Item 1. Business
(a) General development of business
New York State Electric & Gas Corporation (company) was organized under the laws of the State of New York in 1852.
The following general developments have occurred in the business of the company since January 1, 1994:
Rates and regulatory matters (See Item 1(c)(i) - Principal business and 1(c)(x) - Competitive conditions.)
Rate Matters
In September 1993 the company reached a three-year electric and natural gas rate-settlement agreement (Agreement) with the Public Service Commission of the State of New York (PSC) covering the period August 1, 1993 through July 31, 1996. Under the Agreement, the allowed return on equity was 10.8% in year one, 11.4% in year two and 11.4% (subject to an indexing mechanism) in year three. Shareholders were allowed to keep 100% of any earnings above the allowed return in year one. Shareholders and customers are to share, on a 50%/50% basis, any earnings over the allowed return in years two and three. The calculation of earnings over the allowed return includes regulatory adjustments (such as the elimination of the impact of incentives and sharing mechanisms) and certain normalizing adjustments (such as spreading the 1993 restructuring charge over the term of the Agreement). For year one, the twelve months ended July 31, 1994, the company's earned return on equity, with adjustments, as discussed above, was 10.3%. The earned returns on electric equity and natural gas equity, with adjustments, were 10.1% and 12.7% respectively, for year one.
The Agreement also includes a modified revenue decoupling mechanism (RDM) for electric sales. Rates are based on sales forecasts. Since actual sales may differ significantly from forecasted sales because of conservation efforts, unusual weather or changing economic conditions, revenues collected may be more or less than forecasted. Subject to the limits described below, the modified RDM lets the company adjust for most of the differences between forecasted and actual sales. For example, if revenues exceed the forecast for a given year, the excess is passed back to customers in a future year. If revenues are below the forecast, customers receive a surcharge in a future year. The company must share revenue excesses or shortfalls from sales to most large commercial and industrial customers on a 70%/30% (customer/shareholder) basis. In 1994 the company accrued $22.3 million under the modified RDM compared with $3.9 million in 1993. In 1993 the modified RDM covered only the period August through December.
Customer savings of $21 million in production and transmission operating costs are imputed over the three years of the Agreement, at $7 million each year, whether or not such savings are realized.
The estimated total electric price increases anticipated by the Agreement are $99.6 million, or 7.4%, in year one; $109.5 million, or 7.6% in year two; and $87.8 million, or 5.6% in year three. These include base rate increases plus estimated price increases for fuel, purchased power and other costs that are collected through the fuel adjustment clause (FAC). Actual costs collected through the FAC could vary from estimates, causing the total electric price increases to change.
The base rate increases for natural gas allowed by the Agreement are $7.5 million, or 2.9%, in year one; $8.2 million, or 3.0%, in year two; and $7.2 million, or 2.5%, in year three. They do not include changes in natural gas costs, which will be collected through the gas adjustment clause. Natural gas costs can be expected to rise and fall with overall natural gas market conditions. Such fluctuations will affect the total natural gas price increases.
The Agreement also provides for the stated base rate increases for electricity and natural gas to be adjusted up or down in the second and third years, as well as the year after the agreement period (year four). Base rates can be adjusted for several factors, such as electric sales, incentive mechanisms and other true-ups from the prior year. The electric base rate increases could be adjusted upward by up to 1.5% in years two and three and 1.6% in year four. The natural gas base rate increases could be adjusted upward by up to 1.0% in year two and 1.2% in year three. The Agreement does not specify a limit on the upward adjustment for natural gas base rates for year four. There is no limit to any downward adjustment of base rates for electric and natural gas.
In June 1994 the company finalized its filing of adjustments to the second-year electric and natural gas rates in accordance with the terms of the Agreement. The company took voluntary action to lower the estimated total electric price increase to 7.8%. The electric price increase, which was primarily due to increases in mandated purchases of electricity from non-utility generators (NUGs), increases in taxes and sales shortfalls related to mandated conservation programs and the weak economy in New York State, would have been substantially greater than 7.8% without the voluntary action. The filed natural gas base rate increase was 1.9%. On August 15, 1994, the PSC issued an Opinion and Order that approved the electric price increase of 7.8% and the 1.9% natural gas base rate increase effective August 1, 1994. In addition, the PSC directed the company and staff of the PSC to begin discussions on modifying the Agreement to mitigate the projected third-year electric increase and bring rate predictability and stability to future years. Those discussions began in October 1994 and are continuing.
The Agreement provides incentives (rewards or penalties) to the company for controlling production costs (PCI), improving customer service and implementing demand-side management (DSM) programs. Those incentives could have increased the company's allowed return to 12.3% or decreased it to 9.95% in year one, increase it to 13.05% or decrease it to 10.4% in year two, and increase it to 13.25% or decrease it to 10.2% in year three. In June 1994 the company calculated and recorded a production-cost penalty for 1993 of $13.0 million, or 12 cents per share. This was the maximum permitted by the Agreement.
The PCI is based on a comparison of the company with a 19- company peer group (which includes the company). The production measure compared is the relative change in production and certain other costs per megawatt-hour of retail sales occurring between the applicable calendar year and a base period (1989-1992). The company calculated the PCI penalty for 1993 using data reported in the peer group's Federal Energy Regulatory Commission (FERC) Form 1 Reports, which the company received in May 1994. The company's PCI penalty for 1993 was due primarily to a significantly lower increase in retail sales (after adjusting for the effect of sales lost due to DSM programs) for the company than for the peer group. It was also due to a greater increase in DSM program costs and purchased power costs for the company than for the peer group.
The company believes that a penalty for its PCI performance in 1994 is unlikely. This is primarily because of the company's recent cost-reduction efforts and improved sales compared to the sales increase of the peer group, which is projected to be less than the peer group's sales increase in 1993. This estimate includes the company's actual performance through December 31, 1994. However, it was necessary to make certain assumptions regarding the peer group's 1994 performance since the actual information needed for this calculation will not be available until the peer group's FERC Form 1 Reports become available in May 1995. As an example, retail sales units and certain production costs for the peer group were assumed to continue at the levels achieved through the first nine months of 1994. The maximum PCI allowed for 1994 by the agreement is a reward or penalty of $17.5 million, or 16 cents per share.
Diversification
Diversification will play an important role in the company's future. The company's primary objective is to enhance the competitiveness of its core electric and natural gas businesses. At the same time the company is actively evaluating opportunities for investment closely related to its core businesses that have the potential to augment future earnings. In April 1992 the PSC issued an order allowing the company to invest up to 5% of its consolidated capitalization (approximately $180 million at December 31, 1994) in one or more subsidiaries that may engage or invest in energy-related or environmental-services businesses and provide related services.
The company has been making investments in unregulated companies through its wholly owned subsidiary, NGE Enterprises, Inc. (NGE). NGE owns two unregulated businesses - EnerSoft Corporation (EnerSoft) and XENERGY, Inc. (XENERGY).
EnerSoft, a computer software company, was formed in May 1993 to produce and market software for natural gas utilities, marketers and pipeline operators. Through an alliance with the New York Mercantile Exchange, EnerSoft is developing Channel 4, a natural gas and pipeline capacity trading and information system for the North American market. While development of the system has taken longer than anticipated, Channel 4 is expected to be commercially available in the spring of 1995. Like most other start-up companies, EnerSoft has been incurring operating losses. The company expects that EnerSoft will continue to incur operating losses in the near term.
In June 1994 NGE acquired all of the outstanding stock of XENERGY, an energy services, information systems and energy- consulting company that specializes in energy management, conservation engineering and demand-side management. XENERGY currently provides a broad range of services to utilities throughout the United States, Canada, Spain and France. It also provides energy services, conservation engineering and DSM services to governmental agencies at both the state and federal levels, and to a large number of end users.
NGE is exploring environmental-services opportunities with both domestic and foreign strategic partners.
As of December 31, 1994 and 1993, the company had invested approximately $47 million and $3 million, respectively, in NGE to finance its diversified investments. For the years ended December 31, 1994 and 1993, NGE incurred net losses of $6.0 million and $1.4 million, respectively.
(b) Financial information about industry segments
See Note 14 to the Consolidated Financial Statements on page 78.
(c) Narrative description of business (i) Principal business
The company's principal business is generating, purchasing, transmitting, and distributing electricity and purchasing, transporting, and distributing natural gas. The service territory, 99% of which is located outside the corporate limits of cities, is in the central, eastern, and western parts of the State of New York. The service territory has an area of approximately 19,500 square miles, and a population of 2,400,000. The larger cities in which the company serves both electricity and natural gas are Binghamton, Elmira, Auburn, Geneva, Ithaca, and Lockport. The company serves approximately 799,000 electric retail customers and 231,000 natural gas retail customers. Its service territory reflects a diversified economy, including high- tech firms, light industry, agriculture, colleges and universities, and recreational facilities. No customer accounts for 5% or more of either electric or natural gas revenues. For the years 1994, 1993, and 1992, 84%, 85%, and 86%, respectively, of operating revenue was derived from electric service and 16%, 15%, and 14%, respectively, was derived from natural gas service.
The 1994-1995 winter peak load of 2,558 megawatts (mw), was set on February 6, 1995. This is 53 mw less than the previous all time peak of 2,611 mw set during the 1993-1994 winter on January 19, 1994. Power supply capability to meet peak loads is currently 3,284 mw. This is composed of 2,543 mw of generating capacity (90% coal-fired, 7% nuclear, and 3% hydroelectric) and 1,108 mw of purchases offset by 367 mw of firm sales. The purchases are composed of 594 mw from NUGs and 514 mw from the New York Power Authority (NYPA). Most purchases from NYPA are hydroelectric power.
On February 14, 1995, the company filed a petition with the FERC asking for relief from having to pay approximately $2 billion more than its avoided costs for power purchased over the life of the two NUG contracts mentioned below. The company believes that the overpayments under these two contracts violate the Public Utility Regulatory Policies Act of 1978 (PURPA). The relief the company is seeking could take the form of FERC taking any one or more of the following actions: issuing a declaratory order deeming the overpayments to be in violation of PURPA; taking direct action to modify the rates under the two contracts; directing the PSC to modify the rates; revising its rules implementing PURPA or waiving its rules implementing PURPA.
The company is currently required to purchase 594 mw of NUG power. The company is required to make payments under these contracts only for the power it receives or when the company directs the NUG to reduce its output under the terms of the contract. Two contracts the company has with NUGs each provide more than 5% of current system capability. One contract, with Lockport Energy Associates, L.P., provides for 177 mw or 5.4%, and the other, with Saranac Power Partners, L.P., provides for 240 mw or 7.3%. During 1994, 1993 and 1992 the company purchased approximately $214 million, $138 million and $71 million, respectively, of NUG power, including termination costs. The company estimates that NUG power purchases, excluding termination costs, over the next five years will be as follows:
1995 1996 1997 1998 1999 (Millions) $274 $312 $322 $333 $344
Increases in the cost of NUG power purchases will contribute significantly to expected electric price increases in August 1995.
The company has implemented a number of DSM programs. As part of its three-year rate agreement (See Item 1(a)-Rates and regulatory matters - Rate Matters), the rewards the company could earn for conducting efficient DSM programs were reduced from 15% to 5% of the net resource savings achieved by these programs. For 1995 the company expects to earn approximately $1 million in rewards as a result of DSM programs.
In 1994 customers saved approximately 64 million kilowatt- hours (kwh) on an annualized basis through DSM programs. These programs cost $14 million in 1994 and will cost approximately $11 million in 1995. The customer savings estimated for 1995 are 54 million kwh on an annualized basis. At both December 31, 1994 and 1993, the company had approximately $73 million of deferred DSM program costs on its consolidated balance sheets. The two- year (1993-1994) DSM plan, which received PSC approval, was modified to improve cost-effectiveness and reduce rate impacts. In August 1994 the company submitted its 1995 DSM plan to the PSC proposing DSM goals and budgets for the years 1995 through 2000. The company expects to change its DSM approach in 1995 to move toward promoting energy-efficient equipment in the mass market and phasing out rebates for individual customers.
On February 6, 1995, the company experienced its 1994-1995 maximum peak daily sendout for natural gas of 400,235 dekatherms. This is 31,521 dekatherms less than the 1993-1994 peak of 431,756 dekatherms set on January 19, 1994.
The following table provides information on the company's estimated sources and uses of funds for 1995-1997. This forecast is subject to periodic review and revision. Actual capital expenditures may change to reflect the imposition of additional regulatory requirements and the company's continued focus on optimizing capital expenditures.
1995 1996 1997 Total (Millions) Sources of funds Internal funds $298 $288 $284 $870 Long-term financing 39 - - 39 ---- ---- ---- ---- Total $337 $288 $284 $909 ==== ==== ==== ==== Uses of funds Capital expenditures Cash $185 $258 $180 $623 AFDC* 3 6 4 13 ---- ---- ---- ---- Total capital expenditures 188 264 184 636 ---- ---- ---- ---- Retirement of securities and sinking fund obligations 63 26 78 167 Repayment of short-term debt 55 20 33 108 Working capital, deferrals and other 31 (22) (11) (2) ---- ---- ---- ---- Total $337 $288 $284 $909 ==== ==== ==== ==== *Allowance for funds used during construction.
As shown in the preceding table, internal sources of funds represent 137% of capital expenditures for 1995-1997.
The company's 1994 capital expenditures for its core electric and natural gas businesses totaled approximately $248 million. Most of the expenditures were for the extension of service, improvements at existing facilities, compliance with the Clean Air Act Amendments of 1990, and other environmental requirements. The company received $24 million from governmental
and other sources in 1994 to partially offset expenditures for compliance with the Clean Air Act Amendments of 1990.
Capital expenditures projected for 1995-1997 have been limited and reflect planned cuts of more than $200 million. This represents one of the many actions the company is taking to address competition (See Item 1(c)(x)- Competitive conditions). Capital expenditures will be primarily for extension of service, necessary improvements at existing facilities, the natural gas storage project, referred to below, compliance with the Clean Air Act Amendments of 1990 (1990 Amendments) and other environmental requirements (See Item 1(c)(xii)- Environmental matters). The company expects to finance these capital expenditures entirely with internally generated funds. The company forecasts that its current reserve margin, coupled with more efficient use of energy and purchases of power from NUGs, eliminates the need for additional generating capacity until after the year 2007.
(ii) New product or segment (See Item 1(a)-Diversification.)
(iii) Sources and availability of raw materials
Electric
In 1994, approximately 89% of the company's generation was coal-fired steam electric, 9% nuclear and 2% hydroelectric power. About 39% of the company's steam electric generation in 1994 was supplied from its one-half share of the output from the Homer City Generating Station, which is owned in common with Pennsylvania Electric Company. An additional 36% was supplied from the company's Kintigh Generating Station, and the remaining 25% was supplied from its other generating stations which are located in New York State.
Coal
Coal for the New York generating stations is obtained primarily from Pennsylvania and West Virginia. Of the 3.4 million tons of coal purchased for the New York generating stations in 1994, approximately 73% was purchased under contract and the balance on the open market. Coal purchased under contract is expected to be approximately 89% of the estimated 3.0 million tons to be purchased in 1995.
The annual coal requirement for the Homer City Generating Station is approximately 4.2 million tons, the majority of which is obtained under long-term contracts. During 1994, approximately 62% of Homer City Generating Station coal was obtained under these contracts. The company anticipates obtaining approximately 66% of the 1995 requirements under these contracts. The balance will be purchased under short-term contracts and, when necessary, on the open market.
Nuclear
During the spring of 1995, Niagara Mohawk Power Corporation (Niagara Mohawk), the operator of the Nine Mile Point nuclear generating unit No. 2 (NMP2), in which the company has an 18% interest, will install reload No. 4 into the reactor core at NMP2. This planned refueling will support NMP2 operations through September 1996. Enrichment services are under contract with the U.S. Enrichment Corporation for 100% of the enrichment requirements through 1995 and 70% of the requirements through 1998. Fuel fabrication services are under contract through 2004 . Approximately 40% of the uranium and conversion requirements are under contract through 1998.
Natural Gas
As a result of FERC Order 636 (See Item (x)-Competitive conditions), the company completed a major restructuring of its natural gas transportation, storage, and supply contracts. Bundled pipeline sales, natural gas and transportation contracts have been eliminated thereby giving the company greater flexibility with respect to its supply of natural gas. The natural gas supply mix now includes long-term, short-term, and spot natural gas purchases transported on both firm and interruptible transportation contracts. During 1994, about 58% of the company's natural gas supply was purchased from various suppliers under long-term and short-term sales contracts and 42% on the monthly spot natural gas market to maximize natural gas cost savings. The company's natural gas supply is expected to be purchased in 1995 in a similar proration as described previously for 1994.
As one response to the competitive pressures faced by its natural gas business, the company plans to build a natural gas storage project near Seneca Lake, north of Watkins Glen, New York. The project, which will cost $59 million and be regulated by the PSC, includes a storage facility and two separate pipelines to transport the natural gas. Its primary purpose is to ensure adequate supply to the company's core natural gas customers. The project will also increase supply flexibility, allow the company to retire propane plants and ultimately reduce pipeline demand charges. The company expects to receive PSC approval for the project and begin construction in 1995. The storage facility is scheduled to be in service for the 1996-1997 heating season.
(iv) Franchises (See Item 1(c)(x) - Competitive conditions.)
The company has, with minor exceptions, valid franchises from the municipalities in which it renders service to the public. In 1994, the company obtained PSC authorizations for natural gas distribution service in the towns of Canaan, Junius and Tyre.
(v) Seasonal business
Sales of electricity are highest during the winter months primarily due to space heating usage and fewer daylight hours. Sales of natural gas are highest during the winter months primarily due to space heating usage.
(vi) Working capital items
The company has been granted, through the ratemaking process, an allowance for working capital to operate its ongoing electric and natural gas utility services.
(vii) Single customer - Not applicable
(viii) Backlog of orders - Not applicable
(ix) Business subject to renegotiation - Not applicable
(x) Competitive conditions (See Item 1(c)(iii) - Sources and availability of raw materials.)
Competition and deregulation are the foremost challenges currently facing the electric and natural gas industries and will increasingly present both opportunities and risks. There is the potential to gain new customers as well as the risk of losing existing customers. While the transition to a competitive marketplace in the electric industry is just beginning, the transition in the natural gas industry is further along: the production sector is now fully deregulated, and the interstate transmission and distribution sectors are in various stages of increasing competition.
In the electric industry, proceedings studying the possibility of introducing more competition and restructuring in some states, such as New York and California, may be paving the way for industry change nationwide. However, a number of complex issues (including transition costs and recovery of prudently incurred costs) must be addressed before restructuring can be accomplished. This makes it difficult to predict how soon market-driven competition will be established.
Contributing to increasing competition in the utility industry are legislation and regulatory policies such as the National Energy Policy Act of 1992 (Energy Policy Act) and FERC Order 636. The Energy Policy Act, enacted in October 1992, provides open access at the wholesale level to electric transmission services and is contributing to major changes in the electric industry. FERC Order 636, which took effect in November 1993, requires interstate natural gas pipeline companies to offer customers unbundled, or separate, services.
A major challenge to the company's electric business continues to be its ability to retain and expand its industrial base. The company's industrial customers, accounting for about 15% of total electric revenues, will increasingly have more supply alternatives available to them. Those alternatives currently include cogeneration, self-generation and fuel switching. Industrial customers can also decide to relocate.
There are other competitive pressures as well. More efficient technologies and more economical alternative fuels and renewable energy sources may increasingly challenge traditional energy sources. Another possibility is that municipalities would
establish their own electric systems within the company's service territory.
The prospect of limited sales growth due to New York's sluggish economy is another challenge. Low growth potential for the company's core businesses makes it difficult to improve earnings and lower prices.
Faced with growing competition and more efficient technologies, utilities are increasingly focusing on the price of their products. The company's electric prices have been rising. The major contributors to these increases have been mandated purchases of power from NUGs (See Item 1(c)(i) - Principal business), rising taxes, DSM programs, and compliance with environmental laws and regulations. DSM programs are initiatives designed to help customers use energy efficiently. Recent natural gas price increases have been caused by higher purchased gas costs, primarily due to transition costs resulting after FERC Order 636 and higher pipeline transportation costs.
The company has developed flexible rates that allow it to negotiate long-term contracts with both its electric and its natural gas customers. The contracts may cover existing load, new load, or both. To date, 12 major electric industrial customers have signed contracts ranging from three to seven years. These contracts retain more than $36 million and add another $7 million in annual revenues, which together represent 2.7% of the company's total electric annual revenues. Also each month the company develops over 275 natural gas prices to compete with the alternative fuels available.
The PSC has initiated a generic proceeding to study the broad subject of flexible, competitive rates. In July 1994 during Phase I of this proceeding, the PSC issued an opinion which approved flexible rate discounts for nonresidential electric customers having competitive alternatives. In approving the offering of discounts, the PSC adopted several guidelines that reaffirmed most of the company's flexible pricing programs.
In August 1994 the PSC instituted Phase II of the proceeding to address competitive opportunities available to electric customers and investigate the future regulation of electric service in light of competition. The overall objective is to identify regulatory and ratemaking practices that will assist the transition to a more competitive electric industry. Proposed principles to guide this transition were issued for comment by the PSC in December 1994.
This proceeding could affect the eligibility of electric utilities in New York State to apply Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). If the company could no longer meet the criteria of SFAS 71 for all or a part of its business, the company would have to expense certain previously deferred costs. Although the company believes it will continue to meet the criteria of SFAS 71 in the near future, it cannot predict what effect a competitive marketplace or future actions of the PSC will have on its ability to continue to do so.
In June 1994 the FERC issued a Notice of Proposed Rulemaking (NOPR) to address transition costs and invited representatives of the utility industry to comment on or suggest alternatives to the proposals. Transition costs are costs that utilities may incur (and that may become unrecoverable) as the industry moves from a heavily regulated environment to a less-regulated, competitive environment.
In December 1994 the company and a coalition of other New York State utilities filed joint comments addressing legal issues raised by the NOPR. The company also filed a separate document that addressed technical issues specific to the company. The coalition comments urge the FERC to set a national policy that will ensure recovery of transition costs so that competition will benefit all customers fairly. In a purely competitive environment, costs that utilities are required to bear (such as taxes, purchases of NUG power and DSM programs) would be difficult to recover because customers would have the opportunity to buy electricity from competitors who do not bear such costs, such as NUGs and municipal utilities. This could leave remaining customers bearing the full burden of those costs.
In 1994 the gas business operated its first full year under FERC Order 636 (See Note 11 to the Consolidated Financial Statements on page 75). Ultimately FERC Order 636 should prove beneficial to the company and its natural gas customers by providing greater opportunities to access natural gas supply, transportation and storage. Increased choices should result in lower natural gas costs in the intermediate and long term.
In December 1994 the PSC issued an order in its proceeding (instituted in late 1993) to investigate natural gas utility issues in view of FERC Order 636 and to determine to what extent New York State should adopt the federal policies. The PSC order also established a generic proceeding to investigate performance- based natural gas purchasing incentives and the availability and affordability of natural gas as the transition to a more competitive environment develops. While they found the majority of the PSC's findings favorable, the company and certain other parties to the proceeding have asked for a rehearing on certain points that they believe are inconsistent with the overall goal of encouraging competition. The company has already taken advantage of several new opportunities, including flexible customer rates, unbundling of services, and access to the secondary market for natural gas supplies and pipeline capacity.
During 1994 the company took a number of difficult steps to address the competitive challenges it faces. Foremost among them were the restructuring and workforce reduction completed in the first quarter of 1994 (see Note 6 to the Consolidated Financial Statements on page 63) and the decision to reduce the common stock dividend in the fourth quarter of 1994 (See Item 7 - Liquidity and Capital Resources - Common Stock Dividend Policy).
Other steps the company has taken to address competitive pressures during 1994 include reducing capital expenditures and DSM program costs, placing two generating units on long-term cold standby, creating a customer service business unit and moving
responsibility for fuel procurement and bulk power sales to the generation department.
In order to help it meet the challenges of competition, the company has a five-year strategic plan. This plan will be updated annually. Following are some of the goals the company has set for 1995:
- Improve earnings per share by at least 5% over 1994. - Achieve excellence in customer service and meet all customer service targets (See Item 1(a) - Rates and regulatory matters-Rate Matters). - Negotiate a positive modification to the company's existing three-year electric rate agreement. - Develop greater rate flexibility to retain existing customers and attract new ones, and to properly price value-added services. - Obtain PSC approval and begin construction of the $59 million Seneca Lake Gas Storage Project. - Successfully introduce EnerSoft's Channel 4 trading system in the spring of 1995 (See Item 1(a)-Diversification).
(xi) Research and development
Expenditures on research and development in 1994, 1993, and 1992 amounted to $14.5 million, $18.9 million, and $14.6 million, respectively, principally for the company's internal research programs and for contributions to research administered by the Electric Power Research Institute, the Empire State Electric Energy Research Corporation, the New York Gas Group, and the New York State Energy Research and Development Authority. These expenditures are designed to improve existing technologies and to develop new technologies for the production, distribution, and customer use of energy.
(xii) Environmental matters (See Item 3 - Legal proceedings)
The company is subject to regulation by the federal government and by state and local governments in New York and Pennsylvania with respect to environmental matters and is also subject to the New York State Public Service Law requiring environmental approval and certification of proposed major transmission facilities.
The company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Any additional compliance programs will increase the cost of electric and natural gas service by requiring changes in the company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred to comply with environmental laws and regulations.
Capital additions to meet environmental requirements during the three years ended December 31, 1994 were approximately $116 million and are estimated to be $24 million for 1995, $28 million for 1996, and $17 million for 1997.
Water quality
The company is required to comply with federal and state water quality statutes and regulations including the Clean Water Act (Water Act). The Water Act requires that generating stations be in compliance with federally issued National Pollutant Discharge Elimination System Permits (NPDES Permits) or state issued State Pollutant Discharge Elimination System Permits (SPDES Permits), which reflect water quality considerations for the protection of the environment. The company has SPDES Permits for its six coal-fired generating stations in New York and has applied for permit renewals for all of those stations. Permits for these stations have either been renewed or are currently being negotiated with the State of New York, in which case the existing permits for those facilities remain in effect. The company's Homer City Generating Station received a revised NPDES Permit in September 1994 from the Pennsylvania Department of Environmental Resources (PaDER) sections of which it is contesting. The Homer City Station will continue to operate under the existing permit conditions until this matter is resolved. The SPDES permit for NMP2 was recently renewed.
In connection with the issuance of permits under the Water Act, the company has conducted studies of the effects of its coal pile operations on groundwater quality at its Hickling, Jennison, Milliken, and Greenidge Stations. New York State groundwater standards are sometimes exceeded at certain locations at each of those stations and remedial action may be required. Jennison Station will require remedial action which is estimated to cost up to $1 million. The remedial action, if required, at Hickling, Milliken, and Greenidge Stations is estimated to cost $7.4 million. The company expects to recover these expenditures in rates, since the company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements. Remedial action has already been performed at the Goudey Station and the company is currently monitoring the groundwater quality at this station. Groundwater monitoring data for Kintigh Station does not indicate facility induced groundwater contamination. Groundwater studies have been initiated at the Homer City Station.
Air quality
The company is required to comply with federal and state air quality statutes and regulations. All stations have the required federal or state operating permits. Stack tests and continuous emission monitoring indicate that the stations are generally in compliance with permit emission limitations, although occasional opacity exceedances occur. Efforts continue in the identifi- cation and elimination of the causes of opacity exceedances.
The Clean Air Act Amendments of 1990 (1990 Amendments) will result in expenditures of approximately $174 million, on a present value basis, over a 25-year period, for all capital and operating and maintenance expenses related to the reduction of sulfur dioxide and nitrogen oxides at several of the company's coal-fired generating stations, of which $106.5 million had been incurred as of December 31, 1994. The cost to comply with the sulfur dioxide and nitrogen oxide limitations includes the construction of an innovative flue gas desulfurization (FGD) system and a nitrogen oxide reduction system that was recently completed at the company's Milliken Generating Station. The company estimates that approximately a 1% electric rate increase will be required for the cost of reducing sulfur dioxide and nitrogen oxide emissions in both Phase I (which began on January 1, 1995) and Phase II (begins January 1, 2000), as discussed below. In addition, the company anticipates that it will have to significantly reduce its nitrogen oxide emissions even further by the year 2003, which includes an interim reduction in the year 1999, as a result of proposed U.S. Environmental Protection Agency (EPA) regulations. The cost to comply with these proposed regulations cannot be estimated at this time, since the reduction will be based on additional research scheduled to be completed later in the decade. As a result of the 1990 Amendments, the company plans to reduce its annual sulfur dioxide emissions by an amount that will allow the company to meet the sulfur dioxide levels established for the company, which are approximately a 49% reduction from approximately 138,000 tons in 1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990 Amendments, if required, cannot be estimated at this time, since the type and level of reductions that may be required is dependent on a study currently being performed by the EPA, which is scheduled to be completed by the end of 1995. Regulations may be adopted at the state level that would limit toxic emissions even further, at an additional cost to the company. The company anticipates that the costs incurred to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual emissions allowances to each of the company's coal-fired generating stations based on statutory emissions limits. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, the company estimates that it will have allowances in excess of the affected coal-fired generating stations' actual emissions. The company's present strategy is to bank these allowances for use in later years. By using a banking strategy, it is estimated that Phase II allowance requirements will be met through the year 2005 by utilizing the allowances banked during Phase I, which includes the extension reserve allowances discussed below, together with the company's Phase II annual emissions allowances. This strategy could be modified should market or business conditions change. In addition to the annual emissions allowances allocated to the company by the EPA, the company has received a portion of the extension reserve allowances issued by the EPA to utilities electing to build scrubbers in Phase I, as a result of a pooling agreement that it entered into with other utilities who were also eligible to receive some of these extension reserve allowances.
Certain other environmental regulations limit the amount of particulate matter which may be emitted into the environment. The company and Pennsylvania Electric Company may find it necessary either to upgrade or install additional equipment at the Homer City Generating Station in order to consistently meet the particulate emission requirements.
Waste disposal
The company has received or applied for SPDES Permits, Solid Waste Disposal Facilities Permits, and applicable local permits for its active ash disposal sites for its New York generating stations. Groundwater standards have been exceeded in areas close to portions of the Milliken and Weber ash disposal sites. Corrective actions have been taken and studies are continuing to monitor the effectiveness of the corrective actions.
The company has received NPDES permits, a Solid Waste Disposal Permit, and applicable local permits for its active ash disposal site for the Homer City Generating Station and for the active refuse disposal site for the Homer City Coal Cleaning Plant. In September 1993 the company completed its study of costs to comply with the new Pennsylvania residual waste regulations governing solid waste disposal over the next 30 years.
As a result of existing and new solid waste disposal legislation and regulations in Pennsylvania, the company will incur approximately $28 million, on a present value basis, of additional costs over the next 30 years at the Homer City Generating Station. The majority of these costs will be incurred over the next 10 years to install new equipment, modify or replace existing equipment, and improve the design of a proposed expansion of disposal facilities. The company expects to recover these expenditures in rates, since the company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements.
Due to existing and proposed legislation and regulations, and legal proceedings commenced by governmental bodies and others, the company may also incur costs from the past disposal of hazardous substances produced during the company's operations or those of its predecessors. The company has been notified by the EPA and the New York State Department of Environmental Conservation (NYSDEC), as appropriate, that it is among the potentially responsible parties (PRPs) who may be liable to pay for costs incurred to remediate certain hazardous substances at nine waste sites, not including the company's inactive gas manufacturing sites, which are discussed below. With respect to the nine sites, seven sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry) and two of those sites are also included on the National Priorities List.
Any liability may be joint and several for certain of these sites. The company has recorded a liability related to four of these nine sites, which is reflected in the company's consolidated balance sheets at December 31, 1994, in the amount of $1.1 million. The ultimate cost to remediate these sites may be significantly more than this amount and will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed to the company. The company has notified the EPA and the NYSDEC, as appropriate, that it believes it has no responsibility at three sites and has already incurred expenditures related to remediation at another site. The company has not, as yet, determined whether it has any responsibility at the remaining site. A deferred asset has also been recorded in the amount of $2.1 million, of which $1.0 million relates to costs that have already been incurred. The company believes it will recover these costs, since the PSC has allowed other utilities to recover these types of remediation costs and has allowed the company to recover similar costs in rates, such as investigation and cleanup costs relating to inactive gas manufacturing sites. The estimated liability of $1.1 million was derived by multiplying the total estimated cost to clean up a particular site by the related company contribution factor. Estimates of the total cleanup costs were determined by using information related to a particular site, such as investigations performed to date at a site or from the data released by a regulatory agency. In addition, this estimate was based upon currently available facts, existing technology, and presently enacted laws and regulations. The contribution factor is calculated using either the company's percentage share of the total PRPs named, which assumes all PRPs will contribute equally, or the company's estimated percentage share of the total hazardous wastes disposed of at a particular site, or by using a 1% contribution factor for those sites at which it believes that it has contributed a minimal amount of hazardous wastes. The company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A number of the company's inactive gas manufacturing sites have been listed in the New York State Registry. In late March 1994 the company entered into an Order on Consent with the NYSDEC requiring the company to investigate and, where necessary, remediate 33 of the company's 38 known inactive gas manufacturing sites. The schedule for investigating and remediating these 33 sites will be determined through further negotiations with the NYSDEC. The company has a program to investigate and initiate necessary remediation at its 38 known inactive gas manufacturing sites. Expenditures through the year 2009 are estimated at $32.5 million, including the impact of the Order on Consent. This estimate was determined by using the company's experience and knowledge related to these sites as a result of the investigation and remediation that the company has performed to
date. It is based upon currently available facts, existing technology, and presently enacted laws and regulations. This liability to investigate and initiate remediation, as necessary, at the known inactive gas manufacturing sites, is reflected in the company's consolidated balance sheets at December 31, 1994 and 1993 in the amount of $32.5 million and $25 million, respectively. The company also has recorded a corresponding deferred asset, since it expects to recover such expenditures in rates, as the company has previously been allowed by the PSC to recover such costs in rates. The PSC has asked its staff to prepare a recommendation on a generic policy for these types of expenditures by the spring of 1995. The company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A low level radioactive waste management and contingency plan for NMP2 provides assurance that NMP2 is properly prepared to handle interim storage of low level radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of Energy (DOE) for disposal of high level radioactive waste (spent fuel) from NMP2. The company is reimbursing Niagara Mohawk for its 18% share of the cost under the contract (currently approximately $1 per megawatt hour of net generation). The DOE's schedule for start of operations of their high level radioactive waste repository has slipped from 2003 to no sooner than 2010. The company has been advised by Niagara Mohawk that the NMP2 Spent Fuel Storage Pool has a capacity for spent fuel that is adequate until 2014. If further DOE schedule slippage should occur, construction of pre-licensed dry storage facilities would extend the on-site storage capability for spent fuel at NMP2 beyond 2014.
(xiii) Number of employees
The company had 4,192 employees as of December 31, 1994.
(d) Financial information about foreign and domestic operations and export sales - Not applicable
Item 2.
Item 2. Properties
The company's electric system includes coal-fired, nuclear, hydroelectric, and internal combustion generating stations, substations, and transmission and distribution lines, all of which are located in the State of New York, except for the Homer City Generating Station and related facilities which are located in the Commonwealth of Pennsylvania. Generating facilities are:
Name and location of station Generating capability (mw) Coal-fired Goudey (Binghamton, N.Y.) 84 * Greenidge (Dresden, N.Y.) 108 * Hickling (East Corning, N.Y.) 82 Jennison (Bainbridge, N.Y.) 69 Milliken (Lansing, N.Y.) 310 Kintigh (Somerset, N.Y.) 675 Homer City (Homer City, Pa.) 950** ----- Total coal-fired 2,278
Nuclear
NMP2 (Oswego, N.Y.) 189***
Hydroelectric (Various - 9 locations) 69
Internal combustion (Various - 2 locations) 7 ----- Total - all stations 2,543 ===== * In 1994 the company placed one unit at both Goudey and Greenidge on long-term cold standby. These units had a combined capability of 97 megawatts. ** Company's 50% share of the generating capability. ***Company's 18% share of the generating capability.
The company owns 432 substations having an aggregate transformer capacity of 13,142,800 Kilovolt-amperes. The transmission system consists of 4,834 circuit miles of line and the distribution system of 33,503 pole miles of overhead lines and 1,790 miles of underground lines.
The company's natural gas system consists of the distribution of natural gas through 482 miles of transmission pipelines (over 3-inch equivalent) and 5,775 miles of distribution pipelines (under 3-inch equivalent).
Somerset Railroad Corporation (SRC), a wholly-owned subsidiary, owns a rail line consisting of 15 1/2 miles of track and related property rights in Lockport, Newfane, and Somerset, New York which is used to transport coal and other materials to the Kintigh Generating Station.
The company's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all of the company's properties. Substantially all of the properties of SRC, other than rolling stock, are subject to a lien of a mortgage and security agreement.
Item 3.
Item 3. Legal proceedings (See Item 1(a)-Rates and regulatory matters - Rate Matters, 1(c)(i)-Principal business, 1(c)(x)-Competitive conditions, and 1(c)(xii)-Environmental matters)
The company is unable to predict the ultimate disposition of the matters referred to below in (b), (c), (d), (e), (f), (h), (i), (j) and the first paragraph in (g). However, since the PSC has allowed other utilities to recover these types of remediation costs and has previously allowed the company to recover similar costs in rates, such as investigation and clean-up costs relating to coal tar sites, the company expects to recover in rates any remediation costs that it may incur. Therefore, the company believes that the ultimate disposition of the matters referred to below in (b), (c), (d), (e), (f), (h), (i), (j) and the first paragraph in (g) will not have a material adverse effect on its results of operations or financial position.
(a) On January 27, January 31, and February 15, 1984, and on June 29, 1987, numerous individual plaintiffs instituted lawsuits in the Supreme Court of the State of New York (Broome County) for personal injuries allegedly arising out of a transformer fire at the State Office Building in Binghamton, New York, in February 1981. Multiple defendants, including the company, are named in the actions which seek an aggregate of $329 million in compensatory and punitive damages. Because the transformers involved were not owned, installed, or serviced by the company, the company believes that these claims against the company are without merit.
(b) By letter dated February 29, 1988, the NYSDEC notified the company that it had been identified as a PRP for investigation and remediation of hazardous wastes at the Lockport City Landfill Site (Lockport Site) in Lockport, New York. The Lockport Site is listed on the New York State Registry. Five other PRPs have been identified by the NYSDEC. The company believes that remediation costs at the Lockport Site might rise to $6 million. The Lockport Site is currently being remediated by the site owner, the City of Lockport. By letter dated May 2, 1988, the company notified the NYSDEC that it declined to finance remediation costs because it believed that the NYSDEC had not demonstrated that a significant threat to public health or the environment exists at the Lockport Site.
(c) By letter dated December 10, 1990, the NYSDEC notified the company that it had been identified as a PRP for investigation and remediation of hazardous wastes at the Schreck's scrapyard site (Schreck's Site) in the City of North Tonawanda, New York. The Schreck's Site is listed on the New York State Registry. Seven other PRPs were identified in the NYSDEC letter. On February 3, 1992, the NYSDEC again notified the company that it had been identified as a PRP for investigation and remediation costs at the Schreck's Site, this time listing eight other PRPs. The company has been offered an opportunity to conduct remediation or finance remediation costs at the Schreck's Site, failing which the NYSDEC might remediate the Schreck's Site itself and commence an action to recover its costs and damages. The NYSDEC currently estimates that remediation costs at the Schreck's Site will be $4.5 million. By letter dated April 1, 1992, the company notified the NYSDEC that it believed it had no responsibility for the alleged contamination at the Schreck's Site, and it declined to conduct remediation or finance remediation costs.
(d) By letter dated June 7, 1991, the NYSDEC notified the company that it had been identified as a PRP at the Pfohl Brothers Landfill, an inactive hazardous waste disposal site (Pfohl Site) in Cheektowaga, New York. The Pfohl Site is listed on the National Priorities List and the New York State Registry. The NYSDEC offered the company an opportunity to enter into negotiations with it to undertake the investigation and remedia- tion of the Pfohl Site. The NYSDEC informed the company that if it declined such negotiations, the NYSDEC would perform the necessary work at the Pfohl Site using the Hazardous Waste Remedial Fund and would seek recovery of its expenses from the company. On July 3, 1991, the company responded to the NYSDEC by declining to negotiate to undertake work at the Pfohl Site and it noted that the NYSDEC had not shown any significant responsibility on the part of the company for the situation at the Pfohl Site. The company believes that remediation costs at the Pfohl Site will be $35 million to $55 million. By letter dated April 2, 1992, the NYSDEC again notified the company that it had been identified as a PRP for the Pfohl Site and offered the company an opportunity to conduct or finance the on-site remedial design and action. This notice letter was also sent to 19 other PRPs. Ten of these other named PRPs have agreed to perform the remedial work required by the NYSDEC. By letter dated June 1, 1992, the company notified the NYSDEC that it declined to perform such remedial work because it believed that it was not a significant contributor to the Pfohl Site.
(e) By letter dated January 21, 1992, the NYSDEC notified the company that it had been identified as a PRP at the Peter Cooper Corporation's Landfill Site (Peter Cooper Site) in the village of Gowanda, New York. Three other PRPs were identified in the NYSDEC letter. The NYSDEC letter also notified the company that state surface water and groundwater standards had been exceeded at the Peter Cooper Site and offered the company an opportunity to conduct or finance a remedial program. NYSDEC indicated that if the company did not agree to enter into a consent order it would perform the necessary work itself or seek a court order requiring the company to conduct the work. The company believes that remediation costs at the Peter Cooper Site might rise to $16 million. By letter dated May 12, 1992, the company notified the NYSDEC that it believed it had no responsibility for the alleged contamination at the Peter Cooper Site, and it declined to conduct remediation or finance remediation costs.
(f) By letter dated April 20, 1992, the EPA notified the company that it had been identified as a PRP at the Bern Metals Removal Site (Bern Metals Site) in Buffalo, New York. Six other PRPs have been identified by the EPA. The EPA has taken response actions at the Bern Metals Site, including investigation, excavation, and removal of drums and contaminated soil, and implementation of measures to prevent surface water run-off. The EPA has demanded that the company reimburse the EPA Hazardous Substances Superfund $2 million in response costs incurred to date by the EPA, with interest accruing from the date of the demand. Future response or remedial costs which the EPA may incur at the Bern Metals Site are not covered by the EPA demand and the EPA has reserved its rights relating to any such costs.
In addition to the foregoing, the NYSDEC, by letter dated July 21, 1992, notified the company that it had been identified as a PRP at the Bern Metals Site, which the NYSDEC defined to include an adjacent property known as the Universal Iron & Metal Site (Bern Metals/Universal Iron Site). The Bern Metals/Universal Iron Site is listed on the New York State Registry. The NYSDEC has also identified eight other PRPs for the Bern Metals/Universal Iron Site. The NYSDEC has requested that the company, and the eight other identified PRPs, enter into negotiations in which the company and the other identified PRPs would agree to finance or conduct a Remedial Investigation and Feasibility Study (RI/FS) designed to determine what further remediation or removal actions may be appropriate for the Bern Metals/Universal Iron Site. The NYSDEC has provided no estimate of the cost of the response action it proposes. By letter dated December 3, 1992, the company declined to negotiate with NYSDEC to finance or conduct an RI/FS for the Bern Metals/Universal Iron Site, because the company believes it was only a very small contributor to the Bern Metals/Universal Iron Site. In addition, the company believes that it does not have any connection with the Universal Iron & Metal Site.
(g) By letter dated April 20, 1992, the EPA notified the company that the EPA had reason to believe that the company was a PRP for the Clinton-Bender Removal Site (Clinton-Bender Site) in Buffalo, New York. Five other PRPs have been identified by the EPA. Nine private residential lots and one commercial property at the Clinton-Bender Site are contaminated with lead, allegedly due to run-off from the adjacent Bern Metals Site. The EPA has requested that the company perform the necessary removal work at the Clinton-Bender Site and the company is doing so in conjunction with four other identified PRPs. The total cost of the removal actions to be performed at the Clinton-Bender Site is estimated to be $3.1 million.
On November 3, 1993, the company was served with a summons and complaint filed on behalf of certain of the homeowners at the Clinton-Bender Site. Seven other defendants were named in the complaint, which was filed in the New York State Supreme Court, Erie County. The action has since been removed to the U.S. District Court for the Western District of New York (District Court). In their complaint, plaintiffs make general allegations that the defendants violated federal environmental laws without alleging facts in support of these allegations. Plaintiffs also allege personal injury, property damage, and fear of cancer which they claim were caused by the presence of hazardous substances on their property, allegedly resulting from the disposal of such substances by the defendants at the Bern Metals Site. Any liability incurred as a result of these claims may be joint and several. The plaintiffs ask for $30 million in direct damages from all defendants, as well as treble damages (for unspecified reasons) from all defendants, and an additional $10 million in punitive damages from each defendant. The company and some of the other defendants in this matter have made a motion to the District Court for dismissal of all claims based upon the Clean Air Act, the Clean Water Act, and the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), which are the only claims based upon federal causes of action. A decision on this motion is still pending. The company believes that the ultimate disposition of this matter will not have a material adverse effect on its results of operations or financial position.
(h) By letter dated February 12, 1993, NYSDEC notified the company that it had been identified as a PRP for remediation of hazardous wastes at the Booth Oil Site (Booth Oil Site) in North Tonawanda, New York. The Booth Oil Site is listed on the New York State Registry. Nineteen other PRPs have been identified by the NYSDEC. Booth Oil Company is a waste oil re-refiner and recycler. The company had sent waste oils to Booth Oil Company for disposal as had numerous other companies in the Buffalo area. According to NYSDEC, the Booth Oil Site is contaminated with PCBs, lead, and other substances. NYSDEC has requested that the company and the other identified PRPs conduct remediation at the Booth Oil Site pursuant to an Order on Consent to be negotiated with NYSDEC. NYSDEC has estimated that the present value of costs for on-site treatment alternatives range from $12 million to $24 million. The PRPs have presented an alternate concept for remediation of the site and are awaiting a response from the NYSDEC.
(i) On June 14, 1994, the company was served with a summons and complaint joining the company as a defendant in an action that was filed in the United States District Court for the Northern District of New York. The plaintiffs are five companies which have been required by the EPA to conduct remedial activities at the Rosen Brothers Site (Rosen Site) in the City of Cortland, New York. The Rosen Site was the location of a scrap metal processing operation and industrial waste disposal site between approximately 1971 and 1985, and it is now allegedly contaminated with hazardous substances including heavy metals, solvents and PCBs. The Rosen Site is listed on the National Priorities List and the New York State Registry. Among other claims, the plaintiffs seek contribution under CERCLA, from the company and sixteen other defendants for the costs of complying with the EPA order to remediate the Rosen Site. The plaintiffs allege that the company was a contributor to the Rosen Site of transformers which may have contained PCBs. Liability under CERCLA may be joint and several. No remedy has yet been selected by EPA for the Rosen Site and, therefore, the total amount of remedial costs eventually to be incurred by the plaintiffs is currently unknown.
By letter dated August 16, 1994, the EPA notified the company that the EPA had reason to believe that the company was a PRP for the Rosen Site. The EPA has requested that the company participate in the RI/FS currently being prepared for the Rosen Site by the other named PRPs. By letter dated October 20, 1994, the company declined to participate in this study because it believes that no facts have been established showing that it was responsible for any contamination at the Site.
(j) By letter dated February 8, 1995, the EPA notified the company that the EPA had reason to believe that the company was a PRP for the Quanta Resources Site, which was a waste oil reclamation/recycling facility that operated until 1981 in Syracuse, New York. A large volume of product and waste material was left behind when operations ceased. The Quanta Resources Site is listed on the New York State Registry. 140 other PRPs were identified in the EPA letter. The EPA has taken response actions at the Quanta Resources Site, including sampling, monitoring, investigative, corrective and enforcement measures. The EPA has demanded that the company and the other PRPs reimburse the EPA Hazardous Substances Superfund approximately $500,000 in response costs incurred to date by the EPA. Future response or remedial costs which the EPA may incur at the Quanta Resources Site are not covered by the EPA demand and the EPA has reserved its rights relating to any such costs.
(k) By complaint dated October 31, 1991, General Motors Corporation (GM) commenced a lawsuit against the company in the U. S. District Court for the Western District of New York. GM alleges, among other claims, that the company violated various federal antitrust laws in connection with billings for electric service provided by the company at GM's Harrison Radiator Plant at Lockport, New York. GM's claims are for damages incurred and to be incurred. The company estimates that GM is claiming approximately $8 million, after trebling. The company believes that it has not violated the federal antitrust laws and that this lawsuit is without merit.
On October 5, 1993, the Magistrate to whom the case had been referred issued a decision recommending that GM's complaint be dismissed. On July 12, 1994, the District Judge responsible for the case, after reviewing GM's exceptions to the decision and the company's reply adopted the Magistrate's recommended decision in its entirety and dismissed the complaint. On August 9, 1994, GM filed an appeal of that decision. On October 10, 1994, the company and GM stipulated that GM would withdraw its appeal, subject to GM's right to renew it, while the parties attempted to resolve their differences. On December 29, 1994, the parties stipulated to extend to April 3, 1995 GM's right to renew its appeal.
(l) By complaint dated August 12, 1994, as amended October 19, 1994, a class action lawsuit was commenced against the company and James A. Carrigg, Chairman, President and Chief Executive Officer of the company (Defendants) in the United States District Court for the Eastern District of New York. The lawsuit was brought by two alleged shareholders purporting to act on behalf of purchasers of the company's Common Stock pursuant to its Dividend Reinvestment and Stock Purchase Plan between May 15 and August 10, 1994, and on behalf of purchasers of the company's securities on the open market between March 15, 1994 and August 10, 1994. The complaint alleges that certain statements in the company's Form 10-K for 1993 and the company's Annual Report to Shareholders for 1993 relating to the company's diversification program and common stock dividend violated the federal securities laws. Plaintiffs are seeking to recover damages in an unspecified amount. The Defendants believe that this lawsuit is without merit and intend to defend this action vigorously.
Item 4.
Item 4. Submission of matters to a vote of security holders - Not applicable.
* * * * * * * * * *
Executive officers of the Registrant
Positions, offices and business experience - Name Age January 1990 to date
James A. Carrigg 61 Chairman, President and Chief Execu- tive Officer, January 1991 to date; Chairman and Chief Executive Officer, to January 1991.
Jack H. Roskoz 56 Executive Vice President, January 1995 to date; Senior Vice President-Electric Business Unit, April 1990 to January 1995; Senior Vice President, to April 1990.
Richard P. Fagan 54 Senior Vice President-Management Services Business Unit, April 1990 to date; Senior Vice President- Administration, to April 1990.
Michael I. German 44 Senior Vice President-Gas Business Unit, December 1994 to date; Senior Vice President, American Gas Assoc- iation, Arlington, Virginia, to Decem- ber 1994.
Gerald E. Putman 44 Senior Vice President-Customer Service Business Unit, January 1995 to date; Vice President-Fuel Supply and Opera- tion Services, May 1993 to January 1995; Vice President-East Region Electric, September 1992 to May 1993; Executive Assistant to the Chairman, President and Chief Executive Officer, January 1991 to September 1992; District Manager, Auburn, NY, to January 1991.
Daniel W. Farley 39 Vice President and Secretary, May 1991 to date; Secretary, to May 1991.
Carl E. Johnson 52 Vice President-Human Resources & Com- munications, January 1995 to date; Vice President-Consumer Services, Com- munications & Human Resources, Febru- ary 1994 to January 1995; Vice Presi- dent-Consumer Services & Communications January 1991 to February 1994; General Manager, Southeast Area to January 1991.
Executive officers of the Registrant (Cont'd)
Positions, offices and business experience - Name Age January 1990 to date
Sherwood J. Rafferty 47 Vice President and Treasurer, September 1990 to date; Treasurer, to September 1990.
Jeffrey K. Smith 46 Vice President-Generation, January 1995 to date; Executive Assistant to the Chairman, President and Chief Executive Officer, February 1994 to January 1995; Assistant to the Senior Vice President-Electric Business Unit, October 1991 to February 1994; Manager- Plant Operations Services, January 1991 to October 1991; Manager-Strategic Planning, to January 1991.
Ralph R. Tedesco 41 Vice President-Strategic Growth Business Unit, February 1994 to date; Executive Assistant to the Chairman, President and Chief Executive Officer, September 1992 to February 1994; Manager, Corporate Performance June 1991 to September 1992; Manager, Research and Development, to June 1991.
Gary J. Turton 47 Controller and Chief Accounting Officer, December 1994 to date; Assistant Controller, to December 1994.
Denis E. Wickham 46 Vice President-Electric Resource Planning, January 1991 to date; Assistant to Senior Vice President, to January 1991.
The company has entered into an agreement with James A. Carrigg which provides for his employment as Chairman, President and Chief Executive Officer of the company for a term ending on December 31, 1996, with automatic one-year extensions unless either he or the company gives notice that the agreement is not to be extended.
Each officer holds office for the term for which he or she is elected or appointed, and until his or her successor shall be elected and shall qualify. The term of office for each officer extends to and expires at the meeting of the Board of Directors following the next annual meeting of shareholders.
PART II
Item 5.
Item 5. Market for Registrant's common stock and related stockholder matters
See Note 15 to the Consolidated Financial Statements on page 79.
Item 7. Management's discussion and analysis of financial condition and results of operations
Liquidity and Capital Resources
Competitive Conditions
Competition and deregulation are the foremost challenges currently facing the electric and natural gas industries and will increasingly present both opportunities and risks. There is the potential to gain new customers as well as the risk of losing existing customers. While the transition to a competitive marketplace in the electric industry is just beginning, the transition in the natural gas industry is further along: the production sector is now fully deregulated, and the interstate transmission and distribution sectors are in various stages of increasing competition.
In the electric industry, proceedings studying the possibility of introducing more competition and restructuring in some states, such as New York and California, may be paving the way for industry change nationwide. However, a number of complex issues (including transition costs and recovery of prudently incurred costs) must be addressed before restructuring can be accomplished. This makes it difficult to predict how soon market-driven competition will be established.
Contributing to increasing competition in the utility industry are legislation and regulatory policies such as the National Energy Policy Act of 1992 (Energy Policy Act) and Federal Energy Regulatory Commission (FERC) Order 636. The Energy Policy Act, enacted in October 1992, provides open access at the wholesale level to electric transmission services and is contributing to major changes in the electric industry. FERC Order 636, which took effect in November 1993, requires interstate natural gas pipeline companies to offer customers unbundled, or separate, services.
A major challenge to the company's electric business continues to be its ability to retain and expand its industrial base. The company's industrial customers, accounting for about 15% of total electric revenues, will increasingly have more supply alternatives available to them. Those alternatives currently include cogeneration, self-generation and fuel switching. Industrial customers can also decide to relocate.
There are other competitive pressures as well. More efficient technologies and more economical alternative fuels and renewable energy sources may increasingly challenge traditional energy sources. Another possibility is that municipalities would establish their own electric systems within the company's service territory.
The prospect of limited sales growth due to New York's sluggish economy is another challenge. Low growth potential for the company's core businesses makes it difficult to improve earnings and lower prices.
Faced with growing competition and more efficient technologies, utilities are increasingly focusing on the price of their products. The company's electric prices have been rising. The major contributors to these increases have been mandated purchases of power from non-utility generators (NUGs), rising taxes, demand-side management (DSM) programs, and compliance with environmental laws and regulations. DSM programs are initiatives designed to help customers use energy efficiently. Recent natural gas price increases have been caused by higher purchased gas costs, primarily due to transition costs resulting after FERC Order 636 and higher pipeline transportation costs.
The company has developed flexible rates that allow it to negotiate long-term contracts with both its electric and its natural gas customers. The contracts may cover existing load, new load, or both. To date, 12 major electric industrial customers have signed contracts ranging from three to seven years. These contracts retain more than $36 million and add another $7 million in annual revenues, which together represent 2.7% of the company's total electric annual revenues. Also each month the company develops over 275 natural gas prices to compete with the alternative fuels available.
The Public Service Commission of the State of New York (PSC) has initiated a generic proceeding to study the broad subject of flexible, competitive rates. In July 1994 during Phase I of this proceeding, the PSC issued an opinion which approved flexible rate discounts for nonresidential electric customers having competitive alternatives. In approving the offering of discounts, the PSC adopted several guidelines that reaffirmed most of the company's flexible pricing programs.
In August 1994 the PSC instituted Phase II of the proceeding to address competitive opportunities available to electric customers and investigate the future regulation of electric service in light of competition. The overall objective is to identify regulatory and ratemaking practices that will assist the transition to a more competitive electric industry. Proposed principles to guide this transition were issued for comment by the PSC in December 1994.
This proceeding could affect the eligibility of electric utilities in New York State to apply Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). If the company could no longer meet the criteria of SFAS 71 for all or a part of its business, the company would have to expense certain previously deferred costs. Although the company believes it will continue to meet the criteria of SFAS 71 in the near future, it cannot predict what effect a competitive marketplace or future actions of the PSC will have on its ability to continue to do so.
In June 1994 the FERC issued a Notice of Proposed Rulemaking (NOPR) to address transition costs and invited representatives of the utility industry to comment on or suggest alternatives to the proposals. Transition costs are costs that utilities may incur (and that may become unrecoverable) as the industry moves from a heavily regulated environment to a less-regulated, competitive environment.
In December 1994 the company and a coalition of other New York State utilities filed joint comments addressing legal issues raised by the NOPR. The company also filed a separate document that addressed technical issues specific to the company. The coalition comments urge the FERC to set a national policy that will ensure recovery of transition costs so that competition will benefit all customers fairly. In a purely competitive environment, costs that utilities are required to bear (such as taxes, purchases of NUG power and DSM programs) would be difficult to recover because customers would have the opportunity to buy electricity from competitors who do not bear such costs, such as NUGs and municipal utilities. This could leave remaining customers bearing the full burden of those costs.
In 1994 the gas business operated its first full year under FERC Order 636 (see Note 11). Ultimately FERC Order 636 should prove beneficial to the company and its natural gas customers by providing greater opportunities to access natural gas supply, transportation and storage. Increased choices should result in lower natural gas costs in the intermediate and long term.
In December 1994 the PSC issued an order in its proceeding (instituted in late 1993) to investigate natural gas utility issues in view of FERC Order 636 and to determine to what extent New York State should adopt the federal policies. The PSC order also established a generic proceeding to investigate performance- based natural gas purchasing incentives and the availability and affordability of natural gas as the transition to a more competitive environment develops. While they found the majority of the PSC's findings favorable, the company and certain other parties to the proceeding have asked for a rehearing on certain points that they believe are inconsistent with the overall goal of encouraging competition. The company has already taken advantage of several new opportunities, including flexible customer rates, unbundling of services, and access to the secondary market for natural gas supplies and pipeline capacity.
As one response to the competitive pressures faced by its natural gas business, the company plans to build a natural gas storage project near Seneca Lake, north of Watkins Glen, New York. The project, which will cost $59 million and be regulated by the PSC, includes a storage facility and two separate pipelines to transport the natural gas. Its primary purpose is to ensure adequate supply to the company's core natural gas customers. The project will also increase supply flexibility, allow the company to retire propane plants and ultimately reduce pipeline demand charges. The company expects to receive PSC approval for the project and begin construction in 1995. The storage facility is scheduled to be in service for the 1996-1997 heating season.
During 1994 the company took a number of difficult steps to address the competitive challenges it faces. Foremost among them were the restructuring and workforce reduction completed in the first quarter of 1994 (see Note 6) and the decision to reduce the common stock dividend in the fourth quarter of 1994 (see Common Stock Dividend Policy).
Other steps the company has taken to address competitive pressures during 1994 include reducing capital expenditures and DSM program costs, placing two generating units on long-term cold standby, creating a customer service business unit and moving responsibility for fuel procurement and bulk power sales to the generation department.
On February 14, 1995, the company filed a petition with the FERC asking for relief from having to pay approximately $2 billion more than its avoided costs for power purchased over the life of the two NUG contracts mentioned below. The company believes that the overpayments under these two contracts violate the Public Utility Regulatory Policies Act of 1978.
The company is currently required to purchase 594 megawatts (mw) of NUG power. The company is required to make payments under these contracts only for the power it receives or when the company directs the NUG to reduce its output under the terms of the contract. Two contracts the company has with NUGs each provide more than 5% of current system capability. One contract provides for 177 mw or 5.4%, and the other provides for 240 mw or 7.3%. During 1994, 1993 and 1992 the company purchased approximately $214 million, $138 million and $71 million, respectively, of NUG power, including termination costs. The
company estimates that NUG power purchases, excluding termination costs, over the next five years will be as follows:
1995 1996 1997 1998 1999 (Millions) $274 $312 $322 $333 $344
Increases in the cost of NUG power purchases will contribute significantly to expected electric price increases in August 1995.
Diversification
Diversification will play an important role in the company's future. The company's primary objective is to enhance the competitiveness of its core electric and natural gas businesses. At the same time the company is actively evaluating opportunities for investment closely related to its core businesses that have the potential to augment future earnings. In April 1992 the PSC issued an order allowing the company to invest up to 5% of its consolidated capitalization (approximately $180 million at December 31, 1994) in one or more subsidiaries that may engage or invest in energy-related or environmental-services businesses and provide related services.
The company has been making investments in unregulated companies through its wholly owned subsidiary, NGE Enterprises, Inc. (NGE). NGE owns two unregulated businesses - EnerSoft Corporation (EnerSoft) and XENERGY, Inc. (XENERGY).
EnerSoft, a computer software company, was formed in May 1993 to produce and market software for natural gas utilities, marketers and pipeline operators. Through an alliance with the New York Mercantile Exchange, EnerSoft is developing Channel 4, a natural gas and pipeline capacity trading and information system for the North American market. While development of the system has taken longer than anticipated, Channel 4 is expected to be commercially available in the spring of 1995. Like most other start-up companies, EnerSoft has been incurring operating losses. The company expects that EnerSoft will continue to incur operating losses in the near term.
In June 1994 NGE acquired all of the outstanding stock of XENERGY, an energy services, information systems and energy- consulting company that specializes in energy management, conservation engineering and demand-side management. XENERGY currently provides a broad range of services to utilities throughout the United States, Canada, Spain and France. It also provides energy services, conservation engineering and DSM services to governmental agencies at both the state and federal levels, and to a large number of end users.
NGE is exploring environmental-services opportunities with both domestic and foreign strategic partners.
As of December 31, 1994 and 1993, the company had invested approximately $47 million and $3 million, respectively, in NGE to finance its diversified investments. For the years ended December 31, 1994 and 1993, NGE incurred net losses of $6.0 million and $1.4 million, respectively.
Common Stock Dividend Policy
In October 1994 the board of directors reduced the quarterly common stock dividend from 55 cents per share to 35 cents per share. This dividend reduction allows the company to achieve greater financial flexibility and strength and the company believes it will offer improved shareholder value over the long term. Financial flexibility will be essential in a competitive environment, and stronger utilities will command higher stock valuations.
The company can give no assurances as to future dividend levels. Dividends will depend on the company's earnings and financial requirements, developments in the utility industry and other factors. The company's long-term goal is a dividend payout ratio of 60% to 65% of earnings. The board of directors will continue to review the common stock dividend each quarter to ensure that it is consistent with the company's long-term interests.
Net Cash Provided by Operating Activities
Cash provided by operating activities in 1994 increased $38 million, up 9% from 1993. The increase was primarily due to a reduction in cash used for working capital items in 1994. Net cash from operating activities is derived by adjusting reported net income for charges or credits that have no cash effect (primarily depreciation, amortization and deferred income taxes) and changes in working capital items.
Net Cash Used in Investing Activities
In 1994, cash used in investing activities decreased $86 million, down 28% from 1993. The change was primarily due to a decrease in expenditures for utility plant construction.
The company's 1994 capital expenditures for its core electric and natural gas businesses totaled approximately $248 million. Most of the expenditures were for the extension of service, improvements at existing facilities, compliance with the Clean Air Act Amendments of 1990, and other environmental requirements. The company received $24 million from governmental and other sources in 1994 to partially offset expenditures for compliance with the Clean Air Act Amendments of 1990.
Capital expenditures projected for 1995-1997 have been limited and reflect planned cuts of more than $200 million. This represents one of the many actions the company is taking to address competition. Capital expenditures will be primarily for extension of service, necessary improvements at existing facilities, the natural gas storage project, compliance with the Clean Air Act Amendments of 1990 and other environmental requirements (see Note 9). The company expects to finance these capital expenditures entirely with internally generated funds. The company forecasts that its current reserve margin, coupled with more efficient use of energy (see Conservation Programs) and purchases of power from NUGs, eliminates the need for additional generating capacity until after the year 2007.
The following table provides information on the company's estimated sources and uses of funds for 1995-1997. This forecast is subject to periodic review and revision. Actual capital expenditures may change to reflect the imposition of additional regulatory requirements and the company's continued focus on optimizing capital expenditures.
1995 1996 1997 Total (Millions) Sources of funds Internal funds $298 $288 $284 $870 Long-term financing 39 - - 39 ---- ---- ---- ---- Total $337 $288 $284 $909 ==== ==== ==== ==== Uses of funds Capital expenditures Cash $185 $258 $180 $623 AFDC* 3 6 4 13 ---- ---- ---- ---- Total capital expenditures 188 264 184 636 Retirement of securities and sinking fund obligations 63 26 78 167 Repayment of short-term debt 55 20 33 108 Working capital, deferrals and other 31 (22) (11) (2) ---- ---- ---- ---- Total $337 $288 $284 $909 ==== ==== ==== ==== *Allowance for funds used during construction.
As shown in the preceding table, internal sources of funds represent 137% of capital expenditures for 1995-1997.
Net Cash Used in Financing Activities
Cash used in financing activities in 1994 increased $106 million, up 96% from 1993. This increase reflects a reduction of cash provided from the issuance of preferred stock and the use of cash provided by operating activities to reduce debt levels.
The company believes that maintaining financial integrity and flexibility is critical to success in a competitive environment. The dividend reduction,along with recent cost reductions,will allow future cash flows to meet all of the company's operating and capital needs. The company plans to use its strong cash flow in excess of operating and capital needs primarily to reduce debt in preparation for competition. The company will also use its cash flow to invest in both regulated and unregulated businesses that relate to its core businesses and that have the potential to grow and yield value for the company's shareholders. Since 1987 the company has reduced its debt from 61.9% to 46.7% of total capital and has raised its common stock equity from 32.7% to 46%. Its goal is to achieve a 50% common equity ratio.
The common stock equity ratio improved in 1994 primarily as a result of retained earnings, the issuance of shares pursuant to the Dividend Reinvestment and Stock Purchase Plan (DRP), the repayment at maturity of $100 million of 8 3/8% bonds in August 1994 and the repayment of the $50 million revolving credit agreement note. The company received $22.7 million from the issuance of 0.9 million shares of common stock through the DRP. However, beginning in August 1994, the DRP began purchasing shares on the open market rather than the company issuing new shares. The company expects that the DRP will continue purchasing shares on the open market as long as the market price of the stock, which was below book value during the latter half of 1994, remains below book value. Issuing new shares below book value would decrease book value per share and lead to a decrease in future earnings per share.
The following table indicates the company's financing activities during 1994: Interest Month Description Rate Due Amount
Issuances (Thousands)
February (1) Pollution control note Various* Feb. 1, 2029 $37,500 April (2) Pollution control note 6.05% Apr. 1, 2034 $100,000 June (3) Pollution control note Various* June 1, 2029 $63,500 October (4) Pollution control note Various* Oct. 1, 2029 $74,000
* Multi-mode note, maturity could be extended to 2034 under certain circumstances.
Redemptions/ Maturities
January Preferred stock-Series A Adj. Rate n/a $45,000 January Preferred stock 8.80% n/a $25,000 February Preferred stock 8.48% n/a $25,000 February First mortgage bond 8 5/8% Nov. 1, 2007 $23,000 August First mortgage bond 8 3/8% Aug. 15, 1994 $100,000 March Pollution control note 2.75% Mar. 1, 2015 $37,500 May Pollution control note 12.0% May 1, 2014 $60,000 July Pollution control note 12.30% July 1, 2014 $40,000 July Pollution control note 2.60% July 15, 2015 $63,500 December Pollution control note 2.80% Dec. 1, 2014 $74,000 May Revolving credit agreement note 4.06% July 31, 1997 $50,000
(1) Proceeds were used to refund, in March 1994, $37.5 million of one- year adjustable-rate pollution control revenue bonds, due 2015.
(2) Proceeds were used in connection with the redemption in May 1994 of $60 million of 12.0% pollution control bonds, due 2014, and the redemption in July 1994 of $40 million of 12.3% pollution control bonds, due 2014.
(3) Proceeds were used to refund, in July 1994, $63.5 million of one- year adjustable-rate pollution control revenue bonds, due 2015.
(4) Proceeds were used to refund, in December 1994, $74 million of one- year adjustable-rate pollution control revenue bonds, due 2014.
The company reduced its embedded cost of long-term debt to 7.1% at the end of 1994 compared to 9.8% at the end of 1987. The company has refinanced more than $1.5 billion in long-term debt since the beginning of 1988 and reduced annual interest expense by more than $60 million. Unless interest rates fall further it will be difficult to significantly improve from the 7.1% level. All opportunities will continue to be pursued aggressively.
The company uses short-term unsecured notes, usually commercial paper, to finance certain refundings and for other corporate purposes. There was $151.9 million of commercial paper outstanding at December 31, 1994, at a weighted average interest rate of 5.8%.
The company also has a revolving credit agreement with certain banks that provides for borrowing up to $200 million to July 31, 1997. The company had an outstanding $50 million loan under this agreement at December 31, 1993, at an interest rate of 4.06%. This loan was repaid in May 1994.
During 1994 the company had its securities ratings downgraded by both Standard & Poor's and Moody's Investors Service. These downgrades reflect the rating agencies' use of more stringent financial benchmarks in evaluating utilities, in order to reflect increasing competition and mounting business risks. More than one-quarter of the electric utility industry had its securities ratings downgraded in the past 18 months.
The company is committed to its goal of achieving an 'A' bond rating. The company plans to continue to strengthen its balance sheet by paying down debt with excess cash.
Regulatory Matters
In September 1993 the company reached a three-year electric and natural gas rate-settlement agreement with the PSC covering the period August 1, 1993 through July 31, 1996. Under the agreement, the allowed return on equity was 10.8% in year one, 11.4% in year two and 11.4% (subject to an indexing mechanism) in year three. Shareholders were allowed to keep 100% of any earnings above the allowed return in year one. Shareholders and customers are to share, on a 50%/50% basis, any earnings over the allowed return in years two and three. The calculation of earnings over the allowed return includes regulatory adjustments (such as the elimination of the impact of incentives and sharing mechanisms) and certain normalizing adjustments (such as spreading the 1993 restructuring charge over the term of the settlement agreement). For year one, the twelve months ended July 31, 1994, the company's earned return on equity, with adjustments, as discussed above, was 10.3%. The earned returns on electric equity and natural gas equity, with adjustments, were 10.1% and 12.7% respectively, for year one.
The agreement also includes a modified revenue decoupling mechanism (RDM) for electric sales. Rates are based on sales forecasts. Since actual sales may differ significantly from forecasted sales because of conservation efforts, unusual weather or changing economic conditions, revenues collected may be more or less than forecasted. Subject to the limits described below, the modified RDM lets the company adjust for most of the differences between forecasted and actual sales. For example, if revenues exceed the forecast for a given year, the excess is passed back to customers in a future year. If revenues are below the forecast, customers receive a surcharge in a future year. The company must share revenue excesses or shortfalls from sales to most large commercial and industrial customers on a 70%/30% (customer/shareholder) basis. In 1994 the company accrued $22.3 million under the modified RDM compared with $3.9 million in 1993. In 1993 the modified RDM covered only the period August through December.
Customer savings of $21 million in production and transmission operating costs are imputed over the three years of the agreement, at $7 million each year, whether or not such savings are realized.
The estimated total electric price increases anticipated by the agreement are $99.6 million, or 7.4%, in year one; $109.5 million, or 7.6% in year two; and $87.8 million, or 5.6% in year three. These include base rate increases plus estimated price increases for fuel, purchased power and other costs that are collected through the fuel adjustment clause (FAC). Actual costs collected through the FAC could vary from estimates, causing the total electric price increases to change.
The base rate increases for natural gas allowed by the agreement are $7.5 million, or 2.9%, in year one; $8.2 million, or 3.0%, in year two; and $7.2 million, or 2.5%, in year three. They do not include changes in natural gas costs, which will be collected through the gas adjustment clause. Natural gas costs can be expected to rise and fall with overall natural gas market conditions. Such fluctuations will affect the total natural gas price increases.
The agreement also provides for the stated base rate increases for electricity and natural gas to be adjusted up or down in the second and third years, as well as the year after the agreement period (year four). Base rates can be adjusted for several factors, such as electric sales, incentive mechanisms and other true-ups from the prior year. The electric base rate increases could be adjusted upward by up to 1.5% in years two and three and 1.6% in year four. The natural gas base rate increases could be adjusted upward by up to 1.0% in year two and 1.2% in year three. The agreement does not specify a limit on the upward adjustment for natural gas base rates for year four. There is no limit to any downward adjustment of base rates for electric and natural gas.
In June 1994 the company finalized its filing of adjustments to the second-year electric and natural gas rates in accordance with the terms of the agreement. The company took voluntary action to lower the estimated total electric price increase to 7.8%. The electric price increase which was primarily due to increases in mandated purchases of electricity from NUGs, increases in taxes and sales shortfalls related to mandated conservation programs and the weak economy in New York State, would have been substantially greater than 7.8% without the voluntary action. The filed natural gas base rate increase was 1.9%. On August 15, 1994, the PSC issued an Opinion and Order that approved the electric price increase of 7.8% and the 1.9% natural gas base rate increase effective August 1, 1994. In addition, the PSC directed the company and staff of the PSC to begin discussions on modifying the agreement to mitigate the projected third-year electric increase and bring rate predictability and stability to future years. Those discussions began in October 1994 and are continuing.
The agreement provides incentives (rewards or penalties) to the company for controlling production costs (PCI), improving customer service and implementing DSM programs. Those incentives could have increased the company's allowed return to 12.3% or decreased it to 9.95% in year one, increase it to 13.05% or decrease it to 10.4% in year two, and increase it to 13.25% or decrease it to 10.2% in year three. In June 1994 the company calculated and recorded a production-cost penalty for 1993 of $13.0 million, or 12 cents per share. This was the maximum permitted by the agreement.
The PCI is based on a comparison of the company with a 19- company peer group (which includes the company). The production measure compared is the relative change in production and certain other costs per megawatt-hour of retail sales occurring between the applicable calendar year and a base period (1989-1992). The company calculated the PCI penalty for 1993 using data reported in the peer group's FERC Form 1 Reports, which the company received in May 1994. The company's PCI penalty for 1993 was due primarily to a significantly lower increase in retail sales (after adjusting for the effect of sales lost due to DSM programs) for the company than for the peer group. It was also due to a greater increase in DSM program costs and purchased power costs for the company than for the peer group.
The company believes that a penalty for its PCI performance in 1994 is unlikely. This is primarily because of the company's recent cost-reduction efforts and improved sales compared to the sales increase of the peer group, which is projected to be less than the peer group's sales increase in 1993. This estimate includes the company's actual performance through December 31, 1994. However, it was necessary to make certain assumptions regarding the peer group's 1994 performance since the actual information needed for this calculation will not be available until the peer group's FERC Form 1 Reports become available in May 1995. As an example, retail sales units and certain production costs for the peer group were assumed to continue at the levels achieved through the first nine months of 1994. The maximum PCI allowed for 1994 by the agreement is a reward or penalty of $17.5 million, or 16 cents per share.
Conservation Programs
The company has implemented a number of DSM programs. As part of its three-year rate agreement (see Regulatory Matters), the rewards the company could earn for conducting efficient DSM programs were reduced from 15% to 5% of the net resource savings achieved by these programs. For 1995 the company expects to earn approximately $1 million in rewards as a result of DSM programs.
In 1994 customers saved approximately 64 million kilowatt- hours (kwh) on an annualized basis through DSM programs. These programs cost $14 million in 1994 and will cost approximately $11 million in 1995. The customer savings estimated for 1995 are 54 million kwh on an annualized basis. At both December 31, 1994 and 1993, the company had approximately $73 million of deferred DSM program costs on its consolidated balance sheets. The two- year (1993-1994) DSM plan, which received PSC approval, was modified to improve cost-effectiveness and reduce rate impacts. In August 1994 the company submitted its 1995 DSM plan to the PSC proposing DSM goals and budgets for the years 1995 through 2000. The company expects to change its DSM approach in 1995 to move toward promoting energy-efficient equipment in the mass market and phasing out rebates for individual customers.
Environmental Matters
The company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Any additional compliance programs will increase the cost of electric and natural gas service by requiring changes in the company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred to comply with environmental laws and regulations (See Note 9 and Note 10).
Results of Operations 1994 1993 over over 1993 1992 1994 1993 1992 Change Change (Thousands, except per share amounts) Operating revenues $1,898,855 $1,800,149 $1,691,689 5% 6% Earnings available for common stock $168,698 $145,390 $162,973 16% (11%) Average shares outstanding 71,254 69,990 67,972 2% 3% Earnings per share $2.37 $2.08 $2.40 14% (13%) Dividends per share $2.00 $2.18 $2.14 (8%) 2%
Total operating revenues in 1994 increased $99 million, up 5% over 1993. In 1993, total operating revenues increased $108 million, up 6% from 1992. These results are discussed according to business segment beginning on page 44.
Earnings per Share
In 1994 earnings per share increased 29 cents, up 14% over 1993, while in 1993 earnings per share decreased 32 cents, down 13% from 1992. Certain nonrecurring items lowered earnings per share for 1993 and 1992. Earnings in 1993 were reduced 25 cents per share by the corporate restructuring that reorganized the way the company delivers services to its electric and natural gas customers beginning in March 1994 (see Note 6). Earnings in 1992 were 24 cents per share lower than they otherwise would have been because of a six-month moratorium on electric rate increases that began in February 1992. Without these nonrecurring items, earnings per share were up 4 cents in 1994 compared to 1993, and were down 31 cents in 1993 compared to 1992.
The increase in 1994 earnings per share without the nonrecurring items was due to a combination of factors. Lower operation and maintenance expenses that resulted from cost controls and the workforce reduction helped 1994 earnings by 26 cents per share. Also, on a comparative basis, 1994 earnings rose because lower electric retail sales in 1993 before the effective date of the company's modified RDM reduced 1993 earnings 9 cents per share. These increases in earnings per share were partially offset by the reduction in rewards earned from the company's DSM programs that lowered earnings by 13 cents per share; the 1993 production-cost penalty recorded in the second quarter of 1994 that reduced earnings by 12 cents per share; and losses incurred by the company's diversified operations that lowered earnings by 7 cents per share.
The decrease in 1993 earnings per share without the nonrecurring items was mainly due to lower electric retail sales before the effective date of the company's modified RDM, and to lower-than-anticipated natural gas sales. Both of these results were due to the sluggish economy in the company's service territory. Also, earnings per share decreased because of reductions in the company's allowed return on equity, from 11.7% effective through July 1992, to 11.2% effective through July 1993, and then to 10.8% beginning in August 1993.
Interest Expense
Interest expense (before the reduction for allowance for borrowed funds used during construction) decreased by $6 million, or 4% in 1994, and $10 million, or 6% in 1993. Interest on long- term debt decreased in 1994 and 1993 mainly due to the refinancing or refunding of certain high-coupon long-term debt. In 1993 interest expense also decreased due to lower interest rates on the company's variable rate debt.
Average Shares Outstanding
Average shares outstanding were 71 million in 1994, 70 million in 1993 and 68 million in 1992. The increases in average shares outstanding, 2% in 1994, and 3% in 1993, were both due to the issuance of shares of common stock through the DRP. A total of 0.9 million shares of common stock were issued through the DRP in 1994, and 1.2 million shares were issued in 1993. The number of shares issued in 1994 was lower than in 1993 because the DRP began purchasing shares on the open market as of August 1994 rather than the company issuing new shares. The company expects that the DRP will continue purchasing shares on the open market as long as the market price of the stock, which was below book value during the latter half of 1994, remains below book value. Issuing new shares below book value would decrease book value per share and lead to a decrease in future earnings per share.
Dividends per Share
Dividends decreased 8% in 1994 because the board of directors reduced the quarterly common stock dividend from 55 cents per share to 35 cents per share in October 1994 (see Common Stock Dividend Policy).
Operating Results for the Electric Business Segment 1994 1993 over over 1993 1992 1994 1993 1992 Change Change (Thousands)
Retail sales - kilowatt - hours(kwh) 13,147,631 13,088,175 13,294,466 - (2%) Operating revenues $1,600,075 $1,527,362 $1,451,525 5% 5% Operating expenses $1,306,871 $1,250,000 $1,146,619 5% 9% Operating income $293,204 $277,362 $304,906 6% (9%)
Electric retail sales for 1994 were up slightly compared to 1993 sales. In 1993, electric retail sales were down 2% from 1992 (despite a 1% increase in customers) due to the sluggish economy in the company's service territory.
Operating Revenues
Electric operating revenues increased by $73 million, or 5%, in 1994, and by $76 million, or 5%, in 1993. The more significant items contributing to these changes are as follows:
1994 1993 (Millions) Rate changes $69 $53 RDM 18 4 Recovery of increases in NUG power through fuel adjustment clause (FAC) 16 28 Interchange profits 16 - DSM incentives (14) - DSM lost revenues (15) - Production-cost penalty (13) - Other (4) (9) --- --- Total increase $73 $76 === ===
Changes in electric rates effective in September 1993 and August 1994 were the principal reason for higher 1994 revenues. The rate changes were caused primarily by an increase in mandated purchases of NUG power and by higher federal taxes. The modified RDM contributed to revenues since actual electric sales in 1994 were below the levels forecasted in the company's rate agreement. Higher costs of NUG power, which are billed to customers in part through the FAC, also boosted 1994 revenues. Interchange profits helped revenues due to an increase in interchange sales volume over 1993. These increases were partially offset by a decrease in rewards earned from DSM programs, a decrease in DSM lost revenues recorded and the 1993 production-cost penalty recorded in the second quarter of 1994.
The $76 million, or 5%, increase in electric operating revenues in 1993 was primarily due to rate changes effective in August 1992 and September 1993, mainly the result of an increase in mandated purchases of NUG power and rising taxes. Higher costs of NUG power (billed to customers in part through the FAC) also contributed to the growth in revenues.
Operating Expenses
Electric operating expenses in 1994 increased $57 million, or 5%, over the 1993 level. The principal cause was an increase of $80 million in electricity purchased, primarily purchases from NUGs. Federal income taxes grew by $17 million, the result of higher pretax book income. Gross receipts taxes and school taxes added another $7 million to expenses. Depreciation expense rose $12 million compared to 1993. Those increases were partially offset by decreases of $15 million in operating expenses (mainly due to cost controls and the workforce reduction) and $14 million in fuel used in electric generation (due to reduced generation). Also, expenses were $21 million lower in 1994 because of the restructuring charge recorded in the fourth quarter of 1993.
In 1993 electric operating expenses were $103 million, or 9%, higher than in 1992. The major contributor to this increase was electricity purchased from NUGs, which rose by $67 million. Postretirement-benefit costs other than pensions increased $7 million. Corporate restructuring added another $21 million to electric operating expenses. These increases were partially offset by a $17 million decrease in fuel used in electric generation (the result of reduced generation and a lower price for coal) and by a $12 million decrease in federal income taxes (the result of lower pretax book income).
Operating Results for the Natural Gas Business Segment 1994 1993 over over 1993 1992 1994 1993 1992 Change Change (Thousands)
Deliveries - dekatherms (dth) 58,624 58,046 56,366 1% 3% Operating revenues $298,780 $272,787 $240,164 10% 14% Operating expenses $269,300 $249,493 $221,307 8% 13% Operating income $29,480 $23,294 $18,857 27% 24%
Natural gas deliveries rose by 1% in 1994 and by 3% in 1993. The increase in deliveries in 1994 and 1993 was due to the addition of new customers, including several large volume customers.
Operating Revenues
Natural gas operating revenues rose by $26 million, or 10%, in 1994, and by $33 million, or 14%, in 1993. The more significant items that contributed to these changes are as follows: 1994 1993 (Millions) Natural gas price increases $16 $23 Rate changes 7 8 Other 3 2 --- --- Total increase $26 $33 === ===
Higher costs of natural gas (billed to customers) were the primary reason for the rise in 1994 revenues. Rate changes effective in September 1993 and August 1994 also added to revenues. However, since the company has a weather normalization mechanism for natural gas, $0.9 million of revenues attributable to colder weather was returned to customers in 1994.
In 1993 the leading contributors to the increase in revenues were higher costs of natural gas and the rate changes that became effective in August 1992 and September 1993. Revenues of $1.0 million were returned to customers in 1993 through the weather normalization mechanism.
Operating Expenses
Natural gas operating expenses were up by $20 million, or 8%, in 1994, mainly because of an increase of $20 million in natural gas purchased that was mostly due to higher prices. Higher federal income taxes increased operating expenses by $4 million, due to higher pretax book income. Gross receipts taxes and school taxes added another $1 million to expenses. Depreciation expense rose $2 million compared to 1993. Those increases were partially offset by a decrease of $5 million because of the restructuring charge recorded in 1993 and a $1 million decrease in marketing expenses due to improved operations.
Operating expenses in 1993 increased $28 million, up 13% from their 1992 level. Natural gas purchased rose by $12 million, mainly because of higher natural gas prices. Federal income taxes increased $3 million due to higher pretax book income. Corporate restructuring added $5 million to natural gas operating expenses.
Item 8. Financial Statements and Supplementary Data
New York State Electric & Gas Corporation Consolidated Balance Sheets
December 31 1994 1993 - ------------------------------------------------------------------------------- (Thousands) Assets
Utility Plant, at Original Cost (Note 1) Electric (Note 8). . . . . . . . . . . . . . . . . . . $4,916,960 $4,777,368 Natural gas. . . . . . . . . . . . . . . . . . . . . . 414,929 381,389 Common . . . . . . . . . . . . . . . . . . . . . . . . 143,366 158,986 ---------- ---------- . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,475,255 5,317,743 Less accumulated depreciation. . . . . . . . . . . . . 1,642,653 1,535,307 ---------- ---------- Net Utility Plant in Service. . . . . . . . . . . 3,832,602 3,782,436 Construction work in progress. . . . . . . . . . . . . 154,723 143,859 ---------- ---------- Total Utility Plant . . . . . . . . . . . . . . . 3,987,325 3,926,295
Other Property and Investments, Net (Note 12) . . . . . 103,920 73,537
Current Assets Cash and cash equivalents (Notes 1 and 13) . . . . . . 22,322 4,264 Special deposits (Note 13) . . . . . . . . . . . . . . 7,591 145,335 Accounts receivable, net (Note 1). . . . . . . . . . . 155,665 181,586 Fuel, at average cost. . . . . . . . . . . . . . . . . 49,934 54,791 Materials and supplies, at average cost. . . . . . . . 47,843 48,910 Prepayments. . . . . . . . . . . . . . . . . . . . . . 30,441 30,092 Accumulated deferred federal income tax benefits, net (Notes 1 and 2) . . . . . . . . . 11,457 - ---------- ----------
Total Current Assets. . . . . . . . . . . . . . . . 325,253 464,978
Deferred Charges (Note 1) Unfunded future federal income taxes (Notes 1 and 2) . . . . . . . . . . . . . . . 363,151 380,056 Unamortized debt expense . . . . . . . . . . . . . . . 114,444 112,059 Demand-side management program costs . . . . . . . . . 72,849 73,113 Other. . . . . . . . . . . . . . . . . . . . . . . . . 255,963 257,920 ---------- ---------- Total Deferred Charges. . . . . . . . . . . . . . 806,407 823,148 ---------- ---------- Total Assets. . . . . . . . . . . . . . . . . . . $5,222,905 $5,287,958 ========== ==========
The notes on pages 53 through 79 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Balance Sheets
December 31 1994 1993 - ------------------------------------------------------------------------------ (Thousands) Capitalization and Liabilities
Capitalization Common stock equity Common stock ($6.66 2/3 par value, 90,000,000 shares authorized and 71,502,827 and 70,595,985 shares issued and outstanding at December 31, 1994 and 1993, respectively) . . . . . . . . . . $476,686 $470,640 Capital in excess of par value. . . . . . . . . . 841,624 824,943 Retained earnings . . . . . . . . . . . . . . . . 346,547 320,114 ---------- ---------- Total common stock equity. . . . . . . . . . . . . . . 1,664,857 1,615,697 Preferred stock redeemable solely at the option of the company (Note 4). . . . . . . . . . . . . . . . 140,500 140,500 Preferred stock subject to mandatory redemption requirements (Notes 4 and 13) . . . . . . . . . . . 125,000 125,000 Long-term debt (Notes 3 and 13). . . . . . . . . . . . 1,651,081 1,630,629 ---------- ---------- Total Capitalization. . . . . . . . . . . . . . . 3,581,438 3,511,826 Current Liabilities Current portion of long-term debt (Note 3) . . . . . . 36,231 237,709 Current portion of preferred stock (Note 4). . . . . . - 95,000 Notes payable (Notes 5 and 13) . . . . . . . . . . . . 151,900 50,200 Accounts payable and accrued liabilities . . . . . . . 107,356 111,481 Interest accrued (Note 13) . . . . . . . . . . . . . . 25,132 31,348 Accumulated deferred federal income taxes, net (Notes 1 and 2) . . . . . . . . . . . . . . . . . . - 1,132 Other. . . . . . . . . . . . . . . . . . . . . . . . . 94,961 89,443 ---------- ---------- Total Current Liabilities . . . . . . . . . . . . 415,580 616,313
Deferred Credits and Other Liabilities Accumulated deferred investment tax credit (Notes 1 and 2) . . . . . . . . . . . . . . . . . . 132,440 138,478 Excess deferred federal income taxes (Notes 1 and 2) . 34,040 36,378 Other postretirement benefits. . . . . . . . . . . . . 55,887 28,074 Liability for environmental restoration (Note 10). . . 33,600 26,800 Other. . . . . . . . . . . . . . . . . . . . . . . . . 131,585 133,488 ---------- ---------- Total Deferred Credits and Other Liabilities. . . 387,552 363,218
Accumulated Deferred Federal Income Taxes (Notes 1 and 2) Unfunded future federal income taxes . . . . . . . . . 363,151 380,056 Other. . . . . . . . . . . . . . . . . . . . . . . . . 475,184 416,545 ---------- ---------- Total Accumulated Deferred Federal Income Taxes . . . . . . . . . . . . . . . . . . 838,335 796,601
Commitments and Contingencies (Note 9). . . . . . . . . - - ---------- ---------- Total Capitalization and Liabilities. . . . . . . $5,222,905 $5,287,958 ========== ==========
The notes on pages 53 through 79 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Statements of Income
Year Ended December 31 1994 1993 1992 - ---------------------------------------------------------------------------- (Thousands, except per share amounts)
Operating Revenues Electric . . . . . . . . . . . . . . . . $1,600,075 $1,527,362 $1,451,525 Natural gas. . . . . . . . . . . . . . . 298,780 272,787 240,164 ---------- ---------- ---------- Total Operating Revenues . . . . . . 1,898,855 1,800,149 1,691,689 ---------- ---------- ---------- Operating Expenses Fuel used in electric generation . . . . 231,648 245,283 262,531 Electricity purchased (Note 9) . . . . . 242,352 161,967 95,026 Natural gas purchased. . . . . . . . . . 161,627 141,635 126,815 Other operating expenses . . . . . . . . 328,961 349,177 318,680 Restructuring expenses (Notes 6 and 7) . - 26,000 - Maintenance. . . . . . . . . . . . . . . 106,637 111,757 102,500 Depreciation and amortization (Note 1) . 178,326 164,568 158,977 Federal income taxes (Notes 1 and 2) . . 115,891 94,144 102,456 Other taxes . . . . . . . . . . . . . . 210,729 204,962 200,941 ---------- ---------- ---------- Total Operating Expenses . . . . . . . 1,576,171 1,499,493 1,367,926 ---------- ---------- ---------- Operating Income. . . . . . . . . . . . . 322,684 300,656 323,763 Other Income and Deductions (Note 12) . . 1,053 6,471 12,036 ---------- ---------- ---------- Income Before Interest Charges. . . . . . 323,737 307,127 335,799 ---------- ---------- ---------- Interest Charges Interest on long-term debt . . . . . . . 126,083 134,330 145,822 Other interest . . . . . . . . . . . . . 13,642 11,120 9,566 Allowance for borrowed funds used during construction. . . . . . . . (3,633) (4,351) (3,557) ---------- ---------- ---------- Interest Charges, Net. . . . . . . . . 136,092 141,099 151,831 ---------- ---------- ---------- Net Income. . . . . . . . . . . . . . . . 187,645 166,028 183,968 Preferred Stock Dividends . . . . . . . . 18,947 20,638 20,995 ---------- ---------- ---------- Earnings Available for Common Stock . . . $168,698 $145,390 $162,973 ========== ========== ========== Earnings Per Share. . . . . . . . . . . . $2.37 $2.08 $2.40 Average Shares Outstanding. . . . . . . . 71,254 69,990 67,972
The notes on pages 53 through 79 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Statements of Cash Flows
Year Ended December 31 1994 1993 1992 - ------------------------------------------------------------------------------ (Thousands) Operating Activities Net income . . . . . . . . . . . . . . . . . . . . $187,645 $166,028 $183,968 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization. . . . . . . . . . 178,326 164,568 158,977 Deferred fuel and purchased gas. . . . . . . . . (1,944) (10,671) (14,645) Federal income taxes and investment tax credits deferred, net. . . . . . . . . . . . . . . . . 13,670 50,761 52,039 Unbilled revenue amortization (Note 1) . . . . . (3,769) (5,335) (10,451) Demand-side management program costs . . . . . . 264 (29,064) (22,863) Restructuring expenses . . . . . . . . . . . . . - 26,000 - Changes in current operating assets and liabilities: Special deposits . . . . . . . . . . . . . . . . 42,744 2,438 (1,873) Accounts receivable excluding accounts receivable sold. . . . . . . . . . . . . . . . 25,921 (23,703) (38,345) Accounts receivable sold (Note 1). . . . . . . . - 13,800 - Prepayments. . . . . . . . . . . . . . . . . . . (349) 7,805 (878) Inventory. . . . . . . . . . . . . . . . . . . . 5,924 16,013 (1,376) Accounts payable and accrued liabilities . . . . (4,125) 15,485 (4,851) Interest accrued . . . . . . . . . . . . . . . . (6,216) (6,342) (5,750) Other, net . . . . . . . . . . . . . . . . . . . . 12,287 24,407 (7,685) -------- -------- -------- Net Cash Provided by Operating Activities . . . 450,378 412,190 286,267 -------- -------- -------- Investing Activities Utility plant capital expenditures, net of allowance for other funds used during construction . . . . . . . . . . . . . . . . . . (246,536)(265,109)(243,373) Proceeds received from governmental and other sources . . . . . . . . . . . . . . . . . 23,915 22,808 322 Expenditures for other property and investments. . (34,482) (16,975) - Funds restricted for capital expenditures. . . . . 41,113 (42,437) - -------- -------- -------- Net Cash Used in Investing Activities . . . . . (215,990)(301,713)(243,051) -------- -------- -------- Financing Activities Issuance of pollution control notes and first mortgage bonds . . . . . . . . . . . . . . 275,000 217,362 247,668 Proceeds from revolving credit agreement note. . . - 50,000 - Sale of common stock . . . . . . . . . . . . . . . 23,386 38,334 162,965 Sale of preferred stock. . . . . . . . . . . . . . - 97,762 - Repayments of pollution control notes, first mortgage bonds and preferred stock, including premiums. . . . . . . . . . . . (497,450)(326,091)(178,289) Repayment of revolving credit agreement note . . . (50,000) - - Changes in funds set aside for preferred stock and first mortgage bond repayments . . . . . . . 95,000 (8,904) (83,096) Long-term notes, net . . . . . . . . . . . . . . . (2,290) 8,393 (1,593) Notes payable, net . . . . . . . . . . . . . . . . 101,700 (13,900) (39,800) Dividends on common and preferred stock. . . . . . (161,676)(173,137)(165,704) -------- -------- -------- Net Cash Used in Financing Activities . . . . . (216,330)(110,181) (57,849) -------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents 18,058 296 (14,633) Cash and Cash Equivalents, Beginning of Year. . . . 4,264 3,968 18,601 -------- -------- -------- Cash and Cash Equivalents, End of Year (Notes 1 and 13). . . . . . . . . . . . . . . . . $22,322 $4,264 $3,968 ======== ======== ========
The notes on pages 53 through 79 are an integral part of the financial statements.
Notes to Consolidated Financial Statements
1 Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the company's wholly-owned subsidiaries, Somerset Railroad Corporation (SRC) and NGE Enterprises, Inc. (NGE). All significant intercompany balances and transactions are eliminated in consolidation.
Utility plant
The cost of repairs and minor replacements is charged to the appropriate operating expense accounts. The cost of renewals and betterments, including indirect costs, is capitalized. The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.
Depreciation and amortization
Depreciation expense is determined using straight-line rates, based on the average service lives of groups of depreciable property in service. Depreciation accruals were equivalent to 3.5%, 3.4% and 3.3%, of average depreciable property for 1994, 1993 and 1992 respectively. Depreciation expense includes the amortization of certain deferred charges authorized by the Public Service Commission of the State of New York (PSC).
Revenue
During 1994, 1993 and 1992 the company recognized on the income statement approximately $4 million, $5 million and $10 million, respectively, of electric and natural gas unbilled revenues that had been accrued on its balance sheet for energy provided but not yet billed to minimize the rate increases for these years in accordance with various PSC rate decisions. The July 1992 rate decision allowed the company to recognize on its income statement, beginning in August 1992, electric and natural gas unbilled revenues on a full accrual basis.
The company recognizes as revenue, incentives earned as the result of conducting efficient demand-side management (DSM) programs. The company is collecting those incentives in rates within approximately one year after they are recognized. During 1994, 1993 and 1992 incentives earned were $2 million, $16.4 million and $15.6 million, respectively. At December 31, 1994 and 1993, approximately $1.2 million and $14.3 million, respectively, of DSM incentives were accrued and included in accounts receivable.
Accounts receivable
The company has an agreement that expires in November 1996 to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allows the company to receive up to $152 million from the sale of such interests. At December 31, 1994 and 1993, accounts receivable on the consolidated balance sheets are shown net of $152 million of interests in accounts receivable sold. All fees associated with the program are included in other income and deductions on the consolidated statements of income and amounted to approximately $7.4 million, $5.7 million and $6.5 million in 1994, 1993 and 1992, respectively. Accounts receivable on the consolidated balance sheets is also shown net of an allowance for doubtful accounts of $7.2 million and $4 million at December 31, 1994 and 1993, respectively. Bad debt expense was $19.6 million, $15.3 million and $11.5 million in 1994, 1993 and 1992, respectively.
Income taxes
The company adopted Statement of Financial Accounting Standards No. 109 (SFAS 109), Accounting for Income Taxes, in January 1993. Since the company had been accounting for income taxes under Statement of Financial Accounting Standards No. 96, Accounting for Income Taxes, there was no effect on the consolidated statements of income as a result of adopting SFAS 109. However, SFAS 109 did require the company's deferred tax balances to be reclassified on its consolidated balance sheets.
The company files a consolidated federal income tax return with SRC and NGE. Deferred income taxes are provided on all temporary differences between financial statement basis and taxable income. Investment tax credits, which reduce federal income taxes currently payable, are deferred and amortized over the estimated lives of the applicable property. The effect of the alternative minimum tax (AMT), which increases federal income taxes currently payable and generates a tax credit available for future use, is deferred and amortized at such times as the tax credit is used on the company's federal income tax return.
Deferred charges
The company defers certain incurred expenses when authorized by the PSC. Those expenses will be recovered from customers in the future.
Consolidated Statements of Cash Flows
The company considers all highly liquid investments with a maturity or put date of three months or less when acquired to be cash equivalents. These investments are included in cash and
cash equivalents on the consolidated balance sheets.
Total income taxes paid were $69.2 million, $27.0 million and $37.6 million for the years ended December 31, 1994, 1993 and 1992, respectively.
Interest paid, net of amounts capitalized, was $132.0 million, $138.2 million and $149.3 million for the years ended December 31, 1994, 1993 and 1992, respectively.
Reclassifications
Certain amounts have been reclassified on the consolidated financial statements to conform with the 1994 presentation.
2 Income Taxes
Year ended December 31 1994 1993 1992 (Thousands) Charged to operations Current $88,623 $34,989 $37,237 Deferred, net Accelerated depreciation 51,736 49,580 41,492 Unbilled revenues (3,913) 5,073 160 Revenue decoupling mechanism 6,870 - - AMT credit (4,744) (3,194) 2,123 Demand-side management (9,048) 13,479 9,324 NUG termination agreement (1,313) 6,208 8,500 Nine Mile No. 2 litigation proceeds (520) 4,756 (2,047) Restructuring expenses - (6,965) - Postretirement benefits (5,079) (3,492) (593) Transmission facility agreement (2,719) (7,778) (1,172) Miscellaneous (3,970) (4,154) (4,598) Investment tax credit (ITC) (32) 5,642 12,030 -------- ------- ------- 115,891 94,144 102,456 Included in other income Amortization of deferred ITC (6,006) (8,892) (16,927) Miscellaneous (7,424) 498 3,747 -------- ------- ------- Total $102,461 $85,750 $89,276 ======== ======= =======
The company's effective tax rate differed from the statutory rate of 35% in 1994 and 1993 and 34% in 1992 due to the following:
Year ended December 31 1994 1993 1992 (Thousands) Tax expense at statutory rate $101,537 $88,684 $92,903 Depreciation not normalized 18,552 16,984 16,697 ITC amortization (6,006) (8,892) (16,927) Revenue Reconciliation Act of 1993, net (3,736) (631) - Research & Development (R&D) credit (1,352) (5,139) - Cost of removal (5,462) (4,921) (4,079) Other, net (1,072) (335) 682 -------- ------- ------- Total $102,461 $85,750 $89,276 ======== ======= ======= The company's deferred tax assets and liabilities consist of the following:
December 31 1994 1993 (Thousands) Current Deferred Taxes Demand-side management $(548) $(9,897) Unbilled revenue 4,449 (783) Pension expense 3,748 5,600 Other 3,808 3,948 ------- ------- Total current deferred taxes $11,457 $(1,132) ------- ------- Noncurrent Deferred Taxes Depreciation $(740,961) $(698,939) Loss on reacquired debt (26,663) (28,440) Regulatory asset (SFAS 109) (143,285) (149,636) Deferred ITC (net of SFAS 109) (86,205) (91,006) Demand-side management (25,785) (25,484) NUG contract settlement costs (13,850) (15,163) AMT credit 16,716 19,953 Excess tax reserve 11,788 12,603 Nine Mile No. 2 disallowed plant 13,519 19,347 Contributions in aid of construction 20,050 20,913 Capitalized interest 10,280 8,690 Other (4,168) (7,255) --------- --------- Total noncurrent deferred taxes $(968,564) $(934,417) --------- --------- Total deferred taxes $(957,107) $(935,549) Valuation allowance (2,211) (662) --------- --------- Net deferred taxes $(959,318) $(936,211) ========= =========
The Revenue Reconciliation Act of 1993 (RRA 1993), enacted on August 10, 1993, provided among other things, for an increase of 1% in the statutory corporate income tax rate and an extension of the R&D credit until June 30, 1995.
In September 1993 the company reached a three-year rate settlement agreement with the PSC which included a provision for the company to petition to defer the effect of RRA 1993 until it is reflected in rates. The changes related to RRA 1993 were reflected in rates beginning August 1, 1994.
The company has recorded unfunded future federal income taxes and a corresponding receivable from customers of approximately $363 million and $381 million as of December 31, 1994 and 1993, respectively, primarily representing the cumulative amount of federal income taxes on temporary depreciation differences, which were previously flowed through to customers. Those amounts, including the tax effect of the future revenue requirements, are being amortized over the life of the related depreciable assets concurrent with their recovery in rates.
The company has approximately $16.7 million of AMT credits that do not expire.
3 Long-Term Debt
At December 31, 1994 and 1993, long-term debt was (Thousands):
First mortgage bonds Amount Series Due 1994 1993 8 3/8% Aug. 15, 1994 $ - $100,000 5 5/8% Jan. 1, 1997 25,000 25,000 6 1/4% Sept. 1, 1997 25,000 25,000 6 1/2% Sept. 1, 1998 30,000 30,000 7 5/8% Nov. 1, 2001 50,000 50,000 6 3/4% Oct. 15, 2002 150,000 150,000 7 1/4% June 1, 2006 12,000 12,000 6 7/8% Dec. 1, 2006 25,000 25,250 8 5/8% Nov. 1, 2007 37,000 60,000 9 7/8% Feb. 1, 2020 100,000 100,000 9 7/8% May 1, 2020 100,000 100,000 9 7/8% Nov. 1, 2020 100,000 100,000 8 7/8% Nov. 1, 2021 150,000 150,000 8.30% Dec. 15, 2022 100,000 100,000 7.55% Apr. 1, 2023 50,000 50,000 7.45% July 15, 2023 100,000 100,000 --------- --------- Total first mortgage bonds 1,054,000 1,177,250 ========= =========
Pollution control notes
Interest Maturity Interest Rate Letter of Credit Amount Rate Date Adjustment Date Expiration Date 1994 1993 12% May 1, 2014 - - - 60,000 12.30% July 1, 2014 - - - 40,000 2.80% Dec. 1, 2014 - - - 74,000 2.75% Mar. 1, 2015 - - - 37,500 3.25%(1) Mar. 15, 2015 Mar. 15, 1995 Mar. 31, 1996 60,000 60,000 2.60% July 15, 2015 - - - 63,500 4.10%(1) Oct. 15, 2015 Oct. 15, 1995 Oct. 31, 1996 30,000 30,000 4.60%(1) Dec. 1, 2015 Dec. 1, 1995 Dec. 15, 1996 42,000 42,000 4.10%(1) July 1, 2026 July 1, 1996 July 15, 1996 65,000 65,000 5.95% Dec. 1, 2027 - - 34,000 34,000 5.70% Dec. 1, 2028 - - 70,000 70,000 Var.%(2) Feb. 1, 2029 Various Feb. 23, 1996 37,500 - Var.%(2) June 1, 2029 Various June 15, 1996 63,500 - Var.%(2) Oct. 1, 2029 Various Oct. 25, 1996 74,000 - 6.05% Apr. 1, 2034 - - 100,000 - ---------- --------- Total pollution control notes 576,000 576,000 ========== ========= Revolving credit agreement note - 50,000 Long-term notes due December 31, 1997 34,000 36,100 Various long-term notes 5,726 - CNG Transmission Corp. notes due November 10, 1996 and July 11, 1997 6,080 8,862 Obligations under capital leases 21,423 30,902 Unamortized premium and discount on debt, net (9,917) (10,776) ---------- ---------- 1,687,312 1,868,338 Less: debt due within one year-included in current liabilities 36,231 237,709 ---------- ---------- Total $1,651,081 $1,630,629 ========== ==========
At December 31, 1994, long-term debt and capital lease payments that will become due during the next five years are:
1995 1996 1997 1998 1999 (Thousands) $36,231 $16,138 $86,850 $31,414 $1,274
The company's mortgage provides for a sinking and improvement fund. This provision requires the company to make annual cash deposits with the Trustee equivalent to 1% of the principal amount of all bonds delivered and authenticated by the Trustee prior to January 1 of that year (excluding any bonds issued on the basis of the retirement of bonds). The company satisfied this requirement in 1994 by depositing $23 million in
cash that was used to redeem in February 1994 $23 million of 8 5/8% Series first mortgage bonds, due 2007. The company satisfied this requirement in 1995 by depositing $23 million in cash that was used to redeem in February 1995 $23 million of 9 7/8% Series first mortgage bonds, due February 2020.
Mandatory annual cash sinking fund requirements are $600,000 beginning June 1, 2001, for the 7 1/4% Series and $250,000 on December 1 in each year 1995 to 1996, for the 6 7/8% Series. The amount increases to $500,000 and $750,000 on December 1, 1997 and December 1, 2002, respectively, for the 6 7/8% Series.
The company's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all utility plant.
(1) Adjustable rate pollution control notes were issued to secure like amounts of tax-exempt adjustable rate pollution control revenue bonds (Adjustable Rate Revenue Bonds) issued by a governmental authority. The Adjustable Rate Revenue Bonds bear interest at the rate indicated through the date preceding the interest rate adjustment date. The adjustable rate pollution control notes bear interest at the same rate as the Adjustable Rate Revenue Bonds. On the interest rate adjustment date and annually thereafter (every three years thereafter in the case of the Adjustable Rate Revenue Bonds due July 1, 2026), the interest rate will be adjusted, not to exceed a rate of 15%, or at the option of the company, subject to certain conditions, a fixed rate of interest, not to exceed 18%, may become effective. In the case of the Adjustable Rate Revenue Bonds due July 1, 2026, at the option of the company, subject to certain conditions, a fixed rate of interest may become effective prior to the interest rate adjustment date or each third year thereafter. Bond owners may elect, subject to certain conditions, to have their Adjustable Rate Revenue Bonds purchased by the Trustee.
(2) Multi-mode pollution control notes were issued to secure like amounts of tax-exempt multi-mode pollution control refunding revenue bonds (Multi-mode Revenue Bonds) issued by a governmental authority. These Multi-mode Revenue Bonds have a structure that enables the company to optimize the use of short-term rates by allowing for the interest rates to be based on a commercial paper rate, a daily rate, a weekly rate or an auction rate. The structure also provides flexibility to convert the interest rates to term rates or fixed rates, in the event that it is in the company's best interest to do so. The multi-mode pollution control notes bear interest at the same rates as the Multi-mode Revenue Bonds. Bond owners may elect, while the Multi-mode Revenue Bonds bear interest at a daily rate or a weekly rate, to have their Multi-mode Revenue Bonds purchased by the Registrar and Paying Agent. The maturity date of the Multi-mode Revenue Bonds due February 1, 2029, June 1, 2029, and October 1, 2029, can be extended, subject to certain conditions, to a date not
later than February 1, 2034, June 1, 2034, and April 1, 2034, respectively. The weighted average interest rate for all three series (totaling $175 million principal amount) was 3.9%, excluding letter of credit fees, at December 31, 1994.
The company has irrevocable letters of credit that expire on the letter of credit expiration dates and that the company anticipates being able to extend if the interest rate on the related Adjustable Rate Revenue Bonds and Multi-mode Revenue Bonds is not converted to a fixed interest rate. Those letters of credit support certain payments required to be made on the Adjustable Rate Revenue Bonds and Multi-mode Revenue Bonds. If the company is unable to extend the letter of credit that is related to a particular series of Adjustable Rate Revenue Bonds, that series will have to be redeemed unless a fixed rate of interest becomes effective. Multi-mode Revenue Bonds are subject to mandatory purchase upon any change in the interest rate mode and in certain other circumstances. Payments made under the letters of credit in connection with purchases of Adjustable Rate Revenue Bonds and Multi-mode Revenue Bonds are repaid with the proceeds from the remarketing of such Bonds. To the extent the proceeds are not sufficient, the company is required to reimburse the bank that issued the letter of credit.
4 Preferred Stock
At December 31, 1994 and 1993, serial cumulative preferred stock was:
Shares Par Value Authorized Per Redeemable and Amount Series Share Prior to Per Share Outstanding(1) 1994 1993 (Thousands) Redeemable solely at the option of the company: 3.75% $100 $104.00 150,000 $15,000 $15,000 4 1/2%(1949) 100 103.75 40,000 4,000 4,000 4.15% 100 101.00 40,000 4,000 4,000 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 - - 25,000 8.48% 25 - - 25,000 7.40% (2) 25 12/1/98 26.85 1,000,000 25,000 25,000 Thereafter 25.00 Adjustable Rate 25 - - 45,000 Adjustable Rate (3) 25 12/1/98 27.50 2,000,000 50,000 50,000 Thereafter 25.00 -------- -------- 140,500 235,500 Less: preferred stock redemptions within one year - included in current liabilities - 95,000 -------- -------- Total $140,500 $140,500 ======== ========
Subject to mandatory redemption requirements:
6.30% (4) 100 1/1/96 105.04 250,000 $25,000 $25,000 8.95% (5) 25 1/1/96 26.64 4,000,000 100,000 100,000 -------- -------- Total $125,000 $125,000 ======== ========
At December 31, 1994, preferred stock redemptions and annual redeemable preferred stock sinking fund requirements for the next five years were:
1995 1996 1997 1998 1999 (Thousands) $ - $ - $5,000 $5,000 $5,000
(1) At December 31, 1994, there were 1,550,000 shares of $100 par value preferred stock, 3,800,000 shares of $25 par value preferred stock and 1,000,000 shares of $100 par value preference stock authorized but unissued.
(2) The company is restricted in its ability to redeem this Series prior to December 1, 1998.
(3) The payment on the Adjustable Rate Serial Preferred Stock, Series B, for April 1, 1995, is at an annual rate of 6.54% and subsequent payments can vary from an annual rate of 4% to 10%, based on a formula included in the company's Certificate of Incorporation. The company is restricted in its ability to redeem this Series prior to December 1, 1998.
(4) On January 1 in each year 2004 through 2008, the company must redeem 12,500 shares at par, and on January 1, 2009, the company must redeem the balance of the shares at par. This Series is redeemable at the option of the company at $105.04 per share prior to January 1, 1996. The $105.04 price will be reduced annually by 63 cents for the years ending 1996 through 2002; thereafter, the redemption price is $100.00. The company is restricted in its ability to redeem this Series prior to January 1, 2004.
(5) On January 1 in each year 1997 through 2016, the company must redeem 200,000 shares at par. This Series is redeemable at the option of the company at $26.64 per share prior to January 1, 1996. The $26.64 price will be reduced annually by 15 cents for the years ending 1996 through 1999; by 14 cents for the year ending 2000; and by 15 cents for the years ending 2001 through 2005. The company is restricted in its ability to redeem this Series prior to January 1, 1996.
5 Bank Loans and Other Borrowings
The company has a revolving credit agreement with certain banks that provides for borrowing up to $200 million to July 31, 1997. At the option of the company, the interest rate on borrowings is related to the prime rate, the London Interbank Offered Rate (LIBOR) or the interest rate applicable to certain certificates of deposit. The agreement also provides for the payment of a commitment fee that can fluctuate from .15% to .375%
depending upon the ratings of the company's first mortgage bonds. The commitment fee was .1875% at December 31, 1994 and 1993, and was .22% at December 31, 1992.
The company did not have any outstanding loans under the revolving credit agreement at December 31, 1994. At December 31, 1993, the company had an outstanding loan of $50 million under the revolving credit agreement at an interest rate of 4.06% under the LIBOR option. This loan was repaid in May 1994. The revolving credit agreement does not require compensating balances.
The company uses short-term unsecured notes, usually commercial paper, to finance certain refundings and for other corporate purposes. The weighted average interest rates on notes payable balances at December 31, 1994, 1993 and 1992 were 5.8%, 3.5% and 4.0%, respectively. At each year end, notes payable consisted of commercial paper with maturity dates of less than one year.
6 Restructuring
In the fourth quarter of 1993 the company recorded a $26 million restructuring charge. The corporate restructuring reorganized the way the company delivers services to its electric and natural gas customers beginning in March 1994. The restructuring reduced 1993 earnings available for common stock by approximately $17.2 million or 25 cents per share.
During the first quarter of 1994 the restructuring resulted in a workforce reduction totaling 642 persons throughout the organization, the elimination of customer walk-in services at 28 locations, and the closing of seven electric and natural gas operations facilities. The closing of additional electric and natural gas operations facilities will continue to be evaluated.
The workforce reduction of 642 employees, which was greater than the company's target of 600, was accomplished through a voluntary early retirement program (See Note 7) and an involuntary severance program. Of the 642 employees, 384 employees accepted the early retirement program and 258 employees were involuntarily severed. The company estimated the savings, excluding fringe benefits, related to the workforce reduction to be approximately $31.5 million, on an annual basis. As the workforce decreased, the company experienced savings in line with this estimate for 1994. The majority of these savings were used to minimize the company's electric and natural gas price increases in the second and third years of the rate settlement agreement.
7 Retirement Benefits
Pensions
The company has a noncontributory retirement annuity plan that covers substantially all employees. Benefits are based principally on the employee's length of service and compensation for the five highest paid consecutive years out of the last 10 years of service. It is the company's policy to fund pension costs accrued each year to the extent deductible for federal income tax purposes.
Effective January 1, 1993, the retirement benefit plans for hourly and salaried employees were combined into one plan. Combining the two plans did not affect benefit levels.
Net pension benefit for 1994, 1993 and 1992 included the following components:
1994 1993 1992 (Thousands) Service cost: Benefits earned during the year $17,637 $17,688 $15,387 Interest cost on projected benefit obligation 43,328 40,710 35,253 Actual return on plan assets (17,409) (77,129) (60,020) Net amortization and deferral (48,824) 12,989 7,844 -------- -------- -------- Net pension (benefit) $(5,268) $(5,742) $(1,536) ======== ======== ========
The funded status of the plan at December 31, 1994 and 1993 was: 1994 1993 (Thousands) Actuarial present value of accumulated benefit obligation:
Vested $410,732 $390,716 Nonvested 38,176 55,476 -------- -------- Total 448,908 446,192 ======== ========
Fair value of plan assets $733,661 $753,292 Actuarial present value of projected benefit obligation (597,398) (608,216) -------- -------- Plan assets in excess of projected benefit obligation 136,263 145,076 Unrecognized net transition asset (66,374) (73,612) Unrecognized net gain (92,851) (83,709) Unrecognized prior service cost 9,066 4,182 --------- -------- Net pension (liability) $(13,896) $(8,063) ========= ========
Plan assets primarily consist of equity securities; U.S. agency, corporate and Treasury bonds; and cash equivalents.
The projected benefit obligation was measured using an assumed discount rate of 7.75% for 1994, 7% for 1993 and 7.75% for 1992, and a long-term rate of increase in future compensation levels of 5.5% for 1994, 5% for 1993 and 6% for 1992. The net pension benefit was measured using an expected long-term rate of return on plan assets of 8% in 1994 and 1993, and 7.5% in 1992.
Early retirement
As part of the corporate restructuring that was announced in the fourth quarter of 1993 (See Note 6), the company offered a voluntary early retirement program from December 1, 1993, through January 21, 1994, to employees who were 55 years and older and who had at least 10 years of service with the company. The program included two provisions: an unreduced pension benefit for those eligible employees who were under 60 years old, and a monthly supplemental payment to "bridge" employees to age 62 when they can begin collecting Social Security benefits. 384 employees accepted the early retirement opportunity. In 1993 the company recorded a $19.9 million expense for the early retirement program. This was included in the total $26 million restructuring charge.
Postretirement benefits other than pensions
The company has postretirement benefit plans, such as a comprehensive health insurance plan and a prescription drug plan, that provide certain benefits for retired employees and their dependents. Substantially all of the company's employees who retire under the company's pension plan may become eligible for those benefits at retirement. At December 31, 1994, 1993 and 1992, 2,331, 1,996 and 1,905 retirees and their dependents, respectively, were covered under these plans. The postretirement benefit plans are unfunded as of December 31, 1994.
In January 1993 the company adopted Statement of Financial Accounting Standards No. 106 (SFAS 106), Employers' Accounting for Postretirement Benefits Other Than Pensions, which requires the company to accrue a liability for estimated future postretirement benefits during an employee's working career rather than recognize an expense when benefits are paid. At the time of adoption, the actuarially determined accumulated postretirement benefit obligation (APBO) was $206.6 million. The company elected to recognize the APBO over 20 years.
In September 1993 the PSC issued a Statement of Policy concerning the accounting and ratemaking treatment for pensions and postretirement benefits other than pensions (PSC Policy). The PSC Policy was effective January 1993, adopted SFAS 106 for accounting and ratemaking purposes, and complies with generally accepted accounting principles.
The postretirement benefits cost other than pensions recognized on the income statement for the twelve months ended December 31, 1994, 1993 and 1992, was $14.5 million, $11.4 million and $5 million, respectively. The amounts for 1994 and 1993 represent the portion of SFAS 106 costs that the company has been allowed to collect from its customers. The amount for the twelve months ended December 31, 1992 represents the postretirement benefits cost as determined prior to the adoption of SFAS 106, when the cost was not recognized as an expense until the benefits were paid. The company has deferred $10.4 million and $10.1 million of SFAS 106 costs as of December 31, 1994 and 1993, respectively. The company expects to recover any deferred SFAS 106 amounts in accordance with the PSC Policy.
The PSC Policy allows various rate mechanisms, including the use of excess pension fund assets, such as Internal Revenue Service Code of 1986 Section 420 transfers, to temper the effect of SFAS 106 on rates. In 1994 and 1993 the company transferred $6.1 million and $5 million, respectively, of its excess pension plan assets to cover most of the cost of retirees' health care for those years. As a result of these transfers, the company recognized a decrease in its deferred SFAS 106 asset.
The estimated net postretirement benefits cost other than pensions for the 12 months ended December 31, 1994 and 1993, included the following components:
1994 1993 (Thousands) Service cost: Benefits accumulated during the year $7,050 $6,888 Interest cost on accumulated postretirement benefit obligation 15,903 16,304 Amortization of transition obligation over 20 years 10,330 10,330 Amortization of loss 2 - Deferral for future recovery (18,757) (22,095) ------- ------- Net periodic postretirement benefits cost $14,528 $11,427 ======= =======
The status of the plans for postretirement benefits other than pensions, as reflected in the company's consolidated balance sheets at December 31, 1994 and 1993, are as follows:
1994 1993 (Thousands) Accumulated postretirement benefit obligation (APBO): Retired employees $112,311 $69,947 Fully eligible active plan participants 7,774 36,454 Other active plan employees 92,464 107,708 -------- -------- Total APBO 212,549 214,109 Less unrecognized transition obligation 185,937 196,268 Less unrecognized net gain (28,382) (10,233) -------- -------- Accrued postretirement liability $54,994 $28,074 ======== ========
An 11% annual rate of increase in the per capita costs of covered health care benefits was assumed for 1995, gradually decreasing to 5% by the year 2003. Increasing the assumed health care cost trend rates by 1% in each year would increase the APBO as of January 1, 1995, by $44.4 million and increase the aggregate of the service cost and interest cost components of the net postretirement benefits cost for 1994 by $5.0 million. A discount rate of 7.75% was used to determine the APBO.
8 Jointly-Owned Generating Stations
Nine Mile Point Unit 2
The company has an undivided 18% interest in the output and costs of the Nine Mile Point nuclear generating unit No. 2 (NMP2) which is operated by Niagara Mohawk Power Corporation (Niagara Mohawk). Ownership of NMP2 is shared with Niagara Mohawk 41%, Long Island Lighting Company 18%, Rochester Gas and Electric Corporation 14%, and Central Hudson Gas & Electric Corporation 9%. The company's share of the rated capability is 189,000 kilowatts. The company's net utility plant investment, excluding nuclear fuel, was approximately $638 million and $652 million, at December 31, 1994 and 1993, respectively. The accumulated provision for depreciation was approximately $120 million and $103 million, at December 31, 1994 and 1993, respectively. The company's share of operating expenses is included in the consolidated statements of income.
A low level radioactive waste management and contingency plan for NMP2 provides assurance that NMP2 is properly prepared to handle interim storage of low level radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of Energy (DOE) for disposal of high level radioactive waste (spent fuel) from NMP2. The company is reimbursing Niagara Mohawk for its 18% share of the cost under the contract (currently approximately $1 per megawatt hour of net generation). The DOE's schedule for start of operations of their high level radioactive waste repository has slipped from 2003 to no sooner than 2010. The company has been advised by Niagara Mohawk that the NMP2 Spent Fuel Storage Pool has a capacity for spent fuel that is adequate until 2014. If further DOE schedule slippage should occur, construction of pre-licensed dry storage facilities would extend the on-site storage capability for spent fuel at NMP2 beyond 2014.
Nuclear insurance
Niagara Mohawk maintains public liability and property insurance for NMP2. The company reimburses Niagara Mohawk for its 18% share of those costs.
The public liability limit for a nuclear incident is approximately $8.3 billion. Should losses stemming from a nuclear incident exceed the commercially available public liability insurance, each licensee of a nuclear facility would be liable for up to a maximum of $75.5 million per incident, payable at a rate not to exceed $10 million per year. The company's maximum liability for its 18% interest in NMP2 would be approximately $13.6 million per incident. The $75.5 million
assessment is subject to periodic inflation indexing and a 5% surcharge should funds prove insufficient to pay claims associated with a nuclear incident. The Price-Anderson Act also requires indemnification for precautionary evacuations whether or not a nuclear incident actually occurs.
Niagara Mohawk maintains nuclear property insurance for NMP2 and is reimbursed by the company for its 18% interest. Niagara Mohawk has procured property insurance aggregating approximately $2.8 billion through the Nuclear Insurance Pools and the Nuclear Electric Insurance Limited (NEIL). In addition, the company has purchased NEIL insurance coverage for the extra expense incurred in purchasing replacement power during prolonged accidental outages. Under NEIL programs, should losses resulting from an incident at a member facility exceed the accumulated reserves of NEIL, each member, including the company, would be liable for its share of the deficiency. The company's maximum liability per incident under the property damage and replacement power coverages is approximately $2.5 million.
Nuclear plant decommissioning costs
In May 1993 the Nuclear Regulatory Commission (NRC) updated labor, energy and burial cost factors for determining the minimum funding requirement for nuclear decommissioning. As a result, the company's 18% share of the cost to decommission NMP2 is estimated to be $234 million in 2027, when decommissioning is expected to commence ($76 million in 1994 dollars). A preliminary estimate from Niagara Mohawk indicates that the cost to decommission NMP2 is greater than this amount. Niagara Mohawk has advised the company that in 1995 it expects to perform a detailed study to update the cost to decommission NMP2. The company plans to revise its estimate of the cost to decommission NMP2 after Niagara Mohawk completes its study.
The company's annual decommissioning allowance currently included in electric rates is approximately $1.6 million and is sufficient to recover the NRC's minimum funding requirement. These costs are charged to depreciation and amortization expense and are recovered over the expected life of the plant. The company believes that any increase in decommissioning costs will ultimately be recovered in rates.
The company has established a Qualified Fund under applicable provisions of the federal tax law. The fund also complies with the NRC regulations that require the use of an external trust fund to provide funds to decommission the contaminated portion of NMP2. The balance in this fund, including reinvested earnings, was approximately $7.4 million and $5.7 million at December 31, 1994 and 1993, respectively. These amounts are included on the consolidated balance sheets in other property and investments, net. The related liability for
decommissioning is included in deferred credits and other liabilities - other. At December 31, 1994, the external trust fund investments were primarily debt securities, classified as available-for-sale, and their carrying value approximated fair value.
The Financial Accounting Standards Board is currently reviewing the accounting for obligations for decommissioning of nuclear power plants, including the balance sheet presentation of estimated decommissioning costs.
Homer City
The company has an undivided 50% interest in the output and costs of the Homer City Generating Station, which is comprised of three generating units. The station is owned with Pennsylvania Electric Company, which operates the facility. The company's share of the rated capability is 950,000 kilowatts and its net utility plant investment was approximately $265 million and $258 million at December 31, 1994 and 1993, respectively. The accumulated provision for depreciation was approximately $153 million and $159 million, at December 31, 1994 and 1993, respectively. The company's share of operating expenses is included in the consolidated statements of income.
9 Commitments and Contingencies
Capital expenditures
The company has substantial commitments in connection with its capital expenditure program and estimates that expenditures for 1995, 1996 and 1997 will approximate $188 million, $264 million and $184 million, respectively. The program is subject to periodic review and revision. Actual capital expenditures may change to reflect the imposition of additional regulatory requirements and the company's continued focus on optimizing capital expenditures. Capital expenditures will be primarily for extension of service, necessary improvements at existing facilities, the natural gas storage project, compliance with the Clean Air Act Amendments of 1990 (1990 Amendments) and other environmental requirements.
The 1990 Amendments will result in expenditures of approximately $174 million, on a present value basis, over a 25- year period, for all capital and operating and maintenance expenses related to the reduction of sulfur dioxide and nitrogen oxides at several of the company's coal-fired generating stations, of which $106.5 million had been incurred as of December 31, 1994. The cost to comply with the sulfur dioxide and nitrogen oxide limitations includes the construction of an innovative flue gas desulfurization (FGD) system and a nitrogen oxide reduction system that was recently completed at the
company's Milliken Generating Station. The company estimates that approximately a 1% electric rate increase will be required for the cost of reducing sulfur dioxide and nitrogen oxide emissions in both Phase I (which began on January 1, 1995) and Phase II (begins January 1, 2000), as discussed below. In addition, the company anticipates that it will have to significantly reduce its nitrogen oxide emissions even further by the year 2003, which includes an interim reduction in the year 1999, as a result of proposed U.S. Environmental Protection Agency (EPA) regulations. The cost to comply with these proposed regulations cannot be estimated at this time, since the reduction will be based on additional research scheduled to be completed later in the decade. As a result of the 1990 Amendments, the company plans to reduce its annual sulfur dioxide emissions by an amount that will allow the company to meet the sulfur dioxide levels established for the company, which are approximately a 49% reduction from approximately 138,000 tons in 1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990 Amendments, if required, cannot be estimated at this time, since the type and level of reductions that may be required is dependent on a study currently being performed by the EPA, which is scheduled to be completed by the end of 1995. Regulations may be adopted at the state level that would limit toxic emissions even further, at an additional cost to the company. The company anticipates that the costs incurred to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual emissions allowances to each of the company's coal-fired generating stations based on statutory emissions limits. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, the company estimates that it will have allowances in excess of the affected coal-fired generating stations' actual emissions. The company's present strategy is to bank these allowances for use in later years. By using a banking strategy, it is estimated that Phase II allowance requirements will be met through the year 2005 by utilizing the allowances banked during Phase I, which includes the extension reserve allowances discussed below, together with the company's Phase II annual emissions allowances. This strategy could be modified should market or business conditions change. In addition to the annual emissions allowances allocated to the company by the EPA, the company has received a portion of the extension reserve allowances issued by the EPA to utilities electing to build scrubbers in Phase I, as a result of a pooling agreement that it entered into with other utilities who were also eligible to receive some of these extension reserve allowances.
As a result of existing and new solid waste disposal legislation and regulations in Pennsylvania, the company will incur approximately $28 million, on a present value basis, of additional costs over the next 30 years at the Homer City Generating Station. The majority of these costs will be incurred over the next 10 years to install new equipment, modify or replace existing equipment, and improve the design of a proposed expansion of disposal facilities. The company expects to recover these expenditures in rates, since the company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements.
Long-term power purchase contracts
The company is currently required to purchase 594 megawatts (mw) of NUG power. The company is required to make payments under these contracts only for the power it receives or when the company directs the NUG to reduce its output under the terms of the contract. Two contracts the company has with NUGs each provide more than 5% of current system capability. One contract provides for 177 mw or 5.4%, and the other provides for 240 mw or 7.3%. During 1994, 1993 and 1992 the company purchased approximately $214 million, $138 million and $71 million, respectively, of NUG power, including termination costs. The company estimates that NUG power purchases, excluding termination costs, over the next five years will be as follows:
1995 1996 1997 1998 1999 (Millions) $274 $312 $322 $333 $344
Increases in the cost of NUG power purchases will contribute significantly to expected electric price increases in August 1995.
Coal purchasing contracts
The company has long-term contracts with nonaffiliated mining companies for the purchase of coal for the jointly-owned Homer City Generating Station. The contracts, which expire between 1995 and the end of the expected service life of the generating station, require the purchase of either fixed or minimum amounts of the station's coal requirements. The contracts are based on fixed price plus escalation provisions. The company's share of the cost of coal purchased under these agreements is expected to aggregate $52 million, $53 million and $55 million for the years 1995, 1996 and 1997, respectively.
In addition, the company has a long-term contract for the purchase of coal for the Kintigh and Milliken Generating Stations. The contract, which expires in 2003, supplies the
annual coal requirements of the Kintigh station. One-third of the tonnage price is renegotiated annually to reflect market conditions. The contract also supplies the requirements of the Milliken station for the years 1995-1997. The delivered cost of coal purchased under this agreement is expected to be $76 million, $78 million, and $81 million for the years 1995, 1996 and 1997, respectively.
10 Environmental Liability
The company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Any additional compliance programs will increase the cost of electric and natural gas service by requiring changes in the company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred to comply with environmental laws and regulations.
Due to existing and proposed legislation and regulations, and legal proceedings commenced by governmental bodies and others, the company may also incur costs from the past disposal of hazardous substances produced during the company's operations or those of its predecessors. The company has been notified by the EPA and the New York State Department of Environmental Conservation (NYSDEC), as appropriate, that it is among the potentially responsible parties (PRPs) who may be liable to pay for costs incurred to remediate certain hazardous substances at eight waste sites, not including the company's inactive gas manufacturing sites, which are discussed below. With respect to the eight sites, six sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry) and two of those sites are also included on the National Priorities list.
Any liability may be joint and several for certain of these sites. The company has recorded a liability related to four of these eight sites, which is reflected in the company's consolidated balance sheets at December 31, 1994, in the amount of $1.1 million. The ultimate cost to remediate these sites may be significantly more than this amount and will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed to the company. The company has notified the EPA and the NYSDEC, as appropriate, that it believes it has no responsibility at three sites and has already incurred expenditures related to the remediation at the remaining site. A deferred asset has also been recorded in the amount of $2.1 million, of which $1.0 million relates to costs that have already been incurred. The company believes it will recover these costs, since the PSC has allowed other utilities to recover these types of remediation costs and has allowed the company to recover similar costs in rates, such as investigation and cleanup costs relating to inactive gas manufacturing sites.
The estimated liability of $1.1 million was derived by multiplying the total estimated cost to clean up a particular site by the related company contribution factor. Estimates of the total cleanup costs were determined by using information related to a particular site, such as investigations performed to date at a site or from the data released by a regulatory agency. In addition, this estimate was based upon currently available facts, existing technology, and presently enacted laws and regulations. The contribution factor is calculated using either the company's percentage share of the total PRPs named, which assumes all PRPs will contribute equally, or the company's estimated percentage share of the total hazardous wastes disposed of at a particular site, or by using a 1% contribution factor for those sites at which it believes that it has contributed a minimal amount of hazardous wastes. The company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A number of the company's inactive gas manufacturing sites have been listed in the New York State Registry. In late March 1994 the company entered into an Order on Consent with the NYSDEC requiring the company to investigate and, where necessary, remediate 33 of the company's 38 known inactive gas manufacturing sites. The schedule for investigating and remediating these 33 sites will be determined through further negotiations with the NYSDEC. The company has a program to investigate and initiate necessary remediation at its 38 known inactive gas manufacturing sites. Expenditures through the year 2009 are estimated at $32.5 million, including the impact of the Order on Consent. This estimate was determined by using the company's experience and knowledge related to these sites as a result of the investigation and remediation that the company has performed to date. It is based upon currently available facts, existing technology, and presently enacted laws and regulations. This liability to investigate and initiate remediation, as necessary, at the known inactive gas manufacturing sites, is reflected in the company's consolidated balance sheets at December 31, 1994 and 1993 in the amount of $32.5 million and $25 million, respectively. The company also has recorded a corresponding deferred asset, since it expects to recover such expenditures in rates, as the company has previously been allowed by the PSC to recover such costs in rates. The PSC has asked its staff to prepare a recommendation on a generic policy for these types of expenditures by the spring of 1995. The company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
11 Federal Energy Regulatory Commission (FERC) Order 636
FERC Order 636 became effective in November 1993 and requires interstate natural gas pipeline companies to offer customers unbundled, or separate, services equivalent to their former sales service. With the unbundling of services, primary responsibility for reliable natural gas supply has shifted from interstate pipeline companies to local distribution companies, such as the company. FERC Order 636 has substantially restructured the interstate natural gas market.
As a result of the restructuring of services required by FERC Order 636, pipelines have incurred and will continue to incur transition costs. These include the costs of restructuring existing natural gas supply contracts, unrecovered costs that would otherwise have been billable to pipeline customers under previously existing rules and costs of assets needed to implement the order. FERC Order 636 allows pipelines to recover all prudently incurred costs from their customers.
The company's liability for transition costs is based on the pipelines' filings with the FERC to recover such costs. The company has reached a final resolution with one of its pipeline suppliers regarding transition costs and is currently negotiating with its other pipeline suppliers. Final resolution of the issue may not occur for several years. The company's estimated liability for transition costs was $21 million and $29 million at December 31, 1994 and 1993, respectively. The company has recorded a corresponding deferred asset, since it has been recovering transition costs from its customers through its gas adjustment clause and believes that such costs will continue to be recoverable from its customers.
12 Diversified Operations
In April 1992 the PSC issued an order allowing the company to invest up to 5% of its consolidated capitalization (approximately $180 million at December 31, 1994) in one or more subsidiaries that may engage or invest in energy-related or environmental-services businesses and provide related services.
The company has been making investments in unregulated companies through its wholly owned subsidiary, NGE Enterprises, Inc. (NGE). NGE owns two unregulated businesses - EnerSoft Corporation (EnerSoft) and XENERGY, Inc. (XENERGY).
EnerSoft, a computer software company, was formed in May 1993 to produce and market software for natural gas utilities, marketers and pipeline operators. Through an alliance with the New York Mercantile Exchange, EnerSoft is developing Channel 4, a natural gas and pipeline capacity trading and information system for the North American market. While development of the system
has taken longer than anticipated, Channel 4 is expected to be commercially available in the spring of 1995. Like most other start-up companies, EnerSoft has been incurring operating losses. The company expects that EnerSoft will continue to incur operating losses in the near term.
In June 1994 NGE acquired all of the outstanding stock of XENERGY, an energy services, information systems and energy- consulting company that specializes in energy management, conservation engineering and demand-side management. XENERGY currently provides a broad range of services to utilities throughout the United States, Canada, Spain and France. It also provides energy services, conservation engineering and DSM services to governmental agencies at both the state and federal levels, and to a large number of end users.
As of December 31, 1994 and 1993, the company had invested approximately $47 million and $3 million, respectively, in NGE to finance its diversified investments. The majority of this investment is included in other property and investments, net on the consolidated balance sheets. NGE's total liabilities and capitalization at December 31, 1994 and 1993 was approximately $52 million and $7 million, respectively. For the years ended December 31, 1994 and 1993, NGE incurred net losses of $6.0 million and $1.4 million, respectively, which are included in other income and deductions on the consolidated statements of income.
13 Fair Value of Financial Instruments
The estimated fair values of the company's financial instruments at December 31, 1994 and 1993, were as follows:
Carrying Amount Fair Value 1994 1993 1994 1993 (Thousands) First mortgage bonds $1,044,083 $1,166,779 $1,010,239 $1,274,883 Pollution control notes $576,000 $575,695 $484,005 $581,928 Preferred stock subject to mandatory redemption requirements $125,000 $125,000 $127,875 $134,000
The fair value of the company's first mortgage bonds, pollution control notes and preferred stock is estimated based on the quoted market prices for the same or similar issues of the same remaining maturities.
The carrying amount for the following items approximates estimated fair value because of the short maturity (within one year) of those instruments: cash and cash equivalents, notes payable, and interest accrued.
Special deposits include restricted funds that are set aside for preferred stock and long-term debt redemptions. Special deposits also include restricted funds that are used to finance a portion of the costs incurred in the construction of certain solid waste disposal and other related facilities. The carrying amount approximates fair value because the special deposits have been invested in securities with a short-term maturity (within one year).
The carrying amount of the revolving credit agreement note outstanding at December 31, 1993 approximated fair value because its pricing was based on short-term interest rates.
14 Industry Segment Information
Certain information pertaining to the electric and natural gas operations of the company follows:
1994 1993 1992 Natural Natural Natural Electric Gas Electric Gas Electric Gas (Thousands) Operating Revenues $1,600,075 $298,780 $1,527,362 $272,787 $1,451,525 $240,164 Expenses $1,306,871 $269,300 $1,250,000 $249,493 $1,146,619 $221,307 Income $293,204 $29,480 $277,362 $23,294 $304,906 $18,857 Depreciation and amortization* $167,484 $10,842 $155,231 $9,337 $150,549 $8,428 Capital expenditures $183,910 $40,396 $208,576 $36,453 $210,185 $35,433 Identifiable assets** $4,623,731 $486,075 $4,627,905 $458,596 $4,540,724 $377,424
* Included in operating expenses. ** Assets used in both electric and natural gas operations not included above were $113,099, $201,457 and $159,768 at December 31, 1994, 1993 and 1992, respectively. They consist primarily of cash and cash equivalents, special deposits and prepayments.
15 Quarterly Financial Information (Unaudited)
Quarter ended March 31 June 30 Sept. 30 Dec. 31 (Thousands, except per share amounts) Operating revenues $565,167 $388,639(1) $432,451 $512,598 Operating income $119,990 $47,784 $63,351 $91,559 Net income $84,693 $12,395(1) $30,953 $59,604 Earnings available for common stock $79,834 $7,745 $26,251 $54,868 Earnings per share $1.13 $.11(1) $.37 $.77 Dividends per share $.55 $.55 $.55 $.35 Average shares outstanding 70,801 71,214 71,490 71,503 Common stock price* High $30.50 $27.88 $25.88 $19.75 Low $26.50 $23.25 $18.38 $17.75
Operating revenues $522,383 $388,601 $396,410 $492,755 Operating income $109,893 $56,649 $66,108 $68,006 Net income $74,039 $21,500 $32,541 $37,948(2) Earnings available for common stock $68,838 $16,299 $27,340 $32,913 Earnings per share $.99 $.23 $.39 $.47(2) Dividends per share $.54 $.54 $.55 $.55 Average shares outstanding 69,561 69,836 70,119 70,431 Common stock price* High $35.13 $36.50 $36.25 $35.50 Low $31.63 $32.13 $34.63 $28.75
(1) Second quarter 1994 results include the company's change in estimate for the 1993 production cost penalty of $13 million or 12 cents per share.
(2) Fourth quarter 1993 results reflect the effects of restructuring expenses, which decreased net income and earnings for common stock by $17.2 million and decreased earnings per share by 24 cents.
* The company's common stock is listed on the New York Stock Exchange. The number of shareholders of record at December 31, 1994, was 56,279.
Dividend Limitations: After dividends on all outstanding preferred stock have been paid, or declared, and funds set apart for their payment, the common stock is entitled to cash dividends as may be declared by the board of directors out of retained earnings accumulated since December 31, 1946. Common Stock dividends are limited if common stock equity (46% at December 31, 1994) falls below 25% of total capitalization, as defined in the company's Certificate of Incorporation. Dividends on common stock cannot be paid unless sinking fund requirements of the preferred stock are met. The company has not been restricted in the payment of dividends on common stock by these provisions. Retained earnings accumulated since December 31, 1946, were approximately $347 million and $320 million as of December 31, 1994 and 1993, respectively.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors New York State Electric & Gas Corporation and Subsidiaries Ithaca, New York
We have audited the consolidated financial statements and the financial statement schedule of New York State Electric & Gas Corporation and Subsidiaries listed in Item 14(a) of this Form 10-K. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule 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 consolidated financial position of New York State Electric & Gas Corporation and Subsidiaries as of December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
As discussed in Note 7 to the consolidated financial statements, the Company and Subsidiaries changed its method of accounting for postretirement benefits other than pensions in 1993.
COOPERS & LYBRAND L.L.P.
New York, New York January 27, 1995
Item 9. Changes in and disagreements with accountants on accounting and financial disclosure - None
PART III
Item 10. Directors and executive officers of the Registrant
Incorporated herein by reference to the information under the caption "Election of Directors" and "Secton 16 Compliance" in the Company's Proxy Statement dated March 31, 1995. The information regarding executive officers is on pages 26-27 of this report.
Item 11. Executive compensation
Incorporated herein by reference to the information under the captions "Executive Compensation," "Employment and Change in Control Arrangements," "Directors' Compensation," "Report of Executive Compensation and Succession Committee on Executive Compensation" and "Stock Performance Graph" in the Company's Proxy Statement dated March 31, 1995.
Item 12. Security ownership of certain beneficial owners and management
Incorporated herein by reference to the information under the caption "Security Ownership of Certain Beneficial Owners and Management" in the Company's Proxy Statement dated March 31, 1995.
Item 13. Certain relationships and related transactions
Incorporated herein by reference to the information under the caption "Election of Directors" in the Company's Proxy Statement dated March 31, 1995.
PART IV
Item 14. Exhibits, financial statement schedules, and reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial statements Included in Part II of this report: a) Consolidated Balance Sheets as of December 31, 1994 and 1993 b) For the three years ended December 31, 1994: Consolidated Statements of Income Consolidated Statements of Cash Flows Consolidated Statements of Changes in Common Stock Equity c) Notes to Consolidated Financial Statements d) Report of Independent Accountants 2. Financial statement schedules Included in Part II of this report: For the three years ended December 31, 1994: II. Allowance for Doubtful Accounts - Accounts Receivable
Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the Consolidated Financial Statements or notes thereto.
3. Exhibits (a)(1) The following exhibits are delivered with this report:
Exhibit No. (A) 10-18 - Supplemental Executive Retirement Plan Amendment No. 1. (A) 10-31 - Annual Executive Incentive Compensation Plan Amendment No. 3. (A) 10-32 - Annual Executive Incentive Compensation Plan Amendment No. 4. (A) 10-41 - Agreement with M. I. German. 12 - Computation of Ratio of Earnings to Fixed Charges. 21 - Subsidiaries. 23 - Consent of Coopers & Lybrand to incorporation by reference into certain registration statements. 27 - Financial Data Schedule. 99-1 - Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Salaried Employees. 99-2 - Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Hourly Paid Employees.
(a)(2) The following exhibits are incorporated herein by reference: Exhibit No. Filed in As Exhibit No. 3-1 - Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988 - Registration No. 33-50719 . . . 4-11 3-2 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989 - Registration No. 33-50719 . . 4-12 3-3 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990 - Registration No. 33-50719 . . . . . . . . . . . . . 4-13 3-4 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990 - Registration No. 33-50719 . . 4-14 3-5 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991 - Registration No. 33-50719 . . 4-15 3-6 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991 - Registration No. 33-50719 . . 4-16 3-7 - Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991 - Registration No. 33-50719 . . . . . . . . . . . . . . . . . . . 4-20 3-8 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992 - Registration No. 33-50719 . . . . 4-17 ______________________________ (A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
3-9 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992 - Registration No. 33-50719 . . . 4-18 3-10 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993 Registration No. 33-50719 . . . . . . . . . . . . . . 4-19 3-11 - Certificate of Amendment of the Certificate of Incor- poration filed in the Office of the Secretary of State of the State of New York on December 10, 1993 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-11 3-12 - Certificate of Amendment of the Certificate of Incor- poration filed in the Office of the Secretary of State of the State of New York on December 20, 1993 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-12 3-13 - Certificate of Amendment of the Certificate of Incor- poration filed in the Office of the Secretary of State of the State of New York on December 20, 1993 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-13 3-14 - Certificates of the Secretary of the Company concern- ing consents dated March 20, 1957 and May 9, 1975 of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness - Registration No. 2-69988. . . . . . . . . . . . . . 4-7 3-15 - By-Laws of the Company as amended February 25, 1994 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-15 4-1 - First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (Chemical Bank is Successor Trustee) - Registration No. 33-4186 . . . 4-1
Supplemental Indentures to First Mortgage dated as of July 1, 1921: 4-2 - No. 37 - Registration No. 33-31297. . . . . . . . . 4-2 4-3 - No. 39 - Registration No. 33-31297. . . . . . . . . 4-3 4-4 - No. 43 - Registration No. 33-31297. . . . . . . . . 4-4 4-5 - No. 51 - Registration No. 2-59840 . . . . . . . . . 2-B(46) 4-6 - No. 68 - Registration No. 2-59840 . . . . . . . . . 2-B(63) 4-7 - No. 69 - Registration No. 2-59840 . . . . . . . . . 2-B(64) 4-8 - No. 71 - Registration No. 2-59840 . . . . . . . . . 2-B(66) 4-9 - No. 74 - Registration No. 2-59840 . . . . . . . . . 2-B(69) 4-10 - No. 75 - Registration No. 2-59840 . . . . . . . . . 2-B(70) 4-11 - No. 80 - Registration No. 2-59840 . . . . . . . . . 2-B(75) 4-12 - No. 81 - Registration No. 2-59840 . . . . . . . . . 2-B(76) 4-13 - No. 83 - Registration No. 2-65948 . . . . . . . . . 2-B(78) 4-14 - No. 102- Registration No. 33-33838. . . . . . . . . 4-8 4-15 - No. 103- Registration No. 33-43458. . . . . . . . . 4-8 4-16 - No. 104- Registration No. 33-43458. . . . . . . . . 4-9
4-17 - No. 105- Registration No. 33-52040. . . . . . . . . 4-8 4-18 - No. 106- Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . 4-23 4-19 - No. 107- Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . 4-24 4-20 - No. 108- Registration No. 33-50719. . . . . . . . . 4-8 4-21 - No. 109- Registration No. 33-50719. . . . . . . . . 4-9
Agreements and amendments with the Power Authority of the State of New York:
Exhibit No. Filed in As Exhibit No.
10-1 - Letter Agreement dated February 3, 1982 relating to transmission services - Registration No. 2-82192. . 10-1 10-2 - Amendment dated December 21, 1989 to the Letter Agreement dated February 3, 1982 relating to trans- mission services - Company's 10-K for year ended December 31, 1989 - File No. 1-3103-2 . . . . . . 10-4 10-3 - Transmission Agreement dated December 12, 1983, with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2 . . . . 10-6 10-4 - Amendment dated December 21, 1989 to the Transmission Agreement dated December 12, 1983 with respect to connection of the Company's Kintigh (Somerset) Gener- ating Station to the Niagara-Edic 345 kv transmission system - Company's 10-K for the year ended December 31, 1989 File No. 1-3103-2. . . . . . . . . . . . . 10-7
* * * * * * * * * *
10-5 - New York Power Pool Agreement dated July 11, 1985 - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-7 10-6 - Transmission Agreement dated January 10, 1990 between New York State Electric & Gas Corporation and Niagara Mohawk Power Corporation, with respect to remote load and generation wheeling service for the Company - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-17 10-7 - Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-14
Exhibit No. Filed in As Exhibit No.
10-8 - Amendment No. 1 dated as of October 1, 1985 to the Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1986 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-11 10-9 - Amendment No. 2 dated as of August 28, 1986 to the Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1986 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-12 10-10 - Basic Agreement dated as of September 22, 1975 between New York State Electric & Gas Corporation and others concerning Nine Mile Point Nuclear Station, Unit No. 2 - Registration No. 2-54903. . . 5-0 10-11 - Nine Mile Point Nuclear Station Unit 2 Operating Agreement effective as of January 1, 1993 among New York State Electric & Gas Corporation and others - Company's 10-K for the year ended December 31, 1992 - File No. 1-3103-2 . . . . . . . 10-18 10-12 - Coal Hauling Agreement dated as of March 9, 1983 between Somerset Railroad Corporation and New York State Electric & Gas Corporation - Registration No. 2-82352. . . . . . . . . . . . . . 10 (A)10-13 - Retirement Plan for Directors - Company's 10-K for the year ended December 31, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-26 (A)10-14 - Retirement Plan for Directors Amendment No. 1 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-21 (A)10-15 - Form of Deferred Compensation Plan for Directors - Company's 10-K for year ended December 31, 1989 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-22 (A)10-16 - Deferred Compensation Plan for Directors Amendment No. 1 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . 10-23 (A)10-17 - Supplemental Executive Retirement Plan - Company's 10-Q for quarter ended March 31, 1994 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-49
______________________________ (A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
(A)10-19 - Supplemental Executive Retirement Plan Amendment No. 2 - Company's 10-K for year ended December 31, 1987 - File No. 1-3103-2. . . . . . . . . . . . 10-19 (A)10-20 - Supplemental Executive Retirement Plan Amendment No. 3 - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . 10-24 (A)10-21 - Supplemental Executive Retirement Plan Amendment No. 4 - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-30 (A)10-22 - Supplemental Executive Retirement Plan Amendment No. 5 - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-31 (A)10-23 - Supplemental Executive Retirement Plan Amendment No. 6 - Company's 10-Q for quarter ended March 31, 1991 - File No. 1-3103-2. . . . . . . . . . . . . . 10-37 (A)10-24 - Supplemental Executive Retirement Plan Amendment No. 7 - Company's 10-Q for quarter ended June 30, 1992 - File No. 1-3103-2. . . . . . . . . . . . . . 10-44 (A)10-25 - Supplemental Executive Retirement Plan Amendment No. 8 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-32 (A)10-26 - Supplemental Executive Retirement Plan Amendment No. 9 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-33 (A)10-27 - Supplemental Executive Retirement Plan Amendment No. 10 - Company's 10-Q for quarter ended June 30, 1994 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-50 (A)10-28 - Annual Executive Incentive Compensation Plan. Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-30 (A)10-29 - Annual Executive Incentive Compensation Plan Amendment No. 1 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . 10-35 (A)10-30 - Annual Executive Incentive Compensation Plan Amendment No. 2 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . 10-36 (A)10-33 - Performance Share Plan - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . 10-36 (A)10-34 - Performance Share Plan Amendment No. 1 - Company's 10-Q for quarter ended March 31, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-38 (A)10-35 - Performance Share Plan Amendment No. 2 - Company's 10-Q for quarter ended June 30, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-39 (A)10-36 - Performance Share Plan Amendment No. 3 - Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-34 (A)10-37 - Performance Share Plan Amendment No. 4 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-41 (A)10-38 - Performance Share Deferred Compensation Plan - Company's 10-K for year ended December 31, 1991 File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-40 ______________________________ (A) Management contract or compensatory plan or arrangement.
(A)10-39 - Performance Share Deferred Compensation Plan - Amendment No. 1 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . 10-43 (A)10-40 - Employment Contract for A. E. Kintigh - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . 10-26 (A)10-42 - Employment Agreement for J. A. Carrigg - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . . 10-46 (A)10-43 - Form of Severance Agreement for Senior Vice Presidents - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . 10-47 (A)10-44 - Form of Severance Agreement for Vice Presidents - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-48
The Company agrees to furnish to the Commission, upon request, a copy of the Revolving Credit Agreement dated as of July 31, 1992, between the Company, Chemical Bank, as Agent, and certain banks; a copy of the Participation Agreements dated as of June 1, 1987 and December 1, 1988 between the Company and New York State Energy Research and Development Authority (NYSERDA) relating to Adjustable Rate Pollution Control Revenue Bonds (1987 Series A), and (1988 Series A), respectively; a copy of the Participation Agreements dated as of March 1, 1985, October 15, 1985, and December 1, 1985 between the Company and NYSERDA relating to Annual Tender Pollution Control Revenue Bonds (1985 Series A), (1985 Series B), and (1985 Series D), respectively; a copy of the Participation Agreements dated as of February 1, 1993, February 1, 1994, June 1, 1994, October 1, 1994 and December 1, 1994 between the Company and NYSERDA relating to Pollution Control Refunding Revenue Bonds (1994 Series A), (1994 Series B), (1994 Series C), (1994 Series D), and (1994 Series E), respectively; a copy of the Participation Agreement dated as of December 1, 1993 between the Company and NYSERDA relating to Solid Waste Disposal Revenue Bonds (1993 Series A); a copy of the participation agreement dated as of December 1, 1994 between the company and the Indiana County Industrial Development Authority relating to Pollution Control Refunding Revenue Bonds (1994 Series A); a copy of the Credit Agreement dated as of March 9, 1983, as amended, between Somerset Railroad Corporation and Chemical Bank, and a copy of the Revolving Credit Agreement dated as of June 30, 1994, as amended, between Xenergy Inc. and The First National Bank of Boston. The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
(b) Reports on Form 8-K
A report on Form 8-K, dated October 11, 1994, was filed during the fourth quarter of 1994 to report certain information under Item 5, "Other Events."
______________________________ (A) Management contract or compensatory plan or arrangement.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Date: March 10, 1995 By Gary J. Turton Gary J. Turton Controller (Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
PRINCIPAL EXECUTIVE OFFICER
Date: March 10, 1995 By James A. Carrigg James A. Carrigg Chairman, President, Chief Executive Officer and Director
PRINCIPAL FINANCIAL OFFICER
Date: March 10, 1995 By Sherwood J. Rafferty Sherwood J. Rafferty Vice President and Treasurer
PRINCIPAL ACCOUNTING OFFICER
Date: March 10, 1995 By Gary J. Turton Gary J. Turton Controller
Signatures (Cont'd)
Date: March 10, 1995 By Alison P. Casarett Alison P. Casarett Director
Date: March 10, 1995 By Everett A. Gilmour Everett A. Gilmour Director
Date: March 10, 1995 By Paul L. Gioia Paul L. Gioia Director
Date: March 10, 1995 By John M. Keeler John M. Keeler Director
Date: March 10, 1995 By Allen E. Kintigh Allen E. Kintigh Director
Date: March 10, 1995 By Ben E. Lynch Ben E. Lynch Director
Date: March 10, 1995 By Alton G. Marshall Alton G. Marshall Director
Date: March 10, 1995 By David R. Newcomb David R. Newcomb Director
Date: March 10, 1995 By Robert A. Plane Robert A. Plane Director
Date: March 10, 1995 By Charles W. Stuart Charles W. Stuart Director
EXHIBIT INDEX
* 3-1 -- Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988. * 3-2 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989. * 3-3 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990. * 3-4 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990. * 3-5 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991. * 3-6 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991. * 3-7 -- Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991. * 3-8 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992. * 3-9 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992. * 3-10 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993. * 3-11 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 10, 1993. * 3-12 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. ___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 3-13 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. * 3-14 -- Certificates of the Secretary of the Company concerning consents dated March 20, 1957 and May 9, 1975 of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness. * 3-15 -- By-Laws of the Company as amended February 25, 1994. * 4-1 -- First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (Chemical Bank is Successor Trustee).
Supplemental Indentures to First Mortgage dated as of July 1, 1921:
* 4-2 -- No. 37 * 4-9 -- No. 74 * 4-15 -- No. 103 * 4-3 -- No. 39 * 4-10 -- No. 75 * 4-16 -- No. 104 * 4-4 -- No. 43 * 4-11 -- No. 80 * 4-17 -- No. 105 * 4-5 -- No. 51 * 4-12 -- No. 81 * 4-18 -- No. 106 * 4-6 -- No. 68 * 4-13 -- No. 83 * 4-19 -- No. 107 * 4-7 -- No. 69 * 4-14 -- No. 102 * 4-20 -- No. 108 * 4-8 -- No. 71 * 4-21 -- No. 109
Agreements and Amendments with the Power Authority of the State of New York:
* 10-1 -- Letter Agreement dated February 3, 1982 relating to transmission services. * 10-2 -- Amendment dated December 21, 1989 to the Letter Agreement dated February 3, 1982 relating to transmission services. * 10-3 -- Transmission Agreement dated December 12, 1983, with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system.
___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-4 -- Amendment dated December 21, 1989 to the Transmission Agreement dated December 12, 1983 with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system.
* * * * * * * * * *
* 10-5 -- New York Power Pool Agreement dated July 11, 1985. * 10-6 -- Transmission Agreement dated January 10, 1990 between New York State Electric & Gas Corporation and Niagara Mohawk Power Corporation, with respect to remote load and generation wheeling service for the Company.
* * * * * * * * * *
Coal Sales Agreement and Amendments between New York State Electric & Gas Corporation and Consolidation Coal Company:
* 10-7 -- Agreement dated December 21, 1983. * 10-8 -- Amendment No. 1 dated as of October 1, 1985. * 10-9 -- Amendment No. 2 dated as of August 28, 1986.
* * * * * * * * * *
* 10-10 -- Basic Agreement dated as of September 22, 1975 between New York State Electric & Gas Corporation and others concerning Nine Mile Point Nuclear Station, Unit No. 2. * 10-11 -- Nine Mile Point Nuclear Station Unit 2 Operating Agreement effective as of January 1, 1993 among New York State Electric & Gas Corporation and others. ___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-12 -- Coal Hauling Agreement dated as of March 9, 1983 between Somerset Railroad Corporation and New York State Electric & Gas Corporation. (A)* 10-13 -- Retirement Plan for Directors. (A)* 10-14 -- Retirement Plan for Directors Amendment No. 1 (A)* 10-15 -- Form of Deferred Compensation Plan for Directors. (A)* 10-16 -- Deferred Compensation Plan for Directors Amendment No. 1. (A)* 10-17 -- Supplemental Executive Retirement Plan (A) 10-18 -- Supplemental Executive Retirement Plan Amendment No. 1. (A)* 10-19 -- Supplemental Executive Retirement Plan Amendment No. 2. (A)* 10-20 -- Supplemental Executive Retirement Plan Amendment No. 3. (A)* 10-21 -- Supplemental Executive Retirement Plan Amendment No. 4. (A)* 10-22 -- Supplemental Executive Retirement Plan Amendment No. 5. (A)* 10-23 -- Supplemental Executive Retirement Plan Amendment No. 6. (A)* 10-24 -- Supplemental Executive Retirement Plan Amendment No. 7. (A)* 10-25 -- Supplemental Executive Retirement Plan Amendment No. 8. (A)* 10-26 -- Supplemental Executive Retirement Plan Amendment No. 9. (A)* 10-27 -- Supplemental Executive Retirement Plan Amendment No. 10. (A)* 10-28 -- Annual Executive Incentive Compensation Plan. (A)* 10-29 -- Annual Executive Incentive Compensation Plan Amendment No. 1. (A)* 10-30 -- Annual Executive Incentive Compensation Plan Amendment No. 2. (A) 10-31 -- Annual Executive Incentive Compensation Plan Amendment No. 3. (A) 10-32 -- Annual Executive Incentive Compensation Plan Amendment No. 4. (A)* 10-33 -- Performance Share Plan. (A)* 10-34 -- Performance Share Plan Amendment No. 1. (A)* 10-35 -- Performance Share Plan Amendment No. 2. (A)* 10-36 -- Performance Share Plan Amendment No. 3. (A)* 10-37 -- Performance Share Plan Amendment No. 4. (A)* 10-38 -- Performance Share Deferred Compensation Plan. (A)* 10-39 -- Performance Share Deferred Compensation Plan Amendment No. 1. (A)* 10-40 -- Employment Contract for A. E. Kintigh. (A) 10-41 -- Agreement with M. I. German. (A)* 10-42 -- Employment Agreement for J. A. Carrigg. (A)* 10-43 -- Form of Severance Agreement for Senior Vice Presidents. (A)* 10-44 -- Form of Severance Agreement for Vice Presidents.
___________________________________ (A) Management contract or compenstory plan or arrangement. * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
12 -- Computation of Ratio of Earnings to Fixed Charges. 21 -- Subsidiaries. 23 -- Consent of Coopers & Lybrand to incorporation by reference into certain registration statements. 27 -- Financial Data Schedule. 99-1 -- Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Salaried Employees. 99-2 -- Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Hourly Paid Employees.
Item 7. Management's discussion and analysis of financial condition and results of operations
Liquidity and Capital Resources
Competitive Conditions
Competition and deregulation are the foremost challenges currently facing the electric and natural gas industries and will increasingly present both opportunities and risks. There is the potential to gain new customers as well as the risk of losing existing customers. While the transition to a competitive marketplace in the electric industry is just beginning, the transition in the natural gas industry is further along: the production sector is now fully deregulated, and the interstate transmission and distribution sectors are in various stages of increasing competition.
In the electric industry, proceedings studying the possibility of introducing more competition and restructuring in some states, such as New York and California, may be paving the way for industry change nationwide. However, a number of complex issues (including transition costs and recovery of prudently incurred costs) must be addressed before restructuring can be accomplished. This makes it difficult to predict how soon market-driven competition will be established.
Contributing to increasing competition in the utility industry are legislation and regulatory policies such as the National Energy Policy Act of 1992 (Energy Policy Act) and Federal Energy Regulatory Commission (FERC) Order 636. The Energy Policy Act, enacted in October 1992, provides open access at the wholesale level to electric transmission services and is contributing to major changes in the electric industry. FERC Order 636, which took effect in November 1993, requires interstate natural gas pipeline companies to offer customers unbundled, or separate, services.
A major challenge to the company's electric business continues to be its ability to retain and expand its industrial base. The company's industrial customers, accounting for about 15% of total electric revenues, will increasingly have more supply alternatives available to them. Those alternatives currently include cogeneration, self-generation and fuel switching. Industrial customers can also decide to relocate.
There are other competitive pressures as well. More efficient technologies and more economical alternative fuels and renewable energy sources may increasingly challenge traditional energy sources. Another possibility is that municipalities would establish their own electric systems within the company's service territory.
The prospect of limited sales growth due to New York's sluggish economy is another challenge. Low growth potential for the company's core businesses makes it difficult to improve earnings and lower prices.
Faced with growing competition and more efficient technologies, utilities are increasingly focusing on the price of their products. The company's electric prices have been rising. The major contributors to these increases have been mandated purchases of power from non-utility generators (NUGs), rising taxes, demand-side management (DSM) programs, and compliance with environmental laws and regulations. DSM programs are initiatives designed to help customers use energy efficiently. Recent natural gas price increases have been caused by higher purchased gas costs, primarily due to transition costs resulting after FERC Order 636 and higher pipeline transportation costs.
The company has developed flexible rates that allow it to negotiate long-term contracts with both its electric and its natural gas customers. The contracts may cover existing load, new load, or both. To date, 12 major electric industrial customers have signed contracts ranging from three to seven years. These contracts retain more than $36 million and add another $7 million in annual revenues, which together represent 2.7% of the company's total electric annual revenues. Also each month the company develops over 275 natural gas prices to compete with the alternative fuels available.
The Public Service Commission of the State of New York (PSC) has initiated a generic proceeding to study the broad subject of flexible, competitive rates. In July 1994 during Phase I of this proceeding, the PSC issued an opinion which approved flexible rate discounts for nonresidential electric customers having competitive alternatives. In approving the offering of discounts, the PSC adopted several guidelines that reaffirmed most of the company's flexible pricing programs.
In August 1994 the PSC instituted Phase II of the proceeding to address competitive opportunities available to electric customers and investigate the future regulation of electric service in light of competition. The overall objective is to identify regulatory and ratemaking practices that will assist the transition to a more competitive electric industry. Proposed principles to guide this transition were issued for comment by the PSC in December 1994.
This proceeding could affect the eligibility of electric utilities in New York State to apply Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). If the company could no longer meet the criteria of SFAS 71 for all or a part of its business, the company would have to expense certain previously deferred costs. Although the company believes it will continue to meet the criteria of SFAS 71 in the near future, it cannot predict what effect a competitive marketplace or future actions of the PSC will have on its ability to continue to do so.
In June 1994 the FERC issued a Notice of Proposed Rulemaking (NOPR) to address transition costs and invited representatives of the utility industry to comment on or suggest alternatives to the proposals. Transition costs are costs that utilities may incur (and that may become unrecoverable) as the industry moves from a heavily regulated environment to a less-regulated, competitive environment.
In December 1994 the company and a coalition of other New York State utilities filed joint comments addressing legal issues raised by the NOPR. The company also filed a separate document that addressed technical issues specific to the company. The coalition comments urge the FERC to set a national policy that will ensure recovery of transition costs so that competition will benefit all customers fairly. In a purely competitive environment, costs that utilities are required to bear (such as taxes, purchases of NUG power and DSM programs) would be difficult to recover because customers would have the opportunity to buy electricity from competitors who do not bear such costs, such as NUGs and municipal utilities. This could leave remaining customers bearing the full burden of those costs.
In 1994 the gas business operated its first full year under FERC Order 636 (see Note 11). Ultimately FERC Order 636 should prove beneficial to the company and its natural gas customers by providing greater opportunities to access natural gas supply, transportation and storage. Increased choices should result in lower natural gas costs in the intermediate and long term.
In December 1994 the PSC issued an order in its proceeding (instituted in late 1993) to investigate natural gas utility issues in view of FERC Order 636 and to determine to what extent New York State should adopt the federal policies. The PSC order also established a generic proceeding to investigate performance- based natural gas purchasing incentives and the availability and affordability of natural gas as the transition to a more competitive environment develops. While they found the majority of the PSC's findings favorable, the company and certain other parties to the proceeding have asked for a rehearing on certain points that they believe are inconsistent with the overall goal of encouraging competition. The company has already taken advantage of several new opportunities, including flexible customer rates, unbundling of services, and access to the secondary market for natural gas supplies and pipeline capacity.
As one response to the competitive pressures faced by its natural gas business, the company plans to build a natural gas storage project near Seneca Lake, north of Watkins Glen, New York. The project, which will cost $59 million and be regulated by the PSC, includes a storage facility and two separate pipelines to transport the natural gas. Its primary purpose is to ensure adequate supply to the company's core natural gas customers. The project will also increase supply flexibility, allow the company to retire propane plants and ultimately reduce pipeline demand charges. The company expects to receive PSC approval for the project and begin construction in 1995. The storage facility is scheduled to be in service for the 1996-1997 heating season.
During 1994 the company took a number of difficult steps to address the competitive challenges it faces. Foremost among them were the restructuring and workforce reduction completed in the first quarter of 1994 (see Note 6) and the decision to reduce the common stock dividend in the fourth quarter of 1994 (see Common Stock Dividend Policy).
Other steps the company has taken to address competitive pressures during 1994 include reducing capital expenditures and DSM program costs, placing two generating units on long-term cold standby, creating a customer service business unit and moving responsibility for fuel procurement and bulk power sales to the generation department.
On February 14, 1995, the company filed a petition with the FERC asking for relief from having to pay approximately $2 billion more than its avoided costs for power purchased over the life of the two NUG contracts mentioned below. The company believes that the overpayments under these two contracts violate the Public Utility Regulatory Policies Act of 1978.
The company is currently required to purchase 594 megawatts (mw) of NUG power. The company is required to make payments under these contracts only for the power it receives or when the company directs the NUG to reduce its output under the terms of the contract. Two contracts the company has with NUGs each provide more than 5% of current system capability. One contract provides for 177 mw or 5.4%, and the other provides for 240 mw or 7.3%. During 1994, 1993 and 1992 the company purchased approximately $214 million, $138 million and $71 million, respectively, of NUG power, including termination costs. The
company estimates that NUG power purchases, excluding termination costs, over the next five years will be as follows:
1995 1996 1997 1998 1999 (Millions) $274 $312 $322 $333 $344
Increases in the cost of NUG power purchases will contribute significantly to expected electric price increases in August 1995.
Diversification
Diversification will play an important role in the company's future. The company's primary objective is to enhance the competitiveness of its core electric and natural gas businesses. At the same time the company is actively evaluating opportunities for investment closely related to its core businesses that have the potential to augment future earnings. In April 1992 the PSC issued an order allowing the company to invest up to 5% of its consolidated capitalization (approximately $180 million at December 31, 1994) in one or more subsidiaries that may engage or invest in energy-related or environmental-services businesses and provide related services.
The company has been making investments in unregulated companies through its wholly owned subsidiary, NGE Enterprises, Inc. (NGE). NGE owns two unregulated businesses - EnerSoft Corporation (EnerSoft) and XENERGY, Inc. (XENERGY).
EnerSoft, a computer software company, was formed in May 1993 to produce and market software for natural gas utilities, marketers and pipeline operators. Through an alliance with the New York Mercantile Exchange, EnerSoft is developing Channel 4, a natural gas and pipeline capacity trading and information system for the North American market. While development of the system has taken longer than anticipated, Channel 4 is expected to be commercially available in the spring of 1995. Like most other start-up companies, EnerSoft has been incurring operating losses. The company expects that EnerSoft will continue to incur operating losses in the near term.
In June 1994 NGE acquired all of the outstanding stock of XENERGY, an energy services, information systems and energy- consulting company that specializes in energy management, conservation engineering and demand-side management. XENERGY currently provides a broad range of services to utilities throughout the United States, Canada, Spain and France. It also provides energy services, conservation engineering and DSM services to governmental agencies at both the state and federal levels, and to a large number of end users.
NGE is exploring environmental-services opportunities with both domestic and foreign strategic partners.
As of December 31, 1994 and 1993, the company had invested approximately $47 million and $3 million, respectively, in NGE to finance its diversified investments. For the years ended December 31, 1994 and 1993, NGE incurred net losses of $6.0 million and $1.4 million, respectively.
Common Stock Dividend Policy
In October 1994 the board of directors reduced the quarterly common stock dividend from 55 cents per share to 35 cents per share. This dividend reduction allows the company to achieve greater financial flexibility and strength and the company believes it will offer improved shareholder value over the long term. Financial flexibility will be essential in a competitive environment, and stronger utilities will command higher stock valuations.
The company can give no assurances as to future dividend levels. Dividends will depend on the company's earnings and financial requirements, developments in the utility industry and other factors. The company's long-term goal is a dividend payout ratio of 60% to 65% of earnings. The board of directors will continue to review the common stock dividend each quarter to ensure that it is consistent with the company's long-term interests.
Net Cash Provided by Operating Activities
Cash provided by operating activities in 1994 increased $38 million, up 9% from 1993. The increase was primarily due to a reduction in cash used for working capital items in 1994. Net cash from operating activities is derived by adjusting reported net income for charges or credits that have no cash effect (primarily depreciation, amortization and deferred income taxes) and changes in working capital items.
Net Cash Used in Investing Activities
In 1994, cash used in investing activities decreased $86 million, down 28% from 1993. The change was primarily due to a decrease in expenditures for utility plant construction.
The company's 1994 capital expenditures for its core electric and natural gas businesses totaled approximately $248 million. Most of the expenditures were for the extension of service, improvements at existing facilities, compliance with the Clean Air Act Amendments of 1990, and other environmental requirements. The company received $24 million from governmental and other sources in 1994 to partially offset expenditures for compliance with the Clean Air Act Amendments of 1990.
Capital expenditures projected for 1995-1997 have been limited and reflect planned cuts of more than $200 million. This represents one of the many actions the company is taking to address competition. Capital expenditures will be primarily for extension of service, necessary improvements at existing facilities, the natural gas storage project, compliance with the Clean Air Act Amendments of 1990 and other environmental requirements (see Note 9). The company expects to finance these capital expenditures entirely with internally generated funds. The company forecasts that its current reserve margin, coupled with more efficient use of energy (see Conservation Programs) and purchases of power from NUGs, eliminates the need for additional generating capacity until after the year 2007.
The following table provides information on the company's estimated sources and uses of funds for 1995-1997. This forecast is subject to periodic review and revision. Actual capital expenditures may change to reflect the imposition of additional regulatory requirements and the company's continued focus on optimizing capital expenditures.
1995 1996 1997 Total (Millions) Sources of funds Internal funds $298 $288 $284 $870 Long-term financing 39 - - 39 ---- ---- ---- ---- Total $337 $288 $284 $909 ==== ==== ==== ==== Uses of funds Capital expenditures Cash $185 $258 $180 $623 AFDC* 3 6 4 13 ---- ---- ---- ---- Total capital expenditures 188 264 184 636 Retirement of securities and sinking fund obligations 63 26 78 167 Repayment of short-term debt 55 20 33 108 Working capital, deferrals and other 31 (22) (11) (2) ---- ---- ---- ---- Total $337 $288 $284 $909 ==== ==== ==== ==== *Allowance for funds used during construction.
As shown in the preceding table, internal sources of funds represent 137% of capital expenditures for 1995-1997.
Net Cash Used in Financing Activities
Cash used in financing activities in 1994 increased $106 million, up 96% from 1993. This increase reflects a reduction of cash provided from the issuance of preferred stock and the use of cash provided by operating activities to reduce debt levels.
The company believes that maintaining financial integrity and flexibility is critical to success in a competitive environment. The dividend reduction,along with recent cost reductions,will allow future cash flows to meet all of the company's operating and capital needs. The company plans to use its strong cash flow in excess of operating and capital needs primarily to reduce debt in preparation for competition. The company will also use its cash flow to invest in both regulated and unregulated businesses that relate to its core businesses and that have the potential to grow and yield value for the company's shareholders. Since 1987 the company has reduced its debt from 61.9% to 46.7% of total capital and has raised its common stock equity from 32.7% to 46%. Its goal is to achieve a 50% common equity ratio.
The common stock equity ratio improved in 1994 primarily as a result of retained earnings, the issuance of shares pursuant to the Dividend Reinvestment and Stock Purchase Plan (DRP), the repayment at maturity of $100 million of 8 3/8% bonds in August 1994 and the repayment of the $50 million revolving credit agreement note. The company received $22.7 million from the issuance of 0.9 million shares of common stock through the DRP. However, beginning in August 1994, the DRP began purchasing shares on the open market rather than the company issuing new shares. The company expects that the DRP will continue purchasing shares on the open market as long as the market price of the stock, which was below book value during the latter half of 1994, remains below book value. Issuing new shares below book value would decrease book value per share and lead to a decrease in future earnings per share.
The following table indicates the company's financing activities during 1994: Interest Month Description Rate Due Amount
Issuances (Thousands)
February (1) Pollution control note Various* Feb. 1, 2029 $37,500 April (2) Pollution control note 6.05% Apr. 1, 2034 $100,000 June (3) Pollution control note Various* June 1, 2029 $63,500 October (4) Pollution control note Various* Oct. 1, 2029 $74,000
* Multi-mode note, maturity could be extended to 2034 under certain circumstances.
Redemptions/ Maturities
January Preferred stock-Series A Adj. Rate n/a $45,000 January Preferred stock 8.80% n/a $25,000 February Preferred stock 8.48% n/a $25,000 February First mortgage bond 8 5/8% Nov. 1, 2007 $23,000 August First mortgage bond 8 3/8% Aug. 15, 1994 $100,000 March Pollution control note 2.75% Mar. 1, 2015 $37,500 May Pollution control note 12.0% May 1, 2014 $60,000 July Pollution control note 12.30% July 1, 2014 $40,000 July Pollution control note 2.60% July 15, 2015 $63,500 December Pollution control note 2.80% Dec. 1, 2014 $74,000 May Revolving credit agreement note 4.06% July 31, 1997 $50,000
(1) Proceeds were used to refund, in March 1994, $37.5 million of one- year adjustable-rate pollution control revenue bonds, due 2015.
(2) Proceeds were used in connection with the redemption in May 1994 of $60 million of 12.0% pollution control bonds, due 2014, and the redemption in July 1994 of $40 million of 12.3% pollution control bonds, due 2014.
(3) Proceeds were used to refund, in July 1994, $63.5 million of one- year adjustable-rate pollution control revenue bonds, due 2015.
(4) Proceeds were used to refund, in December 1994, $74 million of one- year adjustable-rate pollution control revenue bonds, due 2014.
The company reduced its embedded cost of long-term debt to 7.1% at the end of 1994 compared to 9.8% at the end of 1987. The company has refinanced more than $1.5 billion in long-term debt since the beginning of 1988 and reduced annual interest expense by more than $60 million. Unless interest rates fall further it will be difficult to significantly improve from the 7.1% level. All opportunities will continue to be pursued aggressively.
The company uses short-term unsecured notes, usually commercial paper, to finance certain refundings and for other corporate purposes. There was $151.9 million of commercial paper outstanding at December 31, 1994, at a weighted average interest rate of 5.8%.
The company also has a revolving credit agreement with certain banks that provides for borrowing up to $200 million to July 31, 1997. The company had an outstanding $50 million loan under this agreement at December 31, 1993, at an interest rate of 4.06%. This loan was repaid in May 1994.
During 1994 the company had its securities ratings downgraded by both Standard & Poor's and Moody's Investors Service. These downgrades reflect the rating agencies' use of more stringent financial benchmarks in evaluating utilities, in order to reflect increasing competition and mounting business risks. More than one-quarter of the electric utility industry had its securities ratings downgraded in the past 18 months.
The company is committed to its goal of achieving an 'A' bond rating. The company plans to continue to strengthen its balance sheet by paying down debt with excess cash.
Regulatory Matters
In September 1993 the company reached a three-year electric and natural gas rate-settlement agreement with the PSC covering the period August 1, 1993 through July 31, 1996. Under the agreement, the allowed return on equity was 10.8% in year one, 11.4% in year two and 11.4% (subject to an indexing mechanism) in year three. Shareholders were allowed to keep 100% of any earnings above the allowed return in year one. Shareholders and customers are to share, on a 50%/50% basis, any earnings over the allowed return in years two and three. The calculation of earnings over the allowed return includes regulatory adjustments (such as the elimination of the impact of incentives and sharing mechanisms) and certain normalizing adjustments (such as spreading the 1993 restructuring charge over the term of the settlement agreement). For year one, the twelve months ended July 31, 1994, the company's earned return on equity, with adjustments, as discussed above, was 10.3%. The earned returns on electric equity and natural gas equity, with adjustments, were 10.1% and 12.7% respectively, for year one.
The agreement also includes a modified revenue decoupling mechanism (RDM) for electric sales. Rates are based on sales forecasts. Since actual sales may differ significantly from forecasted sales because of conservation efforts, unusual weather or changing economic conditions, revenues collected may be more or less than forecasted. Subject to the limits described below, the modified RDM lets the company adjust for most of the differences between forecasted and actual sales. For example, if revenues exceed the forecast for a given year, the excess is passed back to customers in a future year. If revenues are below the forecast, customers receive a surcharge in a future year. The company must share revenue excesses or shortfalls from sales to most large commercial and industrial customers on a 70%/30% (customer/shareholder) basis. In 1994 the company accrued $22.3 million under the modified RDM compared with $3.9 million in 1993. In 1993 the modified RDM covered only the period August through December.
Customer savings of $21 million in production and transmission operating costs are imputed over the three years of the agreement, at $7 million each year, whether or not such savings are realized.
The estimated total electric price increases anticipated by the agreement are $99.6 million, or 7.4%, in year one; $109.5 million, or 7.6% in year two; and $87.8 million, or 5.6% in year three. These include base rate increases plus estimated price increases for fuel, purchased power and other costs that are collected through the fuel adjustment clause (FAC). Actual costs collected through the FAC could vary from estimates, causing the total electric price increases to change.
The base rate increases for natural gas allowed by the agreement are $7.5 million, or 2.9%, in year one; $8.2 million, or 3.0%, in year two; and $7.2 million, or 2.5%, in year three. They do not include changes in natural gas costs, which will be collected through the gas adjustment clause. Natural gas costs can be expected to rise and fall with overall natural gas market conditions. Such fluctuations will affect the total natural gas price increases.
The agreement also provides for the stated base rate increases for electricity and natural gas to be adjusted up or down in the second and third years, as well as the year after the agreement period (year four). Base rates can be adjusted for several factors, such as electric sales, incentive mechanisms and other true-ups from the prior year. The electric base rate increases could be adjusted upward by up to 1.5% in years two and three and 1.6% in year four. The natural gas base rate increases could be adjusted upward by up to 1.0% in year two and 1.2% in year three. The agreement does not specify a limit on the upward adjustment for natural gas base rates for year four. There is no limit to any downward adjustment of base rates for electric and natural gas.
In June 1994 the company finalized its filing of adjustments to the second-year electric and natural gas rates in accordance with the terms of the agreement. The company took voluntary action to lower the estimated total electric price increase to 7.8%. The electric price increase which was primarily due to increases in mandated purchases of electricity from NUGs, increases in taxes and sales shortfalls related to mandated conservation programs and the weak economy in New York State, would have been substantially greater than 7.8% without the voluntary action. The filed natural gas base rate increase was 1.9%. On August 15, 1994, the PSC issued an Opinion and Order that approved the electric price increase of 7.8% and the 1.9% natural gas base rate increase effective August 1, 1994. In addition, the PSC directed the company and staff of the PSC to begin discussions on modifying the agreement to mitigate the projected third-year electric increase and bring rate predictability and stability to future years. Those discussions began in October 1994 and are continuing.
The agreement provides incentives (rewards or penalties) to the company for controlling production costs (PCI), improving customer service and implementing DSM programs. Those incentives could have increased the company's allowed return to 12.3% or decreased it to 9.95% in year one, increase it to 13.05% or decrease it to 10.4% in year two, and increase it to 13.25% or decrease it to 10.2% in year three. In June 1994 the company calculated and recorded a production-cost penalty for 1993 of $13.0 million, or 12 cents per share. This was the maximum permitted by the agreement.
The PCI is based on a comparison of the company with a 19- company peer group (which includes the company). The production measure compared is the relative change in production and certain other costs per megawatt-hour of retail sales occurring between the applicable calendar year and a base period (1989-1992). The company calculated the PCI penalty for 1993 using data reported in the peer group's FERC Form 1 Reports, which the company received in May 1994. The company's PCI penalty for 1993 was due primarily to a significantly lower increase in retail sales (after adjusting for the effect of sales lost due to DSM programs) for the company than for the peer group. It was also due to a greater increase in DSM program costs and purchased power costs for the company than for the peer group.
The company believes that a penalty for its PCI performance in 1994 is unlikely. This is primarily because of the company's recent cost-reduction efforts and improved sales compared to the sales increase of the peer group, which is projected to be less than the peer group's sales increase in 1993. This estimate includes the company's actual performance through December 31, 1994. However, it was necessary to make certain assumptions regarding the peer group's 1994 performance since the actual information needed for this calculation will not be available until the peer group's FERC Form 1 Reports become available in May 1995. As an example, retail sales units and certain production costs for the peer group were assumed to continue at the levels achieved through the first nine months of 1994. The maximum PCI allowed for 1994 by the agreement is a reward or penalty of $17.5 million, or 16 cents per share.
Conservation Programs
The company has implemented a number of DSM programs. As part of its three-year rate agreement (see Regulatory Matters), the rewards the company could earn for conducting efficient DSM programs were reduced from 15% to 5% of the net resource savings achieved by these programs. For 1995 the company expects to earn approximately $1 million in rewards as a result of DSM programs.
In 1994 customers saved approximately 64 million kilowatt- hours (kwh) on an annualized basis through DSM programs. These programs cost $14 million in 1994 and will cost approximately $11 million in 1995. The customer savings estimated for 1995 are 54 million kwh on an annualized basis. At both December 31, 1994 and 1993, the company had approximately $73 million of deferred DSM program costs on its consolidated balance sheets. The two- year (1993-1994) DSM plan, which received PSC approval, was modified to improve cost-effectiveness and reduce rate impacts. In August 1994 the company submitted its 1995 DSM plan to the PSC proposing DSM goals and budgets for the years 1995 through 2000. The company expects to change its DSM approach in 1995 to move toward promoting energy-efficient equipment in the mass market and phasing out rebates for individual customers.
Environmental Matters
The company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Any additional compliance programs will increase the cost of electric and natural gas service by requiring changes in the company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred to comply with environmental laws and regulations (See Note 9 and Note 10).
Results of Operations 1994 1993 over over 1993 1992 1994 1993 1992 Change Change (Thousands, except per share amounts) Operating revenues $1,898,855 $1,800,149 $1,691,689 5% 6% Earnings available for common stock $168,698 $145,390 $162,973 16% (11%) Average shares outstanding 71,254 69,990 67,972 2% 3% Earnings per share $2.37 $2.08 $2.40 14% (13%) Dividends per share $2.00 $2.18 $2.14 (8%) 2%
Total operating revenues in 1994 increased $99 million, up 5% over 1993. In 1993, total operating revenues increased $108 million, up 6% from 1992. These results are discussed according to business segment beginning on page 44.
Earnings per Share
In 1994 earnings per share increased 29 cents, up 14% over 1993, while in 1993 earnings per share decreased 32 cents, down 13% from 1992. Certain nonrecurring items lowered earnings per share for 1993 and 1992. Earnings in 1993 were reduced 25 cents per share by the corporate restructuring that reorganized the way the company delivers services to its electric and natural gas customers beginning in March 1994 (see Note 6). Earnings in 1992 were 24 cents per share lower than they otherwise would have been because of a six-month moratorium on electric rate increases that began in February 1992. Without these nonrecurring items, earnings per share were up 4 cents in 1994 compared to 1993, and were down 31 cents in 1993 compared to 1992.
The increase in 1994 earnings per share without the nonrecurring items was due to a combination of factors. Lower operation and maintenance expenses that resulted from cost controls and the workforce reduction helped 1994 earnings by 26 cents per share. Also, on a comparative basis, 1994 earnings rose because lower electric retail sales in 1993 before the effective date of the company's modified RDM reduced 1993 earnings 9 cents per share. These increases in earnings per share were partially offset by the reduction in rewards earned from the company's DSM programs that lowered earnings by 13 cents per share; the 1993 production-cost penalty recorded in the second quarter of 1994 that reduced earnings by 12 cents per share; and losses incurred by the company's diversified operations that lowered earnings by 7 cents per share.
The decrease in 1993 earnings per share without the nonrecurring items was mainly due to lower electric retail sales before the effective date of the company's modified RDM, and to lower-than-anticipated natural gas sales. Both of these results were due to the sluggish economy in the company's service territory. Also, earnings per share decreased because of reductions in the company's allowed return on equity, from 11.7% effective through July 1992, to 11.2% effective through July 1993, and then to 10.8% beginning in August 1993.
Interest Expense
Interest expense (before the reduction for allowance for borrowed funds used during construction) decreased by $6 million, or 4% in 1994, and $10 million, or 6% in 1993. Interest on long- term debt decreased in 1994 and 1993 mainly due to the refinancing or refunding of certain high-coupon long-term debt. In 1993 interest expense also decreased due to lower interest rates on the company's variable rate debt.
Average Shares Outstanding
Average shares outstanding were 71 million in 1994, 70 million in 1993 and 68 million in 1992. The increases in average shares outstanding, 2% in 1994, and 3% in 1993, were both due to the issuance of shares of common stock through the DRP. A total of 0.9 million shares of common stock were issued through the DRP in 1994, and 1.2 million shares were issued in 1993. The number of shares issued in 1994 was lower than in 1993 because the DRP began purchasing shares on the open market as of August 1994 rather than the company issuing new shares. The company expects that the DRP will continue purchasing shares on the open market as long as the market price of the stock, which was below book value during the latter half of 1994, remains below book value. Issuing new shares below book value would decrease book value per share and lead to a decrease in future earnings per share.
Dividends per Share
Dividends decreased 8% in 1994 because the board of directors reduced the quarterly common stock dividend from 55 cents per share to 35 cents per share in October 1994 (see Common Stock Dividend Policy).
Operating Results for the Electric Business Segment 1994 1993 over over 1993 1992 1994 1993 1992 Change Change (Thousands)
Retail sales - kilowatt - hours(kwh) 13,147,631 13,088,175 13,294,466 - (2%) Operating revenues $1,600,075 $1,527,362 $1,451,525 5% 5% Operating expenses $1,306,871 $1,250,000 $1,146,619 5% 9% Operating income $293,204 $277,362 $304,906 6% (9%)
Electric retail sales for 1994 were up slightly compared to 1993 sales. In 1993, electric retail sales were down 2% from 1992 (despite a 1% increase in customers) due to the sluggish economy in the company's service territory.
Operating Revenues
Electric operating revenues increased by $73 million, or 5%, in 1994, and by $76 million, or 5%, in 1993. The more significant items contributing to these changes are as follows:
1994 1993 (Millions) Rate changes $69 $53 RDM 18 4 Recovery of increases in NUG power through fuel adjustment clause (FAC) 16 28 Interchange profits 16 - DSM incentives (14) - DSM lost revenues (15) - Production-cost penalty (13) - Other (4) (9) --- --- Total increase $73 $76 === ===
Changes in electric rates effective in September 1993 and August 1994 were the principal reason for higher 1994 revenues. The rate changes were caused primarily by an increase in mandated purchases of NUG power and by higher federal taxes. The modified RDM contributed to revenues since actual electric sales in 1994 were below the levels forecasted in the company's rate agreement. Higher costs of NUG power, which are billed to customers in part through the FAC, also boosted 1994 revenues. Interchange profits helped revenues due to an increase in interchange sales volume over 1993. These increases were partially offset by a decrease in rewards earned from DSM programs, a decrease in DSM lost revenues recorded and the 1993 production-cost penalty recorded in the second quarter of 1994.
The $76 million, or 5%, increase in electric operating revenues in 1993 was primarily due to rate changes effective in August 1992 and September 1993, mainly the result of an increase in mandated purchases of NUG power and rising taxes. Higher costs of NUG power (billed to customers in part through the FAC) also contributed to the growth in revenues.
Operating Expenses
Electric operating expenses in 1994 increased $57 million, or 5%, over the 1993 level. The principal cause was an increase of $80 million in electricity purchased, primarily purchases from NUGs. Federal income taxes grew by $17 million, the result of higher pretax book income. Gross receipts taxes and school taxes added another $7 million to expenses. Depreciation expense rose $12 million compared to 1993. Those increases were partially offset by decreases of $15 million in operating expenses (mainly due to cost controls and the workforce reduction) and $14 million in fuel used in electric generation (due to reduced generation). Also, expenses were $21 million lower in 1994 because of the restructuring charge recorded in the fourth quarter of 1993.
In 1993 electric operating expenses were $103 million, or 9%, higher than in 1992. The major contributor to this increase was electricity purchased from NUGs, which rose by $67 million. Postretirement-benefit costs other than pensions increased $7 million. Corporate restructuring added another $21 million to electric operating expenses. These increases were partially offset by a $17 million decrease in fuel used in electric generation (the result of reduced generation and a lower price for coal) and by a $12 million decrease in federal income taxes (the result of lower pretax book income).
Operating Results for the Natural Gas Business Segment 1994 1993 over over 1993 1992 1994 1993 1992 Change Change (Thousands)
Deliveries - dekatherms (dth) 58,624 58,046 56,366 1% 3% Operating revenues $298,780 $272,787 $240,164 10% 14% Operating expenses $269,300 $249,493 $221,307 8% 13% Operating income $29,480 $23,294 $18,857 27% 24%
Natural gas deliveries rose by 1% in 1994 and by 3% in 1993. The increase in deliveries in 1994 and 1993 was due to the addition of new customers, including several large volume customers.
Operating Revenues
Natural gas operating revenues rose by $26 million, or 10%, in 1994, and by $33 million, or 14%, in 1993. The more significant items that contributed to these changes are as follows: 1994 1993 (Millions) Natural gas price increases $16 $23 Rate changes 7 8 Other 3 2 --- --- Total increase $26 $33 === ===
Higher costs of natural gas (billed to customers) were the primary reason for the rise in 1994 revenues. Rate changes effective in September 1993 and August 1994 also added to revenues. However, since the company has a weather normalization mechanism for natural gas, $0.9 million of revenues attributable to colder weather was returned to customers in 1994.
In 1993 the leading contributors to the increase in revenues were higher costs of natural gas and the rate changes that became effective in August 1992 and September 1993. Revenues of $1.0 million were returned to customers in 1993 through the weather normalization mechanism.
Operating Expenses
Natural gas operating expenses were up by $20 million, or 8%, in 1994, mainly because of an increase of $20 million in natural gas purchased that was mostly due to higher prices. Higher federal income taxes increased operating expenses by $4 million, due to higher pretax book income. Gross receipts taxes and school taxes added another $1 million to expenses. Depreciation expense rose $2 million compared to 1993. Those increases were partially offset by a decrease of $5 million because of the restructuring charge recorded in 1993 and a $1 million decrease in marketing expenses due to improved operations.
Operating expenses in 1993 increased $28 million, up 13% from their 1992 level. Natural gas purchased rose by $12 million, mainly because of higher natural gas prices. Federal income taxes increased $3 million due to higher pretax book income. Corporate restructuring added $5 million to natural gas operating expenses.
Item 8.
Item 8. Financial Statements and Supplementary Data
New York State Electric & Gas Corporation Consolidated Balance Sheets
December 31 1994 1993 - ------------------------------------------------------------------------------- (Thousands) Assets
Utility Plant, at Original Cost (Note 1) Electric (Note 8). . . . . . . . . . . . . . . . . . . $4,916,960 $4,777,368 Natural gas. . . . . . . . . . . . . . . . . . . . . . 414,929 381,389 Common . . . . . . . . . . . . . . . . . . . . . . . . 143,366 158,986 ---------- ---------- . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,475,255 5,317,743 Less accumulated depreciation. . . . . . . . . . . . . 1,642,653 1,535,307 ---------- ---------- Net Utility Plant in Service. . . . . . . . . . . 3,832,602 3,782,436 Construction work in progress. . . . . . . . . . . . . 154,723 143,859 ---------- ---------- Total Utility Plant . . . . . . . . . . . . . . . 3,987,325 3,926,295
Other Property and Investments, Net (Note 12) . . . . . 103,920 73,537
Current Assets Cash and cash equivalents (Notes 1 and 13) . . . . . . 22,322 4,264 Special deposits (Note 13) . . . . . . . . . . . . . . 7,591 145,335 Accounts receivable, net (Note 1). . . . . . . . . . . 155,665 181,586 Fuel, at average cost. . . . . . . . . . . . . . . . . 49,934 54,791 Materials and supplies, at average cost. . . . . . . . 47,843 48,910 Prepayments. . . . . . . . . . . . . . . . . . . . . . 30,441 30,092 Accumulated deferred federal income tax benefits, net (Notes 1 and 2) . . . . . . . . . 11,457 - ---------- ----------
Total Current Assets. . . . . . . . . . . . . . . . 325,253 464,978
Deferred Charges (Note 1) Unfunded future federal income taxes (Notes 1 and 2) . . . . . . . . . . . . . . . 363,151 380,056 Unamortized debt expense . . . . . . . . . . . . . . . 114,444 112,059 Demand-side management program costs . . . . . . . . . 72,849 73,113 Other. . . . . . . . . . . . . . . . . . . . . . . . . 255,963 257,920 ---------- ---------- Total Deferred Charges. . . . . . . . . . . . . . 806,407 823,148 ---------- ---------- Total Assets. . . . . . . . . . . . . . . . . . . $5,222,905 $5,287,958 ========== ==========
The notes on pages 53 through 79 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Balance Sheets
December 31 1994 1993 - ------------------------------------------------------------------------------ (Thousands) Capitalization and Liabilities
Capitalization Common stock equity Common stock ($6.66 2/3 par value, 90,000,000 shares authorized and 71,502,827 and 70,595,985 shares issued and outstanding at December 31, 1994 and 1993, respectively) . . . . . . . . . . $476,686 $470,640 Capital in excess of par value. . . . . . . . . . 841,624 824,943 Retained earnings . . . . . . . . . . . . . . . . 346,547 320,114 ---------- ---------- Total common stock equity. . . . . . . . . . . . . . . 1,664,857 1,615,697 Preferred stock redeemable solely at the option of the company (Note 4). . . . . . . . . . . . . . . . 140,500 140,500 Preferred stock subject to mandatory redemption requirements (Notes 4 and 13) . . . . . . . . . . . 125,000 125,000 Long-term debt (Notes 3 and 13). . . . . . . . . . . . 1,651,081 1,630,629 ---------- ---------- Total Capitalization. . . . . . . . . . . . . . . 3,581,438 3,511,826 Current Liabilities Current portion of long-term debt (Note 3) . . . . . . 36,231 237,709 Current portion of preferred stock (Note 4). . . . . . - 95,000 Notes payable (Notes 5 and 13) . . . . . . . . . . . . 151,900 50,200 Accounts payable and accrued liabilities . . . . . . . 107,356 111,481 Interest accrued (Note 13) . . . . . . . . . . . . . . 25,132 31,348 Accumulated deferred federal income taxes, net (Notes 1 and 2) . . . . . . . . . . . . . . . . . . - 1,132 Other. . . . . . . . . . . . . . . . . . . . . . . . . 94,961 89,443 ---------- ---------- Total Current Liabilities . . . . . . . . . . . . 415,580 616,313
Deferred Credits and Other Liabilities Accumulated deferred investment tax credit (Notes 1 and 2) . . . . . . . . . . . . . . . . . . 132,440 138,478 Excess deferred federal income taxes (Notes 1 and 2) . 34,040 36,378 Other postretirement benefits. . . . . . . . . . . . . 55,887 28,074 Liability for environmental restoration (Note 10). . . 33,600 26,800 Other. . . . . . . . . . . . . . . . . . . . . . . . . 131,585 133,488 ---------- ---------- Total Deferred Credits and Other Liabilities. . . 387,552 363,218
Accumulated Deferred Federal Income Taxes (Notes 1 and 2) Unfunded future federal income taxes . . . . . . . . . 363,151 380,056 Other. . . . . . . . . . . . . . . . . . . . . . . . . 475,184 416,545 ---------- ---------- Total Accumulated Deferred Federal Income Taxes . . . . . . . . . . . . . . . . . . 838,335 796,601
Commitments and Contingencies (Note 9). . . . . . . . . - - ---------- ---------- Total Capitalization and Liabilities. . . . . . . $5,222,905 $5,287,958 ========== ==========
The notes on pages 53 through 79 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Statements of Income
Year Ended December 31 1994 1993 1992 - ---------------------------------------------------------------------------- (Thousands, except per share amounts)
Operating Revenues Electric . . . . . . . . . . . . . . . . $1,600,075 $1,527,362 $1,451,525 Natural gas. . . . . . . . . . . . . . . 298,780 272,787 240,164 ---------- ---------- ---------- Total Operating Revenues . . . . . . 1,898,855 1,800,149 1,691,689 ---------- ---------- ---------- Operating Expenses Fuel used in electric generation . . . . 231,648 245,283 262,531 Electricity purchased (Note 9) . . . . . 242,352 161,967 95,026 Natural gas purchased. . . . . . . . . . 161,627 141,635 126,815 Other operating expenses . . . . . . . . 328,961 349,177 318,680 Restructuring expenses (Notes 6 and 7) . - 26,000 - Maintenance. . . . . . . . . . . . . . . 106,637 111,757 102,500 Depreciation and amortization (Note 1) . 178,326 164,568 158,977 Federal income taxes (Notes 1 and 2) . . 115,891 94,144 102,456 Other taxes . . . . . . . . . . . . . . 210,729 204,962 200,941 ---------- ---------- ---------- Total Operating Expenses . . . . . . . 1,576,171 1,499,493 1,367,926 ---------- ---------- ---------- Operating Income. . . . . . . . . . . . . 322,684 300,656 323,763 Other Income and Deductions (Note 12) . . 1,053 6,471 12,036 ---------- ---------- ---------- Income Before Interest Charges. . . . . . 323,737 307,127 335,799 ---------- ---------- ---------- Interest Charges Interest on long-term debt . . . . . . . 126,083 134,330 145,822 Other interest . . . . . . . . . . . . . 13,642 11,120 9,566 Allowance for borrowed funds used during construction. . . . . . . . (3,633) (4,351) (3,557) ---------- ---------- ---------- Interest Charges, Net. . . . . . . . . 136,092 141,099 151,831 ---------- ---------- ---------- Net Income. . . . . . . . . . . . . . . . 187,645 166,028 183,968 Preferred Stock Dividends . . . . . . . . 18,947 20,638 20,995 ---------- ---------- ---------- Earnings Available for Common Stock . . . $168,698 $145,390 $162,973 ========== ========== ========== Earnings Per Share. . . . . . . . . . . . $2.37 $2.08 $2.40 Average Shares Outstanding. . . . . . . . 71,254 69,990 67,972
The notes on pages 53 through 79 are an integral part of the financial statements.
New York State Electric & Gas Corporation Consolidated Statements of Cash Flows
Year Ended December 31 1994 1993 1992 - ------------------------------------------------------------------------------ (Thousands) Operating Activities Net income . . . . . . . . . . . . . . . . . . . . $187,645 $166,028 $183,968 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization. . . . . . . . . . 178,326 164,568 158,977 Deferred fuel and purchased gas. . . . . . . . . (1,944) (10,671) (14,645) Federal income taxes and investment tax credits deferred, net. . . . . . . . . . . . . . . . . 13,670 50,761 52,039 Unbilled revenue amortization (Note 1) . . . . . (3,769) (5,335) (10,451) Demand-side management program costs . . . . . . 264 (29,064) (22,863) Restructuring expenses . . . . . . . . . . . . . - 26,000 - Changes in current operating assets and liabilities: Special deposits . . . . . . . . . . . . . . . . 42,744 2,438 (1,873) Accounts receivable excluding accounts receivable sold. . . . . . . . . . . . . . . . 25,921 (23,703) (38,345) Accounts receivable sold (Note 1). . . . . . . . - 13,800 - Prepayments. . . . . . . . . . . . . . . . . . . (349) 7,805 (878) Inventory. . . . . . . . . . . . . . . . . . . . 5,924 16,013 (1,376) Accounts payable and accrued liabilities . . . . (4,125) 15,485 (4,851) Interest accrued . . . . . . . . . . . . . . . . (6,216) (6,342) (5,750) Other, net . . . . . . . . . . . . . . . . . . . . 12,287 24,407 (7,685) -------- -------- -------- Net Cash Provided by Operating Activities . . . 450,378 412,190 286,267 -------- -------- -------- Investing Activities Utility plant capital expenditures, net of allowance for other funds used during construction . . . . . . . . . . . . . . . . . . (246,536)(265,109)(243,373) Proceeds received from governmental and other sources . . . . . . . . . . . . . . . . . 23,915 22,808 322 Expenditures for other property and investments. . (34,482) (16,975) - Funds restricted for capital expenditures. . . . . 41,113 (42,437) - -------- -------- -------- Net Cash Used in Investing Activities . . . . . (215,990)(301,713)(243,051) -------- -------- -------- Financing Activities Issuance of pollution control notes and first mortgage bonds . . . . . . . . . . . . . . 275,000 217,362 247,668 Proceeds from revolving credit agreement note. . . - 50,000 - Sale of common stock . . . . . . . . . . . . . . . 23,386 38,334 162,965 Sale of preferred stock. . . . . . . . . . . . . . - 97,762 - Repayments of pollution control notes, first mortgage bonds and preferred stock, including premiums. . . . . . . . . . . . (497,450)(326,091)(178,289) Repayment of revolving credit agreement note . . . (50,000) - - Changes in funds set aside for preferred stock and first mortgage bond repayments . . . . . . . 95,000 (8,904) (83,096) Long-term notes, net . . . . . . . . . . . . . . . (2,290) 8,393 (1,593) Notes payable, net . . . . . . . . . . . . . . . . 101,700 (13,900) (39,800) Dividends on common and preferred stock. . . . . . (161,676)(173,137)(165,704) -------- -------- -------- Net Cash Used in Financing Activities . . . . . (216,330)(110,181) (57,849) -------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents 18,058 296 (14,633) Cash and Cash Equivalents, Beginning of Year. . . . 4,264 3,968 18,601 -------- -------- -------- Cash and Cash Equivalents, End of Year (Notes 1 and 13). . . . . . . . . . . . . . . . . $22,322 $4,264 $3,968 ======== ======== ========
The notes on pages 53 through 79 are an integral part of the financial statements.
Notes to Consolidated Financial Statements
1 Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the company's wholly-owned subsidiaries, Somerset Railroad Corporation (SRC) and NGE Enterprises, Inc. (NGE). All significant intercompany balances and transactions are eliminated in consolidation.
Utility plant
The cost of repairs and minor replacements is charged to the appropriate operating expense accounts. The cost of renewals and betterments, including indirect costs, is capitalized. The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.
Depreciation and amortization
Depreciation expense is determined using straight-line rates, based on the average service lives of groups of depreciable property in service. Depreciation accruals were equivalent to 3.5%, 3.4% and 3.3%, of average depreciable property for 1994, 1993 and 1992 respectively. Depreciation expense includes the amortization of certain deferred charges authorized by the Public Service Commission of the State of New York (PSC).
Revenue
During 1994, 1993 and 1992 the company recognized on the income statement approximately $4 million, $5 million and $10 million, respectively, of electric and natural gas unbilled revenues that had been accrued on its balance sheet for energy provided but not yet billed to minimize the rate increases for these years in accordance with various PSC rate decisions. The July 1992 rate decision allowed the company to recognize on its income statement, beginning in August 1992, electric and natural gas unbilled revenues on a full accrual basis.
The company recognizes as revenue, incentives earned as the result of conducting efficient demand-side management (DSM) programs. The company is collecting those incentives in rates within approximately one year after they are recognized. During 1994, 1993 and 1992 incentives earned were $2 million, $16.4 million and $15.6 million, respectively. At December 31, 1994 and 1993, approximately $1.2 million and $14.3 million, respectively, of DSM incentives were accrued and included in accounts receivable.
Accounts receivable
The company has an agreement that expires in November 1996 to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allows the company to receive up to $152 million from the sale of such interests. At December 31, 1994 and 1993, accounts receivable on the consolidated balance sheets are shown net of $152 million of interests in accounts receivable sold. All fees associated with the program are included in other income and deductions on the consolidated statements of income and amounted to approximately $7.4 million, $5.7 million and $6.5 million in 1994, 1993 and 1992, respectively. Accounts receivable on the consolidated balance sheets is also shown net of an allowance for doubtful accounts of $7.2 million and $4 million at December 31, 1994 and 1993, respectively. Bad debt expense was $19.6 million, $15.3 million and $11.5 million in 1994, 1993 and 1992, respectively.
Income taxes
The company adopted Statement of Financial Accounting Standards No. 109 (SFAS 109), Accounting for Income Taxes, in January 1993. Since the company had been accounting for income taxes under Statement of Financial Accounting Standards No. 96, Accounting for Income Taxes, there was no effect on the consolidated statements of income as a result of adopting SFAS 109. However, SFAS 109 did require the company's deferred tax balances to be reclassified on its consolidated balance sheets.
The company files a consolidated federal income tax return with SRC and NGE. Deferred income taxes are provided on all temporary differences between financial statement basis and taxable income. Investment tax credits, which reduce federal income taxes currently payable, are deferred and amortized over the estimated lives of the applicable property. The effect of the alternative minimum tax (AMT), which increases federal income taxes currently payable and generates a tax credit available for future use, is deferred and amortized at such times as the tax credit is used on the company's federal income tax return.
Deferred charges
The company defers certain incurred expenses when authorized by the PSC. Those expenses will be recovered from customers in the future.
Consolidated Statements of Cash Flows
The company considers all highly liquid investments with a maturity or put date of three months or less when acquired to be cash equivalents. These investments are included in cash and
cash equivalents on the consolidated balance sheets.
Total income taxes paid were $69.2 million, $27.0 million and $37.6 million for the years ended December 31, 1994, 1993 and 1992, respectively.
Interest paid, net of amounts capitalized, was $132.0 million, $138.2 million and $149.3 million for the years ended December 31, 1994, 1993 and 1992, respectively.
Reclassifications
Certain amounts have been reclassified on the consolidated financial statements to conform with the 1994 presentation.
2 Income Taxes
Year ended December 31 1994 1993 1992 (Thousands) Charged to operations Current $88,623 $34,989 $37,237 Deferred, net Accelerated depreciation 51,736 49,580 41,492 Unbilled revenues (3,913) 5,073 160 Revenue decoupling mechanism 6,870 - - AMT credit (4,744) (3,194) 2,123 Demand-side management (9,048) 13,479 9,324 NUG termination agreement (1,313) 6,208 8,500 Nine Mile No. 2 litigation proceeds (520) 4,756 (2,047) Restructuring expenses - (6,965) - Postretirement benefits (5,079) (3,492) (593) Transmission facility agreement (2,719) (7,778) (1,172) Miscellaneous (3,970) (4,154) (4,598) Investment tax credit (ITC) (32) 5,642 12,030 -------- ------- ------- 115,891 94,144 102,456 Included in other income Amortization of deferred ITC (6,006) (8,892) (16,927) Miscellaneous (7,424) 498 3,747 -------- ------- ------- Total $102,461 $85,750 $89,276 ======== ======= =======
The company's effective tax rate differed from the statutory rate of 35% in 1994 and 1993 and 34% in 1992 due to the following:
Year ended December 31 1994 1993 1992 (Thousands) Tax expense at statutory rate $101,537 $88,684 $92,903 Depreciation not normalized 18,552 16,984 16,697 ITC amortization (6,006) (8,892) (16,927) Revenue Reconciliation Act of 1993, net (3,736) (631) - Research & Development (R&D) credit (1,352) (5,139) - Cost of removal (5,462) (4,921) (4,079) Other, net (1,072) (335) 682 -------- ------- ------- Total $102,461 $85,750 $89,276 ======== ======= ======= The company's deferred tax assets and liabilities consist of the following:
December 31 1994 1993 (Thousands) Current Deferred Taxes Demand-side management $(548) $(9,897) Unbilled revenue 4,449 (783) Pension expense 3,748 5,600 Other 3,808 3,948 ------- ------- Total current deferred taxes $11,457 $(1,132) ------- ------- Noncurrent Deferred Taxes Depreciation $(740,961) $(698,939) Loss on reacquired debt (26,663) (28,440) Regulatory asset (SFAS 109) (143,285) (149,636) Deferred ITC (net of SFAS 109) (86,205) (91,006) Demand-side management (25,785) (25,484) NUG contract settlement costs (13,850) (15,163) AMT credit 16,716 19,953 Excess tax reserve 11,788 12,603 Nine Mile No. 2 disallowed plant 13,519 19,347 Contributions in aid of construction 20,050 20,913 Capitalized interest 10,280 8,690 Other (4,168) (7,255) --------- --------- Total noncurrent deferred taxes $(968,564) $(934,417) --------- --------- Total deferred taxes $(957,107) $(935,549) Valuation allowance (2,211) (662) --------- --------- Net deferred taxes $(959,318) $(936,211) ========= =========
The Revenue Reconciliation Act of 1993 (RRA 1993), enacted on August 10, 1993, provided among other things, for an increase of 1% in the statutory corporate income tax rate and an extension of the R&D credit until June 30, 1995.
In September 1993 the company reached a three-year rate settlement agreement with the PSC which included a provision for the company to petition to defer the effect of RRA 1993 until it is reflected in rates. The changes related to RRA 1993 were reflected in rates beginning August 1, 1994.
The company has recorded unfunded future federal income taxes and a corresponding receivable from customers of approximately $363 million and $381 million as of December 31, 1994 and 1993, respectively, primarily representing the cumulative amount of federal income taxes on temporary depreciation differences, which were previously flowed through to customers. Those amounts, including the tax effect of the future revenue requirements, are being amortized over the life of the related depreciable assets concurrent with their recovery in rates.
The company has approximately $16.7 million of AMT credits that do not expire.
3 Long-Term Debt
At December 31, 1994 and 1993, long-term debt was (Thousands):
First mortgage bonds Amount Series Due 1994 1993 8 3/8% Aug. 15, 1994 $ - $100,000 5 5/8% Jan. 1, 1997 25,000 25,000 6 1/4% Sept. 1, 1997 25,000 25,000 6 1/2% Sept. 1, 1998 30,000 30,000 7 5/8% Nov. 1, 2001 50,000 50,000 6 3/4% Oct. 15, 2002 150,000 150,000 7 1/4% June 1, 2006 12,000 12,000 6 7/8% Dec. 1, 2006 25,000 25,250 8 5/8% Nov. 1, 2007 37,000 60,000 9 7/8% Feb. 1, 2020 100,000 100,000 9 7/8% May 1, 2020 100,000 100,000 9 7/8% Nov. 1, 2020 100,000 100,000 8 7/8% Nov. 1, 2021 150,000 150,000 8.30% Dec. 15, 2022 100,000 100,000 7.55% Apr. 1, 2023 50,000 50,000 7.45% July 15, 2023 100,000 100,000 --------- --------- Total first mortgage bonds 1,054,000 1,177,250 ========= =========
Pollution control notes
Interest Maturity Interest Rate Letter of Credit Amount Rate Date Adjustment Date Expiration Date 1994 1993 12% May 1, 2014 - - - 60,000 12.30% July 1, 2014 - - - 40,000 2.80% Dec. 1, 2014 - - - 74,000 2.75% Mar. 1, 2015 - - - 37,500 3.25%(1) Mar. 15, 2015 Mar. 15, 1995 Mar. 31, 1996 60,000 60,000 2.60% July 15, 2015 - - - 63,500 4.10%(1) Oct. 15, 2015 Oct. 15, 1995 Oct. 31, 1996 30,000 30,000 4.60%(1) Dec. 1, 2015 Dec. 1, 1995 Dec. 15, 1996 42,000 42,000 4.10%(1) July 1, 2026 July 1, 1996 July 15, 1996 65,000 65,000 5.95% Dec. 1, 2027 - - 34,000 34,000 5.70% Dec. 1, 2028 - - 70,000 70,000 Var.%(2) Feb. 1, 2029 Various Feb. 23, 1996 37,500 - Var.%(2) June 1, 2029 Various June 15, 1996 63,500 - Var.%(2) Oct. 1, 2029 Various Oct. 25, 1996 74,000 - 6.05% Apr. 1, 2034 - - 100,000 - ---------- --------- Total pollution control notes 576,000 576,000 ========== ========= Revolving credit agreement note - 50,000 Long-term notes due December 31, 1997 34,000 36,100 Various long-term notes 5,726 - CNG Transmission Corp. notes due November 10, 1996 and July 11, 1997 6,080 8,862 Obligations under capital leases 21,423 30,902 Unamortized premium and discount on debt, net (9,917) (10,776) ---------- ---------- 1,687,312 1,868,338 Less: debt due within one year-included in current liabilities 36,231 237,709 ---------- ---------- Total $1,651,081 $1,630,629 ========== ==========
At December 31, 1994, long-term debt and capital lease payments that will become due during the next five years are:
1995 1996 1997 1998 1999 (Thousands) $36,231 $16,138 $86,850 $31,414 $1,274
The company's mortgage provides for a sinking and improvement fund. This provision requires the company to make annual cash deposits with the Trustee equivalent to 1% of the principal amount of all bonds delivered and authenticated by the Trustee prior to January 1 of that year (excluding any bonds issued on the basis of the retirement of bonds). The company satisfied this requirement in 1994 by depositing $23 million in
cash that was used to redeem in February 1994 $23 million of 8 5/8% Series first mortgage bonds, due 2007. The company satisfied this requirement in 1995 by depositing $23 million in cash that was used to redeem in February 1995 $23 million of 9 7/8% Series first mortgage bonds, due February 2020.
Mandatory annual cash sinking fund requirements are $600,000 beginning June 1, 2001, for the 7 1/4% Series and $250,000 on December 1 in each year 1995 to 1996, for the 6 7/8% Series. The amount increases to $500,000 and $750,000 on December 1, 1997 and December 1, 2002, respectively, for the 6 7/8% Series.
The company's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all utility plant.
(1) Adjustable rate pollution control notes were issued to secure like amounts of tax-exempt adjustable rate pollution control revenue bonds (Adjustable Rate Revenue Bonds) issued by a governmental authority. The Adjustable Rate Revenue Bonds bear interest at the rate indicated through the date preceding the interest rate adjustment date. The adjustable rate pollution control notes bear interest at the same rate as the Adjustable Rate Revenue Bonds. On the interest rate adjustment date and annually thereafter (every three years thereafter in the case of the Adjustable Rate Revenue Bonds due July 1, 2026), the interest rate will be adjusted, not to exceed a rate of 15%, or at the option of the company, subject to certain conditions, a fixed rate of interest, not to exceed 18%, may become effective. In the case of the Adjustable Rate Revenue Bonds due July 1, 2026, at the option of the company, subject to certain conditions, a fixed rate of interest may become effective prior to the interest rate adjustment date or each third year thereafter. Bond owners may elect, subject to certain conditions, to have their Adjustable Rate Revenue Bonds purchased by the Trustee.
(2) Multi-mode pollution control notes were issued to secure like amounts of tax-exempt multi-mode pollution control refunding revenue bonds (Multi-mode Revenue Bonds) issued by a governmental authority. These Multi-mode Revenue Bonds have a structure that enables the company to optimize the use of short-term rates by allowing for the interest rates to be based on a commercial paper rate, a daily rate, a weekly rate or an auction rate. The structure also provides flexibility to convert the interest rates to term rates or fixed rates, in the event that it is in the company's best interest to do so. The multi-mode pollution control notes bear interest at the same rates as the Multi-mode Revenue Bonds. Bond owners may elect, while the Multi-mode Revenue Bonds bear interest at a daily rate or a weekly rate, to have their Multi-mode Revenue Bonds purchased by the Registrar and Paying Agent. The maturity date of the Multi-mode Revenue Bonds due February 1, 2029, June 1, 2029, and October 1, 2029, can be extended, subject to certain conditions, to a date not
later than February 1, 2034, June 1, 2034, and April 1, 2034, respectively. The weighted average interest rate for all three series (totaling $175 million principal amount) was 3.9%, excluding letter of credit fees, at December 31, 1994.
The company has irrevocable letters of credit that expire on the letter of credit expiration dates and that the company anticipates being able to extend if the interest rate on the related Adjustable Rate Revenue Bonds and Multi-mode Revenue Bonds is not converted to a fixed interest rate. Those letters of credit support certain payments required to be made on the Adjustable Rate Revenue Bonds and Multi-mode Revenue Bonds. If the company is unable to extend the letter of credit that is related to a particular series of Adjustable Rate Revenue Bonds, that series will have to be redeemed unless a fixed rate of interest becomes effective. Multi-mode Revenue Bonds are subject to mandatory purchase upon any change in the interest rate mode and in certain other circumstances. Payments made under the letters of credit in connection with purchases of Adjustable Rate Revenue Bonds and Multi-mode Revenue Bonds are repaid with the proceeds from the remarketing of such Bonds. To the extent the proceeds are not sufficient, the company is required to reimburse the bank that issued the letter of credit.
4 Preferred Stock
At December 31, 1994 and 1993, serial cumulative preferred stock was:
Shares Par Value Authorized Per Redeemable and Amount Series Share Prior to Per Share Outstanding(1) 1994 1993 (Thousands) Redeemable solely at the option of the company: 3.75% $100 $104.00 150,000 $15,000 $15,000 4 1/2%(1949) 100 103.75 40,000 4,000 4,000 4.15% 100 101.00 40,000 4,000 4,000 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 - - 25,000 8.48% 25 - - 25,000 7.40% (2) 25 12/1/98 26.85 1,000,000 25,000 25,000 Thereafter 25.00 Adjustable Rate 25 - - 45,000 Adjustable Rate (3) 25 12/1/98 27.50 2,000,000 50,000 50,000 Thereafter 25.00 -------- -------- 140,500 235,500 Less: preferred stock redemptions within one year - included in current liabilities - 95,000 -------- -------- Total $140,500 $140,500 ======== ========
Subject to mandatory redemption requirements:
6.30% (4) 100 1/1/96 105.04 250,000 $25,000 $25,000 8.95% (5) 25 1/1/96 26.64 4,000,000 100,000 100,000 -------- -------- Total $125,000 $125,000 ======== ========
At December 31, 1994, preferred stock redemptions and annual redeemable preferred stock sinking fund requirements for the next five years were:
1995 1996 1997 1998 1999 (Thousands) $ - $ - $5,000 $5,000 $5,000
(1) At December 31, 1994, there were 1,550,000 shares of $100 par value preferred stock, 3,800,000 shares of $25 par value preferred stock and 1,000,000 shares of $100 par value preference stock authorized but unissued.
(2) The company is restricted in its ability to redeem this Series prior to December 1, 1998.
(3) The payment on the Adjustable Rate Serial Preferred Stock, Series B, for April 1, 1995, is at an annual rate of 6.54% and subsequent payments can vary from an annual rate of 4% to 10%, based on a formula included in the company's Certificate of Incorporation. The company is restricted in its ability to redeem this Series prior to December 1, 1998.
(4) On January 1 in each year 2004 through 2008, the company must redeem 12,500 shares at par, and on January 1, 2009, the company must redeem the balance of the shares at par. This Series is redeemable at the option of the company at $105.04 per share prior to January 1, 1996. The $105.04 price will be reduced annually by 63 cents for the years ending 1996 through 2002; thereafter, the redemption price is $100.00. The company is restricted in its ability to redeem this Series prior to January 1, 2004.
(5) On January 1 in each year 1997 through 2016, the company must redeem 200,000 shares at par. This Series is redeemable at the option of the company at $26.64 per share prior to January 1, 1996. The $26.64 price will be reduced annually by 15 cents for the years ending 1996 through 1999; by 14 cents for the year ending 2000; and by 15 cents for the years ending 2001 through 2005. The company is restricted in its ability to redeem this Series prior to January 1, 1996.
5 Bank Loans and Other Borrowings
The company has a revolving credit agreement with certain banks that provides for borrowing up to $200 million to July 31, 1997. At the option of the company, the interest rate on borrowings is related to the prime rate, the London Interbank Offered Rate (LIBOR) or the interest rate applicable to certain certificates of deposit. The agreement also provides for the payment of a commitment fee that can fluctuate from .15% to .375%
depending upon the ratings of the company's first mortgage bonds. The commitment fee was .1875% at December 31, 1994 and 1993, and was .22% at December 31, 1992.
The company did not have any outstanding loans under the revolving credit agreement at December 31, 1994. At December 31, 1993, the company had an outstanding loan of $50 million under the revolving credit agreement at an interest rate of 4.06% under the LIBOR option. This loan was repaid in May 1994. The revolving credit agreement does not require compensating balances.
The company uses short-term unsecured notes, usually commercial paper, to finance certain refundings and for other corporate purposes. The weighted average interest rates on notes payable balances at December 31, 1994, 1993 and 1992 were 5.8%, 3.5% and 4.0%, respectively. At each year end, notes payable consisted of commercial paper with maturity dates of less than one year.
6 Restructuring
In the fourth quarter of 1993 the company recorded a $26 million restructuring charge. The corporate restructuring reorganized the way the company delivers services to its electric and natural gas customers beginning in March 1994. The restructuring reduced 1993 earnings available for common stock by approximately $17.2 million or 25 cents per share.
During the first quarter of 1994 the restructuring resulted in a workforce reduction totaling 642 persons throughout the organization, the elimination of customer walk-in services at 28 locations, and the closing of seven electric and natural gas operations facilities. The closing of additional electric and natural gas operations facilities will continue to be evaluated.
The workforce reduction of 642 employees, which was greater than the company's target of 600, was accomplished through a voluntary early retirement program (See Note 7) and an involuntary severance program. Of the 642 employees, 384 employees accepted the early retirement program and 258 employees were involuntarily severed. The company estimated the savings, excluding fringe benefits, related to the workforce reduction to be approximately $31.5 million, on an annual basis. As the workforce decreased, the company experienced savings in line with this estimate for 1994. The majority of these savings were used to minimize the company's electric and natural gas price increases in the second and third years of the rate settlement agreement.
7 Retirement Benefits
Pensions
The company has a noncontributory retirement annuity plan that covers substantially all employees. Benefits are based principally on the employee's length of service and compensation for the five highest paid consecutive years out of the last 10 years of service. It is the company's policy to fund pension costs accrued each year to the extent deductible for federal income tax purposes.
Effective January 1, 1993, the retirement benefit plans for hourly and salaried employees were combined into one plan. Combining the two plans did not affect benefit levels.
Net pension benefit for 1994, 1993 and 1992 included the following components:
1994 1993 1992 (Thousands) Service cost: Benefits earned during the year $17,637 $17,688 $15,387 Interest cost on projected benefit obligation 43,328 40,710 35,253 Actual return on plan assets (17,409) (77,129) (60,020) Net amortization and deferral (48,824) 12,989 7,844 -------- -------- -------- Net pension (benefit) $(5,268) $(5,742) $(1,536) ======== ======== ========
The funded status of the plan at December 31, 1994 and 1993 was: 1994 1993 (Thousands) Actuarial present value of accumulated benefit obligation:
Vested $410,732 $390,716 Nonvested 38,176 55,476 -------- -------- Total 448,908 446,192 ======== ========
Fair value of plan assets $733,661 $753,292 Actuarial present value of projected benefit obligation (597,398) (608,216) -------- -------- Plan assets in excess of projected benefit obligation 136,263 145,076 Unrecognized net transition asset (66,374) (73,612) Unrecognized net gain (92,851) (83,709) Unrecognized prior service cost 9,066 4,182 --------- -------- Net pension (liability) $(13,896) $(8,063) ========= ========
Plan assets primarily consist of equity securities; U.S. agency, corporate and Treasury bonds; and cash equivalents.
The projected benefit obligation was measured using an assumed discount rate of 7.75% for 1994, 7% for 1993 and 7.75% for 1992, and a long-term rate of increase in future compensation levels of 5.5% for 1994, 5% for 1993 and 6% for 1992. The net pension benefit was measured using an expected long-term rate of return on plan assets of 8% in 1994 and 1993, and 7.5% in 1992.
Early retirement
As part of the corporate restructuring that was announced in the fourth quarter of 1993 (See Note 6), the company offered a voluntary early retirement program from December 1, 1993, through January 21, 1994, to employees who were 55 years and older and who had at least 10 years of service with the company. The program included two provisions: an unreduced pension benefit for those eligible employees who were under 60 years old, and a monthly supplemental payment to "bridge" employees to age 62 when they can begin collecting Social Security benefits. 384 employees accepted the early retirement opportunity. In 1993 the company recorded a $19.9 million expense for the early retirement program. This was included in the total $26 million restructuring charge.
Postretirement benefits other than pensions
The company has postretirement benefit plans, such as a comprehensive health insurance plan and a prescription drug plan, that provide certain benefits for retired employees and their dependents. Substantially all of the company's employees who retire under the company's pension plan may become eligible for those benefits at retirement. At December 31, 1994, 1993 and 1992, 2,331, 1,996 and 1,905 retirees and their dependents, respectively, were covered under these plans. The postretirement benefit plans are unfunded as of December 31, 1994.
In January 1993 the company adopted Statement of Financial Accounting Standards No. 106 (SFAS 106), Employers' Accounting for Postretirement Benefits Other Than Pensions, which requires the company to accrue a liability for estimated future postretirement benefits during an employee's working career rather than recognize an expense when benefits are paid. At the time of adoption, the actuarially determined accumulated postretirement benefit obligation (APBO) was $206.6 million. The company elected to recognize the APBO over 20 years.
In September 1993 the PSC issued a Statement of Policy concerning the accounting and ratemaking treatment for pensions and postretirement benefits other than pensions (PSC Policy). The PSC Policy was effective January 1993, adopted SFAS 106 for accounting and ratemaking purposes, and complies with generally accepted accounting principles.
The postretirement benefits cost other than pensions recognized on the income statement for the twelve months ended December 31, 1994, 1993 and 1992, was $14.5 million, $11.4 million and $5 million, respectively. The amounts for 1994 and 1993 represent the portion of SFAS 106 costs that the company has been allowed to collect from its customers. The amount for the twelve months ended December 31, 1992 represents the postretirement benefits cost as determined prior to the adoption of SFAS 106, when the cost was not recognized as an expense until the benefits were paid. The company has deferred $10.4 million and $10.1 million of SFAS 106 costs as of December 31, 1994 and 1993, respectively. The company expects to recover any deferred SFAS 106 amounts in accordance with the PSC Policy.
The PSC Policy allows various rate mechanisms, including the use of excess pension fund assets, such as Internal Revenue Service Code of 1986 Section 420 transfers, to temper the effect of SFAS 106 on rates. In 1994 and 1993 the company transferred $6.1 million and $5 million, respectively, of its excess pension plan assets to cover most of the cost of retirees' health care for those years. As a result of these transfers, the company recognized a decrease in its deferred SFAS 106 asset.
The estimated net postretirement benefits cost other than pensions for the 12 months ended December 31, 1994 and 1993, included the following components:
1994 1993 (Thousands) Service cost: Benefits accumulated during the year $7,050 $6,888 Interest cost on accumulated postretirement benefit obligation 15,903 16,304 Amortization of transition obligation over 20 years 10,330 10,330 Amortization of loss 2 - Deferral for future recovery (18,757) (22,095) ------- ------- Net periodic postretirement benefits cost $14,528 $11,427 ======= =======
The status of the plans for postretirement benefits other than pensions, as reflected in the company's consolidated balance sheets at December 31, 1994 and 1993, are as follows:
1994 1993 (Thousands) Accumulated postretirement benefit obligation (APBO): Retired employees $112,311 $69,947 Fully eligible active plan participants 7,774 36,454 Other active plan employees 92,464 107,708 -------- -------- Total APBO 212,549 214,109 Less unrecognized transition obligation 185,937 196,268 Less unrecognized net gain (28,382) (10,233) -------- -------- Accrued postretirement liability $54,994 $28,074 ======== ========
An 11% annual rate of increase in the per capita costs of covered health care benefits was assumed for 1995, gradually decreasing to 5% by the year 2003. Increasing the assumed health care cost trend rates by 1% in each year would increase the APBO as of January 1, 1995, by $44.4 million and increase the aggregate of the service cost and interest cost components of the net postretirement benefits cost for 1994 by $5.0 million. A discount rate of 7.75% was used to determine the APBO.
8 Jointly-Owned Generating Stations
Nine Mile Point Unit 2
The company has an undivided 18% interest in the output and costs of the Nine Mile Point nuclear generating unit No. 2 (NMP2) which is operated by Niagara Mohawk Power Corporation (Niagara Mohawk). Ownership of NMP2 is shared with Niagara Mohawk 41%, Long Island Lighting Company 18%, Rochester Gas and Electric Corporation 14%, and Central Hudson Gas & Electric Corporation 9%. The company's share of the rated capability is 189,000 kilowatts. The company's net utility plant investment, excluding nuclear fuel, was approximately $638 million and $652 million, at December 31, 1994 and 1993, respectively. The accumulated provision for depreciation was approximately $120 million and $103 million, at December 31, 1994 and 1993, respectively. The company's share of operating expenses is included in the consolidated statements of income.
A low level radioactive waste management and contingency plan for NMP2 provides assurance that NMP2 is properly prepared to handle interim storage of low level radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of Energy (DOE) for disposal of high level radioactive waste (spent fuel) from NMP2. The company is reimbursing Niagara Mohawk for its 18% share of the cost under the contract (currently approximately $1 per megawatt hour of net generation). The DOE's schedule for start of operations of their high level radioactive waste repository has slipped from 2003 to no sooner than 2010. The company has been advised by Niagara Mohawk that the NMP2 Spent Fuel Storage Pool has a capacity for spent fuel that is adequate until 2014. If further DOE schedule slippage should occur, construction of pre-licensed dry storage facilities would extend the on-site storage capability for spent fuel at NMP2 beyond 2014.
Nuclear insurance
Niagara Mohawk maintains public liability and property insurance for NMP2. The company reimburses Niagara Mohawk for its 18% share of those costs.
The public liability limit for a nuclear incident is approximately $8.3 billion. Should losses stemming from a nuclear incident exceed the commercially available public liability insurance, each licensee of a nuclear facility would be liable for up to a maximum of $75.5 million per incident, payable at a rate not to exceed $10 million per year. The company's maximum liability for its 18% interest in NMP2 would be approximately $13.6 million per incident. The $75.5 million
assessment is subject to periodic inflation indexing and a 5% surcharge should funds prove insufficient to pay claims associated with a nuclear incident. The Price-Anderson Act also requires indemnification for precautionary evacuations whether or not a nuclear incident actually occurs.
Niagara Mohawk maintains nuclear property insurance for NMP2 and is reimbursed by the company for its 18% interest. Niagara Mohawk has procured property insurance aggregating approximately $2.8 billion through the Nuclear Insurance Pools and the Nuclear Electric Insurance Limited (NEIL). In addition, the company has purchased NEIL insurance coverage for the extra expense incurred in purchasing replacement power during prolonged accidental outages. Under NEIL programs, should losses resulting from an incident at a member facility exceed the accumulated reserves of NEIL, each member, including the company, would be liable for its share of the deficiency. The company's maximum liability per incident under the property damage and replacement power coverages is approximately $2.5 million.
Nuclear plant decommissioning costs
In May 1993 the Nuclear Regulatory Commission (NRC) updated labor, energy and burial cost factors for determining the minimum funding requirement for nuclear decommissioning. As a result, the company's 18% share of the cost to decommission NMP2 is estimated to be $234 million in 2027, when decommissioning is expected to commence ($76 million in 1994 dollars). A preliminary estimate from Niagara Mohawk indicates that the cost to decommission NMP2 is greater than this amount. Niagara Mohawk has advised the company that in 1995 it expects to perform a detailed study to update the cost to decommission NMP2. The company plans to revise its estimate of the cost to decommission NMP2 after Niagara Mohawk completes its study.
The company's annual decommissioning allowance currently included in electric rates is approximately $1.6 million and is sufficient to recover the NRC's minimum funding requirement. These costs are charged to depreciation and amortization expense and are recovered over the expected life of the plant. The company believes that any increase in decommissioning costs will ultimately be recovered in rates.
The company has established a Qualified Fund under applicable provisions of the federal tax law. The fund also complies with the NRC regulations that require the use of an external trust fund to provide funds to decommission the contaminated portion of NMP2. The balance in this fund, including reinvested earnings, was approximately $7.4 million and $5.7 million at December 31, 1994 and 1993, respectively. These amounts are included on the consolidated balance sheets in other property and investments, net. The related liability for
decommissioning is included in deferred credits and other liabilities - other. At December 31, 1994, the external trust fund investments were primarily debt securities, classified as available-for-sale, and their carrying value approximated fair value.
The Financial Accounting Standards Board is currently reviewing the accounting for obligations for decommissioning of nuclear power plants, including the balance sheet presentation of estimated decommissioning costs.
Homer City
The company has an undivided 50% interest in the output and costs of the Homer City Generating Station, which is comprised of three generating units. The station is owned with Pennsylvania Electric Company, which operates the facility. The company's share of the rated capability is 950,000 kilowatts and its net utility plant investment was approximately $265 million and $258 million at December 31, 1994 and 1993, respectively. The accumulated provision for depreciation was approximately $153 million and $159 million, at December 31, 1994 and 1993, respectively. The company's share of operating expenses is included in the consolidated statements of income.
9 Commitments and Contingencies
Capital expenditures
The company has substantial commitments in connection with its capital expenditure program and estimates that expenditures for 1995, 1996 and 1997 will approximate $188 million, $264 million and $184 million, respectively. The program is subject to periodic review and revision. Actual capital expenditures may change to reflect the imposition of additional regulatory requirements and the company's continued focus on optimizing capital expenditures. Capital expenditures will be primarily for extension of service, necessary improvements at existing facilities, the natural gas storage project, compliance with the Clean Air Act Amendments of 1990 (1990 Amendments) and other environmental requirements.
The 1990 Amendments will result in expenditures of approximately $174 million, on a present value basis, over a 25- year period, for all capital and operating and maintenance expenses related to the reduction of sulfur dioxide and nitrogen oxides at several of the company's coal-fired generating stations, of which $106.5 million had been incurred as of December 31, 1994. The cost to comply with the sulfur dioxide and nitrogen oxide limitations includes the construction of an innovative flue gas desulfurization (FGD) system and a nitrogen oxide reduction system that was recently completed at the
company's Milliken Generating Station. The company estimates that approximately a 1% electric rate increase will be required for the cost of reducing sulfur dioxide and nitrogen oxide emissions in both Phase I (which began on January 1, 1995) and Phase II (begins January 1, 2000), as discussed below. In addition, the company anticipates that it will have to significantly reduce its nitrogen oxide emissions even further by the year 2003, which includes an interim reduction in the year 1999, as a result of proposed U.S. Environmental Protection Agency (EPA) regulations. The cost to comply with these proposed regulations cannot be estimated at this time, since the reduction will be based on additional research scheduled to be completed later in the decade. As a result of the 1990 Amendments, the company plans to reduce its annual sulfur dioxide emissions by an amount that will allow the company to meet the sulfur dioxide levels established for the company, which are approximately a 49% reduction from approximately 138,000 tons in 1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990 Amendments, if required, cannot be estimated at this time, since the type and level of reductions that may be required is dependent on a study currently being performed by the EPA, which is scheduled to be completed by the end of 1995. Regulations may be adopted at the state level that would limit toxic emissions even further, at an additional cost to the company. The company anticipates that the costs incurred to comply with the 1990 Amendments will be recoverable through rates based on previous rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual emissions allowances to each of the company's coal-fired generating stations based on statutory emissions limits. An emissions allowance represents an authorization to emit, during or after a specified calendar year, one ton of sulfur dioxide. During Phase I, the company estimates that it will have allowances in excess of the affected coal-fired generating stations' actual emissions. The company's present strategy is to bank these allowances for use in later years. By using a banking strategy, it is estimated that Phase II allowance requirements will be met through the year 2005 by utilizing the allowances banked during Phase I, which includes the extension reserve allowances discussed below, together with the company's Phase II annual emissions allowances. This strategy could be modified should market or business conditions change. In addition to the annual emissions allowances allocated to the company by the EPA, the company has received a portion of the extension reserve allowances issued by the EPA to utilities electing to build scrubbers in Phase I, as a result of a pooling agreement that it entered into with other utilities who were also eligible to receive some of these extension reserve allowances.
As a result of existing and new solid waste disposal legislation and regulations in Pennsylvania, the company will incur approximately $28 million, on a present value basis, of additional costs over the next 30 years at the Homer City Generating Station. The majority of these costs will be incurred over the next 10 years to install new equipment, modify or replace existing equipment, and improve the design of a proposed expansion of disposal facilities. The company expects to recover these expenditures in rates, since the company has been allowed by the PSC to recover similar costs in rates, such as groundwater protection costs to meet permit conditions and regulatory requirements.
Long-term power purchase contracts
The company is currently required to purchase 594 megawatts (mw) of NUG power. The company is required to make payments under these contracts only for the power it receives or when the company directs the NUG to reduce its output under the terms of the contract. Two contracts the company has with NUGs each provide more than 5% of current system capability. One contract provides for 177 mw or 5.4%, and the other provides for 240 mw or 7.3%. During 1994, 1993 and 1992 the company purchased approximately $214 million, $138 million and $71 million, respectively, of NUG power, including termination costs. The company estimates that NUG power purchases, excluding termination costs, over the next five years will be as follows:
1995 1996 1997 1998 1999 (Millions) $274 $312 $322 $333 $344
Increases in the cost of NUG power purchases will contribute significantly to expected electric price increases in August 1995.
Coal purchasing contracts
The company has long-term contracts with nonaffiliated mining companies for the purchase of coal for the jointly-owned Homer City Generating Station. The contracts, which expire between 1995 and the end of the expected service life of the generating station, require the purchase of either fixed or minimum amounts of the station's coal requirements. The contracts are based on fixed price plus escalation provisions. The company's share of the cost of coal purchased under these agreements is expected to aggregate $52 million, $53 million and $55 million for the years 1995, 1996 and 1997, respectively.
In addition, the company has a long-term contract for the purchase of coal for the Kintigh and Milliken Generating Stations. The contract, which expires in 2003, supplies the
annual coal requirements of the Kintigh station. One-third of the tonnage price is renegotiated annually to reflect market conditions. The contract also supplies the requirements of the Milliken station for the years 1995-1997. The delivered cost of coal purchased under this agreement is expected to be $76 million, $78 million, and $81 million for the years 1995, 1996 and 1997, respectively.
10 Environmental Liability
The company continually assesses actions that may need to be taken to ensure compliance with changing environmental laws and regulations. Any additional compliance programs will increase the cost of electric and natural gas service by requiring changes in the company's operations and facilities. Historically, rate recovery has been authorized for the cost incurred to comply with environmental laws and regulations.
Due to existing and proposed legislation and regulations, and legal proceedings commenced by governmental bodies and others, the company may also incur costs from the past disposal of hazardous substances produced during the company's operations or those of its predecessors. The company has been notified by the EPA and the New York State Department of Environmental Conservation (NYSDEC), as appropriate, that it is among the potentially responsible parties (PRPs) who may be liable to pay for costs incurred to remediate certain hazardous substances at eight waste sites, not including the company's inactive gas manufacturing sites, which are discussed below. With respect to the eight sites, six sites are included in the New York State Registry of Inactive Hazardous Waste Sites (New York State Registry) and two of those sites are also included on the National Priorities list.
Any liability may be joint and several for certain of these sites. The company has recorded a liability related to four of these eight sites, which is reflected in the company's consolidated balance sheets at December 31, 1994, in the amount of $1.1 million. The ultimate cost to remediate these sites may be significantly more than this amount and will be dependent on such factors as the remedial action plan selected, the extent of site contamination, and the portion attributed to the company. The company has notified the EPA and the NYSDEC, as appropriate, that it believes it has no responsibility at three sites and has already incurred expenditures related to the remediation at the remaining site. A deferred asset has also been recorded in the amount of $2.1 million, of which $1.0 million relates to costs that have already been incurred. The company believes it will recover these costs, since the PSC has allowed other utilities to recover these types of remediation costs and has allowed the company to recover similar costs in rates, such as investigation and cleanup costs relating to inactive gas manufacturing sites.
The estimated liability of $1.1 million was derived by multiplying the total estimated cost to clean up a particular site by the related company contribution factor. Estimates of the total cleanup costs were determined by using information related to a particular site, such as investigations performed to date at a site or from the data released by a regulatory agency. In addition, this estimate was based upon currently available facts, existing technology, and presently enacted laws and regulations. The contribution factor is calculated using either the company's percentage share of the total PRPs named, which assumes all PRPs will contribute equally, or the company's estimated percentage share of the total hazardous wastes disposed of at a particular site, or by using a 1% contribution factor for those sites at which it believes that it has contributed a minimal amount of hazardous wastes. The company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
A number of the company's inactive gas manufacturing sites have been listed in the New York State Registry. In late March 1994 the company entered into an Order on Consent with the NYSDEC requiring the company to investigate and, where necessary, remediate 33 of the company's 38 known inactive gas manufacturing sites. The schedule for investigating and remediating these 33 sites will be determined through further negotiations with the NYSDEC. The company has a program to investigate and initiate necessary remediation at its 38 known inactive gas manufacturing sites. Expenditures through the year 2009 are estimated at $32.5 million, including the impact of the Order on Consent. This estimate was determined by using the company's experience and knowledge related to these sites as a result of the investigation and remediation that the company has performed to date. It is based upon currently available facts, existing technology, and presently enacted laws and regulations. This liability to investigate and initiate remediation, as necessary, at the known inactive gas manufacturing sites, is reflected in the company's consolidated balance sheets at December 31, 1994 and 1993 in the amount of $32.5 million and $25 million, respectively. The company also has recorded a corresponding deferred asset, since it expects to recover such expenditures in rates, as the company has previously been allowed by the PSC to recover such costs in rates. The PSC has asked its staff to prepare a recommendation on a generic policy for these types of expenditures by the spring of 1995. The company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the company is unable to predict the amount of insurance recoveries, if any, that it may obtain.
11 Federal Energy Regulatory Commission (FERC) Order 636
FERC Order 636 became effective in November 1993 and requires interstate natural gas pipeline companies to offer customers unbundled, or separate, services equivalent to their former sales service. With the unbundling of services, primary responsibility for reliable natural gas supply has shifted from interstate pipeline companies to local distribution companies, such as the company. FERC Order 636 has substantially restructured the interstate natural gas market.
As a result of the restructuring of services required by FERC Order 636, pipelines have incurred and will continue to incur transition costs. These include the costs of restructuring existing natural gas supply contracts, unrecovered costs that would otherwise have been billable to pipeline customers under previously existing rules and costs of assets needed to implement the order. FERC Order 636 allows pipelines to recover all prudently incurred costs from their customers.
The company's liability for transition costs is based on the pipelines' filings with the FERC to recover such costs. The company has reached a final resolution with one of its pipeline suppliers regarding transition costs and is currently negotiating with its other pipeline suppliers. Final resolution of the issue may not occur for several years. The company's estimated liability for transition costs was $21 million and $29 million at December 31, 1994 and 1993, respectively. The company has recorded a corresponding deferred asset, since it has been recovering transition costs from its customers through its gas adjustment clause and believes that such costs will continue to be recoverable from its customers.
12 Diversified Operations
In April 1992 the PSC issued an order allowing the company to invest up to 5% of its consolidated capitalization (approximately $180 million at December 31, 1994) in one or more subsidiaries that may engage or invest in energy-related or environmental-services businesses and provide related services.
The company has been making investments in unregulated companies through its wholly owned subsidiary, NGE Enterprises, Inc. (NGE). NGE owns two unregulated businesses - EnerSoft Corporation (EnerSoft) and XENERGY, Inc. (XENERGY).
EnerSoft, a computer software company, was formed in May 1993 to produce and market software for natural gas utilities, marketers and pipeline operators. Through an alliance with the New York Mercantile Exchange, EnerSoft is developing Channel 4, a natural gas and pipeline capacity trading and information system for the North American market. While development of the system
has taken longer than anticipated, Channel 4 is expected to be commercially available in the spring of 1995. Like most other start-up companies, EnerSoft has been incurring operating losses. The company expects that EnerSoft will continue to incur operating losses in the near term.
In June 1994 NGE acquired all of the outstanding stock of XENERGY, an energy services, information systems and energy- consulting company that specializes in energy management, conservation engineering and demand-side management. XENERGY currently provides a broad range of services to utilities throughout the United States, Canada, Spain and France. It also provides energy services, conservation engineering and DSM services to governmental agencies at both the state and federal levels, and to a large number of end users.
As of December 31, 1994 and 1993, the company had invested approximately $47 million and $3 million, respectively, in NGE to finance its diversified investments. The majority of this investment is included in other property and investments, net on the consolidated balance sheets. NGE's total liabilities and capitalization at December 31, 1994 and 1993 was approximately $52 million and $7 million, respectively. For the years ended December 31, 1994 and 1993, NGE incurred net losses of $6.0 million and $1.4 million, respectively, which are included in other income and deductions on the consolidated statements of income.
13 Fair Value of Financial Instruments
The estimated fair values of the company's financial instruments at December 31, 1994 and 1993, were as follows:
Carrying Amount Fair Value 1994 1993 1994 1993 (Thousands) First mortgage bonds $1,044,083 $1,166,779 $1,010,239 $1,274,883 Pollution control notes $576,000 $575,695 $484,005 $581,928 Preferred stock subject to mandatory redemption requirements $125,000 $125,000 $127,875 $134,000
The fair value of the company's first mortgage bonds, pollution control notes and preferred stock is estimated based on the quoted market prices for the same or similar issues of the same remaining maturities.
The carrying amount for the following items approximates estimated fair value because of the short maturity (within one year) of those instruments: cash and cash equivalents, notes payable, and interest accrued.
Special deposits include restricted funds that are set aside for preferred stock and long-term debt redemptions. Special deposits also include restricted funds that are used to finance a portion of the costs incurred in the construction of certain solid waste disposal and other related facilities. The carrying amount approximates fair value because the special deposits have been invested in securities with a short-term maturity (within one year).
The carrying amount of the revolving credit agreement note outstanding at December 31, 1993 approximated fair value because its pricing was based on short-term interest rates.
14 Industry Segment Information
Certain information pertaining to the electric and natural gas operations of the company follows:
1994 1993 1992 Natural Natural Natural Electric Gas Electric Gas Electric Gas (Thousands) Operating Revenues $1,600,075 $298,780 $1,527,362 $272,787 $1,451,525 $240,164 Expenses $1,306,871 $269,300 $1,250,000 $249,493 $1,146,619 $221,307 Income $293,204 $29,480 $277,362 $23,294 $304,906 $18,857 Depreciation and amortization* $167,484 $10,842 $155,231 $9,337 $150,549 $8,428 Capital expenditures $183,910 $40,396 $208,576 $36,453 $210,185 $35,433 Identifiable assets** $4,623,731 $486,075 $4,627,905 $458,596 $4,540,724 $377,424
* Included in operating expenses. ** Assets used in both electric and natural gas operations not included above were $113,099, $201,457 and $159,768 at December 31, 1994, 1993 and 1992, respectively. They consist primarily of cash and cash equivalents, special deposits and prepayments.
15 Quarterly Financial Information (Unaudited)
Quarter ended March 31 June 30 Sept. 30 Dec. 31 (Thousands, except per share amounts) Operating revenues $565,167 $388,639(1) $432,451 $512,598 Operating income $119,990 $47,784 $63,351 $91,559 Net income $84,693 $12,395(1) $30,953 $59,604 Earnings available for common stock $79,834 $7,745 $26,251 $54,868 Earnings per share $1.13 $.11(1) $.37 $.77 Dividends per share $.55 $.55 $.55 $.35 Average shares outstanding 70,801 71,214 71,490 71,503 Common stock price* High $30.50 $27.88 $25.88 $19.75 Low $26.50 $23.25 $18.38 $17.75
Operating revenues $522,383 $388,601 $396,410 $492,755 Operating income $109,893 $56,649 $66,108 $68,006 Net income $74,039 $21,500 $32,541 $37,948(2) Earnings available for common stock $68,838 $16,299 $27,340 $32,913 Earnings per share $.99 $.23 $.39 $.47(2) Dividends per share $.54 $.54 $.55 $.55 Average shares outstanding 69,561 69,836 70,119 70,431 Common stock price* High $35.13 $36.50 $36.25 $35.50 Low $31.63 $32.13 $34.63 $28.75
(1) Second quarter 1994 results include the company's change in estimate for the 1993 production cost penalty of $13 million or 12 cents per share.
(2) Fourth quarter 1993 results reflect the effects of restructuring expenses, which decreased net income and earnings for common stock by $17.2 million and decreased earnings per share by 24 cents.
* The company's common stock is listed on the New York Stock Exchange. The number of shareholders of record at December 31, 1994, was 56,279.
Dividend Limitations: After dividends on all outstanding preferred stock have been paid, or declared, and funds set apart for their payment, the common stock is entitled to cash dividends as may be declared by the board of directors out of retained earnings accumulated since December 31, 1946. Common Stock dividends are limited if common stock equity (46% at December 31, 1994) falls below 25% of total capitalization, as defined in the company's Certificate of Incorporation. Dividends on common stock cannot be paid unless sinking fund requirements of the preferred stock are met. The company has not been restricted in the payment of dividends on common stock by these provisions. Retained earnings accumulated since December 31, 1946, were approximately $347 million and $320 million as of December 31, 1994 and 1993, respectively.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors New York State Electric & Gas Corporation and Subsidiaries Ithaca, New York
We have audited the consolidated financial statements and the financial statement schedule of New York State Electric & Gas Corporation and Subsidiaries listed in Item 14(a) of this Form 10-K. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule 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 consolidated financial position of New York State Electric & Gas Corporation and Subsidiaries as of December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
As discussed in Note 7 to the consolidated financial statements, the Company and Subsidiaries changed its method of accounting for postretirement benefits other than pensions in 1993.
COOPERS & LYBRAND L.L.P.
New York, New York January 27, 1995
Item 9.
Item 9. Changes in and disagreements with accountants on accounting and financial disclosure - None
PART III
Item 10.
Item 10. Directors and executive officers of the Registrant
Incorporated herein by reference to the information under the caption "Election of Directors" and "Secton 16 Compliance" in the Company's Proxy Statement dated March 31, 1995. The information regarding executive officers is on pages 26-27 of this report.
Item 11.
Item 11. Executive compensation
Incorporated herein by reference to the information under the captions "Executive Compensation," "Employment and Change in Control Arrangements," "Directors' Compensation," "Report of Executive Compensation and Succession Committee on Executive Compensation" and "Stock Performance Graph" in the Company's Proxy Statement dated March 31, 1995.
Item 12.
Item 12. Security ownership of certain beneficial owners and management
Incorporated herein by reference to the information under the caption "Security Ownership of Certain Beneficial Owners and Management" in the Company's Proxy Statement dated March 31, 1995.
Item 13.
Item 13. Certain relationships and related transactions
Incorporated herein by reference to the information under the caption "Election of Directors" in the Company's Proxy Statement dated March 31, 1995.
PART IV
Item 14.
Item 14. Exhibits, financial statement schedules, and reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial statements Included in Part II of this report: a) Consolidated Balance Sheets as of December 31, 1994 and 1993 b) For the three years ended December 31, 1994: Consolidated Statements of Income Consolidated Statements of Cash Flows Consolidated Statements of Changes in Common Stock Equity c) Notes to Consolidated Financial Statements d) Report of Independent Accountants 2. Financial statement schedules Included in Part II of this report: For the three years ended December 31, 1994: II. Allowance for Doubtful Accounts - Accounts Receivable
Schedules other than those listed above have been omitted since they are not required, are inapplicable or the required information is presented in the Consolidated Financial Statements or notes thereto.
3. Exhibits (a)(1) The following exhibits are delivered with this report:
Exhibit No. (A) 10-18 - Supplemental Executive Retirement Plan Amendment No. 1. (A) 10-31 - Annual Executive Incentive Compensation Plan Amendment No. 3. (A) 10-32 - Annual Executive Incentive Compensation Plan Amendment No. 4. (A) 10-41 - Agreement with M. I. German. 12 - Computation of Ratio of Earnings to Fixed Charges. 21 - Subsidiaries. 23 - Consent of Coopers & Lybrand to incorporation by reference into certain registration statements. 27 - Financial Data Schedule. 99-1 - Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Salaried Employees. 99-2 - Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Hourly Paid Employees.
(a)(2) The following exhibits are incorporated herein by reference: Exhibit No. Filed in As Exhibit No. 3-1 - Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988 - Registration No. 33-50719 . . . 4-11 3-2 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989 - Registration No. 33-50719 . . 4-12 3-3 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990 - Registration No. 33-50719 . . . . . . . . . . . . . 4-13 3-4 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990 - Registration No. 33-50719 . . 4-14 3-5 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991 - Registration No. 33-50719 . . 4-15 3-6 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991 - Registration No. 33-50719 . . 4-16 3-7 - Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991 - Registration No. 33-50719 . . . . . . . . . . . . . . . . . . . 4-20 3-8 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992 - Registration No. 33-50719 . . . . 4-17 ______________________________ (A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
3-9 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992 - Registration No. 33-50719 . . . 4-18 3-10 - Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993 Registration No. 33-50719 . . . . . . . . . . . . . . 4-19 3-11 - Certificate of Amendment of the Certificate of Incor- poration filed in the Office of the Secretary of State of the State of New York on December 10, 1993 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-11 3-12 - Certificate of Amendment of the Certificate of Incor- poration filed in the Office of the Secretary of State of the State of New York on December 20, 1993 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-12 3-13 - Certificate of Amendment of the Certificate of Incor- poration filed in the Office of the Secretary of State of the State of New York on December 20, 1993 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-13 3-14 - Certificates of the Secretary of the Company concern- ing consents dated March 20, 1957 and May 9, 1975 of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness - Registration No. 2-69988. . . . . . . . . . . . . . 4-7 3-15 - By-Laws of the Company as amended February 25, 1994 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-15 4-1 - First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (Chemical Bank is Successor Trustee) - Registration No. 33-4186 . . . 4-1
Supplemental Indentures to First Mortgage dated as of July 1, 1921: 4-2 - No. 37 - Registration No. 33-31297. . . . . . . . . 4-2 4-3 - No. 39 - Registration No. 33-31297. . . . . . . . . 4-3 4-4 - No. 43 - Registration No. 33-31297. . . . . . . . . 4-4 4-5 - No. 51 - Registration No. 2-59840 . . . . . . . . . 2-B(46) 4-6 - No. 68 - Registration No. 2-59840 . . . . . . . . . 2-B(63) 4-7 - No. 69 - Registration No. 2-59840 . . . . . . . . . 2-B(64) 4-8 - No. 71 - Registration No. 2-59840 . . . . . . . . . 2-B(66) 4-9 - No. 74 - Registration No. 2-59840 . . . . . . . . . 2-B(69) 4-10 - No. 75 - Registration No. 2-59840 . . . . . . . . . 2-B(70) 4-11 - No. 80 - Registration No. 2-59840 . . . . . . . . . 2-B(75) 4-12 - No. 81 - Registration No. 2-59840 . . . . . . . . . 2-B(76) 4-13 - No. 83 - Registration No. 2-65948 . . . . . . . . . 2-B(78) 4-14 - No. 102- Registration No. 33-33838. . . . . . . . . 4-8 4-15 - No. 103- Registration No. 33-43458. . . . . . . . . 4-8 4-16 - No. 104- Registration No. 33-43458. . . . . . . . . 4-9
4-17 - No. 105- Registration No. 33-52040. . . . . . . . . 4-8 4-18 - No. 106- Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . 4-23 4-19 - No. 107- Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . 4-24 4-20 - No. 108- Registration No. 33-50719. . . . . . . . . 4-8 4-21 - No. 109- Registration No. 33-50719. . . . . . . . . 4-9
Agreements and amendments with the Power Authority of the State of New York:
Exhibit No. Filed in As Exhibit No.
10-1 - Letter Agreement dated February 3, 1982 relating to transmission services - Registration No. 2-82192. . 10-1 10-2 - Amendment dated December 21, 1989 to the Letter Agreement dated February 3, 1982 relating to trans- mission services - Company's 10-K for year ended December 31, 1989 - File No. 1-3103-2 . . . . . . 10-4 10-3 - Transmission Agreement dated December 12, 1983, with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2 . . . . 10-6 10-4 - Amendment dated December 21, 1989 to the Transmission Agreement dated December 12, 1983 with respect to connection of the Company's Kintigh (Somerset) Gener- ating Station to the Niagara-Edic 345 kv transmission system - Company's 10-K for the year ended December 31, 1989 File No. 1-3103-2. . . . . . . . . . . . . 10-7
* * * * * * * * * *
10-5 - New York Power Pool Agreement dated July 11, 1985 - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-7 10-6 - Transmission Agreement dated January 10, 1990 between New York State Electric & Gas Corporation and Niagara Mohawk Power Corporation, with respect to remote load and generation wheeling service for the Company - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-17 10-7 - Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-14
Exhibit No. Filed in As Exhibit No.
10-8 - Amendment No. 1 dated as of October 1, 1985 to the Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1986 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-11 10-9 - Amendment No. 2 dated as of August 28, 1986 to the Coal Sales Agreement dated December 21, 1983 between the Company and Consolidation Coal Company - Company's 10-K for year ended December 31, 1986 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-12 10-10 - Basic Agreement dated as of September 22, 1975 between New York State Electric & Gas Corporation and others concerning Nine Mile Point Nuclear Station, Unit No. 2 - Registration No. 2-54903. . . 5-0 10-11 - Nine Mile Point Nuclear Station Unit 2 Operating Agreement effective as of January 1, 1993 among New York State Electric & Gas Corporation and others - Company's 10-K for the year ended December 31, 1992 - File No. 1-3103-2 . . . . . . . 10-18 10-12 - Coal Hauling Agreement dated as of March 9, 1983 between Somerset Railroad Corporation and New York State Electric & Gas Corporation - Registration No. 2-82352. . . . . . . . . . . . . . 10 (A)10-13 - Retirement Plan for Directors - Company's 10-K for the year ended December 31, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-26 (A)10-14 - Retirement Plan for Directors Amendment No. 1 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-21 (A)10-15 - Form of Deferred Compensation Plan for Directors - Company's 10-K for year ended December 31, 1989 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-22 (A)10-16 - Deferred Compensation Plan for Directors Amendment No. 1 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . 10-23 (A)10-17 - Supplemental Executive Retirement Plan - Company's 10-Q for quarter ended March 31, 1994 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-49
______________________________ (A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
(A)10-19 - Supplemental Executive Retirement Plan Amendment No. 2 - Company's 10-K for year ended December 31, 1987 - File No. 1-3103-2. . . . . . . . . . . . 10-19 (A)10-20 - Supplemental Executive Retirement Plan Amendment No. 3 - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . 10-24 (A)10-21 - Supplemental Executive Retirement Plan Amendment No. 4 - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-30 (A)10-22 - Supplemental Executive Retirement Plan Amendment No. 5 - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-31 (A)10-23 - Supplemental Executive Retirement Plan Amendment No. 6 - Company's 10-Q for quarter ended March 31, 1991 - File No. 1-3103-2. . . . . . . . . . . . . . 10-37 (A)10-24 - Supplemental Executive Retirement Plan Amendment No. 7 - Company's 10-Q for quarter ended June 30, 1992 - File No. 1-3103-2. . . . . . . . . . . . . . 10-44 (A)10-25 - Supplemental Executive Retirement Plan Amendment No. 8 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-32 (A)10-26 - Supplemental Executive Retirement Plan Amendment No. 9 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-33 (A)10-27 - Supplemental Executive Retirement Plan Amendment No. 10 - Company's 10-Q for quarter ended June 30, 1994 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-50 (A)10-28 - Annual Executive Incentive Compensation Plan. Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-30 (A)10-29 - Annual Executive Incentive Compensation Plan Amendment No. 1 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . 10-35 (A)10-30 - Annual Executive Incentive Compensation Plan Amendment No. 2 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . 10-36 (A)10-33 - Performance Share Plan - Company's 10-K for year ended December 31, 1990 - File No. 1-3103-2 . . . . 10-36 (A)10-34 - Performance Share Plan Amendment No. 1 - Company's 10-Q for quarter ended March 31, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-38 (A)10-35 - Performance Share Plan Amendment No. 2 - Company's 10-Q for quarter ended June 30, 1991 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-39 (A)10-36 - Performance Share Plan Amendment No. 3 - Company's 10-K for year ended December 31, 1992 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-34 (A)10-37 - Performance Share Plan Amendment No. 4 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-41 (A)10-38 - Performance Share Deferred Compensation Plan - Company's 10-K for year ended December 31, 1991 File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-40 ______________________________ (A) Management contract or compensatory plan or arrangement.
(A)10-39 - Performance Share Deferred Compensation Plan - Amendment No. 1 - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . 10-43 (A)10-40 - Employment Contract for A. E. Kintigh - Company's 10-K for year ended December 31, 1988 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . 10-26 (A)10-42 - Employment Agreement for J. A. Carrigg - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . . . . . . . . . . . 10-46 (A)10-43 - Form of Severance Agreement for Senior Vice Presidents - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . 10-47 (A)10-44 - Form of Severance Agreement for Vice Presidents - Company's 10-K for year ended December 31, 1993 - File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-48
The Company agrees to furnish to the Commission, upon request, a copy of the Revolving Credit Agreement dated as of July 31, 1992, between the Company, Chemical Bank, as Agent, and certain banks; a copy of the Participation Agreements dated as of June 1, 1987 and December 1, 1988 between the Company and New York State Energy Research and Development Authority (NYSERDA) relating to Adjustable Rate Pollution Control Revenue Bonds (1987 Series A), and (1988 Series A), respectively; a copy of the Participation Agreements dated as of March 1, 1985, October 15, 1985, and December 1, 1985 between the Company and NYSERDA relating to Annual Tender Pollution Control Revenue Bonds (1985 Series A), (1985 Series B), and (1985 Series D), respectively; a copy of the Participation Agreements dated as of February 1, 1993, February 1, 1994, June 1, 1994, October 1, 1994 and December 1, 1994 between the Company and NYSERDA relating to Pollution Control Refunding Revenue Bonds (1994 Series A), (1994 Series B), (1994 Series C), (1994 Series D), and (1994 Series E), respectively; a copy of the Participation Agreement dated as of December 1, 1993 between the Company and NYSERDA relating to Solid Waste Disposal Revenue Bonds (1993 Series A); a copy of the participation agreement dated as of December 1, 1994 between the company and the Indiana County Industrial Development Authority relating to Pollution Control Refunding Revenue Bonds (1994 Series A); a copy of the Credit Agreement dated as of March 9, 1983, as amended, between Somerset Railroad Corporation and Chemical Bank, and a copy of the Revolving Credit Agreement dated as of June 30, 1994, as amended, between Xenergy Inc. and The First National Bank of Boston. The total amount of securities authorized under each of such agreements does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
(b) Reports on Form 8-K
A report on Form 8-K, dated October 11, 1994, was filed during the fourth quarter of 1994 to report certain information under Item 5, "Other Events."
______________________________ (A) Management contract or compensatory plan or arrangement.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Date: March 10, 1995 By Gary J. Turton Gary J. Turton Controller (Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
PRINCIPAL EXECUTIVE OFFICER
Date: March 10, 1995 By James A. Carrigg James A. Carrigg Chairman, President, Chief Executive Officer and Director
PRINCIPAL FINANCIAL OFFICER
Date: March 10, 1995 By Sherwood J. Rafferty Sherwood J. Rafferty Vice President and Treasurer
PRINCIPAL ACCOUNTING OFFICER
Date: March 10, 1995 By Gary J. Turton Gary J. Turton Controller
Signatures (Cont'd)
Date: March 10, 1995 By Alison P. Casarett Alison P. Casarett Director
Date: March 10, 1995 By Everett A. Gilmour Everett A. Gilmour Director
Date: March 10, 1995 By Paul L. Gioia Paul L. Gioia Director
Date: March 10, 1995 By John M. Keeler John M. Keeler Director
Date: March 10, 1995 By Allen E. Kintigh Allen E. Kintigh Director
Date: March 10, 1995 By Ben E. Lynch Ben E. Lynch Director
Date: March 10, 1995 By Alton G. Marshall Alton G. Marshall Director
Date: March 10, 1995 By David R. Newcomb David R. Newcomb Director
Date: March 10, 1995 By Robert A. Plane Robert A. Plane Director
Date: March 10, 1995 By Charles W. Stuart Charles W. Stuart Director
EXHIBIT INDEX
* 3-1 -- Restated Certificate of Incorporation of the Company pursuant to Section 807 of the Business Corporation Law filed in the Office of the Secretary of State of the State of New York on October 25, 1988. * 3-2 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 17, 1989. * 3-3 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 22, 1990. * 3-4 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 31, 1990. * 3-5 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on February 6, 1991. * 3-6 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 15, 1991. * 3-7 -- Certificate of Merger of Columbia Gas of New York, Inc. into the Company filed in the Office of the Secretary of State of the State of New York on April 8, 1991. * 3-8 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on May 28, 1992. * 3-9 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 20, 1992. * 3-10 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on October 14, 1993. * 3-11 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 10, 1993. * 3-12 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. ___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 3-13 -- Certificate of Amendment of the Certificate of Incorporation filed in the Office of the Secretary of State of the State of New York on December 20, 1993. * 3-14 -- Certificates of the Secretary of the Company concerning consents dated March 20, 1957 and May 9, 1975 of holders of Serial Preferred Stock with respect to issuance of certain unsecured indebtedness. * 3-15 -- By-Laws of the Company as amended February 25, 1994. * 4-1 -- First Mortgage dated as of July 1, 1921 executed by the Company under its then name of "New York State Gas and Electric Corporation" to The Equitable Trust Company of New York, as Trustee (Chemical Bank is Successor Trustee).
Supplemental Indentures to First Mortgage dated as of July 1, 1921:
* 4-2 -- No. 37 * 4-9 -- No. 74 * 4-15 -- No. 103 * 4-3 -- No. 39 * 4-10 -- No. 75 * 4-16 -- No. 104 * 4-4 -- No. 43 * 4-11 -- No. 80 * 4-17 -- No. 105 * 4-5 -- No. 51 * 4-12 -- No. 81 * 4-18 -- No. 106 * 4-6 -- No. 68 * 4-13 -- No. 83 * 4-19 -- No. 107 * 4-7 -- No. 69 * 4-14 -- No. 102 * 4-20 -- No. 108 * 4-8 -- No. 71 * 4-21 -- No. 109
Agreements and Amendments with the Power Authority of the State of New York:
* 10-1 -- Letter Agreement dated February 3, 1982 relating to transmission services. * 10-2 -- Amendment dated December 21, 1989 to the Letter Agreement dated February 3, 1982 relating to transmission services. * 10-3 -- Transmission Agreement dated December 12, 1983, with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system.
___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-4 -- Amendment dated December 21, 1989 to the Transmission Agreement dated December 12, 1983 with respect to connection of the Company's Kintigh (Somerset) Generating Station to the Niagara-Edic 345 kv transmission system.
* * * * * * * * * *
* 10-5 -- New York Power Pool Agreement dated July 11, 1985. * 10-6 -- Transmission Agreement dated January 10, 1990 between New York State Electric & Gas Corporation and Niagara Mohawk Power Corporation, with respect to remote load and generation wheeling service for the Company.
* * * * * * * * * *
Coal Sales Agreement and Amendments between New York State Electric & Gas Corporation and Consolidation Coal Company:
* 10-7 -- Agreement dated December 21, 1983. * 10-8 -- Amendment No. 1 dated as of October 1, 1985. * 10-9 -- Amendment No. 2 dated as of August 28, 1986.
* * * * * * * * * *
* 10-10 -- Basic Agreement dated as of September 22, 1975 between New York State Electric & Gas Corporation and others concerning Nine Mile Point Nuclear Station, Unit No. 2. * 10-11 -- Nine Mile Point Nuclear Station Unit 2 Operating Agreement effective as of January 1, 1993 among New York State Electric & Gas Corporation and others. ___________________________________ * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-12 -- Coal Hauling Agreement dated as of March 9, 1983 between Somerset Railroad Corporation and New York State Electric & Gas Corporation. (A)* 10-13 -- Retirement Plan for Directors. (A)* 10-14 -- Retirement Plan for Directors Amendment No. 1 (A)* 10-15 -- Form of Deferred Compensation Plan for Directors. (A)* 10-16 -- Deferred Compensation Plan for Directors Amendment No. 1. (A)* 10-17 -- Supplemental Executive Retirement Plan (A) 10-18 -- Supplemental Executive Retirement Plan Amendment No. 1. (A)* 10-19 -- Supplemental Executive Retirement Plan Amendment No. 2. (A)* 10-20 -- Supplemental Executive Retirement Plan Amendment No. 3. (A)* 10-21 -- Supplemental Executive Retirement Plan Amendment No. 4. (A)* 10-22 -- Supplemental Executive Retirement Plan Amendment No. 5. (A)* 10-23 -- Supplemental Executive Retirement Plan Amendment No. 6. (A)* 10-24 -- Supplemental Executive Retirement Plan Amendment No. 7. (A)* 10-25 -- Supplemental Executive Retirement Plan Amendment No. 8. (A)* 10-26 -- Supplemental Executive Retirement Plan Amendment No. 9. (A)* 10-27 -- Supplemental Executive Retirement Plan Amendment No. 10. (A)* 10-28 -- Annual Executive Incentive Compensation Plan. (A)* 10-29 -- Annual Executive Incentive Compensation Plan Amendment No. 1. (A)* 10-30 -- Annual Executive Incentive Compensation Plan Amendment No. 2. (A) 10-31 -- Annual Executive Incentive Compensation Plan Amendment No. 3. (A) 10-32 -- Annual Executive Incentive Compensation Plan Amendment No. 4. (A)* 10-33 -- Performance Share Plan. (A)* 10-34 -- Performance Share Plan Amendment No. 1. (A)* 10-35 -- Performance Share Plan Amendment No. 2. (A)* 10-36 -- Performance Share Plan Amendment No. 3. (A)* 10-37 -- Performance Share Plan Amendment No. 4. (A)* 10-38 -- Performance Share Deferred Compensation Plan. (A)* 10-39 -- Performance Share Deferred Compensation Plan Amendment No. 1. (A)* 10-40 -- Employment Contract for A. E. Kintigh. (A) 10-41 -- Agreement with M. I. German. (A)* 10-42 -- Employment Agreement for J. A. Carrigg. (A)* 10-43 -- Form of Severance Agreement for Senior Vice Presidents. (A)* 10-44 -- Form of Severance Agreement for Vice Presidents.
___________________________________ (A) Management contract or compenstory plan or arrangement. * Incorporated by reference.
EXHIBIT INDEX (Cont'd)
12 -- Computation of Ratio of Earnings to Fixed Charges. 21 -- Subsidiaries. 23 -- Consent of Coopers & Lybrand to incorporation by reference into certain registration statements. 27 -- Financial Data Schedule. 99-1 -- Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Salaried Employees. 99-2 -- Form 11-K for New York State Electric & Gas Corporation Tax Deferred Savings Plan for Hourly Paid Employees.