gas retail sales pri- construction). Interest on long-tenn debt marily due to an increase in retail customers, decreased in 1992 and 1991 mainly due to colder mather, and the April 1991 acquisition the refinancing of certain highmupon long-of CNY. 'Ihe Company's efforts to control costs term debt at lower interest rates. In 1992 and also contributed to the increase in 1992 eam- 1991, interest expense also declined due to a ings per share. Earnings per share were decrease in the average amount of commer-limited by a six-month electric rate mor- cial paper outstanding and lower interest rates atorium that began in February 1992. In on the Company's variable rate debt. (See 1991, earnings per share decreased primarily Liquidity and Capital Resources - Financing because of the reduction in our allowed Activities).
return on equity from 13% in 1990 to 11.7%
19 Operating Results by Business Unit 1992 1991 over over 1991 1990 Electric 1992 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 increase in certain New York State gross 1992 compared to 1991 was the result of receipts taxes which are passed on to cus-colder weather and an increase in customers. tomers.
Retail sales decreased 1% in 1991 compared Electric operating expenses increased $ 90 to 1990 mainly due to wanner weather and million, or 8%, in 1992 compared to 1991, the weak economy. while operating expenses increased $ 35 mil-Flectric operating revenues increased $ 84 lion, or 3%%d, in 1991 compared to 1990. In million, or 6%, in 1992 compared to 1991. 1992, expenses increased primarily because of This reflects the increases in electric rates higher non-utility generation purchase costs which became effective February 1991 and and certain New York State gross receipts August 1992. It also reflects the higher non- 'axes, both of which are passed on to cus-utility generation purchase costs and an tomers. Operating expenses also increased increase in certain New York State gross because of higher DSM program costs and an receipts taxes, both of which are passed on to increase in federal income taxes resulting customers. Also; the 1% increase in electric from higher pretax book income. However, a retail sales, due to colder weather and an decrease in maintenance expense reduced the rease in customers, boosted revenues. Elec- increase in operating expenses. In 1991, elec-operating revenues increased $ 33 million, tric operating expenses rose 3% primarily 3%, in 1991 comparnl to 1990, despite a because of higher gross receipts taxes and 1% decrease in electric retail sales. This higher federal income taxes resulting from increase is primarily because of the increase higher pretax book income.
in rates effective February 1991 and an 1992 1991 over over 1991 1990 Natural Gas 1992 1991 1990 Change Change tThousands)
Retail sales&katherms (dth) 39,357 29,874 25,515 32% 17%
Deliveries (dth) SG,3GG 42,404 33,672 33% 26%
Operating reenues $ 240,1G4 $ 187,879 $ 162,271 28% 16%
0 ratin nses $ 221,307 $ 177,751 $ 147,278 25% 21%
Natural gas retail sales increased 32% in result of the acquisition of CNY and the 1992 compainl to 1991, and 17% in 1991 increases in rates effective February 1991 and compared to 1990. 'Ihe 1992 and 1991 August 1992. Also, an increase in certain increases in retail sales, along with the gross receipts taxes, which is passed on to increase in deliveries, are largely because of customers, boosted 1992 revenues.
the April 1991 acquisition of CNY. Excluding Natural gas operating expenses increased CNY, natural gas retail sales increased 8%%d in $ 44 million, or 25%, in 1992 compared to 1992, primarily because of colder weather. In 1991. This increase is primarily due to the 1991, natural gas retail sales decreased 7%, increased quantity of natural gas purchased luding CNY, because of warmer winter as a result of the CNY acquisition, and an ther and the weak economy. increase in certain New York State gross Natural gas operating revenues rose $ 52 receipts taxes passed on to customers. Natural million, or 28%, in 1992 compared to 1991, gas operating expenses increased $ 30 million, and $ 26 million, or 16%, in 1991 compared or 21%, in 1991 compared to 1990, mainly to 1990. Those increases are principally the because of the acquisition of CNY.
20 LIQUIDITYAND CAPITAL RESOURCES Competitive Conditions The utility industry is rapidly changing In April 1992, the FERC issued Order 636 rather than recognize an expense when bene-and moving towanl a competitive environ- which requires interstate natural gas pipeline fits are paid. SFAS 106 is elfective for fiscal ment. Factors contributing to this are: open companies to offer customers unbundled or yes beginning after December 15, 1992.
access to electric transmission lines; Federal separate services. With the unbundling of ser- The Company adopted SFAS 106 in Janu-Energy Regulatory Commission (FERC) Order vices, primary responsibility for reliable ary 1993. At the time of adoption, the 636 which significantly affects the natural gas natural gas supply will sjiift fmm interstate accumulated benefit obligation was $ 225 mil-industry; and the National Energy Policy Act pipeline companies to local distribution com- lion. The Company plans to reegnize the of 1992 (Energy Policy Act). In'ddition, the panies, such as the Company. This should accumulated benefit obligation over 20 yetrs Company's desire to respond to the economic result in increased direct access to low cost in accordance with SFAS 106. Adoption of the pressures on its large customers, high pur- natural gas supplies by local distribution new standard is expected to IncreaM annual chase costs of non-utility generation, rising companies and end users. One goal of Order expenses, before deferral for ratemaking pur-health care costs, increasing taxes, weak eco- 636 is to provide equitable access to inteistate poses, by about $ 32 million, or 7 times the nomic conditions, conservation programs, and pipeline capacity. FERC Order 636 will sub- 1992 expense.
compliance with environmental laws and reg- stantially restructure the inteistate natural gas In March 1992, the PSC issued a draft ulations are factors that are placing increased market and intensify competition within the Statement of Policy concerning the account-pressure on our electric and natural gas rates. natural gas industry. Order 636 will allow us, ing and ratemaking treatment for post-The Company's five-year strategic plan subject to PSC approval, to restructure rates retirement benefit costs. 'Ihis draft policy pro-addresses the competitiiv, rapidly changing and provide multiple service options to our vides for, among other things, recovery in utility industry. The plan positions us to meet customers. rates for deferred SFAS 106 costs. In addition, the challenges of the future. The Company's 'Ihe Energy Policy Act was enacted in the draft policy proposes that deferred SFAS objective is to remain competitive in its October 1992, and will bring major changes 106 costs will be ielvered in rates within 10 core businesses in the face of increased to the utility industry. Certain provisions of years of the adoption of SFAS 106. The State-competition and continued deregulation. the Energy Policy Act amended the Public ment of Policy is expected to be approved by Diversification, whether in the regulated or Utility Holding Company Act of 1935 the PSC during the spring of 1993. In addi-nonregulated arena, will play an important (PUHCA). These amendments will encourage tion, the July 1992 rate decision allows the role in the Company's future. While the greater competition by establishing a new cat- Company to recover a portion of SFAS 106 strength of the Company's core electric and egory of wholesale electric generators which costs in reenues from its customers and to natural gas businmes remains our focus, and are exempt from PUHCA. The Energy Policy defer the remainder of these costs for recovery while we will not compromise the Company's Act also enables the FERC to order utilities to in accordance mth the draft Statement of financial integrity, we are actively evaluating provide open access to transmission systems. Policy. The Company anticipates that future a number of corporate devlopment oppor- The alternative fuel titles of the Act should SFAS 106 costs will be remverable through tunities for Innstment. serve to promote the use of natural gas and rates.
In April 1992, the Public Service Commis- electric vehicles. In November 1992, the FASB issued State-sion of the State of New York (PSC) issued Recent Accounting Standards ment of Financial Accounting Standanls No.
an onler allowing the Company to invest up The Financial Accounting Standards Board 112, Employers'ccounting for Postemploy-to 5% of its consolidated capitalization (FASB) issued Statement of Financial ment Benefits (SFAS 112), which is effective (approximately $ 180 million at December 31, Accounting Standards No. 106, for fiscal years beginning after December 15, 1992) in one or more subsidiaries that may 1993. SFAS 112 will require the Company to Employers'ccounting for Postietirement Benefits Other engage or invest in energy-related or environ- Than Pensions (SFAS 106) in December 1990. recognize the obligation to provide post-mental services businesses and provide related SFAS 106 requires that the Company accrue a employment benefits to former or inactive services. At December 31, 1992, the Company liability for estimated future postretirement employe5 after employment but before retire-had not invested in any such businesses. benefits during an employee's working career 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 mortgage, the remaining $ 20.4 million of In February 1993, the Company plans to roving its financial integrity. We believe IOs/s% Series first mortgage bonds due 2016. price $ 100 million of taxmempt pollution s commitment will take on added In October 1992, we issued $ 150 million of control bonds. Net proceeds from the sale, significance as competition heightens in 6s/A'eries first mortgage bonds due 2002. which will be delivered in April 1994, will be the industry. Yel proceeds from the sale were used in con- used to redeem, at a premium, $ 60 million nection with the redemption, at a premium, of 12% pollution control bonds and $ 40 mil-Capital Structure in October 1992 of $ 145.1 million of first lion of 12.3(% pollution control bonds.
mortgage bonds: $ 31.1 million of the 9.35% The Company uses interim financing in Series due 2003; $ 75 million of the 93AX the form of short-term unsecured notes, usu-Series due 2005; and $ 39 million of the ally commercial paper, to finance certain refundings and construction expenditures, and 9M'%eries 59.5 56.3 54.2 52.2 50.5 due 2006.
In December 1992, we issued $ 100 million for other corporate purposes. This provides 7.2 of 8.30% Series first mortgage bonds due flexibility in the timing and amounts of long-
'7.7 2022. Net proceeds from the sale were used in term financings. We had $ 64 million of com-connection with the redemption of $ 100 mil- mercial paper outstanding at December 31, 35.2 36.3 40.7 40.1 42.3 lion of 10s/s% Series first mortgage bonds due 1992, at a weighted average interest rate of 2018. In January 1993, $ 77.5 million of those 4.0X. The weighted average interest rate dur-10s/sx bonds were redeemed, at a premium, ing 1992 was 4.3%.
1988 1989 1990 1991 1992 and the remaining $ 22.5 million were We also have a revolving credit agreement C3 Long-term debt redeemed, at par, in February 1993 through a with certain banks which provides for borrow-0 Preferred Stock sinking fund provision in our mortgage. ing up to $ 200 million to July 31, 1995. The Q Common Stock Equity The refinancings will save approximately Company did not have any outstanding loans
$ 3.2 million in annual interest costs. Our under this agreement during 1992.
In March 1992, the Company sold 5 mil- embedded cost of long-term debt was reduced The Company's first mortgage bonds and lion shares of common stock at $ 27.25 a to 7.9% at the end of 1992 from 9.8% in prefened stock were upgraded by Fitch Inves-1re. After deducting underwriting fees, net 1987 and was further rtxluced to 7.7% in tors Services, Inc. in July 1992. Fitch stated of $ 26.54 per share, or $ 132.7 mil- early 1993 after the redemption of $ 100 mil- that the higher ratings reflect signiflicantly on, were used to repay commercial paper. lion'of 10s/s% Series first mortgage bonds due improiei financial protection measures since The sale increased the Company's common 2018. Unless interest rates fall further, it will 1987. Fitch also noted our efforts in lowering stock equity ratio in March 1992 to over 43%, . be difficult to improve from the 7.7% level; our embedded cost of long-tenn debt during the highest le~el since we became an inde- hoover, all opportunities will be aggressively the past snvral )ears.
pendent utility in 1949. pursu61. Moody's Innstors Service upgraded our The common equity ratio also impro1el in first mortgage bonds and unsecured pollution 1992 as a result of the Dividend Reinnstment Embedded Cost of Long-Term Debt control bonds in August 1992. This upgrade and Stock Purchase Plan (Plan) and retained 98/o was based on improvements in our financial, earnings. We receiieI $ 30.3 million from the 9~/o 9.1% operating, and regulatory profile, as well as R 0 issuance of 1,039,159 shares of common stock fL4'.9/o the likelihood that our financial condition thmugh the Plan and retained earnings will continue to improv 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 'l987 1988 1989 1990 1991 1992
22 Capital Expenditures The Company's 1992 construction program In June 1992, the Company entefel into is part of our continuing effort to minimize totaled approximately $ 246 million. Most of an agreement with Indeck Energy Services of future rate increases associated w'th uneco-the expenditures were for the extension of ser- Kirk~exl, Inc., Indeck Energy Services, Inc., nomical power purchases from NUGs.
vice and for improvements at existing and Indeck Kirhwod Limited Partnership to As a result of the PSC's competitive bid-facilities. terminate the power purchase agreement for ding program, the Company is contracting for Construction Expenditures the 55 mw Indeck-Kirh~uod project. The ter- 25 mw in conseNation projects to be avail-(Millions of Dollars) mination agreement will save customers an able by November 1994. In accordance with estimated $ 350 million over 20 >ears. In Jan- a PSC ruling issued in October 1992, the 248 248 uary 1993, the PSC approtel full recovery of Company will conduct an auction for an 211 the $ 11.5 million in termination costs in additional 10 mw of conservation projects.
rates. The timing of the auction has not yet been In December 1992, the Company entered determined, but the Company does not expect into an agreement with Kamine/Besicofp Cor- that those conservation projects will be avail-ning L.P., Kamine South Coming Cogen Co., able before 1995. We expect to recover the Inc., and Beta South Coming, Inc. to termi- costs associated with these contracts from our nate the power purchase agfeement for the 79 customers. The Company will utilize various mw South Coming cogeneration project. The methods, including competitive bidding, to termination agreement thrill save customers an minimize the economic impacts on customers estimated $ 300 million over 25 )ears. The of adding new resources to our sptem, while
~
1988 1989 1990 1991 1992 1993 1994 1995 Company plans to petition the PSC in early maintaining our current Ie)el of system CD Actual Forecast 1993 to recover $ 34 million in termination reliability.
costs in rates. Terminating these agreements 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 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-1990 (See Environmental Matters). The Com-struction costs may vary because of revised load eslimates, imposition of additional regulatory pany has no need for additional large base-load generating capacity. tVe forecast that our requirements, and the availability and cost of capital.
current reserve margin, coupled with more 1993 1994 1995 Total efficient use of energy (See Conservation Pro- tMlllions) grams) and generation from non-utility Sources of funds generators (NUGs) will eliminate the need for Internal funds $ 251 $ 259 $ 262 $ 772 additional generating capacity until well into Sale of accounts receivable 14 14 the first decade of the 21st century. Long-term financing The Company has on line and under con- Debt and stock proceeds 140 238 43 421 tract 347 megawatts (mw) of NUG power. In Debt foceeds held in trust (56) 48 8 addition, another 257 mw of NUG power is Net nanctn roceeds 84 286 51 421 under construction. We are lequil61 to make Increase (decrease) in short-term debt 91 27 (2) 116 payments under these contracts only for the Total $ 440 $ 572 $ 311 $ 1323 power we receiw. During 1992, 1991, and Uses of funds 1990, the Company purchased approximately Construction Cash expenditures $ 261 $ 296 $ 248 $ 805
$ 71 million, $ 30 million, and $ 8 million of NUG power. We estimate that we will pur- AFDC 10 13 9 32 chase approximately $ 151 million, $ 251 Total constraetton 271 309 257 837 million, and million of NUG power for Retirement of securities and sinking fund obligations 111 227 24 362
$ 287 the years 1993, 1994, and 1995. The require- Working capital and deferrals 37 12 4 53 ment to purchase NUG power is expected to Demand-side mana ement ro m costs (net) 21 24 26 71 be a major contributor to rate increases over Total 440 $ 572 $ 311 $ 1323 the next 3 years, and is expected to increase As shown in the pfmding table, internal sources of funds represent 92% of construction rates by approximately 8% during this time expenditures for 1993-1995, or approximately 7'fter adjusting for working capital and defer-period. rals and net demand-side management (DSM) program costs.
23 Conservation Programs The Company has implemenled a number cessors. We have been notified by the U.S. dioxide, nitrogen oxides, and possibly toxic DShi programs. In 1990, we received Environmental Protection Agency (EPA) and emissions al several of our coal-fired generat-iproval from the PSC for a plan to obtain the New York State Department of Environ- ing stations. Under the 1990 Amendments, we earnings incentin5 for conducting eflicient mental Conservation that we are among the must reduce our annual sulfur dioxide emis-DShi programs. Those incentin5 are currently potentially responsible parties who may be sions by 49X from approximately 138,000 limited to a .75% return on equity (approx- liable to pay for costs incurred to iemediate tons in 1989 to 71,000 tons by 2000. We esti-imately $ 16.1 million, before taxes, at certain hazardous substances at 9 waste sites, mate that over a 25->mr period the cost to December 31, 1992) allocated to electric oper- not including our inactive gas manufacturing comply with the sulfur dioxide and nitrogen ations. The incentins are based on savings sites which are discussed below. With respect oxide limitations specified in the 1990 from 20 large-scale programs including to the 9 sites, I site is included on the Fed- Amendments is approximately $ 252 million financial and technical assistance to various eral National Priorities list, I site is unlisted (on a present value basis) for all capital and customers. but is the subject of an FPA administrative operating and maintenance expenses, of In 1992, our customeis saved approx- order, and 7 sites are included in the New which $ 17.3 million has been incurtei to imately 139.6 million kilowatt-hours (kwh) York State Registry of Inactive Hazardous date. This cost includes $ 159 million for an on an annualized basis through our DSM Waste Sites (New York State Registry). Any innovative flue gas desulfurization (FGD) sys-programs. The implementation of these pro- liability may be joint and several for certain tem and a nitrogen oxide nxluction system grams cost $ 40 million in 1992 and will cost of these sites. The ultimate cost to remediate expected to be completed in 1995 at our approximately $ 34 million in 1993 with esti- these sites will be dependent on such factors hiilliken Generating Station (hiilliken).
mated customer savings of 158 million h& as the remedial action plan selected, the In September 1991, we were selected by the on an annualized basis, thus producing more extent of site contamination, and the portion Department of Fnergy (DOF) to receive fed-savings with less cost. We filed a taxi-par attributed, if any, to the Company. As a eral funds for these s)stems. In October 1992, (1993-1994) conservation plan with the PSC result, we are unable to estimate the extent of the DOE approiel $ 45 million for these s)s-in June 1992, seeking approval to continue possible remediation costs. There is no clear tems. In addition, the Company expects to implementation of those programs which precedent with the PSC for rate recovery of receive funding totaling up to $ 17 million have demonstrated cost effectiveness. Marginal these types of remediation costs. Honorer, from other sources. We estimate that a 2%
high unit-cost programs will be eliminated since lhe PSC has previously allwwl us to electric rate increase will be required for the d the remaining DShi programs will be recover similar costs in rates (e.g., innstiga- cost of reiucing sulfur dioxide and nitrogen consolidated into five new comprehensive pro- tion and clean-up costs relating to coal tar oxides emissions for both Phase I (begins grams which will benefit all customer classes. sites), we expect to recover any remediation January I, 1995) and Phase H (begins The Company receiiel PSC approval for this costs that we may incur. Januaiy I, 2000).
plan in December 1992. A number of the Company's inactive gas The cost of controlling toxic emissions, if manufacturing sites have been listed in the required, cannot be estimated at this time.
Environmental Matters Regulations may be adoptei at the state level New York State Registry. We have filed peti-The Company continually assesses actions which would limit emissions even further, at tions to delist the majority of the sites. Our that may need to be taken to ensure compli-program to investigate and initiate remedia- an additional cost to the Company. We antici-ance with changing environmental laws and tion at our 38 known inactive gas pate that the costs incunel to comply with regulations. Compliance programs will very manufacturing sites has been extended the 1990 Amendments w'll be recoverable likely increase the cost of electric and natural through 2000. Estimated expenditures over through rates based on previous rate recovery gas service by requiring changes to our oper-this time period are $ 25 million, which are of required environmental costs.
ations and facilities. Historically, rate recovery reflected in our Consolidated Balance Sheets The 1990 Amendments require the FPA to has been authorized for the cost incurred at December 31, 1992, to inmstigate and ini- allocate annual emissions allowances to each for compliance with environmental laws of our coal-fired generating stations based on tiate remediation, as necessary, at the known and regulations.
gas manufacturing sites. We expect to recover statutory emissions limits. An emissions Due to existing and proposed legislation such expendituies in rates, as we have previ- allowance iepresents an authorization to emit, and regulations, and legal proceedings com-ously been allo~el by the PSC to recover during or after a specified calendar year, one menced by governmental bodies and others, such costs in rates. ton of sulfur dioxide. During Phase I, we esti-the Company may also incur costs from the The Clean Air Act Amendments of 1990 mate that the Company will have allowances disposal of hazardous substances produced (1990 Amendments) will result in significant in excess of the affected coal-flred generating during our operations or those of our piede- future expenditures for the reduction of sulfur stations'ctual emissions. The Company is
24 considering various methods of using, bank- common equity and an overall rate of return for a six-month electric rate moratorium ing, or selling these excess emissions allow- of 9.7%. beginning on February I, 1992. Eaminy ances. During Phase II, we estimate that the The rate decision alloviel the Company to for common stock decreased approximately annual tons emitted by the Company's coal- recognize on its income statement, beginning $ 16 million in 1992 as a result of the fired generating stations will equal our August 1992, electric and natural gas unbilled rate moratorium.
annual emissions allowances. revenues on a full accrual basis. This recog-In addition to the annual emissions Federal Energy Regulatory nition did not materially affect annual Commission (FERC) Proceeding allowances allocated to the Company by the revnues and earnings for common stock in In August 1991 and October 1992, the EPA, we may obtain extension mene 1992 and is not expected to do so in 1993, FERC issued orders which revised its generic allowances that the EPA will issue to com- but will affect the recognition of revenues policy related to filing requirements for con-panies electing to build scrubbers in Phase I from 'quarter to quarter, on a comparative tracts determined to be subject to its such as the FGD sistern at Milliken. Due to basis.
jurisdiction under the Federal Power AcL the uncertainty of how many extension In July 1992, the Company entered into Under the revised policy, FERC may require a resene allowances will be demanded, the discussions with the PSC stalf and other inter-utility to refund certain revenues collected extent to which the demand may exceed the ested parties in an attempt to develop a under late-filed contracts.
supply, and the method of allocating exten- multi-year rate plan that addresses costs and In December 1992, FFRC issued a notice sion reserve allowances, the Company entered associated rate changes. The Company con-requesting comments from interested parties into a pooling agreement with other utilities tinues to work with the PSC staff and other relating to its filing requirements for con-which are eligible to receive some of the parties to reach a multi-year rate settlement. tracts. The notice solicited comments on extension reserve allowances. This agreement In August 1992, the Company had planned
,. whether the obligation to file jurisdictional provides assurance that the Company to file with the PSC for electric and natural agreements should extend to certain termi-will receive some of the extension reserve gas rate increases to be effective in August nated agreements as well as existing allowances in the cent that demand 1993. However, since the Company was work- agreements. The Company and many other exceeds supply. ing with the PSC staff and other parties to utilities filed comments in January 1993 chal-reach a multi-)mr rate settlement, the filing Regulatory Matters lenging the filing requirements and the was dela>el until November 1992. In Novem-In July 1992, the PSC approiel an electric appropriateness of the refund obligations.
ber 1992, the Company filed for an electric 'Ihe Company continues to review its rate increase of $ 63.9 million annually, or rate increase of $ 77.5 million annually, or 5%, and a natural gas rate increase of $ 10.4 compliance with FERC contract filing 5.5%, and a natural gas rate increase of $ 9.5 requirements. In October 1992, the Company million annually, or 4.1%, effective August I, million annually, or 3.6%, to be effective determined that it may be required to file at 1992. 'Ihe electric rate increase included August 1993. 'Ihe rate filing provides for an least four additional contracts with FERC. The approximately $ 16 million of capacity charges 11.4% return on common equity and an over-associated with the cmt of purchasing elec- Company is unable to predict what actions all rate of return of 9.6%. We cannot predict FERC may take as a result of its notice and tricity from NUGs. In the event the capacity the outcome of this proceeding.
component of purchasing electricity from is unable to estimate the amount and timing On hfay 14, 1991, the PSC issued an order of refunds, if any, that may be requirel.
NUGs falls below or exceeds $ 16 million, the approving an agreement betvimn the Com- Therefore, the Company cannot predict the difference will be deferred and passed on to pany and the PSC staff which settled a fuel; ultimate disposition of this matter, but customers in a future rate year. The rate procurement proceeding instituted by the PSC. belien5 that it will not have a material decision provided for an 11.2/o return on The agreement, among other things, provided adverse effect on its financial position.
CONSOLIDATED STATEMENTS OF INCOME 1992 1991 1990 tThousands, except Per Share Amounts)
OPERATING REVENUES Electric $ 1,451,525 $ 1867,936 $ 1/34,509 Natural as 240,164 187,879 162,271 TOTAL OPERATING REVENUES 1,G91,689 1,555,815 1,496,780 OPERATING EXPENSES Fuel used in electric generation 2G2,531 274,877 274,245 Electricity purchased 95)02G 45,808 34,613 Natural gas purchased 126,815 99,528 88,589 Other operating expenses 318)680 279,364 268,829 Maintenance 102,500 110,131 io6,665 Depreciation and amortization (Note 1) 158,977 152,380 147,659 Federal income taxes (Notes 1 and 2) 102,45G 94,447 89,577 Other taxes (Note 11) 200,941 178,185 158,770 TOTAL OPERATING EXPENSES 1,367,92G 1,234,720 i,168,947 OPERATING INCOME 323,763 321,095 327,833 OTHER INCOME AND DEDUCTIONS 12,03G 6,076 (i,508)
INCOi41E BEFORE INTEREST CIIARGHS 335,799 327,171 326,325 INTERESI'IIARGES Interest on long-term debt 145,822 151,649 158,209 Other interest 9,5GG 11,877 15,181 AFDC - borrovel (Note 1) 3,557 (4,998) (5,078)
INTEREST CKNGES-NET 151,831 158,528 168312 INCOitIH 183,968 168,643 158,013
.FH K S 20 995 20,330 12,662 INGS AVAILABLEFOR COilIMON STOCK $ 1G2,973 $ 148,313 $ 145851 EARNINGS PHR SIIARE 82.40 $ 2.36 $ 2.48 AVERAGE SENES OIJFSTANDING 67,972 62,906 58,678 The notes on pages 30 through dt are an integral part of the financial statements.
AEC h allosiunce for funds used during construction.
CONSOLIDATED BALANCE SHEETS December 31 1992 1c tThousands)
ASSETS UFILm PLANF, AT ORIGINAL COST (NOTE 1)
Electric (Note 8) $ 4,573,444 $ 4,421,839 Natural gas 352)059 317,694 Common 157,979 156342 5t083,482 4,895,875 Less accumulated d reciation 1,427,793 1,309,829 NET UTILITYPLANT IN SERVICE 3,G55,G89 3,586,046 Construction work in ro 177,56G 166,815 TOTAL UTILITYPLANT 3,833,255 3,752,861 OTHER PROPERTY AND INVESXIIENTS 59,157 56,581 CURRENT ASSETS Cash and cash equivalents (Notes 1 and 6) 3,968 18,601 Special deposits (Note 6) 96,432 11,463 Accounts receivable, net (Note I) 171t683 133,338 Fuel, at average cost 69,077 66,602 Materials and supplies, at average cost 50,G37 51,736 Prepayments 37,897 37,019 Accumulated defeml federal income tax benefits (Notes I and 2) 15,437 16,278 Unfunded future federal income taxes (Notes 1 and 2) 20,880 22,659 TOTAL CURRENT ASSETS 46G 011 35 DEFERRED CHARGES (NOTE 1)
Accumulated deferred federal income tax benefits (Notes 1 and 2) 84,257 83,718 Unfunded future federal income taxes (Notes 1 and 2) 372,840 413,586 Unamortized debt expense 96,378 91,850 Other 264,530 168,544 TOTAL DEFERRED CHARGES 818,005 757,698 TOTAL ASSETS $ 5,176,428 $ 4. 24836 The notes on pages 30 thtough <t ate an inteyal patt of the finandal statements.
27 CONSOLIDATED BALANCE SHEETS 1992 1991 tThousands)
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) $ 4G2,929 $ 422,668 Capital in excess of par value 796,505 673,791 Retained eamin 327,040 308,688 Total common stock ui 1,58G,474 1,405,147 Prefemd stock redeemable solel at the o tion of the Com an (Note 4) 1G0,500 160,500 Prefemd stock sub'ect to mandato redem lion uirements (Notes 4 and 6) 106,900 108,550 Lon -term debt (Notes 3 and 6) 1,777,027 1,788,915 TOTAL CAPITALIZATION 3,630,901 3,463,112 CURRENT LIABILITIES Current portion of long-term debt and preferred stock (Notes 3 and 4) 115,G59 38,653 Commercial paper (Notes 5 and 6) 64,100 103,900 Accounts payable and accrued liabilities 95,996 mO,847 Interest accrued (Note 6) 37,G90 43,440 Unfunded future federal income taxes (Notes 1 and 2) '20)880 22,659 Accumulated deferred federal income taxes (Notes 1 and 2) 24,083 16,747 Other 6'7,499 75,483 TOTAL CURRENT LIABILITIES 425,907 401,729 FERRED CREDITS ccumulated deferred inmstment tax credits (Notes 1 and 2) 141,729 148,078 Excess defemd federal income taxes (Notes 1 and 2) 55,762 63,778 Other 107,160 67,961 TOTAL DEFERRED CREDITS 304,G51 279,817 ACCUMULATED DEFERRED FEDERAL INCOME TAX (NOTES 1 AND 2)
Unfunded future federal income taxes 372)840 413,586 Other 417,129 366,592 TOTAL ACCUMULATED DEFERRED FEDERAL INCOME TAXES 789,969 780,178 CO)tIMITMENTS AND CONTINGENCIES (NOTE 9) 25,000 TOTAL CAPITALIZATIONAND LIABILITIES $ 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 $ 183)968 $ 168>643 $ 158,013 Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 158,977 152~ 147,659 Defened fuel and purchased gas (14,G45) 2,507 (6,225)
Federal income taxes and investment tax credits deferred - net 50)683 53,105 50,924 Recovered (deferred) transmission wheeling charges (86I) 20,793 Unbilled revenue recognition (Note I) (22)228) (4o,i47) (43,849)
Demand-side management program costs (22,8G3) (IS,>>8) (2,051)
Other - net (13,022) 3,832 >>,103 Changes in certain cumnt assets and liabilities, net of effects from the purchase of Columbia Gas of New York, Inc. in 1991:
Special deposits (1,873) (4,108) (443)
Accounts receivable (11,936) (Is,s41) (>>,123)
Prep ayments (878) (7,882) (2,650)
Inventory (1,417) 4,59o 87,874)
Accounts payable and accrued liabilities (8,287) s,6s6 >>,67o Interest accrued (5,750) 8,6io) (4,486)
Olher - net 4,4G2 2,44o (s,42o)
NET CASH PROVIDED BY OPERATING ACTIVITIES 28G,2G7 305,886 286,04I INVESfING ACTIVITIES Utility plant construction expenditures, net of AFDC - other (Note I) (243,051) (244,o37) (210,540)
Pa ent for urchase of Columbia Gas of New York, Inc., net of cash uited (57,096)
NET CASH USED IN INVKSfING ACTIVITIES 243,051 (301,133) (21 FINANCING ACTIVITIES Issuance of first mortgage bonds 247,6G8 147,243 294,316 Sale of common stock 162,965 25,380 >>5,089 Sale of preferred stock 98,975 First mortgage bonds and prefeml stock repayments (178,289) (142,715) (296,289)
Special deposit - first mortgage bond repayments (83,096) (498)
Long-term notes repayment (1,593) (2,322) (5,078)
Commercial paper - net (39)800) 30,675 (47,775)
Dividends on common and referred stock 165,704 (iSo,lo6) (133,906)
NET CASH PROVIDED BY USED IN FINANCING ACTIVITIES 57,849 7,130 (74,141)
NET INCREASE (DECREASE) IN CASH AND CASH KQUIVALKNfS (14,G33) >>,883 1860 CASH AND CASH E UIVALKNfS, BEGINNING OF YEAR 18,601 6,718 5358 CASH AND CASH E UIVALENTS, END OF YEAR NOTES 1 AND 6 $ 3,968 $ 18,601 $ 6,718 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFOIMATION Cash paid during the period:
Interest, net of amounts capitalized $ 149)299 $ 159,927 $ 171,675 Income taxes $ 38,477 $ 31,790 $ 33,1>>
SUPPLKllIENfALDISCLOSURE OF NONCASH INVFSfING AND FINANCING ACTIVITIES Capital lease additions $ 2)970 $ 9,s24 $ 12,192 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 $ 81,982 Cash aid (57,096)
Liabilities assumed $ 24,886 1he notes on pages 30 through 4l ate an integral patt of the financial statements.
hFDC is alb)jant>> for funds used during consttuctton.
29 CONSOLIDATED STATEMENTS OF CHANGES COMMON STOCK EQUITY tThousands, except Shares and Per Share Amounts)
Common Stock Capital S6.66 2j3 Par Value , ln Excess Retained Shares Amount of Par Value Earnings Total BAIANCE, JANUARY I, 1990 57,553,528 $ 383,690 $ 573,293 $ 268,201 $ 1,225,184 Net income 158,013 158,013 Cash dividends declatoi:
Preferred stock (at serial rates)
Redeemable - optional (iI,484) (11,484)
- mandatory (1,178) (1,178)
Common stock ($ 2.06 per share) (121,302) (121802)
Issuance of stock Public Offering 4,000,000 26,667 66990 93,657 Dividend reinvestment and stock urchase lan 876,769 5,845 iS,&8 2i,454 BALsiNCE, DECEMBER 31, 1990 62,430,297 416,202 655,892 292,250 1,364,344 Net income i68,643 i68,643 Cash dividends declared:
Prefemd stock (at serial rates)
Redeemable - optional (11 395) (I 1,395)
- mandatory (8,935) (8,935)
Common stock ($ 2.10 per share) (131,875) (131,875)
Issuance of stock Dividend reinvestmentandstock urchase lan 969,941 6,466 17899 4365 NCE DFCEh/BER 31 199 63 400238 422,668 673,791 308,688 1,405,147 t income 183,968 183,968 Cash dividends declared:
Preferred stock (at serial rates)
Redeemable - optional (>>,IQ) oi,iQ)
- mandatory (9,831) (9,831)
Common stock ($ 2.14 per share) (144,621) (144,621)
Issuance of stock Public OfFering 5,000,000 33333 99,367 132,700 Dividend reinn5tment and stock urchase lan 1,039,159 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. SIGNIFICANT ACCOUNTING POLICIES Principles of consolidation The consolidated financial statements statement to minimize the rate increases for The Financial Accounting Standards Board include the Company's wholly-owned subsid- these >van in accordance vdth various PSC issued Statement of Financial Accounting iary, Somerset Railroad Corporation (SRC). rate decisions. The July 1992 rate decision Standards No. 109, Accounting for Income All significant intercompany balances and allows the Company to recognize on its Taxes (SFAS 109), in February 1992, and it is transactions are eliminated in consolidation. income statement, beginning August 1992, effective for fiscal >ears beginning after electric and natural gas unbilled revenues on December 15, 1992. The Company will adopt Utilityplant a full accrual basis. SFAS 109 in the first quarter of 1993. The The cost of repairs and minor replace-The Company recognizes as revenues adoption of SFAS 109 will not have a mate-ments is charged to appropriate operating incentives earned as the result of conducting rial effect on the Company's results of expense accounts. The cost of renewals and efficient demand-side management (DSM) operations or financial position because SFAS betterments, including indirect cost, is cap-programs. The Company is collecting those 109 does not differ materially from the State-italized. The original cost of utility plant incentives in rates within 12 to 13 months ment of Financial Accounting Standards retited or othenvise disposed of and the cost after they are recognized. During 1992, 1991, No. 96, Accounting for Income Taxes, which of removal less salvage are charged to accu-and 1990, incentims earned were $ 15.6 mil- the Company adopted in 1987.
mulated depreciation.
lion, $ 12.4 million, and $ 2.6 million, The Company files a consolidated federal Depreciation and amortization respectively. At December 31, 1992 and 1991, income tax return with SRC. Defend income Depreciation expense is determined using approximately $ 9.8 and $ 11.3 million, respec- taxes are provided on all temporary differ-straight-line rates, based on the average ser- tively, of DStI Incentins were accrued and ences betwtx.n book and taxable income.
vice line of groups of depreciable property in included in accounts receivable. Innstment tax credits, which reduce federal service. Depreciation accruals were equivalent income taxes currently pa@hie, are deferred Accounts receivadie and amortized over the book lin5 of the to 3.3% of average depreciable property for 1lie Company has an agreement that 1992, 1991, and 1990. Depreciation expense applicable property. 'Ihe effect of the altem.
expires in November 1996 to sell, with limited includes the amortization of certain deferred tive minimum tax, which increases federal recoutse, undivided percentage interests in charges authorized by the Public Service income taxes cumntly payable and generates certain of its accounts receivable from cus-Commission of the State of New York (PSC). a tax credit available for future use, is tomers. The agreement allows the Company deferred and amortized at such times as the Allowance for funds used during to receive up to $ 152 million from the sale of tax credit is used on the Company's federal construction IAFDC) such interests. At December 31, 1992 and income lax return.
AFDC represents the cost of funds used to 1991, accounts receivable on the Consolidated finance the construction of utility plant. Balance Sheets is shown net of $ 138 million Deferred charges Those costs are capitalized during the con- of interests in accounts receivable sold. All The Company defers certain incurred struction'period and recorded in construction fees associated with the program are included expenses, when authorized by the PSC. Those work-in.progrm. AI'DC is recovered over the in olher income and deductions on the Con- expenses are recovered from customers in the life of the plant through depreciation when solidated Statements of Income and amounted future.
the construction project is placei in service. to approximately $ 6.5 million, $ 9.3 million, Those costs are also credited on the income Consolidated Statements of and $ 12.5 million in 1992, 1991, and 1990, Cash Flows statement during the construction period as respectively. Axounts receivable on the The Company considers all highly liquid an allowance for borroiiel funds used during Consolidated Balance Sheets is also shown net investments with a maturity or put date of construction, which reluces the net interest of an allowance for doubtful accounts which three montlts or less when acquired by the charges, and as an allowance for other (i.e., was $ 1.9 million and $ .7 million at Decem- Company to be cash equivalents. These innst-equity) funds used during construction, which ber 31, 1992 and 1991, respectively. Bad debt ments are included in cash and cash is included in other income. expense was $ 11.5 million, $ 10.7 million, equivalents on the Consolidated Balance and $ 8.9 million in 1992, 1991, and 1990, Sheets.
Revenue respectively.
In 1988, the Company began accruing Reclasslficatton electric and natural gas revenues on its Federal income taxes Certain amounts have been reclassified on balanoe sheet for energy provided but not The Company follows the method of the consolidated financial statements to con-yet billed. During 1992, 1991, and 1990, accounting for income taxes prescribed by form with the 1992 presentation.
the Company recognized approximately $ 22 Statement of Financial Accounting Standards million, $ 40 million, and $ 44 million, No. 96, Accounting for Income Taxes.
n5pectively, of these revenues on ttie income
31
- 2. FEDERAL INCOME TAXES
~
cended December 31 1992 1991 1990 tThousends)
Charged to operations Current $ 37,237 $ 22,991 $ 37,804 Deferred - net Accelerated depreciation 41,492 37,409 33,704 Unbilled revenues 160 13,644 io,i67 Tax Reform Act (TRA) 1986 (2,295) (2,284) 6,566).
Alternative minimum tax (AhiT) credit 2,123 5,557 (1,763)
Demand management 9,324 8,589 1,985 Power purchase termination agreement 6,800 Miscellaneous (4,415) (8,243) 697 Investment tax credit (ITC) deferred 12 030 16,784 10,549 102,456 94,447 89,577 Included in other of defeml ITC income'mortization (16,927) (11,297) (5,756)
Miscellaneous 3 747 (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 1990 tThousends)
Tax expense at statutory rate $ 92)903 $ 85,428 $ 82,283 iation not normalizel 16,697 16,051 14,459 86- net (2,485) (2806) 8,566) amortization (16,927) (11,297) (5,756)
Cost of removal (4,079) (6,120) (4,148)
Other - net 3 167 861 725 TOTAL $ 89,276 $ 82,617 $ 83,997 The Company has recorded unfunded including the tax effect of the future revenue future federal income taxes and a corres- requirements, are being amortized over the ponding receivable from customers of life of the related depreciable assets concur-approximately $ 393 million and $ 436 million rent with their recovery in rates.
as of December 31, 1992 and 1991, respec- The Company has approximately $ 6 mil-timiy, primarily representing the cumulative lion of unused Investment tax crelits at amount of federal income taxes on temporary December 31, 1992, which will begin to depreciation differences which were previously expire in 2001, and $ 12 million of AhIT flo~1xi through to customers. Those amounts, 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 8s/s% Aug. 15, 1994 $ 100,000 $ 100,000 67/s% Dec. I, 2006 $ 25,500 $ 25,750 Ss/A June I, 1996 50,000 50,000 8s/s% Nov. I, 2007 60,000 60,000 5s/sX Jan. I, 1997 25,000 25,000 10s/s% Feb. I, 2016 20,424 6~/A Sept. I, 1997 25,000 25,000 9i/A Apr. I, 2016 50,000 50,000 6~/t% Sept. I, 1998 30)000 30,000 9% hlar. I, 2017 100,000 100,000 7s/s% Nov. I, 2001 50,000 50,000 IOs/s% Jan. I, 100,000 100,000 2018'7/s%
6s/<% OcL 15, 2002 150,000 Feb. I, 2020 100,000 100,000 9.35%%d July I, 2003 33,200 97/s%%d May I, 2020 100,000 100,000 9s/s% hlar. I, 2005 75,000 9~/s% Nov. I, 2020 100,000 100,000 9s/s%%d Jan. I, 2006 3)000 45,000 87/s%%d Nov. I, 2021 150,000 150,000 7~/~%%d une I, 2006 12,000 12,000 8.AS Dec. 15, 2022 100,000 Total rst mort a e bonds 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 Maturity Interest Rote Letter of Credit Amount Rate Date Adjustmont Dote Expiration Dote 1992 1991 12%%d hiay I, 2014 60,000 60,NI 12.3IS July I, 2014 40,000 40,NI 3'ec. I, 2014 hiar. I, 2015 Dec. I, 1993 hlar. I, 1993 Dec. 15, 1994 Mar. 15, 1994 74,000 37,500 74,000 3.25%%d 37,500 2.9% hlar. 15, 2015 Mar. 15, 1993 hiar. 31, 1994 60,000 60,ee 3.1IS July 15, 2015 July 15, 1993 July 31, 1994 63,500 63,500 2.$ S Oct. 15, 2015 Oct. 15, 1993 Oct. 31, 1994 30,000 30,000 2.9% Dec. I, 2015 Dec. I, 1993 Dec. 15, 1994 42,000 42,000 6.6% July I, 2026 July I, 1993 July 15, 1996 65,000 65,000 5.375%%d Dec. I, 2027 Dec. I, 1994 Dec. 15, 1994 34,000 34,000 Total ollutlon control notes 50G,000 506,000 SRC commercial paper due December 31, 1995 27,707 29,300 Obligations under capital leases 38)804 47,260 Unamortized remium and discount on debt - net (11,975) (8,016) 1,891,03G 1,825,918 Les~: debt due within one ear - included in current liabilities 114,009 37003 Total $ 1,777,027 $1 788915
33
- 3. LONG-TERM DEBT (Continued) t December 31, 1992, long-term debt and interest at the rate indicated through the date capital lease payments which will become due preceding the interest rate adjustment date.
during the next five pars are: The pollution control notes bear interest at 1993 1994 1995 1996 1997 the same rate as the Revenue Bonds. On the tThouaanda) interest rate adjustment date and annually thereafter (every three pars thereafter in the
$ 114,009 $ 110,609 $ 36,035 $ 56,156 $ 52,196 case of the Revenue Bonds due July I, 2026 and December I, 2027), the interest rate will The Company's mortgage provides for a be adjusted, nol to exceed a rate of 15%%d, or sinking and improvement fund. This provision at the option of the Company, subject to cer-requires the Company to make annual cash tain conditions, a fixed rate of interest, not to deposits with the Trustee equivalent to IX of exceed 18Ã, may become effects. In the the principal amount of all bonds delivered case of the Revenue Bonds due July I, 2026 and authenticated by the Trustee prior to Jan- and December I, 2027, at the option of the uary I of that year (excluding any bonds Company, subject to certain conditions, a issued on the basis of the retirement of fixed rate of interest may become effective bonds). The Company satisfied this require- prior to the interest rate adjustment date ment in 1992 by depositing $ 20.4 million in or each third year thereafter. Bond ownen cash which was used to releem the remain- may elect, subject to certain conditions, ing $ 20.4 million of 10s/A'eries first to have their Revenue Bonds purchased by mortgage bonds, due 2016. The Company sat- ttle Trustee.
Isfied this requirement in 1993 by depositing The Company has irrevocable letters of
$ 22.5 million in cash which was used to credit which expire on the letter of credit m in February 1993, $ 22.5 million of expiration dates and which the Company
%%d Series first mortgage bonds, due 2018. anticipates being able to extend if the interest mandatory annual cash sinking fund rate on the related Revenue Bonds is not con-requirements are $ 600,000 beginning June I, verted to a fixed interest rate. TIrose letten of 2001, for the 7/A Series and $ 250,000 on credit support certain payments required to be December I in each par 1993 to 1996, for made on the Reenue Bonds. If the Company the 6~/a%%d Series. Tire amount increases to is unable to extend the letter of credit that is
$ 500,000 and $ 750,000 on December I, 1997 related to a particular series of Retinue and December I, 2002, rr5pectively, for the Bonds, that series w'll have to be redeemed 6N%%d Series. unless a fixed rate of interest becomes effec-The Company's first mortgage bond inden- tive. Payments made under the letters of ture constitutes a direct first mortgage lien on credit in connection with purchases of Reve-substantially all utility plant. nue Bonds by the Trustee are repaid with the Adjustable rate pollution control notes were proceeds from the remarketing of the Revenue issued to secure like amounts of taxmempt Bonds. To the extent the proceeds are not suf-adjustable rate pollution control revenue ficient, the Company is required to reimburse bonds (Revenue Bonds) issued by a govem- the bank that issued the letter of credit.
mental authority. The Revenue Bonds bear
34
- 4. PREFERRED STOCK At December 31, 1992 and 1991, serial cumulative prefeml stock was:
Shares Par Value Authorbied Per Redeemable a)id Amount Series Share Prior to Per Share Outstanding(1) 1992 1991 tThousands)
Redeemable solely at the option of the Company:
3.75% $ 100 $ io4.oo 150,000 $ 15,000 $ 15,ooo 4 i/i% (1949) 100 103.75 4o,ooo 4,ooo 4,ooo 4 15% 100 101.00 '4o,ooo 4,ooo 4,ooo 4.40% 100 102.00 75,000 7,500 7,500 4.15% (1954) 100 102,00 50,000 5,000 5,000 6.48% 100 102.00 300,000 30)000 30,000 8.80% 100 102.00 250,000 25)000 25,000 8.48% 25 t/i/94 26.23 1,000,000 25,000 25,000
'Ihereafter 25.70 Adjustable Rate (2) 25 '/i/93 25.75 1,800,000 45,ooo 45,NI Thereafter 25.00 Total $ 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 4,000,000 100,000 100,000 108,550 110,200 Im: sinking fund requirements at par value included in current liabilities 1,650 1,650 Total $ 106,900 $ 108,550 Annual redeemable preferred stock sinking shares at par. For the years 1990 through fund requirements for the next five >ears are: 1992, 16,500 shares were rtxleemed and 1993 1994 1995 1996 1997 cancelled annually. This Series is tThousands) redeemable at the option of the Company at $ 101.00 per share prior to October I,
$ 1,650 $ 1,650 $ 1,650 $ 3,600 $ 5,000 1993. 'Ihe $ 101.00 price per share will be reduced annually by 50 cents. As of (I) At December 31, 1992, there were October I, 1994, and thereafter, the 1,550,000 shares of $ 100 par value pre-redemption price will be at par. By Sep-ferrei stock, 4,000,000 shares of $ 25 par tember 30, 1996, the Company must set value preferred stock and 1,000,000 aside the amount required to redeem at shares of $ 100 par value preference stock par all remaining shares outstanding.
authorized but unissued.
(4) On January I, in each )ear 1997 through (2) The payment on the Adjustable Rate 2016, the Company must nxleem 200,000 Serial Preferred Stock, Series A, for April shares at par. This Series is redeemable I, 1993 has been adjusted to an annual at the option of the Company at $ 26.94 rate of 7.5% and subsequent payments per share prior to January I, 1994. The can vary from an annual rate of 7.5% to
$ 26.94 price will be reduced annually by 13.5%, based on a formula included in 15 cents for the )ears ending 1994 the Company's Certificate of Incorpora-through 1999; by 14 cents for the >uar tion. Dividends paid from the date of ending 2000; and by 15 cents for the issuance (1983) through the January I, >ears ending 2001 through 2005. The 1993 payment varied from an annual Company is restricted in its ability to rate of 7.5/o to 12.95%.
redeem this Series prior to January I, (3) On October I, in each year 1993 through i996.
1995, the Company must redeem 16,500
35
- 5. BANK LOANS AND OTHER RROWINGS e Company Itas a revolving credit agree- The revolving credit agreement does not ment with certain banks>>1tich provides for require compensating balances. The Company borrowing up to $ 200 million to July 31, did not have any outstanding loans under 1995. At the option of the Company, the this agreement or a similar prior agreement interest rate on bormwings is related to the at December 31, 1992 or 1991.
prime rate, the landon Interbank Offeted In order to pmvide flexibility in the timing Rate or the interest rate applicable to and amounts of long-term financings, the certain certificates of deposit. Tlie agreement Company uses interim financing in the form also provides for the payment of a com- of short-term unsecured notes, usually com-mitment fee of .22%%d per annum on the mercial paper, to finance certain refundings unbono>>el amount. and construction expenditures, and for other corporate purposes.
Information relative to shoit-temi bonowings is as folio>>s:
Commercial Paper 1992 1991 1990 tThousandsl Ending balance $ 64,ioo $ 103,900 $ 73,225 Maximum amount outstanding $ 140,000 $ 111,000 $ 142,600 Average amount outstanding (1) $ 3i,400 $ 66,700 $ 98,400 Weighted average interest rate On ending balance 4.0/o 5.3%%d 8.6X Durin the riod 2 4.3/o 6.2X, 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 VALUE OF FINANCIAL INSTRUMENTS The estimal61 fair values of the Company's financial instruments at December 31, 1992 are as follows (Thousands):
Carrying Fair Amount 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 First Mortgage Bonds and Pollution Control Notes items approximates fair value because of the The fair value of the Company's first short maturity of those instruments: Cash and mortgage bonds and pollution control notes is Cash Equivalents, Commercial Paper, Special estimated based on the quoted market prices Deposits, and Interest Accrued.
for the same or similar issues of the same The following methods and assumptions remaining maturities.
used to estimate the fair value of each of financial instruments for which it is Preferred Stock practicable to estimate that value:
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- pension benefit for 1992, 1991, and 1990 ment annuity plans which cover substantially totaled $ 1.5 million, $ 2.9 million, and all emplo>ms. Benefits are based principally $ 4.9 million, respectively.
on the emplo)1x,'s length of service and com- Effective January I, 1993, the retirement pensation for the five highest paid >ears benefit plans for hourly and salaried out of the last 10 >ears of service. It is the emplo)es were combined into one plan.
Company's policy to fund pension costs Combining the twu plans will not affect accrued each )var to the extent deductible bendit levels.
for federal income tax putposes. 'Ihe net Net pension benefit for 1992, 1991, and 1990 included the following components:
1992 1991 1990 tThousands)
Service cost: Benefits earned during the >var $ 15,387 $ 13,252 $ 11,968 Interest cost on projected benefit obligation 35,253 32,096 28,636 Actual return on plan assets (60,020) (111,749) (6,499)
Net amortization and deferral 7 844 63,487 (39,017)
Net enston bene t $ 1,536 $ (2,914) $ (4,912)
The funded status of the plans at December 31, 1992 and 1991 were: 1992 1991 tThousands)
Actuarial present value of accumulated benefit obligation:
Vested $ 287,504 $ 270,052 Non)15ted 42,286 34,o67 Total $ 329,790 $ 304,119 Fair value of plan assets $ 701,893 $ 659,993 Actuarial resent value of ro'ected benefit obli ation (480.429) (440,519)
Plan assets in excess of projected benefit obligation 221,464 219,474 Unrecognized net transition asset (80,850) (88,103)
Unrecognized net (gain) loss (139,729) (132,642)
Unreco ized rior service cost 5,209 5,578 Net enston asset $ 6,094 $ 4,3o7 Plan assets primarily consist of equity self-insures. The cost of providing those bene- tion of the new standard is expected to securities, corporate, U.S. agency, and Treas- fits to retirees was approximately $ 5 million, increase annual expenses, before deferral for ury bonds, and cash equivalents. $ 4.4 million, and $ 4.1 million in 1992, 1991, ratemaking purposes, by about $ 32 million, For 1992, 1991, and 1990, the projected and 1990, respectively. or 7 times the 1992 expense.
benefit obligation was measured using an The Financial Accounting Standards Board In March 1992, the PSC issued a draft assumed discount rate of 7.75%%d, 7.75%, and issued Statement of Financial Accounting Statement of Policy concerning the account-8N, respectively, and a long-term rate of Standards No. 106, Employers'ccounting for ing and ratemaking treatment for postretire-increase in future compensation levels of 6%%d, Postretirement Benefits Other Than Pensions ment benefit costs. This draft policy provides while the net pension benefit was measured (SFAS 106) in December 1990. SFAS 106 for, among other things, recovery in rates for using an expected long-term rate of return on requires that the Company accrue a liability deferred SFAS 106 costs. In addition, the draft plan assets of 7.5%%d. for estimated future postretirement benefits policy proposes that deferred SFAS 106 costs In addition to providing pension benefits, during an employe's working career rather will be recovered in rates within 10 years of the Company provides certain postretirement than recognize an expense when benefits are the adoption of SFAS 106. The Statement of benefits for retired emploies and their depen- paid. SFAS 106 is effective for fiscal >zan Policy is expected to be approiel by the PSC dents. Substantially all of the Company's beginning after December 15, 1992. during the spring of 1993. In addition, the emplo>es who retire under a Company pen- The Company adopted SFAS 106 in July 1992 rate decision allows the Company'o sion plan may become eligible for those January 1993. At the time of adoption, the recover a portion of SFAS 106 costs in rei benefits at retirement. At December 31, 1992, actuarially determined accumulated postretire- enues from its customers and to defer the 1991, and 1990, 1,905, 1,866, and 1,785 ment benefit obligation attributable to eligible remainder of these costs for recovery, in retirees and their dependents, respectively, plan participants and eligible dependents was accordance vdth the draft Statement of Policy.
were covered under the Company's compre- $ 225 million. The Company plans to recog- The Company anticipates that future SFAS hensive health insurance plan and nize the accumulat61 benefit obligation over 106 costs will be recoverable through rates.
pnscription drug plan, vvhich the Company 20 >ears in accordance with SFAS 106. Adop-
37
- 8. JOINTLY-OWNED ENERATING STATIONS e Mile Point Unit 2 The Company has an undivided IS% inter- from NMP2. The DOE announced in early age and replacement power coverages is est in the output and costs of the Nine Mile 1990 thai the schedule for start of operations approximately $ 2.3 million.
Point nuclear generating unit No. 2 (NMP2) of their high level radioactive waste repository which is being operated by Niagara Mohawk had slipped from 2003 to no sooner than Nuclear Fuel Disposal and Nuclear Plant Decommissioning Costs Power Corporation (Niagara Mohawk). Owner- 2010. The Company has been advised by Niagara Mohawk has contracted with the ship of NMP2 is shared with Niagara Mohawk Niagara Mohawk that the NMP2 Spent fUel DOE for the disposal of nuclear fuel. The 41'A, Ixing Island lighting Company 18K, Storage Pool has a capacity for spent fuel Company is reimbursing Niagara Mohawk for Rochester Gas and Electric Corporation 14%, that is adequate until 2014. If further DOE its I8% share of the cost under the contract and Central Hudson Gas Bi. Electric Corpora- schedule slippage should occur, the recent (currently approximately $ 1 per megawatt tion 9X. The Company's share of the rated development of pie-licensed diy storage facili-hour of net generation).
capability is 188,000 kilowatts. The Com- ties for use at any nuclear power plant The Company has been informed by pany's net utility plant inmstment, excluding extends the on-site storage capability for spent Niagara Mohawk that its 18% share of the nuclear fuel, was approximately $ 660 million fuel at NMP2 beyond 2014.
cost to decommission NMP2 is currently esti-and $ 679 million, at December 31, 1992 and NMP2's next refueling outage is antici-mated to be $ 235 million in 2027, when 1991, respectively. The accumulated provision pated to begin in September 1993.
decommissioning is expectnl to commence.
for depreciation was approximately $ 90 mil-Nuclear Insurance Included in the Company's current electric lion and $ 72 million, at December 31, 1992 Niagara Mohawk maintains public liability rates is an annualized allowance of approx-and 1991, respectively. The Company's share and property insurance for NMP2. The Com- imately $ 1.6 million, based on Niagara of opemting expenses is included in the Consolidated Statements of Income. pany reimburses Niagara Mohawk for its W Mohawk's estimate, which the Company share of those costs. expects will provide for its I8% share of An interim operating agreement that pro-The Price-Andetson Amendments Act of decommissioning NMP2 in 2027.
vided for policy, budget, and ntanagement 1988 increased the public liability limit for a In March 1990, the Company established a oversight functions of NMP2 by the four non-nuclear incident to approximately $ 7.6 bil- Qualified Fund under applicable provisions of rating cotenants expixd on December 31, lion. Should losses stemming from a nuclear the federal tax law. The fund also complies Z. Effective January I, 1993, an operating incident exceed the commercially available with NRC regulations which require the use agreement replaced the interim operating public liability insurance, each licensee of a of an external trust fund to provide funds to agreement, and its temis are substantially the nuclear facility veld be liable for up to a decommission the contaminated portion of same. The operating agreement, which expires maximum of $ 63 million per incident, NMP2. The balance in this fund was approx-December 31, 1994, provides for automatic payable at a rate not to exceed $ 10 million imately $ 3.9 million and $ 2.4 million at
. extensions unless terminated by one or more per >ear. December 31, 1992 and 1991, respectively, of the cotenants after appropriate notice. The The Company's maximum liability for its and is included in other property and Inmst-operating agreement is subject to PSC IS% interest in NMP2 would be approxinuttely ments on the Consolidated Balance Sheets.
approval.
$ 11 million per incident. The $ 63 million Niagara Mohawk filed a decommissioning In August 1992, the Nuclear Regulatory assessment is subject to periodic inflation report for NMP2 with the NRC. The report Commission (NRC) issued a systematic assess-indexing and a 5% surcharge should funds outlined the proposed plans, which included ment of licensee performance (SALP) review the Company's funding plan, to provide of the Nine Mile Point Station (includes both priv insuAicient to pay claims associated with a nuclear incident. The Price-Andenon linancial assurance to fund costs lo decom-Nine Mile Point nuclear generating unit No.
Act also requires indemnification for precau- mission NMP2 when its license expires.
I and NMP2) for the period April 1991 through May 1992. The M.P report indicated tionaiy evacuations whether or not a nuclear Homer City incident actually occuts.
that Nh1P2 operates safely and is a good The Company has an undivided 5% inter-Niagara Mohawk maintains nuclear prop-overall performer. The ratings for plant est in the output and costs of the Homer City erty insurance for NMP2. Niagara Mohawk operations, engineering/technical support, Generating Station, which is comprised of has procured property insurance aggregating radiological controls, saf'ety assessment/quality three genemting units. The station is owned verification, and maintenance/surveillance approximately $ 2.6 billion through the with Pennsylvania Electric Company which Nuclear Insurance Pools and the Nuclear remained at Category 2, representing good operates the facility. The Company's share of Electric Insurance Limited (NEIL). In addi-performance. Emergency prepatedness and the rated capability is 952,000 kilowatts and security safeguanls remained at Category I, tion, the Company has purchased NEII. its net utility plant innstment was approx-insurance coverage for the extra expense nting superior performance. imately $ 251 million and $ 257 million at low level radioactive waste managemenl incurred in purchasing replacement power A December 31, 1992 and 1991, respectively.
and contingency plan has been developed for during prolonged accidental outages. Under The accumulated provision for depreciation that it is prop- NEIL programs, should losses resulting from million and $ 144 Nh1P2 and provides assurance was approximately $ 148 an incident at a member facility exceed the erly prepared to handle interim storage of low million, at December 31, 1992, and 1991, accumulated resents of NEHeach member, level radioactive waste until 1998. respectively. The Company's share of operat-including the Company, would be liable for Niagara Mohawk has contracted with the ing expense is included in the Consolidated its share of the deficiency. The Company's U.S. Department of Energy (DOE) for disposal Statements of Income.
of high level radioactive waste (spent fuel) maximum liability under the property dam-
38
- 9. COMMITMENTS AND CONTINGENCIES Construction Program The Company has made substantial com- remedial action plan selected, the extenl of $ 159 million for an innovative flue gas mitments in connection with its construction site contamination, and the portion attributed, desulfurization (FGD) sistern and a nitrogen program and estimates that 1993 costs will if any, to the Company. As a result, the Com- oxide reduction sistern expected to be com-approximate $ 271 million. The program is pany is unable to estimate the extent of pleted in 1995 at the Company's Milliken subject to periodic review and revision, and possible remediation costs. There is no clear Generating Station (Milliken).
actual construction costs may vary because of precedent with the PSC for rate recovery of In September 1991, the Company its revised load estimates, imposition of addi- these t)ps of remediation costs. Hogdeer, selected by the DOE to receive federal funds tional regulatory requirements, and the since the PSC has previously allovel the for these systems. In October 1992, the DOE availability and cost of capital. Company to tamer similar costs in rates (e.g, approiei $ 45 million for these systems. In investigation and clean-up costs relating to addition, the Company expects to receive Environmental Matters coal tar sites), the Company expects to recover funding totaling up to $ 17 million from The Company continually assesm actions any remediation costs that it may incur. other sources. The Company estimates that a that may need to be taken to ensure compli-A number of the Company's inactive gas 2% electric rate increase will be required for ance with changing environmental laws and manufacturing sites have been listed in the the cost of reducing sulfur dioxide and nitro-regulations. Compliance programs will very New York State Registry. The Company has gen oxides emissions for both Phase I (begins likely increase the cost of electric and natural filed petitions to delist the majority of the January I, 1995) and Phase H (begins Janu-gas service by requiring changes to its opera-sites. The Company's program to investigate ary I, 2000).
tions and facilities. Historically, rate recovery and initiate remediation at its 38 known The cost of controlling toxic emissions, if has been authorized for the cost incurred inactive gas manufacturing sites has been required, cannot be estimated at this time.
for compliance with environmental laws extended through 2000. Fstimated expendi- Regulations may be adopted at the state level and regulations.
tures over this time period are $ 25 million, which would limit emissions even further, at Due to existing and proposed legislation which are ieflected in'the Company's Consoli- an additional cost to the Company. The Com-and regulations, and legal proceedings com-dated Balance Sheets at Decmber 31, 1992, pany anticipates tliat the costs Incumxl to menced by governmental bodies and others, to investigate and initiate remediation, as comply with the 1990 Amendments will be the Company may also incur costs from the necessary, at the known gas manufacturing recoverable through rates based on previous disposal of hazardous substances produced sites. The Company expects to recover such rate recovery of required environmental costs.
during the Company's operations or those of expenditures in rates, as the Company has The 1990 Amendments require the EPA to its predecmors. The Company has been noti-previously been allowel by the PSC to recover allocate annual emissions allowances to each lied by the U.S. Environmental Protection such costs in rates. of the Company's coal.flred generating sta-Agency (EPA) and the New York State Depart-The Clean Air Act Amendments of 1990 tions based on statutory emissions limits. An ment of Fnvironmental Conservation that the (1990 Amendments) w'll result in significant emissions allowance represents an authoriza-Company is among the potentially responsible future expenditures for the reduction of sulfur tion to emit, during or after a specified parties who may be liable to pay for costs dioxide, nitrogen oxides, and possibly toxic calendar )ear, one ton of sulfur dioxide.
incurred to remediate certain hazardous sub-emissions at several of the Company's coal- During Phase I, the Company estimates that stances at 9 waste sites, not including the fired generating stations. Under the 1990 it will have allowances in excess of the Company's inactive gas manufacturing sites Amendments, the Company must reduce its affected coal-fired generating stations'ctual which are discussed below. With respect to the annual sulfur dioxide emissions by 4gà from emissions. The Company is considering var-9 sites, I site is included on the Federal approximately 138,000 tons in 1989 to 71,000 ious methods of using, banking, or selling National Priorities List, I site is unlisted but tons by 2000. The Company estimates that these excess emissions allowances. During is the subject of an EPA administrative order, over a 25->ear period the cost to comply with Phase H, the Company estimates that the and 7 sites are included in the New York the sulfur dioxide and nitrogen oxide limita- annual tons emitted by its coal-fired State Registry of Inactive Hazardous Waste tions specified in the 1990 Amendments is generating stations will equal its annual Sites (New York State Registry). Any liability approximately $ 252 million (on a present emissions allowances.
may be joint and several for certain of these In addition to the annual emissions value basis) for all capital and operating and sites. The ultimate cost to remediate these maintenance expenses, of which $ 17.3 million allowances allocated to the Company by the sites will be dependent on such factom as the has been incurred to date. This cost includes EPA, the Company may obtain extension
- 9. COMMITMENTS AND CONTINGENCIES (Continued) nu allowances that the EPA will issue to In December 1992, the Company entered tion provisions. lite Company's share of the companies electing to build scrubbers in into an agreement with Kamine/Besicorp cost of coal purchased under these agree-Phase I such as the FGD sistern at Milliken. Coming LP., Kamine South Coming Cogen ments is expected to aggregate $ 55 million Due to the uncertainty of how many exten- Co., Inc., and fata South Coming, Inc. to for 1993.
sion mene allowances will be demanded, the terminate the power purchase agreement for In add,'tion, the Company has a long-term extent to which the demand may exceed the the 79 mw South Coming cogeneration proj- contract for the purchase of coal for the Kint-supply, and the method of allocating exten- ect. The termination agreement will save igh Generating Station. The contract, which sion reserve allowances, the Company entered customers an estimated $ 300 million over 25 expires in 1997, supplies the annual coal into a pooling agreement with other utilities years. The Company plans to petition the PSC requirements of the station. One-third of the which are eligible to receive some of the in early 1993 to recover $ 34 million in termi- tonnage price is renegotiated annually to extension reserve allowances. This agreement nation costs in rates. Terminating these reflect market conditions. The delivered cost pmvides assurance that the Company agreements is part of a continuing effort by of coal purchased under this agreement is will receive some of the extension reserve the Company to minimize future rate expected to be $ 56 million for 1993.
allowances in the event that demand increases associated with uneconomical power Federal Energy Regulatory exceeds supply. purchases from NUGs. Commission (FERCI Proceeding Long-Term Power Purchase As a nuit of the PSC's competitive bid-In August 1991 and October 1992, the Contracts ding program, the Company is contracting for FERC issued orders tvhich revised its generic The Company has on line and under con- 25 mw in conservation projects to be avail-policy related to filing requirements for tract 347 megawatts (mw) of NUG power. In able by November 1994. In accordance w'th a contracts determined to be subject to its addition, another 257 mw of NUG power is PSC ruling issued in October 1992, the Com-jurisdiction under the Federal Power Act.
under construction. The Company is required pany will conduct an auction for an Under the revised policy, FERC may require a to make payments under these contracts only additional 10 mw of conservation projects.
utility to refund certain revenues collected for the power it recess. During 1992, 1991, The timing of the auction has not yet been under late-filed contracts.
1990 the Company purchased approx- determined, but the Company does not expect In December 1992, FERC issued a notice ely $ 71 million, $ 30 million, and that those conservation projects will be avail-requesting comments from interested parties million, respectively, of NUG power. The able before 1995. The Company expects to relating to its filing requirements for con-Company estimates that it will purchase recover the costs associated with these con-tracts. The notice solicited comments on approximately $ 151 million, $ 251 million, tracts from its customers. Tlie Company will whether the obligation to file jurisdictional and $ 287 million of NUG power for the pars utilize various methods, including competitive agreements should extend to certain temii-1993, 1994, and 1995, respectively. The bidding, to minimize the economic impacts nated agieements as well as existing requirement to purchase NUG power is on customers of adding new resources to its agreements. The Company and many other expected to be a major contributor to rate sistern, while maintaining the Company's utilities filel comments in January 1993 chal-increases over the next 3 pars, and is current Iml of system reliability.
lenging the filing requirements and the expected to increase rates by approximately appropriateness of the refund obligations.
Coal Purchasing Contracts 8% during this time period. The Company continues to review its The Company has long-term contracts with In June 1992, the Company enteiel into compliance with FERC contract filing nonaffiliatel mining companies for the pur-an agreement with Indeck Energy Services of requirements. In October 1992, the Company chase of coal for the jointly-owned Homer Kirhvood, Inc., Indeck Energy Services, Inc., determined that it may be required to file at City Generating Station. The contracts, which and Indeck Kir4md Limited Partnership to least four additional contracts with FERC. The expire between 1995 and the end of the terminate the power purchase agreement for Company is unable to predict what actions expectel service life of the generating station, the 55 mw Indeck-Kirkwmd project. The ter- FERC may take as a result of its notice and require the purchase of either lixed or mination agreement will save ratepaprs an, minimum amounts of the station's coal is unable to estimate the amount and timing estimated $ 350 million over 20 pars. In Jan- of refunds, if any, that may be required.
requirements. The price of the coal under one uary 1993, the PSC approved full recovery Therefore, the Company cannot predict the of these contracts is based on recovery of pro-of the $ 11.5 million in termination costs ultimate disposition of this matter, but duction costs plus incentive. The remaining in rates. belie@5 that it will not have a material contracts are based on fixed price plus escala-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 Natural Natural Natural Electric Gas Electric Gas Electric Gas tThousands)
Operating Revenues $ 1,451,525 $ 240,164 $ g67,936 $ 187,879 $ 1+34,509 $ 162,271 Fspenses $ 1,146,619 $ 221,307 $ 1,056,969 $ 177,75I $ 1,021,669 $ 147,278 Income $ 304,906 $ 18,857 $ 310,967 $ 10,128 $ 312,840 $ 14,993 Depreciation and $ 150,549 $ 8,428 $ 145,700 $ 6,68o $ i42,286 $ 5373 amortization'onstruction expenditures $ 210,185 $ 35,433 $ 210,127 $ 35,756 $ 187,66o $ 23,065 Identifiable assets" $ 4,49o,436 $ 373,269 $ 4,42o,i66 $ 33o,7S4 $ 4,355,218 $ 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 of cash 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 $ 81,640 $ 76,s89 $ 73,495 Franchise and gross receipts 92,153 76,721 62,849 Payroll 17,096 is,467 14,179 Miscellaneous 10,052 9,408 8,247 Tolal OCker Ta.dies $ 200,941 $ 178 185 $ 158,770
41
- 12. QUARTERLY FINANCIAL NFORMATION (UNAUDITED)
M h31 June 30 Sept.30 Dec.31 tThousends, Except Per Share Amounts) 1992 Operating revenues $ 489,847 $ 401,934 $ 367,833 $ 432,075 Operating income $ 111,373 $ 82,755 $ 60,109 $ 69,52G Net income $ 76,4i6 $ 46,772 $ 2G,581 $ 34)199 Flemings for common stock $ 71,iG7 $ 4i,488 $ 21,320 $ 28,998 Fzminy per share $ 1.10 $ .Go $ .42 Dividends per share $ .53 $ .53 $ .54 $ 54 Average shares outstanding 64,682 68,800 69,o63 69,318 Common stock price'igh
$ 29.G3 $ 29.38 $ 32 $ 32.75 IBw $ 26.i3 $ 26.75 $ 29.25 $ 30.38 1997 Operating reunues $ 443,5sl $ 373,362 $ 349,6z6 $ 3s9,246 Operating income $ 105,695 $ 81,992 $ 66,oos $ 67,4oo Nel income $ 73,208(1) $ 43,087 $ 29,374 $ 22,974(2)
Earnings for common stock $ 68,909 $ 37,722 $ 23,997 $'17,685 Faminy per share $ 1.iO $ .60 $ .38 $ .28 Dividends per share $ .52 $ .52 $ .53 $ .53 Average shares outstanding 62,54z 62,775 63,oz4 63,273 Common stock price'igh
$ z6.75 $ 27 $ 27.63 $ 29.63 IA)w $ 2438 $ 24 $ 24.63 $ 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 Dividends on common stock cannot be paid outstanding preferred stock have been paid, or unless sinking fund requirements of the pre-declared, and funds set apart for their pay- ferred stock are met. The Company has not ment, the common stock is entitled to cash been restricted in the payment of dividends diyidends as may be declared by the Board of on common stock by these provisions. The Directors out of retained eaminy accumu- retained earnings balances of $ 327,040 and lated since December 31, 1946. Common $ 308,688 million as of December 31, 1992 Stock dividends are limited if Common Stock and 1991, respectiwly, have been accumu-Equity (43.7X at December 31, 1992) falls lated since December 31, 1946.
bellv 25% of total capitalization, as defined in the Company's Certificate of Incorporation.
42 REPORT OF MANAGEMENT REPORT OF INDEPENDENT ACCOUNTANTS The Company's management is responsible for the preparation, integrity, and objectivity of the consolidated flnancial statements, notes, and other information in Coopers this Annual Report. The consolidated financial statements have been prepared in accordance with generally accepted accounting 8 Lybrand principles and include estimates which are basel upon manage-To the Stockholders and Board of Directors, ment's judgment and the best available information. Other New York State Electric & Gas Corporation financial information contained in this report was prepared on a and Subsidiary basis consistent with that of the consolidated financial statements.
Ithaca, New York In recognition of its responsibility for the consolidated financial statements, management maintains a system of internal accounting We have audited the accompanying consolidated balance sheets controls which is designed to provide reasonable assurance as to of New York State Electric & Gas Corporation and Subsidiary as of the integrity and reliability of the financial statements, the protec-December 31, 1992 and 1991, and the related consolidated state-tion of assets from unauthorized use or disposition, and the ments of income, changes in common stock equity, and cash flows prevention and detection of fraudulent financial reporting. hianage-ment continually moniton its system of internal controls for for each of the three pm in the period ended December 31, 1992.
~ These financial statements are the responsibility of the Company's compliance. The Company maintains an internal audit department management. Our responsibility is to express an opinion on these which independently assesm the effectiveness of the internal con-financial statements based on our audits.
trols. In addition, the Company's independent accountants, Coopers We conducted our audits in accordance with generally accepted
& Lybrand, have considered the Company's internal control struc-auditing standmls. Those standanls require that we plan and per-ture to the extent they considered necemry in expressing an form the audit to obtain reasonable assurance about whether the opinion on the consolidated financial statements. hlanagement is financial statements are free of material misstatement. An audit responsive to the nxmmmendatfons of its internal audit department includes examining, on a test basis, evidence supporting the and Coopers & Lybrand concerning internal controls and corrective amounts and disclosures in the financial statements. An audit also measures are taken when considered appropriate. Management includes assessing the accounting principles used and significant hellene that as of December 31, 1992, the Company's system of estimates made by management, as well as evaluating the overall internal controls provicles reasonable assurance as to the integrity financial statement presentation. We believe tliat our audits provide and reliability of the consolidated financial statements.
a reasonable basis for our opinion.
The Board of Directors oversees the Company's financial report-In our opinion, the financial statements referred to above pre-ing through its Audit Committee. This Committee, which is sent fairly, in all material respects, the consolidated financial comprised entirely of outside directors, meets regularly with man-position of New York State Electric & Gas Corporation and Subsid-agement, the internal auditor, and Coopers & I.ybrand to discuss iary at December 31, 1992 and 1991, and the consolidated results auditing, internal control, and financial reporting matters. To of their operations and their cash flows for each of the three ensure their independence both the internal auditor and indepen-years in the period ended December 31, 1992, in conformity with dent accountants have free access to the Audit Committee, without generally accepted accounting principles.
management's presence.
New York, New York James A. Garrigg January 29, 1993 Cbairnran, Presidenl and Chief Eveculirv; Ogicer Sherwood J. Rafferty Vice Presidenl and yyeasurer (Cbief Financial Ogicer)
Everett A. Robinson Vice Presidenl and Conlroiier (Chief Amunling Opiner)
43 SELECTED FINANCIALDATA ousands - Except Per Share Amounts) 1992 1991 1990 1989 1988 tmg revenues $ 1,691)G89 $ 1,555,S)5 $ 1,496,780 $ 1,427,745 $ 1,340,169 income $ 183,968 $ 168,643 $ 158,013 $ 157,779* $
171,467'2.814.
Earnings per share $ 2.40 $ 2.36 $ z.48 $
2.53'2.O2 Dividends declatel and paid per share $ 2.14 $ 2.10 $ 2.06 $ 2.00 Average shares outstanding 67,972 62,906 58,678 57,)38 56,239 Book value per share of common stock ()oar end) $ 22.85 $ 22.16 $ 21.85 $ 21.29 $ 20,71 Intemt charges $ 155,388 $ 163,526 $ 173390 $ )so,o6s $ 199,730 AFDC and non<ash return $ 6,482 $ 7,54i $ 5,776 $ 6@7 $ 28,788 Depreciation and amortization $ 158,977 $ 152/80 $ 147,659 $ 148,375 $ )34,037 Other taxes $ 200,941 $ 178,185 $ 158,770 $ i46,6o5 $ )36,706 Construction expenditures $ 245)G18 $ 245,883 $ 210,725 $ 192,022 $ 228,223 Total assets $ 5,176,428 $ 4,924,s36 $ 4,737,43) $ 4,670,283 $ 4,693,277
)xnan -term obli ations, c ital leases, and redeemable refened stock $ 1,883,927 $ 1,897,465 $ 1,766,457 $ 1,799,800 $ 1,837,648
'iVet inconre and earnings per sbare for 1988 anrl 1989 indnde lbe egects of adj 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 Earnings per share: earnings for com- Price/earnings (P/E) ratio: a mea-construction (AFDC): the cost of money mon stock for a given period dividel by the surement of the market's petoeption of a to finance a project v hich is added to average number of shares outstanding for the company's youth potential (the higher the truction costs and recovered over the life period P/E ratio, the more potential the market he asset Embedded cost of long-term debt: be)i@15 there is for yore)
Allowed return on common equity: the average interest rate on long-term debt Retained earnings: the portion of the cost of common equity as determined by outstanding at the end of the >oar eaminy that is reimt5ted in the business the PSC Heat rate: a measure of generating sta- and not paid out as dividends Book value per share: common stock tion efficiency often expressed as the number Return on common equity: the rate equity divided by the number of common of Btu needed to generate one kilowatt-hour of return earned on common equity calcu-shares outstanding for the period of electricity lated by dividing earnings for common stock Btu (British thermal unit): the quan- Load factor: the average load of an by average common equity tity of heat required to raise the temperature electric or natural gas distribution s)stem Total shareholder return: the of one pound of water by one degree fahren- compared to its maximum load capability increase in the value of a shareholder's heit at sea level for a certain period of time, expressed as a iniostment including dividends received and Common equity: the value of common percentage changes in the market price per common stockholders'nvestment in a company along Market-to-book ratio: an indication share with retained eaminy of the market's perception of a stock's value Transportation gas: natural gas pur-Competitive bidding: a mandated (a ratio of over 100 indicates that the market chased directly from a supplier by an end prem by which utilities must seek bids believe the stock is ivorth more than its book user and transported, for a fee, by a local dis-for additional generation or demand-side value) tribution company such as the Company management projects Net income: earnings after all expenses Unbilled revenues: the estimated revo-Dekatherm: a measure of heating value are recognized, but before preferred dividends nues attributable to energy which has been equal to one million Btu (1,000 cubic feet of are paid delivered to the Company's customers but for natural gas (one mco equals approximately Non-utility generator (NUG): a which the metered amount has not been one dekathenn) non-traditional pomr generator that is also billed to the customers Demand-side management (DSM): known as an independent power producer or Watt: one ampere of electric current planning and implementation of pro- energy service company under one volt of pressure (one kilowatt is designed to help midential, commer- Peak load: the point of highest cus- 1,000 watts; one kilowatt-hour is one kilowatt
, and industrial electric customers tomer demand for electricity (the Company is usel for one hour, and one megawatt is consent'nergy a w'nter peaking utility; its record peak is 1,000 kilowatts or one million watts)
Earnings for common stock: eam- 2,597 megawatts) Ytetd: the return which dividends provide iny after all expenses are recognized and a shareholder calculated by dividing the cur-prefenel dividends have been paid rent annualized dividend per share by the cunent market price per share
44 FINANCIALAND OPERATING STATISTICS 1992 1991 1990 1989 1988 1987 198 tThousands, except Per Share Amounts)
OPERATING REVENUES Electric $ 1>451>525 $ 1,367,936 $ 1/34,509 $ 1,26o,668 $ 1,191,806 $ 1,136,799 $ 768,717 Natural as 240,164 187,879 162,271 161,077 148363 152.839 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 262>531 274,877 274,245 279,075 253,326 249,520 200,895 Electricity purchased 95,026 45,808 34,6i3 26,019 19,432 29,638 68,781 Natural gas purchased 12G,815 99,528 88,589 101,598 82,822 90,974 132,300 Other operating expenses 318,G80 279g64 268,829 238,804 2i3,959 195,204 125,044 Maintenance 102,500 110,131 io6,665 97,420 90,097 93,274 6o,54i Depteciation and amortixation 158,977 152,380 147,659 148,375 134,037 iio,679 53,174 Federal income taxes 102,45G 94,447 89,577 Q,4S9 81,689 110,355 53,6o6 Other taxes 200,941 178,185 158,770 146,605 136.706 128,776 82,877 TOTAL 1,3G7,926 1,234,720 1,168,947 1,102385 1,012,068 i,oos,4zo 777.218 OPERATING INCOillE 323,763 321,095 327,833 325,360 328,101 281,218 176,496 OTIIER INCOME AND DEDUCTIONS 12,03G 6.o76 (1,508) 7,474 28350 (73,876) 66,346 INCOME BEFORE INfEREST CHARGES 335,799 327,171 326325 33z.s34 356,451 207,342 24z,s4z INTEREST CHARGES Interest on long-term debt 145,822 151,649 158,209 164,573 187,304 195,264 io4,oso Other interest 9,5GG 11,877 15,181 15,495 12,426 7,057 5,186 Allowance for borrovttxi funds used durin construction (3,557) (4,998) (5,078) (5,013) (i4,746) (47,312) (11,5 INIXRESI'IIARGES-NEf 151,831 158,528 168312 175,055 184,984 155.009 97,74>
INCOilIE BEFORE CUMULATIVEEFFECT OF ACCOUNTING CHANGES 183,968 168,Q3 158,013 157,779 171,467 52333 145,095 Cumulative effect for )eats prior to 1987 of accounting change for disallow~el project costs (less applicable taxes of $ 95,434) (210,914)
Cumulative effect for )ears prior to 1987 of accounting chan e for income taxes (19,156)
NET INCOME (LOSS) 183,968 168,643 158,013 157,779 i7i,467 (177,737) 145,095 PREFERRED STOCK DIVIDENDS 20,995 20,330 12,662 12,975 13,492 13.662 22,610 EARNINGS (LOSS)
AVAILABLEFOR COibIMON STOCK 162,973 148,313 145,351 i44,so4 157,975 (191899) 122,485 COMMON STOCK DIVIDENDS 144,621 131,875 121,302 115,224 112,252 145.794 75.484 RETAINED EARNINGS INCREASE DECREASE $ 18,352 $ i6,43S $ z4,049 $ 29,580 $ 45,723 ($ 337,193) $ 47,001 Average number of shares of common stock outstanding 67,972 62,9o6 58,678 57,138 56,239 55318 36,41 Earnings (ix5s) per share $ Z.40 $ 2.36 $ 2.48 $ 2.53 $ 2,81 ($ 346) $ 3..
Dividends aid r share $ 2.14 $ 2.10 $ z.o6 $ z.oz $ z.oo $ 2.64
FINANCIALSTATISTICS 1992 1991 1990 1989 1988 1987 1982
. ANCIAL STATISTICS Return on average common stock equity. percent 10.G 10.7 11.4 11.5* 15.2 13.2'2.2'.1 Percentage of.AFDC and non~h return to total earnings 4.0 4.0 4.6 15.5 50.3 445 Mortgage bond interest-times earned 3.1 3.0 2.9 2.9 2.6 1.6 2.7 Interest charges and prefemd dividends-times earned 1.8 1.8 1.8 1.7 1.2 1.9 Book value per share of common stock ()car end) $ 22.85 $ 22.16 $ 21.85 $ 21.29 $ 20.71 $ 19.85 $ 22.39 l iarket value per share of common stock ()car end) $ 32.50 $'29.00 $ 26.00 $ 28.88 $ 22.75 $ 20.88 $ 2i.63 Dividend payout ratio (percent) 89.2 89.0 83.1 79.8 71.2 82.2** 62.5 Price earnings ratio ()car end) 13.5 12.3 10.5 11.4 8.1 6.54* 6.4 PROPERTY, PLANT AND EQUIPhIENT (INCLUDES COiVSTRUCTION WORK IN PROGRESS) tThousands)
Electric $ 4>G94)073 $ 4,537/56 $ 4,367,913 $ 4,217,920 $ 4,089,485 $ 3,885,989 $ 2,616,720 Natural gas 3G1,G30 336,199 222,125 201,942 189,580 176,019 137,788 Common 205,345 189,135 175,703 155/40 129,860 100.252 50,432 TOTAL $ 5,2G1,048 $ 5,062,690 $ 4,765,741 $ 4,575,202 $ 4,408,925 $ 4,162,260 $ 2,804,940 ACCUMULATED DEPRECIATIOiV $ 1>427>793 $ 1/09,829 $ 1,174,651 $ 1,063,630 $ 956,415 $ 855,198 $ 526,471 CAPITALIZATION(INCLUDES URRENT hIATURITIES) tThousands) x)ng-term debt $ 1>891>03G $ 1,825,918 $ 1,815,686 $ 1,801,762 $ 1,985,276 $ 2,091,678 $ 1,123,789 Preferred stock 269,050 270,700 172,350 174,000 178,650 183,320 236,075 Common stock uit 1,58G,474 1,405,147 1,364,344 1,225,184 1,174,028 1,106,518 888,594 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 52.2 54.2 56.3 59.5 61.9 50.0 Preferred stock 7.7 5.1 5 4 53 54 10.5 Common stock equity 40.1 40.7 38.3 35.2 32.7 39.5 NUMBER OF STOCKIIOLDERS Common stock G1,183 59,593 60,585 62,552 66,6S9 7o,44i 76,o73 Preferred stock 3,829 3,943 4,o6s 4,238 4 444 4,583 6,669 PAYROLL (INCLUDING PENSIONS, ETC.) (Thousands)
Charged to operations $ 181>245 $ 163,421 $ 148,007 $ 140,415 $ 132,617 $ 134,484 $ 94,219 Charged to construction and other accounts 89,463 82,455 72,761 64,890 61,808 . 54,276 51,015 TOTAL $ 270,708 $ 245,876 $ 220,768 $ 205,305 $ 194,425 $ 188,760 $'145,234 Number of em lo ees ( car end) 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 writewff of 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.
ELECTRIC SALES STATISTICS KILOWATr-HOUR(KWH) SALES 1992 1991 1990 1989 1988 1987 198 (MILLIONS)
Residential 5,472 5,297 UI9 5,233 5,148 4,9o5 4,4i2 Commercial 3,283 3,285 3,235 3,181 3,069 2,882 2,492 Industrial 3,082 3,068 3,175 3,210 3,159 3,018 2,621 Other 1,457 i,457 i,46s 1,431 1,400 1,372 1,201 TOTAL RETAIL 13,294 13.107 13,197 13,055 12.776 12,177 10,726 Other electric utilities 6,003 5,o66 4,750 4,461 3,896 4,295 1,827 TOTAL 19,297 18,173 17,947 17.516 i6,672 16,472 12,553 OPERATING REVENUES (THOUSANDS)
Residential $ 6OI,O42 $ 553,056 $ 521,688 $ 510,941 $ 507,428 $ 483,531 $ 325,124 Commercial 314,272 293,197 267,598 26i,6o6 257,707 244,4i6 163,755 Industrial 225)832 207,933 196,016 196,701 198+44 190,806 128,633 Other 133,819 124.575 116.352 114364 113,576 iio.s46 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 143,414 131,412 145,104 134,108 89,784 109,453 64,780 Unbilled menue mognitlon - net (427) 35333 42,995 Other o ratin revenues 33,573 22,430 44,756 48,948 24,967 (2,253) 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 10.98 10.44 9.81 9.76 9.86 9.86 7.37 Commercial 9.57 893 8.27 8.22 8.40 8.48 6 Industrial 7.33 6.7s 6.17 6.13 6.28 6.32 4 Other 9.18 8.55 7.93 799 8.11 8.08 6.o Total Retail 959 899 8.35 8.30 s.43 8.46 643 Other electric utilities 2.39 2.59 3.05 3.01 2.30 2.55 3.55 NUMBER OF CUSTOMERS (YEAR END)
Residential 699,387 692,922 685,898 676,590 665,296 653,398 6o4,936 Commercial 72,463 7i,463 70,802 69,230 67,4ss 65,923 59,413 Industrial 1,508 i,so6 1,498 i,465 1,437 i,4ii 1,338 Other 11,073 10,907 10,825 io,694 io,556 10,363 9,843 TOTAL 784,431 776,798 769,023 757,979 744,777 731,095 675,530 ANNUAL AVERAGE USE (IOVH)>>
Residential 7,843 7,672 7,796 7,7s6 7,791 7,569 7,306 Commercial 45,258 45,s64 45,826 46,095 45,6oo 43,787 41,895 Industrial (thousands) 2,O47 2,047 2,i42 2,200 2,226 2,134 1,956 ANiiUALAVERAGE BILL>>
Residential $ s61 $ soi $ 765 $ 76o $ 768 $ 746 $ 538 Commercial 4,333 4,093 3,791 3,791 3,829 3,713 2,753 Industrial 149,955 138714 132 265 134 81 13 777 I34 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 2,415 2,41z z,414 z,4i4 2,405 1,731 Nuclear 188 196 194 193 Hplro 70 70 68 66 67 68 38 internal Combustion 8 8 7 7 7 7 11 TOTAL GENERATING CAPABILITY 2,681 2,686 2,683 2,680 2,673 2,461 1,780 Purchased*Pomr Authority 489 488 487 487 510 768
-Other 347 110 53 9 350 less: Firm Sales 8 (115) (125)
TOTAL SYSTHhI CAPABILITY 3,509 3,284 3,223 3,061 3,058 2,970 2,898 SYSTEhI CAPABILITY (PERCENT)
Coal 69 74 75 79 81 Nuclear 5 6 6 6 6 11 1lro 2 2 2 2 2 2 TOTAL GENERATING CAPABILITY 76 83 87 83 6i Purchased.Poaer Authority 14 15 15 16 17 17 27
-Other 10 3 2 12 Less: Firm Sales (4) (4)
TOTAL SYSfEM CAPABILITY 100 PRODUCTION STATISTICS Annual load factor (percent) 74.6 68.9 69.4 64.7 63.5 6s.s 6s.i Coal burned (thousands of net tons) 6,478 6,310 6395 6,47z 6,io6 5,956 4,803 Coal heat value (Btu per lb.) 12,668 12,610 12,510 12,477 12,572 12,487 11,937 tu per kwh generated (net) 9,902 9,898 9,936 9,931 9,881 9,897 io,67o WATf-HOUR (KWH) PRODUCTION-NET (MILLIONS)
Generated:
Coal 16,709 i6,is7 16,211 16845 15,589 15,025 10,748 Nuclear 922 1,180 743 773 639 60 H dro 301 258 356 292 245 280 197 TOTAL GENERATED 17,932 17,595 17310 17,410 16,473 15365 10,945 Purchased-Pov er Authority 1,G35 i,667 i,6o7 i,667 1,743 1,911 2,104
-Other 1,250 343 347 102 45 583 663 TOTAL 20,817 19,605 i9,264 19,179 18,261 17,859 13,712 PRODUCTION EXPENSES (THOUSANDS)
Generated $ 375i209 $ 391,393 $ 391,977 $ 381,371 $ 351,963 $ 332,250 $ 248,278 Purchased-Pomr Authority 15,GG1 14,668 13,534 12,012 11,360 14,729 27,511
-NUG* 71,260 30,028 7,700 1,905 1,393 1/41 731
-Other 8,105 1,112 13379 12,102 6,679 13,568 40.539 TOTAL $ 470,235 $ 437,201 $ 426,590 $ 407,390 $ 371,395 $ 361,888 $ 317,059 COSI'HR KWH (hIILLS)
Generated 20.92 22.24 22.64 21.91 21.37 21.62 zz.68 Puxhased-Pomr Authority 9.58 8.80 8.4z 7.21 6.sz 7.71 13.08
-NUGAE 5G.SG 63.48 62.10 56.03 55.72 55.88 52.21
-Other 21.39 21.67 30.41 4o.47 26.61 18.84 5299 0 ratin nse (excludin mduction) 12.15 11.34 11.70 10.57 9.6z 979 8.39 TOTAL 34.74 33.64 33.84 31.81 29.96 30.05 31.51 ELECTRIC OPERATION AND hlAINfHNANCE HNSES (THOUSANDS) uction $ 470,235 $ 437,201 $ 426,S9o $ 407,390 $ 371,395 $ 361,888 $ 317,059 Transmission s" 31,623 3o,46z 30,118 29,239 22,196 24,3i4 13,023 Distribution 64,428 62,763 58,876 54,420 49,737 55,673 36,495 Customer accounting 31,180 28,861 26,861 23,242 21,031 20,158 i6,s68 Customer service 31,390 24845 27,625 23,426 20,527 12,047 4,457 Administrative and eneral 94,349 75,812 81,815 72,405 62,258 62,66o 44,476 TOTAL $ 723,205 $ 659444 $ 651,885 $ 610 122 $ 547 144 $ 536,740 $'432 078
'Non.utility generator
48 NATURALGAS SALES STATISTICS DHKATHERM (DTH) SALES (THOUSANDS)*
Residential 1992 24,913 1991 18,115 1990 i4,86 1989 15331 1988 14,818 1987 13,897
-i5,688 Commercial 10,796 8,054 6,532 6,9z6 7,055 6,803 8,123 Industrial 1,G89 1,788 2,023 z,i67 3,121 3,038 9,804 Other 1,959 1,917 2,151 2,071 2,242 2,499 4,3i4 TOTAL RETAIL 39,357 29,874 25,515 26,495 27,236 26,237 37,929 Trans rtation of customer-owned natural as 17,009 12,530 8,157 8,853 7,825 5,959 TOTAL 56,3GG 42,404 33,672 35,348 35,061 32,196 37,929 OPERATING REVENUES (THOUSANDS)*
Residential $ 152,325 $ 111,106 $ 94,531 $ 93,873 $ 83,115 $ 85,242 $ 83,167 Commercial 59,939 43,969 37,852 38,726 35,680 37,620 38,192 Industrial 8)092 8,640 10,267 10,437 12,821 13,909 43,383 Other 10,762 10,243 ii,574 io,776 10,738 12,620 20,255 TOTAL RETAIL 231,118 173,958 i54,224 153,812 142354 149,391 184,997 Tmnsportation of customer-owned natural gas 11,G39 9,571 7,169 6,7zi 5,523 2,931 Unbilled revenue recognition - net (3,626) 3,770 853 Other natural as revenue 1,033 580 25 544 486 517 SUBTOTAL 13,921 8047 7,265 6,009 3,448 TOTAL OPERATING REVENUES $ 240,1G4 $ 187,879 $ 162,271 $ 161,077 $ 148863 $ 152.839 $ 184,997 OPERATING REVENUES PER DTII Residential $ 6.11 $ 6.13 $ 6.38 $ 6.iz $ 5.61 $ 6.13 $ 5.30 Commercial 5.55 5.46 5.79 5.59 5.o6 5.53 4.7o Industrial 4.79 4.83 5.08 4.8z 4.ii 4.58 443 Other 5.49 H4 5.38 5.20 4.79 5.05 Total Retail 5.87 5.82 6.o4 5.83 5.24 5.71 Transportation 0.GS o.76 0.88 o.76 0.71 0.49 NUMBER OF CUSTOMERS (YEAR END)>>
Residential with house heating 182,795 178,625 117,429 II4,497 111,543 108,515 103,033 Residential without house heating 13,181 12,906 8860 8,079 8+0 8,220 9,057 Commercial vdth space heating 23,165 23,023 i6,843 i6,6z6 16,419 16,265 14,980 Commercial vdthout space heating 2,282 2,24i i,548 i,476 i,444 i,4o8 1,383 Industrial 390 334 343 343 386 Transportation of customer-owned natural gas 389 342 277 228 zi4 149 Other 1,657 1,557 1,246 i,154 1,133 1,202 1,141 TOTAL 223,859 219,080 146,037 142,4o3 139,436 136,159 129,980 ANNUALAVERAGE USH (DTH)>>>>
Residential 129 105 119 126 125 120 14o Commercial 42S 345 358 386 398 387 5i4 Industrial 4,387 4,781 6,0o3 6,246 8,694 7,6i4 25,531 ANNUALAVERAGE BILL>>>>
Residential $ 786 $ 641 $ 763 $ 774 $ 703 $ 738 $ 742 Commercial 2)377 1,882 2,076 2,158 2,012 2,139 2,417 Industrial 21)018 23,102 3o,466 30,079 35,713 34,86o 112,977 COST OF NATURAL GAS PURCHASED Amount (thousands) $ 12G)815 $ 99,528 $ 88,589 $ 101,598 $ 82,822 $ 90,974 $ 132/00 Per dth $ 3.22 $ 3.30 $ 3.64 $ 3.57 $ 3.02 $ 3.43 $ 3.49 NATURAL GAS OPERATION AND MAIPfKNANCE EXPENSES (THOUSANDS)
Production $ 126,984 $ io1,458 $ 88,901 $ 102,014 $ 83,155 $ 91,369 $ 132 19)938 (
Transmission and distribution 18,491 13,982 13,247 11,712 11,570 Customer accounting 9)233 8,046 5,765 4,99o 4,516 4,656 3,-
Customer service 8,152 6,533 5,942 3,972 3,352 2/74 I,I41 Administrative and eneral 18,040 15,735 6,464 8,571 9,758 11,901 8,66i TOTAL $ 182,347 150263 121054 127 1124 3 $ 121.870 155483
'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.
VESTOR INFORMATION Binghamton Executive Offices Ithaca Executive Offices General Counsel Independent Accountants 4500 Vestal Parkway East Ithaca-Dryden Road Huber Lawrence K Abell Coopers 8c Lybrand P.O. Box 3607 P.O. Box 3287 605 Third Avenue 1301 Avenue of the Americas Binghamton, NY 13902-3607 Ithaca, NY 14852-3287 New York, NY 10158 New York, NY 10019 (607) 729-2551 (607) 3474131 To present certificates for transfer For stock transfer instructions, write to: write to:
Chemical Bank Chemical Bank Attention: Stock Transfer Administration Attention: Legal Transfer P.O. Box 24935 450 West 33rd Street Church Street Station New York, NY 10001 New York, NY 10249 (Certified or registered mail is recommended.)
ase contact NYSEG shareholder services with Securities Listed on the New York Stock Exchange stions regarding: a Common Stock dividend payments or lost dividend checks D 3.75% Preferred Stock a direct deposit of dividends D 8.89Y0 Preferred Stock a our dividend reinvestment and stock purchase plan a 8.480/0 Preferred Stock ($ 25 par value) a replacement of lost certificates a Adjustable Rate Preferred Stock ($ 25 par value) a a change of address a 7 5/80/o First Mortgage Bonds (Due 2001) a report requests a 8 5/80/o First Mortgage Bonds (Due 2007) a our annual meeting of stockholders Trading Symbol We are available between 8 a.m. and 4:30 p.m. The trading symbol for our common stock which is listed (Eastern Time) on regular business days at
'I-800-225-5643. Or you may write to: on the New York Stock Exchange is NGE.
New York State Electric 8c Gas Corporation Attention: Shareholder Services P.O. Box 3200 Annual Meeting Ithaca, NY 14852-3200 Friday, May 14, 1993 at 11 a.m.
Ithaca Executive Offices You may also obtain a free copy of Ithaca-Dryden Road Form 10-K, which is filed each year with Dryden, NY the Securities and Exchange Commission, by contacting shareholder services at Formal notice of the meeting, a proxy the telephone number or address above. statement and form of proxy will be mailed to stockholders in early April.
BULK New York State Electric'& Gas Corporation U
Ithaca-Dryden Road POSTA P
P.O. Box 3287 ew York ate Ithaca, NY 14852-3287 & Gas Corporation -'
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New Tork Ct Territory served by Long Island Lighting Company The Long Island Lighting Company's 6,500 employees provide electric and gas service to more than 1 million customers in Nassau and Suffolk Counties 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.
Meeting the challenge...
l 992 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 of coastline offer some of tho 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, LILCO continued 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 LILCO to 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, LILCO has been examining its business to prepare the Company for success in the 1990s and beyond. A blueprint for the 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 Company does business. Decreases in defense t an just moving boxes around on an organiza- spending and a nationwide recession have slowed tional chart, we are seeking to fundamentally local economic growth, but there are pockets of change the way we do business. growth in Long Island's emerging technology industries. LILCO, along with Long Island's Business Units government and business communities, introduced The reorganization divides the Company's an economic development campaign to help activities into three business units Electric, boost the region's economy.
Natural Gas and Energy Conservation allowing In addition to targeting new and growing each to concentrate on the energy service they businesses, the campaign also promotes higher are providing. In July, 1992, the Electric Business education and tourism on Long Island. These Unit was formed, with the Natural Gas and efforts have yielded significant results, with Conservation Units scheduled to be formed by LILCO economic development specialists helping the end of 1993. more than 175 businesses start up, expand or relocate to Long Island.
torner Service In addition to dividing the Company into Meeting the Challenge key competitive units, LILCO's reorganization Facing both a changing industry and business incorporates two vital customer service elements. environment, LILCO has worked throughout Later this year, we will be opening a "one-call 1992 to position itself to meet the challenges of a center" in Melville, providing a single point of more competitive marketplace. We seek a future contact for customers conducting any type of in which LILCO becomes a model of service business with LILCO. We will also be regionalizing excellence and efficiency.
the electric and gas businesses into four On behalf of LILCO's Board of Directors geographic locations to bring these services and Officers, I would like to thank you for your closer to the customer. Both steps are designed continued confidence in our leadership.
to improve LILCO's ability to respond to customer needs more efficiently and effectively. Sincerely, rowing Long Island In 1992, we not only developed a blueprint William J. Catacosinos for LILCO's future, we helped map out Long Chairman and Chief Executive Officer Island's economic future. As the utility industry changes, so does the environment in which our Oe
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 utility industry.
In 1992, the Long Island Lighting Company examined and discarded old utility paradigms 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 Meeting the challenge...
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-utility generation 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 of current U.S. electric capacity.
In addition, non-utility generators 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.
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 LILCO was 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-million dollar 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.
Meeting the challenge...
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. By taking an integrated approach to business planning, the Company is
lacrosse is one of the many competitive sports thol have a iong history on long Island.
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 Meeting the challenge...
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.
played an equally vital role. The passage of the Clean AirAct Amendments and the National Energy Security Act have brought environmental concerns to the forefront of utility planning.
Air quality 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, LILCO was active in pursuing both alternative fuel options. With natural gas vehicles Meeting the challenge...
(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 Old Bethpage Village ft Restoration is a living museum ol Long 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.
Involvement and Innovation In 1992, LILCO encouraged economic growth by spearheading an economic development campaign depicting Long Island's innovative business atmosphere, Meeting the challenge...
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 LILCO service.
In February, 1992, LILCO awarded more than
$ 3.5 million in 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 million worth of work that will be performed locally.
Direction for the Future Change, particularly change of ingrained beliefs and behaviors, takes time. The progress made in Meeting the challenge...
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 utility model.
LILCO will remain focused on providing unparalleled service to all Long Islanders. In 1993, that will include the completion of our "one-call center," a single point of contact for all LILCO customer transactions.
And we will continue 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 of educational opportunities with 19 colleges and universities.
Financial Review Overview e The refinancing of a significant amount of the Company's securities as a result of very favorable The year 1992 represents the fourth consecutive year of long-term interest rates.
continued improvement in the Company's financial health. The refinancing of approximately $ 1.5 billion of The financial viability of the Company had been jeopardized higher-cost securities which significantly lowered the in the past by the controversy concerning the Shoreham Company's cost of debt and preferred stock. These Nuclear Power Station (Shoreham) and the federal 1992 refinancings will result in more than $ 17 million Racketeer Influenced and Corrupt Organizations Act (RICO in annual cash savings through lower interest and Act) litigation. The 1989 Settlement between the Company preferred stock dividend expenses.
and the State of New York (State) was designed to eliminate Since the 1989 Settlement became effective, the the controversy over Shoreham by providing for, among Company's aggressive refinancing program has other matters, the transfer of Shoreham to an agency of the resulted in annual cash savings of approximately State and reciting the intention to return the Company to $ 70 million through lower interest and preferred stock investment grade financial condition by providing rate dividend expenses.
increases in each year from 1989 through 1998. The The elimination of all of the Company's outstanding Company's financial recovery began in 1989 following the bank debt of approximately $ 446 million.
1989 Settlement and a class action settlement (Class The conversion of $ 400 million of variable rate Settlement) entered into between the Company and its tax-exempt securities to a 30-year fixed annual ratepayers to resolve the RICO Act litigation. rate of 7.15%.
The improvement in the Company's financial condition is ~ The issuance of $ 200 million of low-cost tax-exempt evidenced, in part, by the elevation of the Company's First securities resulting in substantial savings for the Mortgage Bonds and General and Refunding Bonds (G8 R Company's ratepayers since these securities carry Bonds) to one notch above "minimum investment grade" significantly lower interest rates than taxable bonds.
and the elevation of the Company's unsecured debt and 4 The addition of approximately 10,000 new gas space preferred stock to "minimum investment grade." heating customers for the third consecutive year.,
Other significant events in 1992 included: ~ An increase in gas rates of 7.1% effective Decembe
~ The transfer of ownership of Shoreham to an agency 1, 1992.
of the State on February 29, 1992.
4 Approval, by the New York State Public Service Investment Rating Commission (PSC), of the second annual electric rate increase of 4.1% effective December 1, 1992, under The Company's securities are rated by Moody's Investors the three-year electric rate plan approved in 1991. Service, Inc. (Moody's), Standard and Poor's Corporation This three-year rate plan follows the receipt of electric (S8 P), Fitch Investors Service, Inc. (Fitch) and Duff and rate increases in each of the years 1989 through 1991. Phelps (D8 P).
~ The reinstatement of the Company's Automatic Since 1989, the rating agencies have significantly upgraded Dividend Reinvestment Plan beginning with the their ratings on the Company's First Mortgage Bonds and October 1, 1992 common stock dividend payment. G8cR Bonds to one level above "minimum investment grade"
~ An increase in the Company's common stock quarterly and the Company's debentures and preferred stock to dividend from 42'/~ cents per quarter to 43'/2 cents per "minimum investment grade."
quarter. The chart below indicates the current ratings for each of the Earnings for common stock in 1992 were $ 2.14 per Company's principal securities and the minimum investment common share compared to $ 2.15 per common share grade ratings used by each agency.
in 1991. The 1992 results reflect a significant improve- Moody's S8P Fitch D&P ment in the Company's gas business earnings. The Company's electric business earnings were lower in First Mortgage Bonds Baa2 BBB BBB BBB 1992 as a result of the lower allowed rate of return G8 R Bonds Baa2 BBB BBB BBB which is prescribed by the PSC. Debentures Baa3 BBB- BBB- BBB-Preferred Stock baa3 BBB- BBB- BB+
~ The common stock traded on average at a twenty-one year high. Minimum Investment Grade Baa3 BBB- BBB- BB
e Matters moderation plan provided for in the RMA. The RMC has provided the Company with a substantial amount of non-ectric Pursuant to the 1989 Settlement, the Company cash earnings since the 1989 Settlement became effective.
received electric rate increases contemplated by the Rate The RMA was designed to provide rate increases sufficient to Moderation Agreement (RMA), a constituent document of the 1989 Settlement discussed below, for each of the three recover the RMC within a ten-year period. The RMC balance has increased as the difference between revenues resulting rate years in the period ended November 30, 1991. In response to the Company's rate filing in December 1990, the from the implementation of the rate moderation plan PSC approved the Long Island Lighting Company Rate-provided for in the RMA and revenue requirements under conventional ratemaking, together with a carrying charge making and Performance Plan (LRPP) in November 1991, which provides for annual electric rate increases of 4.15%, equal to the allowed rate of return on rate base, has been 4.1% and 4.0% effective December 1, 1991, 1992 and deferred. The RMC balance will subsequently decrease and is expected to be fully amortized by November 30, 1999, as 1993, respectively. Effective December 1, 1992, the deferred revenue requirements are recovered.
Company began receiving the second of the three annual electric rate increases provided for within the LRPP. The LRPP The LRPP was designed to be consistent with the RMA's long-provides for an allowed return on common equity from term goals including: (i) the recovery of the BFC; (ii) the electric operations of 11.6%. recovery of the RMC in approximately ten years; (iii) the One principal objective of the LRPP is to reassign risk so that Company's return to investment grade ffnancial condition the Company assumes the responsibility for risks within the and (iv) the Company's receipt of adequate and timely rate control of management, whereas risks largely beyond the relief. Although the LRPP provides for slightly lower annual control of management would be assumed by the ratepayers. electric rote increases than originally anticipated in the 1989 One of the major components of the LRPP provides for a Settlement, the Company believes that it will still fully recover revenue reconciliation mechanism that reduces the impact on the RMC within a ten-year period principally as a result of earnings of experiencing electric sales that are above or below changes in the original assumptions. The revenues assumed the LRPP forecast by providing a fixed annual net margin by the LRPP are adequate to provide the Company with I (defined as sales revenues, net of fuel and gross receipts recovery of its revenue requirements under conventional ratemaking and recovery of the RMC balance over the
) that the Company will receive over the three rate years er the LRPP. Another component of the LRPP allows the remainder of the ten-year period. However, actual revenues Company to earn for each rate year up to 60 additional may differ from those assumed for this period. The original basis points, or forfeit up to 38 basis points, of the allowed assumptions underlying the RMA included projections of return on common equity as a result of its performance within future revenues, operating expenses and required rates of certain incentive and/or penalty programs. The LRPP also return. Since then, the Company has experienced interest contains a mechanism whereby earnings in excess of the rates, operations and maintenance expenses, non-Shoreham allowed rate of return on common equity, excluding the property taxes and fuel expenses that are lower than those impacts of the various incentive and/or penalty programs, originally anticipated. As a result, amounts deferred in the are shared equally between ratepayers and shareowners. RMC have been less than expected.
For a further discussion of the 1989 Settlement and Rate In conjunction with the 1989 Settlement, the PSC authorized Matters, see Notes 2 and 3 of Notes to Financial Statements.
the recognition of a regulatory asset known as the Financial Resource Asset (FRA). The FRA consists of two components, Gas In November 1992, the PSC approved a gas rate the Base Financial Component (BFC) and the Rate Moderation increase of 7.1%, or $ 35.7 million annually, effective Component (RMC). The RMA provides for the full recovery of December 1, 1992, with an allowed return on common the FRA. The RMA, by its terms, specifies that the FRA is equity from gas operations of 11.0%. In November 1991, being created to provide the Company adequate financial the Company received a gas rate increase of 4.1% effective indicia for the period 1989 through 1999 and to restore the December 1, 1991.
Company's debt securities to investment grade levels as determined by independent rating agencies. On December 31, 1992, the Company filed an application with the PSC seeking gas rate relief for the three rate years The BFC, as initiallyestablished, represents the present value beginning December 1, 1993. The Company has requested of the future net-after-tax cash flows which the RMA provided a gas rate increase of 6.7%, or $ 37.7 million in additional the Company for its financial recovery. The BFC was granted revenues to become effective for the first rate year under rate base treatment under the terms of the RMA and is this filing. The Company's filing also includes a proposed uded in the Company's revenue requirements through an methodology for determining rate increases, not to exceed tization included in rates over forty years on a straight- approximately $ 30 million annually, for the subsequent asis beginning July 1, 1989. second and third rate years. This filing reflects the Company's l The RMC reflects the difference between the Company's latest projections of capital expenditures, operations and revenue requirements under conventional ratemaking and maintenance expense< and the continued expansion of its the revenues resulting from the implementation of the rate gas business.
Results of Operations Earnings Summary results of earnings for the years 1992, 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
~
1991 and 1990 were as follows: Company's revenues included estimated consumption of gas delivered to customers, but not yet billed at month end, (In millions of dollars ond shares except earnings per share) resulting in the full accrual of all unbilled gas revenues. The 1992 1991 19900 cumulative effect of this accounting change increased 1990 earnings by nearly $ 12 million, net of tax effects. The Net Income $ 302 $ 306 $ 319 Company did not earn in excess of its allowed rate of return Earnings for Common Stock $ 238 $ 239 $ 251 for the rate year ended November 30, 1990.
Earnings per Common Share $ 2.14 $ 2.15 $ 2.26 Average Shares Outstanding 111.4 111.3 111.3 Revenues Total revenues in 1992, including revenues from recovery of fuel costs, were $ 2.6 billion, which represents an AFC 8 RMC Included increase of $ 74 million or 2.9% over 1991 revenues. Total in Net Income $ 60 $ 183 $ 214 revenues for the Company's electric and gas operations for AFC8 RMC %of Net Income 20% 60% 67% the years 1992, 1991 and 1990 were as follows:
'Excludes the effect of an accounting change for unbilled gas revenues.
(In mi%l'ons of dollars)
For all periods, net income, earnings for common stock and 1992 1991 1990 earnings per common share include non-cash allowance for Electric $ 2,195 $ 2,197 $ 2,096 funds used during construction (AFC) and the RMC. Gas 427 351 361 The earnings in the electric business were lower in 1992 when Total Revenues $ 2,622 $ 2,548 $ 2,457 compared to 1991. This lower level of earnings in the electric business was offset by the significant increase in the gas E/ectrIc In 1992, electric revenues decreased $ 2 million business earnings in 1992. when compared to 1991. Revenues in 1991 had increased The increase in the gas business earnings was the result of $ 101 million or 4.8% over 1990. The changes in the leve revenues when compared to the prior year resulted fram higher revenues and continued cost containment programs.
The higher gas revenues were due to the 1992 gas rate following factors:
increase and the Company's aggressive gas expansion (In millions of dollars) program, which has resulted in an increase in the number of
'92/'91 '91/'90 gas space heating customers.
Rate Increases $ 85 $ 114 The electric business earnings for 1992 were lower as a result Sales Volumes (74) (7) of the lower allowed rate of return of 11.6% in 1992 when Fuel Cost Recoveries (6)
(13) compared to the allowed rate of return of 12.75% in 1991.
The allowed rate of return is prescribed by the PSC. Total $ (2) $ 101 Incentives earned for electric operations provided 6 cents per Rate Increases The Company received electric rate increases share in 1992 and 12 cents per share in 1991. In addition, of 4.1% effective December 1, 1992, and 4.15% effective for the rate year ended November 30, 1992, the Company December 1, 1991. These rate increases provided $ 85 earned $ 16.2 million, net of tax effects, in excess of its million in additional revenues for 1992 when compared to allowed rate of return on common equity which, in accordance 1991. A 5.0% rate increase effective December 1, 1990, with the LRPP, was shared equally between ratepayers and provided $ 114 million in additional revenues for 1991 when shareowners. These excess earnings were generated as a compared to 1990.
result of a reduction in operations and maintenance expenses Sa(es Vo(umes The decrease in revenue from sales volumes and the effect of a decrease in capital expenditures included was primarily attributable to cooler weather experienced in in rate base.
the summer of 1992 when compared to the same period in The decrease in earnings for common stock for 1991 of 1991. The Company's current electric rate structure, discussed approximately $ 12 million, or 11 cents per share, compared above under the heading "Rate Matters," provides for a with 1990, was primarily attributable to increases in revenue reconciliation mechanism which reduces the impact non-fuel operations and maintenance expenses, operating on earnings of experiencing electric sales that are above or taxes and interest expense, partially offset by higher electric below the levels reflected in rates. As a result of lower th revenues. For the rate year ended November 30, 1991, adjudicated electric sales, the Company recorded non-c the Company earned $ 10.1 million, net of tax effects, in income whichis included in "Other Regulatory Amortizatio excess of its allowed rate of return, which was applied as a of $ 78.5 million and $ 0.4 million in 1992 and 1991, reduction to the RMC. respectively.
att Hour Sales Summary of electric kilowatt hour (kWh) Rate Increases The Company received gas rate increases for the years 1992, 1991 and 1990 were as follows: of 7.1% effective December 1, 1992, and 4.1% effective December 1, 1991. These rate increases provided $ 17 million (In millions of kWh) in additional revenues in 1992 when compared to 1991. A 1992 1991 1990 gas increase of 1.3% in January 1990 provided $ 2 million in Residential 6,788 7,023 7,022 additional revenues for 1991 when compared to 1990.
Commercial/Industrial 8,652 8,791 8,832 Sa/es Vo/umes The increase in 1992 revenues due to sales System Sale's 15,440 15,814 15,854 volumes was primarily due to customer additions and Power Pool Sales 227 598 532 conversions resulting from the Company's gas expansion Total Sales 15,667 16,412 16,386 program, aided by a colder heating season in 1992. The Company added approximately 10,000 new gas space The decrease in residential and commercial/industrial sales heating customers to its system for the third consecutive year.
in 1992 was largely due to the cooler weather experienced Summary of gas decatherm (dth) sales for the years 1992, during the summer months. Residential sales, which 1991 and 1990 were as follows:
comprised 44% of system sales, were down by 3.3% when (In thousands of dth) compared with 1991, while commercial/industrial sales, 1992 1991 1990 which accounted for 53% of system sales, declined by 1.7%.
Power pool sales fluctuate with relative costs and power pool Space Heating 48,751 41,323 41,081 system availabilities. Non-Space Heating 7,541 7,366 7,800 Total Firm 56,292 48,689 48,881 The average number of electric customers served in 1992 Interruptible 5,090 4,538 6,347 and 1991 was approximately 1,009,000 and 1,005,000, respectively. The 4,000 customer increase in 1992 is Total System 61,382 53,227 55,228 similar to the increase experienced in 1991 when Summary of average use per customer for the years 1992, compared to 1990.
1991 and 1990 was as follows:
ary of average use per customer for the years 1992, (In dth per customer) and 1990 was as follows:s 1992 1991 1990 (In kWh per customer)
Space Heating 188 165 171 1992 1991 1990 Non-Space Heating 42 40 41 Residential 7,518 7,812 7,844 Interruptible 9,568 9,614 15,480 Commercial/Industrial 80,346 81,797 82,304 System 140 123 129 System 15,297 15,731 15,832 Fuel Cost Recoveries Recoveries of fuel expenses in 1992 Fuel Cost Recoveries Total electric fuel cost recoveries for revenues increased by $ 9 million compared with 1991, 1992 were down $ 13 million compared with 1991, primarily primarily due to higher sales volumes. In 1991, fuel recovery as a result of lower sales volumes, partially offset by an revenues had decreased by $ 5 million, primarily due to increase in the average cost of fuel. In 1991, fuel cost lower sales volumes.
recoveries decreased by $ 6 million compared with 1990, principally due to a lower average cost of fuel. Fuel and Purchased Power Expenses for fuel and purchased power for electric operations and for gas Gas In 1992, gas revenues increased by $ 76 million, or delivered to customers decreased by $ 27 million in 1992 21.7%, when compared to 1991. Revenues in 1991 compared with 1991, and decreased by $ 18 million in 1991 decreased by $ 10 million, or 2.8%, when compared to 1990. compared with 1990. Summary of fuel and purchased power The changes in the level of revenues when compared to the expenses for the years 1992, 1991, and 1990 were as prior year resulted from the following factors: follows:
(In thousands of dollars) (In mi%I'ons of dollars)
'92/'91 '91/'90 1992 1991 1990 Rate Increases $ 17 $ Electric Fuel $ 279 $ 381 $ 441
.s Volumes 50 (7) Purchased Power 281 213 170 ost Recoveries (5) Gas 182 175 176
$ 76 $ (10) Total $ 742 $ 769 $ 787
The Company has substantially reduced its dependence on For the years 1992, 1991 and 1990, the Company reco~
foreign oil for electric generation, substituting gas and non-cash charges to income of approximately $ 101 mill~i purchased power whenever economical. Summary of electric reflecting the continuing amortization of the BFC, which is fuel and purchased power mix for the years 1992, 1991 and afforded rate base treatment under the RMA. For a further 1990 were as follows: discussion of the BFC and 1989 Settlement, see Notes 1 and 2 of Notes to Financial Statements.
(Percent of system energy requirements) l992 199I t990 Uquidity Oil 37% 50% 56%
18 20 Cash and Revolving Credit At December 31, 1992, Gas 19 the Company's cash and cash equivalents amounted to Purchased Power 38 25 20 approximately $ 309 million, compared to $ 298 million at Nuclear Fuel 6 7 4 December 31, 1991.
Total 100% 100% 100%
In addition, the Company has approximately $ 251 million available under its revolving line of credit through October 1, Operations and Maintenance Expenses Total 1993, provided by its 1989 Revolving Credit Agreement operations and maintenance expenses, excluding fuel and (1989 RCA). At December 31, 1992, no amounts were purchased power, for 1992, 1991 and 1990 were $ 498 outstanding under the 1989 RCA. For a further discussion of million, $ 523 million and $ 476 million, respectively. The $ 25 the 1989 RCA, see Note 7 of Notes to Financial Statements.
million, or 4.8%, decrease in 1992 was primarily due to lower electric operations expenses which resulted from the Financing Programs During 1992, the Company issued Company's aggressive expense reduction and cost $ 211 million aggregate principal amount of GER Bonds, containment programs. The Company also instituted and has approximately $ 1.3 billion aggregate principal amount of pursued more aggressive collection practices as evidenced debentures and $ 420 million of preferred stock. The net by a lower provision for doubtful accounts in 1992. Partially proceeds from the sale of these securities were used to offsetting these decreases were certain higher expenses, eliminate all bank debt, redeem higher-cost debt and including expenses related to the Company's share in the preferred stock and to pay any related redemption cost Nine Mile Point Nuclear Power Station, Unit 2 (NMP2) and The details respecting the Company's $ 2.3 billion of employee related benefits. refinancing activities in 1992 were as follows:
The $ 47 million, or 9.9%, increase in 1991 was primarily Securities Issued Securities Redeemed attributable to increases in employee wages and benefits,
$ 56 million G&R Bonds $ 53 million G8 R Bonds electric production and gas distribution costs, and provision 7.85% Series Due 1999 9.75% Series Due 1999 for doubtful accounts.
$ 75 million G8 R Bonds $ 70 million G&R Bonds 8.50% Series Due 2006 9.625% Series Due 2006 Other Items In 1992, federal income taxes were 80 million G8 R Bonds $ 75 million G8 R Bonds approximately $ 161 million, compared with $ 182 million 7.90% Series Due 2008 9.20% Series Due 2008 in 1991. In 1990, these taxes amounted to $ 183 million, $ 319 million Debentures
$ 397 million Debentures excluding the effect of the accounting change for unbilled 7.30% Series Due 1999 10.875% Series Due 1999 gas revenues. $ 420 million Debentures $ 346 million Debentures Interest expenses for 1992, 1991 and 1990 were $ 512 8.90% Series Due 2019 11.375% Series Due 2019 million, $ 524 million and $ 508 million, respectively. The $ 25 million First Mortgage Bonds decrease in 1992 was the result of lower interest rates, 9.125% Series Due 2000 primarily achieved through refinancings. $ 451 million Debentures $ 446 million under the 1989 9% Series Due 2002 Term Loan Agreement In 1992, the Company recorded non-cash charges to $ 363 million Preferred Stock $ 320 million Preferred Stock income of approximately $ 23 million which represents 7.95% Series AA 10.60% Series Y the increase in the present value of the Class Settlement $ 57 million Preferred Stock $ 55 million Preferred Stock liability. These charges amounted to $ 25 million and 7.66% Series CC 9.80% Series S '.
$ 23 million for 1991 and 1990, respectively. For a $ 400 million tax-exempt $ 400 million tax-exempt securities further discussion of the Class Settlement see Note 4 securities, 7.15%, 30-year vanable weekly rate of Notes to Financial Statements. Axed annual rate For the years 1992, 1991 and 1990, the Company recorded In addition to the above refinancings, the Company utili'200 non-cash credits to income of $ 73 million, $ 269 million and million of tax-exempt securities in 1992. The net
$ 313 million, respectively, reflecting the RMC and related proceeds from the sale of these tax-exempt securities were carrying charges. For a further discussion of the RMC and used to reimburse the Company's treasury for previously RMA, see Notes 2 and 3 of Notes to Financial Statements. incurred capital expenditures.
ddition to the conversion of $ 400 million of tax-exempt $ 7.3 billion. This increase in capitalization primarily reflects rities in June 1992, the Company converted $ 100 million an increase in long-term debt associated with the Company's of tax-exempt securities in January 1993 from a variable financing activities in 1991 and an increase in common weekly interest rate to a 30-year fixed annual rate of 6.90%. shareowners'quity comprising 1991 net income of $ 306 In January 1993, the Company issued $ 36 million principal million reduced by common and preferred stock dividends amount of Debentures, 7.30% Series Due 2000, the net of $ 245 million.
proceeds of which will be used in February 1993 to redeem, At December 31, 1992 and 1991, the components of the at the applicable redemption price, $ 35 million principal Company's capitalization ratios were as follows:
amount of First Mortgage Bonds, 8.20% Series R Due 1999.
1992 1991 In February 1993, the Company sold $ 142 million principal amount of Debentures, 7.50% Series Due 2007, the net Long-Term Debt 64.7% 63.9%
proceeds of which will be used in March 1993 to redeem, at Preferred Stock 8.8 8.8 the applicable redemption prices, the following series of G8 R Common Shareowners' ui 26.5 27.3 Bonds: $ 50 million, 8/e% Series Due 2006 and $ 85 million, Total 100.0% 100.0%
8/e% Series Due 2007.
Capital Requirements and Capital provided The Company has been able to utilize $ 100 million of tax-exempt securities in each of the years 1989 through 1992. In Capital requirements and capital provided for 1992 and 1990, the Company was able to utilize an additional $ 100 1991 were as follows:
In millions of dollars million of tax-exempt securities (1991 Series A Electric 1992 1991 Facilities Revenue Bonds) allocated for its benefit.
Capital Requirements During the period January 1, 1993 to December 31, 1995, the Company has estimated that it will be required to seek Construction external financing of approximately $ 1.4 billion, principally Electric $ 137 $
to refund maturing debt and secondarily to meet its operating Gas 104 90 d capital requirements. In addition, the Company intends Common 27 18 ontinue to access the capital markets to refund higher-cost Total Construction 268 235 t and preferred stock, when market conditions permit. Refundings and Dividends The Company currently has debt and equity securities regis- Long-term debt 1,344 1,129 tered with the Securities and Exchange Commission on shelf Preferred stock 389 71 registration statements. The sale of $ 615 million of these secur- Preferred stock dividends 70 66 ities will be used to refund the following securities maturing in Common stock dividends 191 173 1993: $ 40 million of First Mortgage Bonds, 4.40% Series M Redem tion costs 159 68 Due April 1, 1993, $ 375 million of Debentures, 11 3/8% Total Refundin s and Dividends 2,153 1,507 Series Due April 1, 1993 and $ 175 million of Debentures, Shoreham ost settlement costs 228 158 11.70% Series Due November 15, 1993. The Company may Total Ca ital Re uirements $ 2,649 $ 1,900 also sell an additional $ 146 million of previously registered securities, which will be used, when market conditions permit, Capital Provided to refund higher-cost debt or preferred stock. (Increase) in cash $ (11) $ (195)
For a further discussion on the Company's capital stock and Long-term debt 1,660 1,532 Preferred stock 411 63 long-term debt, see Notes 6 and 7 of Notes to Financial Statements. Financing costs (7) (20)
Other financing activities 6 Internal cash generation Capltallzatlon from o erations 590 520 The Company's capitalization (defined as the total of long-term Total Capital Provided $ 2,649 $ 1,900 debt, preferred stock and common shareowners'quity) at For further information, see the Statement of Cash Flows.
December 31, 1992, was approximately $ 8.2 billion, as For 1993, total capital requirements (excluding common compared to $ 7.8 billion at December 31, 1991. This increase stock dividends) are estimated at $ 1.2 billion, of which in capitalization of approximately $ 420 million principally construction requirements are estimated to be $ 320 million, reflects an increase in long-term debt and preferred stock mandatory redemptions are $ 590 million, preferred stock ociated with the Company's financing activities in 1992 sinking fund requirements are $ 8 million, preferred stock an increase in common shareowners'quity comprising dividends are $ 57 million, and Shoreham post settlement 2 net income of approximately $ 302 million reduced by costs are estimated at approximately $ 189 million. The common and preferred stock dividends of $ 254 million.
Company intends to satisfy these capital requirements At December 31, 1991, capitalization increased by approxi- through external financing, as discussed above, and internal mately $ 492 million from the December 31, 1990, balance of cash generation from operations.
O
Other Matters acceptably low levels of sulfur. However, the Company expects that it will incur costs to comply with additional Electric Competition, Conservation and Supply The continuous emission monitoring (CEM) requirements and or Company is experiencing competition from cogenerators future nitrogen oxide reduction requirements that may be and other independent power producers located within the imposed under federal or state regulations. The Company Company's service territory. These facilities supply electric estimates that the cost of installing CEM and nitrogen oxide energy to existing or new industrial and commercial control equipment, which the Company will seek to recover customers and excess electricity is sold to the Company through rates, will be approximately $ 15 million and $ 100 pursuant to the purchase requirements of the Public Utility million, respectively.
Regulatory Policy Act of 1978 (PURPA). The Company has contracts with owners of these facilities which will provide for Accounting Pronouncements The Company will a total of approximately 340 megawatts (MW) of capacity adopt the provisions of Statement of Financial Accounting by 1994, which includes the New York Power Authority's Standards (SFAS) No. 106, Employers'ccounting for 136 MW Holtsville facility. The Company has also entered Postretirement Benefits Other Than Pensions, during the first into contracts for approximately 450 MW of power from quarter of 1993. SFAS No. 106 requires the Company to various projects on an energy-only basis. recognize the expected cost of providing postretirement benefits when employee services are rendered rather than The Company has implemented conservation and load on a pay-as-you-go method. The Company will record an management programs to meet Long Island's energy needs accumulated postretirement benefit obligation and in the future. In 1992, the Company met its targeted corresponding regulatory asset of approximately $ 376 reductions in its revised 1992 Electric Conservation and Load million which represents the transition obligation at Management Plan, which called for a 235 MW reduction in December 31, 1992. Additionally, as a result of adopting coincident peak demand by December 31, 1992, and SFAS No. 106, the Company's annual postretirement benefit annualized energy savings of 454 gigawatt hours, at a expense will increase by approximately $ 44 million above budgeted cost of approximately $ 45.3 million. The Company the amount previously recorded under the pay-as-you-go anticipates that the Conservation and Load Management method. This additional $ 44 million of non-cash post-Plan will continue in future years to gain further reductions in retirement benefit expense will also be accounted for as system peak and energy usage. a regulatory asset. The Company believes that the recovery of these regulatory assets through rates.
PSC'ermit The Company's current electric load forecasts indicate that, with continued implementation of its aggressive conser- For a further discussion of SFAS No. 106, including the vation and load management programs and with electricity recoverability of these regulatory assets, see Note 8 of provided by independent power producers and cogenerators, Notes to Financial Statements.
the Company's existing generating facilities, the Company's The Company will adopt SFAS No. 109, Accounting for portion of nuclear energy generated at NMP2 and contracts Income Taxes, during the first quarter of 1993. SFAS No. 109 for purchased power are adequate to meet the energy prohibits net of tax accounting and reporting and requires demands on Long Island beyond the end of the century. recognition of a deferred tax liabilityfor the tax benefits which are flowed through to its customers and the equity component Gas Competition In 1987, the Federal Energy Regulatory of AFC. A regulatory asset or liabilitywill be recognized Commission (FERC) issued an order allowing gas pipeline relating to such items if it is probable that the future increase companies and producers access to certain of the Company's or decrease in taxes payable thereon shall be recovered customers for the purpose of supplying competing gas from or returned to customers through future rates. The service. As of December 31, 1992, approximately 104 of the Company estimates that had it adopted SFAS No. 109 at Company's former large gas customers were purchasing gas December 31, 1992, the Company would have recorded an directly from gas pipeline companies and producers and accumulated deferred tax liabilityand a corresponding arranging for its transportation through the Company's gas regulatory asset of approximately $ 1.2 billion. The impact of mains. The Company receives a fee for this transportation SFAS No. 109 on the Statement of Income is not expected to service which accounted for approximately $ 6.7 million, or be material. For a further discussion of SFAS No. 109, see 1.6%, of total gas revenues for 1992. Note 1 of Notes to Financial Statements.
Clean AirAct In late 1990, significant amendments to the Selected Financial Data federal Clean Air Act were adopted. A number of electric utilities anticipate substantial increases in operating costs Additional financial information for the last five years is and capital expenditures as a result of the amendments. provided in Tables 1 through 11 of Selected Financial The Company does not expect to incur any costs to satisfy Information with regard to the Company's business seg these amendments with respect to the reduction of sulfur for the last three years is provided in Note 11 of Notes to dioxide emissions, since the Company already uses fuel with Financial Statements.
Financial Statements I
tement of Income (tn thousands of dollars except per share amounts I year ended December 31 1992 1991 1990 Revenues Electric $ 2,194,632 $ 2,196,568 $ 2,095,660 Gas 427,207 351,161 361,242 Total Revenues 2,621,839 2,547,729 2,456,902 Expenses Operations fuel and purchased power 741,784 768,702 786,999 Operations other 372,209 375,267 340,518 Maintenance 125,736 147,492 135,291 Depreciation and amortization 119,137 118,955 110,884 Base financial component amortization 100,971 100,971 100,971 Regulatory liabilitycomponent amortization (88,573) (88,573) (88,573)
Other regulatory amortizations (22,072) 8,666 14,427 Rate moderation component (30,444) (228,572) (297,214)
Operating taxes 388,988 388,380 370,317 Federal income tax current 530 515 3,638 Federal income tax deferred and other 172,468 168,937 177,014 Total Expenses 1,880,734 1,760,740 1,654,272 Operating Income 741,105 786,989 802,630 Other Income and (Deductions)
Allowance for other funds used during construction 4,725 2,202 2,940 Rate moderation component carrying charges 42,837 40,456 15,683 Other income and deductions, net 28,832 33,783 27,218 ss Settlement (22,541) (25,467) (22,574) leral income tax (charge) deferred and other 12,036 (12,201) (2,629) otal Other Income and (Deductions) 65,889 38,773 20,638 Income Before Interest Charges and Cumulative Effect of Accounting Change 806,994 825,762 823,268 Interest Charges and (Credits)
Interest on long-term debt 450,621 472,974 467,700 Other interest 61,785 50,842 40,559 Allowance for borrowed funds used during construction (7,386) (3,592) (4,628)
Total Interest Charges and (Credits) 505,020 520,224 503,631 Income Before Cumulative Effect of Acc'ounting Change 301,974 305,538 319,637 Cumulative Effect of Accounting Change for Unbllled Gas Revenues (net of applicable taxes of $ 6,017) 11,680 Net Income 301,974 305,538 331,317 Preferred stock dividend requirements 63,954 66,394 68,161 Earnings for Common Stock $ 238,020 239,144 263,156 Average Common Shares Outstanding (000) 111,439 111,348 111,290 Earnings per Common Share Before cumulative effect of accounting change $ 2.15 2.26 Cumulative effect of accounting change .10 Earnings per Common Share $ 2.14 2.15 2.36 Dlvldends Declared per Common Share $ 1.72 1.60 1.25 Notes to Financial Statements.
Balance Sheet A In thousands of della At December 3 l l 992 UtilityPlant Electric $ 3,429,803 $ 3,323,008 Gas 760,635 666,904 Common 172,703 157,495 Construction work in progress 161,663 157,511 Nuclear fuel in rocess and in reactor 19,216 29 818 4,544,020 4,334,736 Less Accumulated depreciation and amortization 1,382,872 1 332 003 Total Net Utilit Plant 3,161,148 3 002 733 Regulatory Asset Base financial component (less accumulated amortization of $ 353 398 and $ 252 427 3,685,432 3 786 403 Nonutility Property and Other Investments 20,730 9 788 Current Assets Cash and cash equivalents 309,485 298,098 Special deposits 23,683 23,207 Customer accounts receivable (less allowance for doubtful accounts of $ 24,375 and $ 26,935) 208,049 210,525 Other accounts receivable 6,937 6,515 Accrued unbilled revenues 143,172 136,565 Materials and supplies at average cost 86,482 86,863 Fuel oil at average cost 51,702 44, Gas in storage at average cost 47,002 43, Pre a ments and other current assets 40,402 34, Total Current Assets 916,914 884,017 Deferred Charges Rate moderation component 651,657 602,053 Shoreharn post settlement costs 586,045 378,386 Unamortized cost of issuing securities 380,267 227,713 Shoreham nuclear fuel 77,629 79,760 Accumulated deferred income taxes 511,898 439,235 Other 256,904 133,213 Total Deferred Char es 2,464,400 1,860,360 Total Assets $ 10,248,624 $ 9,543,301 See Notes to Financial Statements.
pltallzatlon and Liabilities (In thousands of dollars) ce ber31 1992 1991 apltallzatl on Long-term debt $ 4,755,733 $ 5,001,016 Unamortized remium and discount on debt (14,731 14,850 4,741,002 4,986,166 Preferred stock redemption required 557,900 524,912 Preferred stack no redemption re uired 154,276 154,371 Total Preferred Stock 712,176 679,283 Common stock 558,002 556,825 Premium on capital stock 998,089 993,509 Capital stock expense (39,304) (40,216)
Retained earnin s 667,988 620,373 Total Common Shareowners' uit 2,184,775 2,130,491 Total Ca italization 7,637,953 7,795,940 Current Liabilities Current maturities of long-term debt 590,000 10,000 Current redemption requirements of preferred stock 8,200 10,616 Accounts payable and accrued expenses 286,102 223,589 Accrued taxes (including federal income taxes of $ 27,100 and $ 27,693) 67,525 60,174 Accrued interest 131,179 85,565 Dividends payable 53,966 60,287 ass Settlement 30,000 20,000 tamer de osits 24,815 22,664 al Current Liabilities 1,191,787 492,895 Deferred Credits 1989 Settlement credits 164,294 173,507 Class Settlement 167,066 173,564 Accumulated deferred income taxes 970,373 816,053 Other 110,341 84,035 Total Deferred Credits 1,412,074 1,247,159 Reserves for Claims, Damages, Pensions and Benefits 6,810 7,307 Commitments and Contingencies Total Capitalization and Liabilities $ 10,248,624 $ 9,543,301 See Notes to Financial Statements.
Shareowners'quity (In thousands of dolla Statement of Retained Earnings 1992 1991 Balance at January 1 $ 620,373 560,405 436,6 Net income for the ear 301,974 305,538 331,317 922,347 865,943 768,007 Deductions Cash dividends declared on preferred stock 62,387 67,261 68,218 Cash dividends declared on common stock 191,693 178,169 139,128 Ca ital stockex ense 279 140 256 Balance at December 31 $ 667,988 620,373 560,405 Preferred Stock (In thousands of dollars)
At December 31 1992 1991 1990 Call Price Per Share December 31 1992 Final Par Value $ 100 per Share, Cumulative Shares authorized 7,000,000 7,000,000 7,000,000 Shares issued and outstandin 2,353,757 2,438,993 2,528,400 5.00% Series B $ 101.00 $ 101.00 $ 10,000 10,000 10,000 4.25% Series D 102.00 102.00 7,000 7,000 7,000 4.35% Series E 102.00 102.00 20,000 20,000 20,000 4.35% Series F 102.00 102.00 5,000 5,000 5,000 5 1/8%Series H 102.00 102.00 20,000 20,000 20,000 5 3/4%Series I Convertible 100.00 100.00 2,276 2,371 2,674 8.12% Series J 101.00 101.00 25,000 25,000 25,000 8.30% Series K 103.29 103.29 30,000 30,000 30,000 7.40% Series L* 103.22 100.00 20,300 21,350 22.
8.40% Series M* 103.36 100.00 23,800 25,200 26, 8.50% Series 101.00 100.00 15,000 22,500 26,2 Series S*R'.80%
55,478 57,916 7.66% Series CC* 100.00 57,000 Total Par Value $ 100 $ 235,376 243,899 252,840 Par Value $ 25 per Share, Cumulative Shares authorized 30,000,000 30,000,000 30,000,000 Shares issued and outstandin 19,400,000 17,840,000 17,720,000
$ 2.47 Series 0* $ 25.25 $ 25.25 $ 22,000 $ 26,000 28,000
$ 2.43 Series P 27.75 27.75 35,000 35,000 35,000
$ 3.31 Series T* 60,000
$ 2.65 Series Y* 320,000 320,000
$ 2.35 Series Z* 27.35 25.00 65,000 65,000 7.95% Series AA* 25.00 363,000 Total Par Value $ 25 $ 485,000 446,000 443,000 Less Sinkin fund re uirements $ 8,200 10,616 13,616 Total Preferred Stock $ 712,176 679,283 682,224 Common Stock (In thousands of dollars)
At December 31 1992 1991 1990 Par Value $ 5 per Share Shares authorized 150,000,000 150,000,000 150,000,000 Shares issued and outstanding 111,600,376 111,365,056 111,324,081 Increase in shares outstandin 235,320 40,975 74,613 Increase in $ 5 par value $ 1,177 205 Increase in premium on capital stock $ 4,493 614 Decrease in capital stock expense $ 912 2,460
'Redemption required, see Note 6. "Not callable at December 31, 1992.
The aggregate fair value of redeemable preferred stock at December 31, 1992 amounted to $ 581,984 compared to its carryfng amount of $ 566,100.
See Notes to Financial Statements.
Statement of Cash Flows (In thousands of dollars) l991 l 990 Operating Activities Net Income 301,974 305,538 331,317 Adjustments to reconcile net income to net cash provided by operating activities Cumulative effect of accounting change for unbilled gas revenues (11,680)
Depreciation and amortization 119,137 118,955 110,884 Fuel moderation component 34,025 3,804 Provision for doubtful accounts 16,329 35,431 30,097 Base financial component amortization 100,971 100,971 100,971 Regulatory liabilitycomponent amortization 88,573) (88,573) (88,573)
Other regulatory amortizations 22,072) 8,666 14,427 Rate moderation component 30,444) (228,572) (297,214)
Rate moderation component carrying charges 42,837 (40,456) (1 5,683)
Class Settlement 22,541 25,467 22,574 Amortization of cost of issuing and redeeming securities 41,204 27,456 23,648 Federal income taxes deferred and other 160,432 181,138 179,643 Allowance for other funds used during construction (4,725) (2,202) (2,940)
Other 699 38,068 15,234 Changes in operating assets and liabilities Accounts receivable (14,275) (26,045) (22,463)
Accrued unbilled revenues (6,607) 2,352 30,748 Materials and supplies, fuel oil and gas in storage (10,933) 28,217 (48,040)
Prepayments and other current assets (5,548) (1,035) 23,752 Accounts payable and accrued expenses 62,513 34,560 2,345 ass Settlement (20,129)
.crued taxes 7,351 3,926 (42,187) ther (17,073) (37,459) (19,477)
Net Cash Provided by Operating Activities 590,064 520,428 321,058 Investing Activities Construction and nuclear fuel expenditures (268,179) (235,349) (229,525)
Shoreham post settlement costs (227,658) (158,432) (152,675)
Other (1,484 (3,923) 81 Net Cash Used in Investing Activities (497,321 (397,704) (382,119)
Financing Activities Proceeds from issuance of Iong-term debt 1,659,928 1,532,247 112,319 Redemption of long-term debt (1,344,283) (1,129,000) (82,000)
Proceeds from sale of preferred stock 411,373 63,130 Redemption of preferred stock (389,428) (70,638) (13,659)
Preferred stock dividends paid (69,923) (65,838) (68,046)
Common stock dividends paid (190,477) (172,584) (125,192)
Cost of issuing and redeeming securities (166,066) (88,586) (1,327)
Other 7,520 3,707 1,598 Net Cash (Used in) Provided by Financing Activities (81,356) 72,438 (176,307)
Net Increase (Decrease) in Cash and Cash Equivalents 11,387 195,162 $ (237,368)
Cash and cash equivalents at beginning of year 298,098 102,936 $ 340,304 Net increase (decrease) in cash and cash equivalents 11,387 195,162 (237,368)
Cash and Cash Equivalents at End of Year 309,485 298,098 102,936 nterest paid, before reduction for the allowance r borrowed funds used during construction 424,842 477,240 479,278 eral income taxes paid 2,100 1,650 900 ederal income taxes refunded 1,566 642 23,588 See Notes to Financial Statements.
Notes to Financial Statements Note 1. Summary of Significant Accounting Policies Financial Resource Asset GAAP authorizes recogniti of the existence of a regulatory asset when it is probable th .
Regulation The Company's accounting policies conform a regulator will permit full recovery of a previously incurred to generally accepted accounting principles (GAAP) as they cost. Pursuant to the 1989 Settlement, the Company apply to a regulated enterprise. Its accounting records are recorded a regulatory asset known as the Financial Resource maintained in accordance with the Uniform Systems of Asset (FRA), to provide the Company with sufficient cash Accounts prescribed by the Public Service Commission of the flows to assure its financial recovery. The FRA has two State of New York (PSC) and the Federal Energy Regulatory components, the Base Financial Component (BFC) and the Commission (FERC). Rate Moderation Component (RMC). The Rate Moderation Agreement (RMA), one of the constituent documents of the UtilityPlant Additions to and replacements of utility plant 1989 Settlement, provides for the full recovery of the FRA.
are capitalized at original cost, which includes material, For a further discussion of the 1989 Settlement and the FRA, labor, overhead and an allowance for the cost of funds used see Note 2.
during construction. The cost of renewals and betterments relating to units of property is added to utility plant. The Cash and Cash Equivalents Cash equivalents are highly cost of property replaced, retired or otherwise disposed of is liquid investments with maturities of three months or less deducted from utility plant and, generally, together with when purchased. The carrying amount approximates fair dismantling costs less any salvage, is charged to accumulated value because of the short maturity of these investments.
depreciation. The cost of repairs and minor renewals is charged to maintenance expense. Mass properties (such as Unbilied Revenues The Company accrues electric poles, wire and meters) are accounted for on an average revenues for services rendered to customers but not billed unit cost basis by year of installation. at month-end.
Effective January 1, 1990, the Company adopted the full Allowance for Funds Used During Construction accrual method for unbilled gas revenues. Previously, The Uniform Systems of Accounts deAnes the allowance for unbilled gas revenues were recognized only for customers funds used during construction (AFC) as the net cost of billed on a bi-monthly cycle basis for the month in which th borrowed funds for construction purposes and a reasonable were normally not billed. This change better matches rate of return upon the utility's equity when so used. AFC is revenues and expenses and provides consistency with the not an item of current cash income. AFC is computed monthly Campany's revenue recognition method for electric using a rate permitted by FERC on that portion of construc-revenues. The cumulative effect of this change at January 1, tion work in progress which is not included in the Company's 1990 was $ 11.7 million, net of tax effects, or $ .10 per share rate base. The average annual AFC rate, without giving and had been included in net income for the year ended effect to compounding, was 9.98%, 10.74% and 11.03% for December 31, 1990. The effect of this change on income the years 1992, 1991 and 1990, respectively.
before the cumulative effect of accounting change and on earnings for common stock for the year ended December 31, DePreciation The provisions for depreciation result from 1990 was not material.
the application of straight-line rates to the original cost, by groups, of depreciable properties in service. The rates are Fuel Cost Adjustments The Company's electric and gas determined by age-life studies performed annually on tariffs include fuel cost adjustment (FCA) clauses which depreciable properties. Depreciation for electric properties provide for the difference between actual fuel costs and the was equivalent to approximately 3.2%, 3.3% and 3.2% of fuel costs allowed in the Company's base tariff rates (base respective average depreciable plant costs for the years fuel costs). The Company defers these adjustments, net of tax 1992, 1991 and 1990. Depreciation for gas properties was effects, to future periods in which they will be billed or equivalent to approximately 2.6%, 2.9% and 2.8% of credited to customers, except for base electric fuel costs in respective average depreciable plant costs for the years excess of actual electric fuel costs, which are currently 1992, 1991 and 1990.
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 in Note 10. The Company defers the benefit of 60% of ote 3 authorized the adoption of a partial pass-through pre-1982 gas and pre-1983 electric and 100% of all other fuel cost incentive plan which includes a mechanism that investment tax credits, with respect to regulated properties, compares, on a monthly basis, the Company's actual cost to when realized on its tax returns.
produce electric energy against a targeted fuel value. The For ratemaking purposes, certain accumulated deferred incentive measures the Company's ability to purchase fuel at federal income taxes are deducted from rate base and the lowest possible cost, to purchase energy economically amortized or otherwise applied as a reduction (increase) in from other power suppliers and to operate its generating federal income tax expense in future years. Accumulated plants at optimum efficiency. The shareowners are allocated deferred investment tax credits are amortized ratably over 40% of the impact between actual fuel costs and targeted the lives of the related properties.
fuel values up to a maximum benefit or penalty of 20 basis points of the allowed return on common equity. The The tax effects of other differences between income for shareowners'ortion of these impacts are being deferred financial statement purposes and for federal income tax on a monthly basis. The accumulated net deferral will be purposes are accounted for as current adjustments in federal recovered or returned, through the FCA, over a twelve- income tax provisions.
month period in the following rate year. For a further The Financial Accounting Standards Board (FASB) Statement discussion of the partial pass-through fuel cost incentive, of Financial Accounting Standards (SFAS) No. 109, see Note 3.
Accounting for Income Taxes requires, among other matters, Fair Values of Financial Instruments The fair values recognition of the amount of current and deferred taxes for the Company's long-term debt and redeemable preferred payable or refundable at the date of the financial statements stock are based on quoted market prices, where available. as a result of all events that have been recognized in the The fair values for all other long-term debt and redeemable financial statements and adjustment of deferred income taxes preferred stock are estimated using a discounted cash flow for an enacted change in tax laws. For regulated enterprises, analyses which is based upon the Company's current SFAS No. 109 prohibits net of tax accounting and reporting remental borrowing rate for similar types of securities. and requires recognition of a deferred tax liabilityfor the tax beneAts which are flowed through to its customers and the italization-premiums, Discounts and Expenses equity component of AFC. A regulatory asset or liabilitywill Premiums or discounts and expenses related to the issuance be recognized relating to such items if it is probable that the of long-term debt are amortized over the life of each issue. future increase or decrease in taxes payable thereon shall Unamortized premiums or discounts and expenses related to be recovered from or returned to customers through future issues of long-term debt that are refinanced are amortized rates. The Company estimates that had it adopted SFAS and recovered through rates over the shorter life of the No. 109 at December 31, 1992, the Company would have redeemed or new issues. Capital stock expense related to recorded an accumulated deferred tax liability and a that portion of preferred stock that is required to be corresponding regulatory asset of approximately $ 1.2 redeemed is written-off as an adjustment to retained billion. The Company will adopt SFAS No. 109 during the earnings upon redemption unless the preferred stock is first quarter of 1993 and does not expect a material impact redeemed below par value. In that case, any resulting gain, on the Statement of Income.
net of the related capital stock expense, is recorded as additional premium on capital stock. Capital stock expense Reserves for Claims, Damages, Pensions and redemption costs related to certain issues of preferred and Benefits Losses arising from claims against the stock that have been refinanced as well as the cost of Company are partially self-insured. Extraordinary storm issuance of the preferred stock issued are recorded as losses are partially self-insured up to $ 5 million until March 1, deferred charges. These amounts are being amortized and 1993, at which time the Company will bear a greater portion recovered through rates over the shorter life of the of these costs. Amounts provided are credited to the reserves redeemed or new issues. based upon experience, risk of loss, actuarial estimates and/or specific orders of the PSC.
Federal Income Taxes The Company provides deferred federal income taxes with respect to certain differences Reclasslfications Certain prior year amounts have been between net income before income taxes and taxable income reclassified in the financial statements to be consistent with in certain instances when approved by the PSC, as disclosed the current year's presentation.
Note 2. The 1989 Settlement energy conservation and load management program costs, costs to provide added electric system reliability On February 28, 1989, the Company and the State of New and inflation.
York (by its Governor) entered into the 1989 Settlement The RMC balance, which was $ 652 million and $ 602 million resolving certain issues relating to the Company and at December 31, 1992 and 1991, respectively, has increased providing, among other matters, for the transfer of the as the difference between revenues resulting from the Shoreham Nuclear Power Station (Shoreham) and its implementation of the rate moderation plan provided for in subsequent decommissioning. On February 29, 1992, the the RMA and revenue requirements under conventional Company transferred ownership of Shoreham to the Long ratemaking, together with a carrying charge equal to the Island Power Authority (LIPA), an agency of the State of allowed rate of return on rate base, has been deferred. The New York. Pursuant to the 1989 Settlement, LIPA is RMC balance will subsequently decrease and is expected to responsible for the decommissioning of Shoreham and has be fully amortized by November 30, 1999, as deferred estimated that the decommissioning, in which Company revenue requirements are recovered.
employees are participating, will be completed in 1994.
The PSC opproved the Long Island Lighting Company The 1989 Settlement recites the intention of the parties that Ratemaking and Performance Plan (LRPP), discussed in the Company shall be returned to investment grade financial Note 3, effective for each of the three rate years in the condition and that the Company and the State of New York period beginning December 1, 1991. Although the LRPP anticipate that the PSC shall ensure that the future impacts on provides for slightly lower annual electric rate increases than rates are to be minimized to the maximum extent practicable. originally anticipated in the 1989 Settlement, the Company It is the Company's position that these objectives will continue believes that it will still fully recover the RMC over the ten-to be achieved, in part, through the continued receipt of year period principally as a result of changes in the original adequate and timely rate relief. assumptions. The revenues assumed by the LRPP are Upon the effectiveness of the 1989 Settlement, the Company adequate to provide the Company with recovery of its simultaneously recorded on its Balance Sheet the retirement revenue requirements under conventional ratemaking and of its investment of approximately $ 4.2 billion in Shoreham recovery of the RMC balance over the remainder of the and Bokum Resources Corporation (Bokum) and the ten-year period. However, actual revenues may differ fro establishment of the FRA. those assumed for this period. The original assumptions underlying the RMA included projections of future revenues, The BFC, a component of the FRA, as initiallyestablished, operating expenses and required rates of return. Since then, represents the present value of the future net-after-tax cash the Company has experienced interest rates, non-Shoreham flows which the RMA provided the Company for its financial property taxes and fuel expenses that are lower than those recovery. The BFC was granted rate base treatment under originally anticipated. As a result, amounts deferred in the the terms of the RMA and is included in the Company's RMC have been less than expected. In addition, as a result of revenue requirements through an amortization included in the Company's improved credit ratings and an overall rates over forty years on a straight-line basis beginning decline in the cost of money in the Rnancial marketplace, the July 1, 1989. At December 31, 1992 and 1991, the PSC provided the Company in the LRPP with a lower rate of unamortized balance of the BFC was approximately $ 3.7 return on common equity than that initially provided for in billion and $ 3.8 billion, respectively. the RMA. This lower rate of return, which will be in effect for the three years associated with the LRPP, results in a lower The RMC, a component of the FRA, reflects the difference RMC balance than had been anticipated in the 1989 between the Company's revenue requirements under Settlement.
conventional ratemaking and the revenues resulting from the implementation of the rate moderation plan provided for in Under the 1989 Settlement, certain tax benefits attributable the RMA. The RMC, which has provided the Company with a to the Shoreham abandonment are to be shared between substantial amount of non-cash earnings over the last several ratepayers and shareowners. A regulatory liabilityof years, is based upon forecasted data filed in connection with approximately $ 794 million was recorded in June 1989 to the RMA. The RMA was designed to provide rate increases preserve an amount equivalent to the ratepayer tax benefits sufficient to recover the RMC within a ten-year period. The attributable to the Shoreham abandonment. This amount is RMC is currently adjusted, on a monthly basis, for the being amortized over a ten-year period an a straight-line 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 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 fully recognized under GAAP were it not for the
~
~
December 1, 1991, the RMC was adjusted to reflect actual fact that its recovery is assured under the 1989 Settlement property taxes, cost of asbestos removal, interest expense, through the regulatory liability offset.
oreham post settlement costs (decommissioning, payments Revenue reconciliation is provided through a mechanism that in lieu of property taxes and other costs as incurred) are reduces the impact of experiencing electric sales that are being capitalized and amortized and recovered through above or below the LRPP forecast by providing a fixed rates over a forty-year period on a straight-line remaining annual net margin level (defined as sales revenues, net of life basis. fuel and gross receipts taxes) that the Company will receive over the three rate years under the LRPP. The differences Upon the effectiveness of the 1989 Settlement, Shoreham between the actual electric net revenues and the annual nuclear fuel was reclassified to deferred charges and is being net margin level are deferred on a monthly basis during amortized and recovered through rates over a forty-year the rate year.
period on a straight-line remaining life basis.
The expense attrition and reconciliation component permits The 1989 Settlement credits on the Balance Sheet of the Company to make adjustments for certain expenses approximately $ 164 million, net of amortization, reflect an recognizing that certain cost increases are unavoidable due adjustment of the book write-off to the negotiated 1989 to inflation and changes in the business. The LRPP includes Settlement amount. A portion of this amount is being the annual reconciliation of certain expenses for wage rates, amortized over a ten-year period. The remaining portion is not currently being recognized for ratemaking purposes property taxes, interest charges and demand side under the 1989 Settlement. management (DSM) costs, the deferral and amortization of certain costs for enhanced reliability and operations and Note 3. Rate Matters maintenance expenses, and the application of an inflation index to other expenses for the rate years beginning December 1, 1992 and 1993.
Electric Pursuant to the 1989 Settlement, discussed in Note 2, the Company received electric rate increases The deferred balances resulting from the net margin, contemplated by the RMA for each of the three rate years property taxes, interest expense and wage rates will be in the period ended November 30, 1991. The RMA netted at the end of each rate year. The LRPP established a ontemplates that the Company will apply to the PSC for band whereby the first $ 15 million of the total net deferrals geted annual rate increases of 4.5% to 5.0% in each year will be used to increase or decrease the RMC balance. The r an eight-year period beginning December 1, 1991. In LRPP provides for the disposition of the total net deferrals in response to the Company's rate filing, the PSC approved the excess of the $ 15 million band. The total net deferrals in LRPP in November 1991, which provides that the Company excess of $ 15 million will be refunded to or recovered from receive, for each of the three rate years in the period the ratepayers in the following twelve-month period beginning December 1, 1991, annual electric rate increases beginning in the second quarter of each year. For the rate of 4.15%, 4.1% and 4.0%, respectively, with an allowed year ended November 30, 1992, the total net deferrals in return on common equity from electric operations of 11.6% excess of $ 15 million, to be recovered from the ratepayers, for each of the three rate years. After giving effect to the amounted to approximately $ 29.5 million.
reductions required by the Class Settlement discussed in Note 4, the Company's annual electric rote increases are Under the performance incentive component of the LRPP, the Company is allowed to earn for each rate year up to approximately 4.15%, 3.9% and 3.9%, with an allowed return on common equity from electric operations of 60 additional basis points, or forfeit up to 38 basis points, 10.92%, 10.72% and 10.58%, for the rate years beginning of the allowed return on common equity as a result of its December 1, 1991, 1992 and 1993, respectively. performance within certain incentive and/or penalty programs. These programs consist of a customer service The LRPP was designed to be consistent with the RMA's long- performance plan, a DSM program, a time-of-use term goals including: (a) the recovery of the BFC; (b) the program and a partial pass-through fuel cost incentive recovery of the RMC in approximately ten years; (c) the plan, discussed in Note 1. The incentives and/or penalties Company's return to investment grade financial condition; related to the customer service performance plan and and (d) the Company's receipt of adequate and timely rate the time-of-use program are determined an a monthly relief. One principal objective of the LRPP is to reassign risk basis during the rate year. The total amounts deferred so that the Company assumes the responsibility for risks at the end of each rate year will be refunded to or within the control of management, whereas risks largely recovered from the ratepayers through the FCA in the beyond the control of management would be assumed by the following twelve-month period beginning in the second ratepayers. The LRPP reflects an update of the long-range quarter of each year. The incentives earned from the ecast of the Company's revenue requirements, which was DSM program are collected in rates, on a monthly basis, basis of the RMA's initial three rate increases. The LRPP through the FCA. For the rate year ended November 30, ntains three major components revenue reconciliation, 1992, the Company earned a total of approximately 23 expense attrition and reconciliation, and performance basis points, or $ 4.3 million, net of tax effects, based upon incentives. its performance within these programs.
For the rate year ended November 30, 1992, the Company Note 4. The Class Settlement earned $ 16.2 million, net of tax effects, in excess of its allowed rate of return on common equity which, in The Class Settlement, which became effective on June 28, accordance with the LRPP, was shared equally between 1989, resolved a civil lawsuit against the Company brought ratepayers (by a reduction to the RMC) and shareowners. under the federal Racketeer Influenced and Corrupt These excess earnings were generated as a result of a Organizations Act (RICO Act). The lawsuit which the Class reduction in operating expenses and the effect of a decrease Settlement resolved had alleged that the Company made in capital expenditures included in rate base. Prior to inadequate disclosures before the PSC concerning the December 1, 1991, the RMA provided that earned returns construction and completion of nuclear generating facilities.
on common equity in excess of targeted allowed rates of The Class Settlement provides the Company's ratepayers return, as adjusted, were to be applied to reduce the RMC with reductions, aggregating $ 390 million, that are to be ar mitigate rates, as determined by the PSC, at the end of reflected as adjustments to their monthly electric bills over a eachrate year. For the rate year ended November 30, 1991, ten-year period beginning June 1, 1990. The reductions the Company earned $ 10.1 million, net of tax effects, in required for the ffrst three years have already been reflected excess of its allowed rate of return, which was applied in rates. The reductions in each subsequent twelve-month as a reduction to the RMC. The Company did not earn in period are as follows:
excess of its allowed rate of return for the rate year ended 1993 June $ 30 million November 30, 1990. June 1994 $ 30 million To assist in recovering the RMC within a ten-year period June 1995 $ 40 million under the rates provided by the LRPP, the Company, in June 1996 $ 50 million accordance with the LRPP, has credited the RMC with several June 1997 $ 60 million deferred ratepayer benefits. In December 1992, the June 1998 $ 60 million Company applied a total of approximately $ 22.5 million of June 1999 $ 60 million various deferred ratepayer benefits to the RMC including the Upon its effectiveness, the Company recorded its liabilityfor ratepayers portion of the excess earnings for the rate year the Class Settlement on a present value basis at $ 170 milli ended November 30, 1992. In December 1991, the and simultaneously recorded a charge to income (net of ta Company applied approximately $ 57.6 million of previously effects of $ 57 million) of approximately $ 113 million. Each deferred credits and related carrying charges for amounts month the Company records the changes in the present value collected in excess of actual fuel costs and other of such liabilitythat result from the passage of time and from miscellaneous deferred credits as a reduction to the RMC.
monthly reductions. Because the reductions of the liabilityare greater in the later years, the current present value Gas In November 1992, the PSC approved a gas rate calculations result in an increase in total liabilitydespite the increase of 7.1%, or $ 35.7 million annually, which became reductions in the total amount due. Beginning sometime in effective on December 1, 1992. The gas rate decision 1993, the amount of the total remaining Class Settlement provides for an 11.0% allowed return on common equity liabilitywill begin to decrease as the monthly reductions of for the rate year beginning December 1, 1992. the liability exceed the incremental increases in the present On December 31, 1992, the Company filed an application value. The Company expects the Class Settlement liabilitywill with the PSC seeking gas rate relief for the three rate years in be fully satisfied by May 31, 2000.
the period beginning December 1, 1993. The Company has As a result of the Class Settlement, the Company's electric requested a gas rate increase of 6.7%, or $ 37.7 million in rate increases on average will be approximately.2% to .3%
additional revenues to become effective for the first rate per year lower than they would otherwise have been during year under this filing. The Company's filing also includes a the balance of the Class Settlement period. The amounts proposed methodology for determining rate increases, recorded on the Statement of Income for 1992, 1991 and not to exceed approximately $ 30 million annually, for the 1990 of approximately $ 23 million, $ 25 million and $ 23 subsequent second and third rate years. This filing reflects million, respectively, represent the increase in present value the Company's latest prajections of capital expenditures, of the Class Settlement liability.
operations and maintenance expenses and the continued expansion of its gas business.
te 5. Nine Mile Point Nuclear Power Station, of a qualified fund under applicable provisions of the federal nit 2 income tax law. This IRS ruling allows the Company's contributions to the decommissioning trust to be deductible The Company has an 18% undivided interest in NMP2 which for income tax purposes for the tax year in which they is operated by Niagara Mohawk Power Corporation are made.
(NMPC) near Oswego, New York. Ownership of NMP2 is shared by five cotenants: the Company (18%), NMPC Note 6. Capital Stock (41%), New York State Electric Sc Gas Corporation (18%),
Rochester Gas and Electric Corporation (14%) and Central Preferred Stock Redemption of certain series of Hudson Gas 8 Electric Corporation (9%). At December 31, preferred stock is effected through the operation of various 1992, the Company's net utility plant investment in NMP2 sinking fund provisions. The aggregate par value of was $ 776 million, net of accumulated depreciation of $ 97 preferred stock required to be redeemed in each of the years million, which is included in the Company's rate base. Output 1993 through 1996 is $ 8.2 million and in 1997 is $ 4.5 million.
of NMP2, which had an operating capability of 1,080 Dividends on preferred stock are paid in preference to megawatts in 1992, is shared in the same proportions as the dividends on common stock or any other stock ranking junior cotenants'espective ownership interests. NMPC has to preferred stock.
determined that the operating capability of NMP2, effective January 1, 1993, is 1,047 megawatts. The operating Preference Stock None of the authorized 7,500,000 expenses of NMP2 are also allocated to the cotenants in the shares of nonparticipating preference stock, par value $ 1 per same proportions as their respective ownership interests. The share, which ranks junior to preferred stock, are outstanding.
Company's share of these expenses is included in the appropriate operating expenses on the Statement of Income. Common Stock Of the 150,000,000 shares of authorized The Company is required to provide its respective share of common stock at December 31, 1992, 1,834,289 shares financing for any capital additions to NMP2. Nuclear fuel were reserved for sale through the Company's Employee osts associated with NMP2 are being amortized on the basis Stock Purchase Plan, 6,620,755 shares were committed to the quantity of heat produced for the generation of the Automatic Dividend Reinvestment Plan (ADRP) and ctricity. 132,694 shares were reserved for conversion of the Series I Convertible Preferred Stock at a rate of $ 17.15 per share. In NMPC has contracted with the United States Department June 1992, the Company reinstated the ADRP which had of Energy for the disposal of nuclear fuel. The Company been suspended since February 1984. Common and reimburses NMPC for its 18% share of the cost under the preferred stock dividend limitations in the mortgage securing contract at a rate of $ 1.00 per megawatt hour of net genera-the Company's First Mortgage Bonds are not material. There tion less a factor to account for transmission line losses.
are no dividend limitations contained in the Company's other Based upon a study performed by NMPC, the Company's debt instruments.
share of the decommissioning costs for NMP2 is estimated to be $ 37 million (in 1989 dollars) assuming that decom- Note 7. Long-Term Debt missioning will commence in 2027 or $ 237 million (in 2027 dollars). The Company's share of estimated decommissioning Each of the Company's outstanding mortgages is a lien on costs are being provided for in electric rates and are being substantially all of the Company's properties.
charged to operations as depreciation expense. The amount of accumulated decommissioning costs collected from the First Mortgage All of the bonds issued under the First Company's ratepayers through December 31, 1992 was Mortgage, including those issued after June 1, 1975 and
$ 5.4 million. Amounts collected by the Company for the pledged with the Trustee of the G8 R Mortgage (G8 R decommissioning of the contaminated portion of the NMP2 Trustee) as additional security for General and Refunding plant, which approximate 84% of total decommissioning Bonds (G8cR Bonds), are secured by the lien of the First costs, are held in an independent decommissioning trust Mortgage. First Mortgage Bonds pledged with the G8 R fund. This fund complies with regulations issued by the Trustee do not represent outstanding indebtedness of the Nuclear Regulatory Commission (NRC) governing the Company. Amounts of such pledged bonds outstanding were funding of nuclear plant decommissioning costs. The $ 1.03 billion and $ 957 million at December 31, 1992 and Company's funding plan for its share of decommissioning 1991, respectively. The annual First Mortgage depreciation costs will provide reasonable assurance that, at the time fund and sinking fund requirements for 1992, due not later ermination of operation, adequate funds for the than June 30, 1993, are estimated at $ 194 million and $ 18 ommissioning of the Company's share of the million, respectively. The Company expects to meet these contaminated portion of NMP2 plant will be available. requirements with property additions and retired First The Internal Revenue Service (IRS) has ruled that the Mortgage Bonds.
Company's decommissioning trust meets the requirements
G&R Mortgage The lien of the G8 R Mortgage is one-year periods upon the acceptance by the lending ba'f subordinate to the lien of the First Mortgage. The annual the Company's request delivered to the lending banks G8 R Mortgage sinking fund requirement for 1992, prior to April 1 in each year.
due not later than June 30, 1993, is estimated at $ 27 million.
The Company expects to satisfy this requirement with retired Debentures On January19, 1993, the Company issued G8 R Bonds. $ 36 million principal amount of Debentures, 7.30% Series Due 2000. The net proceeds from the issuance of these Third Mortgagel1989 Term Loan Agreement In debentures will be used in February 1993 to redeem, at the November 1992, the Company used the net proceeds from applicable redemption price, $ 35 million principal amount of the issuance of $ 451 million principal amount of debentures First Mortgage Bonds, 8.20% Series R Due 1999.
to repay the then outstanding 1989 Term Loan Agreement which had been secured by the Third Mortgage. The Third Authority Financing Notes Authority Financing Notes Mortgage has been discharged as a result of the repayinent are issued by the Company to the New York State Energy of the 1989 Term Loan Agreement. Research and Development Authority (NYSERDA) to secure certain tax-exempt Pollution Control Revenue Bonds, Electric Fourth Mortgage In December 1992, the Company Facilities Revenue Bonds (EFRBs) and Industrial Development satisfied the Fourth Mortgage which had secured $ 85 million Revenue Bonds issued by NYSERDA. Certain of these bonds of the Company's obligations under the letters of credit are subject to periodic tender at which time their interest then supporting the 1985 Pollution Control Revenue Bonds rates are subject to redetermination.
(1985 PCRBs). The 1985 PCRBs are presently supported by The Company has $ 400 million of EFRBs that were converted unsecured letters of credit discussed below under the heading in June 1992 from a variable weekly interest rate to a Axed Authority Financing Notes.
annual rate of 7.15% and $ 100 million of EFRBs that were converted in January 1993 from a variable weekly interest 1989 Revolving Credit Agreement The Company has rate to a Axed annual rate of 6.90%. Letters of credit an estimated $ 251 million available to it through October 1, supporting these EFRBs, by their terms, were terminated 1993, under its $ 300 million 1989 Revolving Credit Agree-upon the conversion to a fixed interest rate.
ment (1989 RCA). This line of credit is secured by a Arst lien upon the Company's accounts receivable and fuel oil The 1985 PCRBs are supported by letters of credit pursuant inventories. to which the letter of credit bank has agreed to pay the principal, interest and premium on the tendered 1985 PCRBs, The Company has, with the approval of the NRC, dedicated in the aggregate, up to approximately $ 163 million in the
$ 49 million of the 1989 RCA sufficient to cover estimated, not event of default. The obligation of the Company to reimburse yet incurred, costs attributable to the decommissioning of the letter of credit bank is unsecured. These letters of credit Shoreham. As of December 31, 1992, LIPA was projecting, expire on March 16, 1996, at which time the Company is based on current information, that the Shoreham decommis-required to obtain either an extension of the letters of credit sioning costs would total $ 160 million. The Company has or substitute credit backup. If neither can be obtained, the provided LIPA with funds aggregating approximately 1985 PCRBs must be redeemed unless the Company
$ 111 million for decommissioning costs incurred to date purchases the 1985 PCRBs in lieu af redemption and and for decommissioning costs expected to be incurred subsequently remarkets them. Prior to December 16, 1992, during the first quarter of 1993. Actual decommissioning the letters of credit supporting the 1985 PCRBs were partially costs may differ from LIPA's current estimate. The amount secured by the Fourth Mortgage in the amount of $ 85 of credit available to the Company under the 1989 RCA million.
will increase as decommissioning costs are funded by the Company.
Fair Values of Long-Term Debt The carrying amounts At December 31, 1992, no amounts were outstanding under and fair values of the Company's long-term debt consisted of the 1989 RCA. The Company has the option, when amounts the following at December 31, 1992:
are outstanding, to commit to one of three interest rates (In thousands of dollars) including: (a) the Adjusted Certificate of Deposit Rate which is a rate based on the certificate of deposit rates of certain of Fair Car~ing Valve Amount the lending banks, (b) the Base Rate which is generally a rate based on Citibank, N.A.'s prime rate and (c) the Eurodallar First Mortgage Bonds $ 397,971 $ 400,000 Rate which is a rate based on the London Interbank Offering General and Refunding Bonds 1,891,842 1,801, Rate (LIBOR). The Company has agreed to pay a fee of one Debentures 2,523,721 2,428, quarter of one percent per annum on the unused portion. Authority Financing Notes 729,61 0 716, The termination date of the 1989 RCA may be extended for Total Long-Term Debt $ 5,543,144 $ 5,345,733
(In thousands of dollars) gT Dbt b 31 Maturity Interest Rate Series 1992 1991 First Mortgage Bonds (excludes Pledged Bonds)
April 1, 1993 4.40% M 40,000 40,000 June 1, 1994 4 5/8% N 25,000 25,000 u
June 1, 1995 4.55% 0 25,000 25,000
, March 1, 1996 5 1/4% P 40,000 40,000.
April 1, 1997 5 1/2% Q 35,000 35,000 September 1, 1999 8.20% R 35,000 35,000 September 1, 2000 9 1/8% S 25,000
'pril 1, 2001 7 1/4% U 40,000 40,000 December 1, 2001 7 1/2% V 50,000 50,000 September 1, 2002 7 5/8% W 50,000 50,000 December 1, 2003 8 1/8% X 60,000 60,000 t
TotalFirstMort a e Bonds 400,000 425,000 General and Refunding Bonds May 1, 1996 8 3/4% 415,000 415,000 February 15, 1997 8 3/4% 250,000 250,000 March 1, 1999 9.75% 63,000 May 15, 1999 7 85% 56,000 May 15, 2006 8.50% 75,000 June 1, 2006 9 5/8% 70,000 December 1, 2006 8 5/8% 50,000 50,000 May 1, 2007 8 5/8% 85,000 85,000 April 1, 2008 9.20% 75,000 July 15, 2008 7.90% 80,000 May 1, 2021 9 3/4% 415,000 415,000 Jul 1,2024 9 5/8% 375,000 375,000 1,801,000 1,798,000 Third Mortgage/1989 Term Loan Agreement 446,341 Debentures April 1, 1993 11 3/8% 375,000 375,000 November 15, 1993 11.70% 175,000 175,000 June 15, 1994 10.25% 400,000 400,000 November 15, 1994 11.75% 175,000 175,000 June 15, 1999 10.875% 30,545 350,000 July 15, 1999 7.30% 397,000 June 15, 2019 11.375% 4,513 350,000 July 15, 2019 8.90% 420,000 November 1, 2022 9% 451,000 Total Debentures 2,428,058 1,825,000 Authority Financing Notes Pollution Control Revenue Bonds December 1, 2006 7.5% 1976A 28,375 28,375 December 1, 2009 7.8% 1979 B 19,100 19,100 October 1, 2012 8 1/4%'p/ 1982 17,200 17,200 March 1, 2016 1985A,B 150,000 150,000 Electric Facilities Revenue Bonds September 1, 2019 7.15% 1989A,B 100,000 100,000 June 1, 2020 7.15% 1990A 100,000 100,000 December 1, 2020 7.15% 1991 A 100,000 100,000 February 1, 2022 7.15% 1992 A,B 100,000 August 1, 2022 3 95P/ 44 4 1992 C 50,000 August 1, 2022 4p/ 44 4 1992 D 50,000 ustrial Development Revenue Bonds December 1, 2006 7.5% 1976A,B 2,000 2,000 tal Authority Financin Notes 716,675 516,675 Total Long-Term Debt 5,345,733 5,011,016 Less Current maturities 590,000 10,000 Total Long-Term Debt Less Current Maturities $ 4,755,733 S5,001,016
"'Tendered
'Converted every throe years, next tondor October 1994. "Tendorod annually an March 1.
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 Periodic pension cost for 1992, 1991 and 1990 for the Primary Plan included the following components:
Pension Plans The Company maintains a primary Itn thousands of dollaa) defined benefit pension plan (Primary Plan) which covers 1992 1991 1990 substantially all employees, a supplemental plan (Supplemental Plan) which covers officers and certain key Service cost benefits executives and a retirement plan which covers the Board earned during the period $ 13,661 $ 14,323 $ 12,720 of Directors (Directors'lan). Interest cost on projected benefit obligation and Primary Plan The Company's funding policy is to contribute service cost 39,574 33,698, 32,264 annually to the Primary Plan a minimum amount consistent Actual return on plan assets (47,156) (63,875) (23,121) with the requirements of the Employee Retirement Income Net amortization and deferral 12,849 33,569 (5,449)
Security Act of 1974 (ERISA) plus such additional amounts, if Net eriodic pension cost $ 18,928 $ 17,715 $ 16,414 any, as the Company may determine to be appropriate from time to time. Assumptions used in accounting for the Primary Plan were:
For service before January 1, 1992, pension benefits are determined based on the greater of an accrued benefit as 1992 1991 1990 of December 31, 1991, or applying a moving five-year Discount rate 7.75% 7.75% 7.25%
average to a certain percentage per year of service. For Rate of future compensation service after January 1, 1992, pension benefits are increases 5.5% 5.5% 6.0%
established by crediting the employee with an amount Long-term rate of return on determined using the base salary for each year the employee assets 75% 7Q% 7Q%
is a participant in the plan. This change in the pension benefits calculation resulted in an increase of approximately The Primary Plan assets at fair value primarily include cash,
$ 70 million in the actuarial present value of projected benefit cash equivalents, group annuity contracts, bonds and listed obligation. Employees are vested in the pension plan after equity securities.,
five years of service with the Company.
Supplemental Plan The Supplemental Plan, the cost of The Primary Plan's funded status and amounts recognized on which is borne by the Company's shareowners, provides the Balance Sheet at December 31, 1992 and 1991 were as supplemental death and retirement benefits for officers follows: and other key executives without contribution from such employees. The Supplemental Plan is a non-qualified plan fin thousands of dollaa) 1991 under the Internal Revenue Code. Death benefits are 1992 currently provided by insurance. The provision for retirement Actuarial present value of benefit benefits, which is unfunded, totaled approximately $ 685,000, obligation $ 675,000 and $ 561,000 and was recognized as an expense Vested benefits $ 453,201 $ 375,326 in 1992, 1991 and 1990, respectively.
Nonvested benefits 4,326 5,315 Directors'lan The Directors'lan, adopted in February Accumulated benefit obligation $ 457,527 $ 380,641 1990, provides benefits to directors who are not officers of the Company. Directors who have served in that capacity for Plan assets at fair value $ 556,399 $ 519,816 more than five years qualify as participants under the plan.
Actuarial present value of The Directors'lan is a non-qualified plan under the Internal projected benefit obligation 536,818 446,718 Revenue Code. The provision for retirement benefits, which Projected benefit obligation is unfunded, totaled approximately $ 133,000, $ 101,000 less than plan assets 19,581 73,098 and $ 99,000 and was recognized as an expense in 1992, Unrecognized January 1, 1991 and 1990, respectively.
net obligations 98,147 33,113 Unrecognized net gain (128,218 (114,389)
Net accrued pension cost $ (10,490 $ (8,178) 0
tretlrement Benefits Other Than Pensions In condition and results of operations. The Company believes it dition to providing pension benefits, the Company provides will be permitted to recover these costs through rates. The certain medical and life insurance benefits for retired employ- Company must adopt SFAS No. 112 by January 1, 1994, ees. Substantially all of the Company's employees may and does not expect to do so prior to that date.
become eligible for these beneRts if they reach retirement age after working for the Company for a minimum of five years. Note 9. Commitments and Contingencies These and similar beneRts for active employees are provided by the Company or by insurance companies whose premiums Litigation On February 11, 1988, the Company began a are based on the benefits paid during the year. The cost of lawsuit in Suffolk County Supreme Court against Suffolk providing these benefits on a pay-as-you-go method was County, seeking the recovery of approximately $ 54 million
$ 38,044,000, $ 37,312,000 and $ 29,410,000 for 1992, in damages for Suffolk County's breach of a contract to 1991 and 1990, respectively, and were recognized as an prepare an offsite emergency response plan for Shoreham expense as beneRts and premiums were paid. The cost of (Long Island Lighting Company v. County of Suffolk). In providing these benefits for approximately 2,200 retirees addition, the complaint alleges that, because of the delays is not separable from the cost of providing benefits. for that have resulted, the Company has been damaged in an approximately 6,200 active employees for the years 1990 additional amount of $ 706 million. On October 30, 1992, through 1992. the court granted in part and denied in part Suffolk County's motion to amend its answer to assert additional defenses and In December 1990, the FASB issued SFAS No. 106, counterclaims. Two proposed counterclaims were allowed Employers'ccounting for Postretirement Benefits Other seeking approximately $ 16 million in damages as well as Than Pensions which requires the Company to recognize the
$ 700 million in alleged punitive damages. The outcome of expected cost of providing postretirement benefits when these counterclaims, if adverse, could have a material effect employee services are rendered rather than on a pay-as-on the financial condition of the Company. The Company has you-go method.
argued that there is no basis for punitive damages and The Company will adopt the provisions of SFAS No. 106 intends to vigorously prosecute its claim against Suffolk
'ng the first quarter of 1993 and record an accumulated County and to defend against these counterclaims.
retirement benefitobligation and a corresponding regula-ry asset of approximately $ 376 million. This regulatory Commitments The Company has entered into substantial asset will be amortized and recovered in rates over a twenty- commitments for fossil fuel, gas supply, purchased power year period. Additionally, as a result of adopting SFAS No. and transmission facilities. The costs associated with these 106, the Company's annual postretirement benefit expense commitments are normally recovered from ratepayers will increase approximately $ 44 million above the amount through provisions in the Company's rate schedules.
previously recorded under the pay-as-you-go method.
Nuclear Plant Insurance The Company has property In 1992, the PSC staff issued a proposed generic accounting damage insurance and third-party bodily injury and property order which proposes that the effects of implementing SFAS liabilityinsurance for its 18% share in NMP2 and for No. 106 be phased into rates. The PSC proposes that the Shoreham. The premiums for this coverage are not material.
difference between the postretirement beneRt expense The policies for this coverage provide for retroactive recorded for accounting purposes in accordance with SFAS premium assessments under certain circumstances. Maximum No. 106 and the postretirement beneRt expense reflected in retroactive premium assessments could be as much as rates will be deferred and accumulated as a regulatory asset.
approximately $ 4.7 million. For property damage at each The ongoing annual postretirement benefit expense will be nuclear generating site, the NRC requires a minimum of phased into and fully reflected in rates within a Rve-year
$ 1.06 billion of coverage. The NRC has provided Shoreham period with the accumulated postretirement obligation being with a partial exemption from these requirements for recovered in rates over a twenty-year period.
Shoreham.
In November 1992, the FASB issued SFAS No. 112, Under certain circumstances, the Company may be assessed Employer's Accounting for Postemployment Benefits. SFAS additional amounts in the event of a nuclear incident. Under No. 112 establishes accounting standards for employers who agreements established pursuant to the Price Anderson Act, provide benefits to former or inactive employees after the Company could be assessed up to approximately $ 74 employment but before retirement. SFAS No. 112 requires million per nuclear incident in any one year at any nuclear employers to recognize the obligation to provide unit, but not in excess of approximately $ 12 million in employment benefits if the following conditions are met:
payments per year for each incident. The Price Anderson Act bligation is attributable to employees services already also limits liabilityfor third-party bodily injury and third-party ndered, employee rights to those benefits are accumulated or vested, payment is probable and the amount of the benefit property damage arising out of a nuclear occurrence at each unit to $ 7.4 billion.
is reasonably estimated. The Company has not yet evaluated the effect of implementing SFAS No. 112 on its financial
Note 10. Federal Income Taxes The amount of investment tax credit (ITC) carryforward fo financial statement purposes after 1992 is approximately On April 17, 1989, the Company received a private letter $ 206 million. The Revenue Agents have proposed ITC ruling from the IRS which stated that the Company would be adjustments which, if sustained, would reduce the Company's entitled, for federal income tax purposes, to an abandon- carryforward by approximately $ 96 million. These credits ment loss deduction in connection with Shoreham, upon expire by the year 2002. In accordance with the Tax Reform effectiveness of the 1989 Settlement. The Company claimed Act of 1986 (TRA 86), ITC allowable as credits to tax returns an abandonment loss deduction on its 1989 federal income for years after 1987 must be reduced by 35%. The amount of tax return of approximately $ 1.8 billion. The Company's net the reduction will not be allowed as a credit for any other operating loss carryforward is estimated to be approximately taxable year.
$ 2.3 billion at December 31, 1992. The Company has not provided deferred taxes on approxi-On January 8, 1990 and October 10, 1992, the Company mately $ 500 million of various other deductions and received Revenue Agents'eports disallowing certain depreciation method differences'for property placed in deductions claimed by the Company on its tax returns for the service prior to 1981 which, in conformity with the audit cycle years 1984-1987 and 1988-1989, respectively. ratemaking 'practices of the PSC, have been flowed through.
The Revenue Agents'eports reflects proposed adjustments These various other flow-through tax deductions, which were to the Company's federal income tax returns for 1984 deductible currently for tax purposes but capitalized for through 1989 which, if sustained, would give rise to tax accounting and ratemaking purposes, include certain taxes, deficiencies totaling approximately $ 220 million. The a portion of AFC, pensions and certain other employee Company is protesting some of the adjustments and seeks an benefits. See Note 1 with respect to a change in the method administrative and, if necessary, a judicial review of the of accounting for income taxes which the Company will conclusions reached in the Revenue Agents'eports. The adopt during the first quarter of 1993.
Company cannot predict either the timing or the manner in which this matter will be 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 will be 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.
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 of dollars) 1992 1991 1990
%of %of %of Pre-tox Pre.tax Pre-tax Amount Income Amount Income Amount Income Federal income tax, per Statement of Income Current $ 530 $ 515 $ 3,638 Deferred and other (see Note 1) 1989 Settlement Shoreham property 3,806 10,677 3,239 Bokum Resources Corporation 20,400 Rate moderation component 10,351 77,715 101,053 Other 1989 Settlement items (5,499) (13,638) (13,577)
Shoreham post settlement costs 60,125 50,375 61,475 Contractor litigation settlement (18,758)
Class Settlement (1,190) (2,038) (534)
Interest capitalized (2,100) (2,562) (3,220)
Mortgage recording tax (222) 4,653 (589)
Accelerated tax depreciation 35,951 30,447 33,342 Call premiums 35,441 18,496 (3,111)
Fuel cost adjustments 8,747 (3,289) 4,879 Capitalized overheads 180 2,287 tired debt costs 2,645 9,185 temaking and performance plan 17,680 (371) ien date property taxes (6,161)
Other items, net 858 (334) (5,601 Total Deferred and Other 160,432 181,138 179,643 Total federal income tax expense 160,962 181,653 183,281 Income before cumulative effect of accounting change 301,974 305,538 319,637 Income Before Cumulative Effect of Accounting Change and Income Taxes $ 462,936 $ 487,191 $ 502,918 Statutory federal income tax $ 157,398 34.0% $ 165,645 34.0% $ 170,992 34.0%
Additions (reductions) in federal income tax resulting from:
1989 Settlement Shoreham property 4,003 0.9 4,003 0.8 4,035 0.8 Allowance for funds used during construction (4,118) (0.9) (1,310) (0.3) (2,573) (0.5)
Lien date property taxes 277 0.1 (8,757) (1.8)
Tax credits (6,586) (1.4) (2,980) (0.6) 1,537 0.3 Excess of book depreciation over tax depreciation 12,193 2.6 13,108 2.7 11,987 2.4 Interest capitalized 2,947 0.6 4,232 0.9 6,031 1.2 Other items, net 4,875) (1.0 1,322 (0.3 29 00 Total Federal Income Tax Expense $ 160,962 34.8% $ 181,653 37.3% $ 183,281 36.4%
Note 11. Segments of Business The Company is a public utility operating 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 utility plant, 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 of dollars)
For year ended December 31 1992 1991 1990 Operating revenues Electric $ 2,194,632 $ 2,196,568 $ 2,095,660 Gas 427,207 351,161 361,242 Total $ 2,621,839 $ 2,547,729 $ 2,456,902 Operating expenses (excludes federalincomo taxes)
Electric $ 1,354,959 $ 1,252,993 $ 1,151,105 Gas 352,777 338,295 322,515 Total $ 1,707,736 $ 1,591,288 $ 1,473,620 Operating income (before federalincome taxes)
Electric $ 839,673 $ 943,575 $ 944,555 Gas 74,430 12,866 38,727 Total 914,103 956,441 983,282 AFC (12,111) (5,794) (7, Other income and deductions (49,128) (48,772) (20,'08,2 Interest charges 512,406 523,816 Federalincome taxes operating 172,998 169,452 180,652 Federal income taxes non o eratin (12,036) 12,201 2,629 Income before cumulative effect of accounting change 301,974 305,538 319,637 Cumulative effect of accounting change (net of a licable taxes 11,680 Net Income $ 301,974 $ 305,538 $ 331,317 Depreciation and amortization Electric $ 104,034 $ 104,172 $ 98,022 Gas 15,103 14,783 12,862 Total $ 119,137 $ 118,955 $ 110,884 Construction and nuclear fuel 144,356 151,425 expenditures'lectric
$ 163,609 $ $
Gas 109,295 93,195 81,040 Total $ 272,904 $ 237,551 $ 232,465
'Includes non-cash allowance for other funds used during construction and excludes Shoreham post settlement costs.
(In thousands of dollars)
At December 31 1992 1991 1990 Identifiable assets Electric $ 8,351,370 $ 7,986,887 $ 7,643,963 Gas 767,444 621,570 540,3 Total 9,118,814 8,608,457 8,184, Assets utilized for overall Com an o erations 1,129,810 934,844 658,36 Total Assets $ 10,248,624 $ 9,543,301 $ 8,842,684
te 12. Quarterly Financial information udited J In thousands of dollars exce t earnin s er common share 1992 1991 Operating revenues For the quarter ended March 31 $ 697,761 $ 657,921 June 30 580,498 543,250 September 30 747,729 773,706 December 31 595,851 572,852 Operating income For the quarter ended March 31 $ 179,741 $ 207,830 June 30 166,954 166,830 September 30 256,800 268,041 December 31 137,610 144,288 Net income For the quarter ended March 31 $ 66,7O6 $ 86,4O4 June 30 59,285 50,089 September 30 141,388 144,449 December 31 34,595 24,596 Earnings for common stock For the quarter ended March 31 $ 50,553 $ 69,567 June 30 41,040 33,013 September 30 126,295 128,175 December 31 20,132 8,389 s nings per common share For the quarter ended March 31 $ .45 $
June 30 .37 .30 September 30 1.14 1.15 December 31 .18 .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 1992 1991 1990 1989 Summary of Operations(See Notes to Financial Statements) Tab, Total revenues (000) $ 2,621,839 $ 2,547,729 $ 2,456,902 $ 2,347,614 $ 2,137,834 Total operating income (loss) (000)
Before federal income taxes $ 914,103 $ 956,441 S 983,282 $ (93,997) $ 701,049 After federal income taxes $ 741,105 $ 786,989 S 802,630 S 620,423 $ 500,938 Income (loss) before cumulative effect of accounting changes (000) S 301,974 S 305,538 S 319,637 S (95,803) S 298,490 Cumulative effect of accounting change for unbilled gas revenues (net of taxes) (000) S 11,680 Cumulative effect of accounting change for disallowed costs (net of taxes) (000) $ (1,345,110)
Earnings (loss) for common stock (000) $ 238,020 $ 239,144 $ 263,156 $ (175,035) $ (1,121,128)
Average common shares outstanding (000) 111,439 111,348 111,290 111,215 111,177 Earnings (loss) per common share Before cumulative effect of accounting changes $ 2.14 $ 2.15 $ 2.26 $ (1.57) $ 2.02 Cumulative effect of accountin chan es .10 12.10 Earnin s loss ercommonshare S 2.14 S 2.15 S 2.36 S (1.57 S (10.08 Pro forma earnings with accounting changes for unbilled gas revenues and disallowed project costs applied retroactively Earnings (loss) for common stock (000) $ 251,476 S (173,251) S 223,712 Earnin s loss er common share S 2.26 S 1.56 S 2.01 Common stock dividends declared per share S 1.72 S 1.60 S 1.25 S .50 Common stock dividends paid per share S 171 S 155 S 1125 S .25 Book value per common share at year end S 1958 S 1913 S 1857 S 1745 S 1 Common shareowners at ear end 86,111 90,435 82,903 85,142 93, Ratio of earnings to fixed charges 1.90 1.93 1.98 1.95 Ratio of earnings to combined fixed charges and preferred stock dividends 1.59 1.60 1.64 1.58 Ratio of earnings to fixed charges (excluding AFC and RMC) 1.73 1.40 1.36 1.60 Ratio of earnings to combined fixed charges and preferred stock dividends (excluding AFC and RMC) 1.46 1.17 1.12 1.30
'The Company had no earnings to cover fixed charges.
In thousands of dollars Operations and Maintenance Expense Details 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 289,741 274,162 260,039 211,933 184,351 Fuels electric operations 282,138 354,859 444,458 461,576 410,174 Fuels gas operations 182,201 175,046 175,877 188,139 172,431 Purchased power costs 280,914 197,154 168,749 128,368 88,465 Fuel cost ad'ustments deferred (3,469) 41,643 2,085 5,631 3,359 Total Fuel and Purchased Power 741,784 768,702 786,999 772,452 674,429 All other 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 of dollars) 1992 1991 1990 1989 1988 ectric Operating Income Table 3 Revenues Residential $ 1,045,799 $ 1,047,490 $ 997,868 915,644 835,584 Commercial and industrial 1,076,302 1,070,098 1,017,387 981,740 883,267 Other s stem revenues 49,395 47,838 46,673 42,232 40,518 Total system revenues 2,171,496 2,165,426 2,061,928 1,939,616 1,759,369 Sales to other utilities 9,997 23,040 24,140 42,880 24,152 Other revenues 13,139 8,102 9,592 792 3,412 Total Revenues 2,194,632 2,196,568 2,095,660 1,983,288 1,786,933 Expenses Operations fuel and purchased power 559,583 593,656 611,122 584,313 501,998 Operations other 294,909 296,798 271,608 237,931 195,283 Maintenance 105,341 127,446 118,545 115,502 96,599 Depreciation and amortization 104,034 104,172 98,022 91,759 82,811 Base financial component amortization 100,971 100,971 100,971 50,485 Regulatory liability component amortization (88,573) (88,573) (88,573) (44,286)
Other regulatory amortizations (21,984) 8,666 14,427 1,248 Rate moderation component (30,444) (228,572) (297,214) (131,167)
Regulatory liability component 793,592 Jamesport amortization 104,160 Operating taxes 331,122 338,429 322,197 312,456 262,644 Federal income tax current 530 515 3,138 14,612 18,394 Federal income tax deferred and other 158,908 173,259 169,274 738,500 166,557 al Ex enses 1,514,397 1,426,767 1,323,517 1,392,105 1,324,286 ctric Operating Income 680,235 769,801 772,143 591,183 462,647 (In thousands of dollars Gas Operating Income Table 4 Revenues Residential space heating 243,950 190,976 198,734 209,192 201,312 other 33,035 29,383 30,854 31,692 31,803 Non-residential space heating 90,363 70,938 68,441 72,351 68,114 other 29,094 25,515 26,501 28,674 28,078 Total firm revenues 396,442 316,812 324,530 341,909 329,307 Interru tible revenues 19,658 21,686 30,515 19,226 18,821 Total system revenues 416,100 338,498 355,045 361,135 348,128 Other revenues 11,107 12,663 6,197 3,191 2,773 Total Revenues 427,207 351,161 361,242 364,326 350,901 Expenses Operations fuel 182,201 175,046 175,877 188,139 172,431 Operations other 77,300 78,469 68,910 59,587 53,415 Maintenance 20,395 20,046 16,746 14,286 12,599 Depreciation and amortization 15,103 14,783 12,862 11,671 10,785 Regulatory amortizations (88)
Operating taxes 57,866 49,951 48,120 51,935 48,220 Federal income tax current 500 Federal income tax deferred and other 13,560 4,322 7,740 9,468 15,160 tal Ex enses 366,337 333,973 330,755 335,086 312,610 s Operating Income 60,870 17,188 30,487 29,240 38,291
1992 )991 1990 1989 Electric Sales and Customers Sales millions of kWh Residential 6,788 7,022 7,022 7,063 6,979 Commercial and industrial 8,181 8,322 8,359 8,636 8,566 Other 471 469 472 470 483 System sales 15,440 15,813 15,853 16,169 16,028 Sales to other utilities 227 598 532 633 445 Total Sales 15,667 16,411 16,385 16,802 - 16,473 Customers monthly average Residential 902,885 898,974 895,294 890,406 882,962 Commercial and industrial 101,838 101,740 101,562 100,481 98,450 Other 4,593 4 540 4 504 4 452 4 436 Customers total monthly average 1,009,316 1,005,254 1,001,360 995,339 985,848 Customers total at ear end 1,009,028 1 005 363 1 001 441 996 488 989 097 Residential kWh per customer 7,518 7,812 7,844 7,932 7,905 Revenue er kWh 15.41'4.92 14.21 12.96'1.97'ommercial and Industrial 80,346 81,797 82,304 87,005 kWh per customer Revenue er kWh 13.16'2.86'2.17'5,943 11.37'0.31'ystem 15,297 15,731 15,832 16,245 kWh per customer Revenue per kWh 14.06'3.69< 13.01'2.00'6,258 10.
Gas Sales and Customers Sales thousands of dth Residential space heating 35,089 29,687 29,810 32,024 31,276 other 3,203 3,195 3,448 3,491 3,589 Non-residential space heating 13,662 11,636 11,271 11,548 11,054 other 4,338 4,171 4,352 4,539 4,580 Total firm sales 56,292 48,689 48,881 51,602 50,499 Interru tible sales 5,090 4,538 6,347 5,300 5,078 Total Sales 61,382 53,227 55,228 56,902 55,577 Customers monthly average Residential space heating 227,834 220,562 211,400 204,982 198,949 other 169,189 171,581 176,000 179,415 181,926 Non-residential space heating 31,666 30,453 29,072 27,733 25,979 other 10,777 11,003 11,310 11,517 11,725 Total firm customers 439,466 433,599 427,782 423,647 418,579 Interruptible customers 531 472 410 359 325 Customers total monthly average 439,997 434,071 428,192 424,006 418,904 Customers total at ear end 442,117 436,853 430,571 426,060 421,429 Residential dth per customer 96.4 83.9 85.8 92.4 91.5 Revenue per dth $ 7.23 $ 67O $ 6.90 $ 6.78 $ 6.69 Non-residential dth per customer 424.1 381.3 386.9 409.9 41 Revenue per dth $ 664 $ 6.10 $ 6O8 $ 628 $
System dth per customer 139.5 122.6 128.9 134.2 132.7 Revenue per dth $ 6.78 $ 6.36 $ 6.43 $ 6.35 $ 6.26 O
1992 1991 1990 1989 1988 ctric Operations Table 7 Energy millions of kWh Net generation 10,592 13,570 13,981 15,220 15,228 Power purchased net 6,211 3,638 2,989 2,087 1,940 Total system requirements 16,803 17,208 16,970 17,307 17,168 Company use and unaccounted for (1,363 (1,395) (1,117) (1,138) (1,128)
System sales 15,440 15,813 15,853 16,169 16,040 Sales to other utilities 227 598 532 633 433 Total Energy Available 15,667 16,411 16,385 16,802 16,473 Peak Demand mW Station coincident demand 2,975 3,085 3,260 3,178 3,347 Power purchased net 636 819 426 510 475 System Peak Demand 3,611 3,904 3,686 3,688 3,822 System Capability mW LILCO stations 4,091 4,078 4,077 4,066 3,834 Nine Mile Point 2 (LILCO's 18% share) 188 194 194 194 194 Firm purchases net 170 244 300 400 482 Total Capability 4,449 4,516 4,571 4,660 4,510 Fuel Consumed for Electric Operations Oil thousands of barrels 10,656 15,314 16,401 20,480 19,927 Gas thousands of dth 34,475 32,924 36,477 26,490 29,126 Nuclear thousands of mW days 124 154 108 105 87 tal billions of Btu 102,126 129,937 139,874 154,669 153,828 lars per million Btu $ $ 2.61 $ 307 $ 2.86 $ 2.53 ts per kWh of net generation 2.76< 2.73/ 3.24< 2.67<
Heat rate Btu per net kWh 3.06'0,704 10,558 10,484 10,564 10,545 Fuel Mix (f'ereentage of system requirements)
Oil 37% 50% 56% 67% 68%
Gas 19 18 20 13 15 Purchased Power 38 25 20 16 13 Nuclear Fuel 6 7 4 4 Total 100% 100% 100 100% 100%
Gas Operations Table 8 Energy thousands of dth Natural gas 64,911 55,579 55,407 60,359 58,743 Manufactured gas and change in storage 48 60 (15) 53 (18)
Total Natural and Manufactured Gas 64,959 55,639 55,392 60,412 58,725 Total system requirements 64,959 55,639 55,392 60,412 58,725 Company use and unaccounted for 3,577 (2,412) (164) (3,510) (3,148)
Total Energy Available 61,382 53,227 55,228 56,902 55,577 Maximum Day Sendout dth 448,726 435,050 406,177 462,610 431,940 System Capability dth per day Natural gas 561,584 507,344 507,344 461,788 411,596 LNG manufactured or LP gas 120,700 128,200 128,200 145,600 145,600 Total Capability 682,284 635,544 635,544 607,388 557,196 endar Degree Days
-year average 5,028) 5,066 4,378 4,139 5,169 5,162
fin thousands of dolla Construction Expenditures'992 1991 1990 1989 Tab Electric Production 46,217 $ 32,541 S 36,400 S 59,880 S 419,028 Transmission 15,535 12,452 23,418 9,022 13,379 Distribution 74,951 74,770 82,975 66,679 64,653 General (includes nuclear fuel) 5,049 9,880 (1,765) 3,615 17,227 Electric Total 141,752 129,643 141,028 139,196 514,287 Gas Total 104,028 89,950 78,766 49,847 37,518 Common Total 27,124 17,958 12,671 11,007 9,352 Total Construction Expenditures $ 272,904 S 237,551 S 232,465 S 200,050 $ 561,157
'Includes noncash allowance for other funds used during construction and excludes Shoreham post settlement costs.
(In thousands of dollars)
Balance Sheet Table 10 Assets Utility plant 4,544,020 $ 4,334,736 $ 4,150,822 $ 3,939,410 $ 8,017,047 Less Accumulated depreciation and amortization 1,382,872 1,332,003 1,262,743 1,158,253 1,071,923 Total Net Utility Plant 3,161,148 3,002,733 2,888,079 2,781,157 6,945,124 Regulatory asset 3,685,432 3,786,403 3,887,373 3,988,344 Nonutility property and other investments 20,730 9,788 6,381 6,050 69,271 Current assets 916,914 884,017 726,060 982,032 571,934 Deferred charges Rate moderation component 651,657 602,053 411,443 102,971 Shoreham post settlement costs 586,045 378,386 225,818 75,044 Unamortized cost of issuing securities Shoreham nuclear fuel 380,267 77,629 227,713 79,760 132,875 92,069 150,610 97,925 s2, Accumulated deferred income taxes 511,898 439,235 359,768 262,298 525,029 Other 256,904 133,213 112,818 73,607 162,290 Total Deferred Charges 2,464,400 1,860,360 1,334,791 762,455 740,008 Total Assets $ 10,248,624 S 9,543,301 S 8,842,684 S 8,520,038 S 8,326,337 Capitalization and Liabilities Capitalization Long-term debt 4,755,733 S 5,001,016 S 4,556,016 S 4,560,016 S 3,449,821 Unamortized premium and (discount) on debt (14,731) ( 14,850) (23,125) (28,587) (25,011)
Preferred stock redemption required 557,900 524,912 527,550 541,187 513,924 Preferred stock no redemption required 154,276 154,371 154,674 155,592 221,050 Treasury stock, at cost (58,430)
Retained earnings restricted for preferred stock dividend requirements 341,008 Common stock and premium 1,556,091 1,550,334 1,549,505 1,547,971 1,557,293 Capital stock expense (39,304) (40,216) (42,676) (42,916) (56,151)
Retained earnings 667,988 620,373 560,405 436,690 679,579 Total Capitalization 7,637,953 7,795,940 7,282,349 7,169,953 6,623,083 Current Liabilities 1,191,787 492,895 449,830 470,885 583,017 Deferred Credits 1989 Settlement credits 164,294 173,507 182,720 191,933 Class Settlement 167,066 173,564 167,569 164,040 Accumulated deferred income taxes 970,373 816,053 634,704 430,933 963,97 Other 110,341 84,035 117,172 81,443 144, Total Deferred Credits 1,412,074 1,247,159 1,102,165 868,349 1,107, Reserves for Claims, Damages, Pensions and Benefits 6,810 7,307 8,340 10,851 12,247 I
Total Capitalization and Liabilities $ 10,248,624 $ 9,543,301 $ 8,842,684 $ 8,520,038 S 8,326,337
1992 1991 1990 1989 1988 pitalization Table 11 debt Ratios'ong-term 65% 64% 62% 63% 53%
Preferred stock 9 9 10 10 15 Common equity 26 27 28 27 32 Total Capitalization 100% 100% 100% 100% 100%
'Includes current motunties of long-term debt and current redemption requirements of preferred 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 AA of 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 1991 Quarter Quarter First Second Third Fourth First Second Third Fourth Common Stock High 24'/e 24'/4 25s/e 25r/a 23'/s 23/e 24'/~ 25 Low 22'/e 22/e 23'/e 23'/e 19 21'/~ 22'/e 23'/
Preferred Stock Series B 5.00% High Low 61 56'/z 66 57 70 65 67 62 53'/~
48 54 51'/2 5 6s/4 53 '2 58 Series E 4.35% High 52'/4 59'/2 62 60 47 46'/4 49 52 Low 49 491/2 55 54 431/2 441/2 45 471/g Series l 5 /4% High 138 146'/2 136 125 131 131
'36 134 141 /e 139 Low 133 143'/e Series J 8.12% High 96'/~ 96'/4 100 /s 101 85'/2 86 91 94 Low 92 92'/~ 94'/2 96 78 82s/4 83 88'/e Series K 8.30% High 98'/2 98 102 101 85 88 91 97 Low 94 1/2 94 96 1/4 97 1/2 78 83'h 85 91 Series 0 $ 2.47 High 28 28 29'/ 27'/~ 25s/4 26'/2 27 27s/e Low 26'/e 26 26 25'/z 24'/4 24% 25 26 Series P $ 2.43 High 27/e 28'/~ 29'/e 28'/s 25 /s 27'/~ 27s/e 28 Low 26% 27'/4 27/e 27/s 24th 24% 25>/s 26/e Series S 9.80% High 105s/s 105 99/e 101 102'/z 105 Low 102 102'/2 96'h 100 101 102 Series T $ 3.31 High 273/4 27'/4 Low 26 26'/e Series Y $ 2.65 High 29 28'/e 27 27'li 28 28'/z Low 27s/a 27'/4 25 25~/a 26s/s 26'/e Series Z $ 2.35 High 28 /4 28 29 29 25'/2 26/e 28/e Low 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 102 103 Low 100s/e 100 referred Stock $ 100 par value, Series D 425% 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 Annual Meeting 175 East Old Country Road The Annual Meeting of Shareowners will be held on Hicksville, New York 11801 Tuesday, April 20, 1993 at 3:00 p.m. In connection with this meeting, proxies will be solicited by the Company.
Common Stock Usted New York Stock Exchange Form 10-K Annual Report Pacific Stock Exchange The Company will furnish, without charge, a copy of the Company's Annual Report, Form 10-K, as filed with Ticker Symbol: LIL the Securities and Exchange Commission, upon written request to: Investor Relations, Long Island Lighting Transfer Agent and Registrar Company, 175 East Old Country Road, Hicksville, Common Stock and Preferred Stock New York 11801.
The Bank of New York Shareholder Services Department 11th Floor 101 Barclay Street New York, NY 10286-1258 1-800-524-4458 Shareowners'Agent for Automatic 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 Anthony F. Earley, Jr. Richard L. Schmalensee rman of the Board and President and Director Chief Executive Officer Chief Operating Officer Center for Energy and Long Island Lighting Company Long Island Lighting Company Environmental Policy Research Massachusetts Institute of Technology A. James Barnes Winfield E. Fromm Dean Retired Vice President George J. Sideris School of Public and Eaton Corporation Retired Senior Vice President Finance Environmental Affairs Electrical Engineering Long Island Lighting Company Indiana University John H. Talmage Basil A. Paterson George Bugliarello Partner Partner President Meyer, Suozzi, English H.R. Talmage 8 Son Polytechnic University 8 Klein, PC Agriculture Law Renso L. Caporali Phyllis S. Vineyard Chairman of the Board Eben W. Pyne Director and Chief Executive Officer Corporate Director Long Island Community Grumman Corporation and Consultant Foundation W.R. Grace and Company Peter O. Crisp Retired Senior Vice President President Citibank, N.A.
Venrock, Inc.
Venture Capital Investments icers WilliamJ. Catacosinos Adam M. Madsen Walter F. Wilm, Jr.
Chairman of the Board and Vice President Vice President Chief Executive Officer Corporate Planning Edward J. Youngling Anthony F. Earley, Jr. Arthur C. Marquardt Vice President President and Vice President Customer Relations Chief Operating Officer Gas Operations James T. Flynn Brian R. McCaffrey Robert J. Grey Executive Vice President Vice President General Counsel Administration Edward C. Dietz Senior Vice President Joseph W. McDonnell Kathleen A. Marion Electric Business Unit Vice President Corporate Secretary and External Affairs Assistant to the Chairman Ralph T. Brandifino Vice President William G. Schiffmacher Anthony Nozzolillo Finance and Vice President Treasurer Chief Financial Officer Electric Operations Thomas J. Vallely, III William N. Dimoulas Robert B. Steger Controller Vice President Vice President Herbert M. Leiman Information Systems Fossil Production Assistant General Counsel and Technology William E. Steiger, Jr. and Assistant Corporate rt X. Kelleher Vice President Secretary
- President Engineering and Construction Human Resources Christian G. Wilding John D. Leonard, Jr. Vice President Vice President Conservation and Corporate Services and Load Management Nuclear Operations
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