ITEM 1. BUSINESS
COMPANY AND SUBSIDIARIES
The Company, a registered holding company under the Holding Company Act, was organized under the laws of the State of New Jersey in 1902. The Company is engaged in the business of owning and holding all of the securities of the subsidiary companies identified below. All references to years in this report are to the Company's fiscal year ended September 30 unless otherwise noted.
The System constitutes an integrated natural gas operation and consists of operations which are regulated as to their rates and operations which are not so regulated. The Regulated Operations fall within two business segments: Utility Operation and Pipeline and Storage. The Nonregulated Operations consist principally of the Exploration and Production business segment. Other Nonregulated operations include the System's natural gas marketing and brokerage operations, pipeline construction operations, sawmill and dry kiln operations, and natural gas market area hub operations.
The Utility Operation is carried out by Distribution Corporation. Pipeline and Storage operations are carried out by Supply Corporation. Effective July 1, 1994, all of the Company's natural gas storage services were consolidated into Supply Corporation through the merger of Penn-York into Supply Corporation. Seneca is engaged in Exploration and Production operations. Effective July 1, 1994, all of the Company's Exploration and Production operations were consolidated into Seneca through the merger of Empire into Seneca. Supply Corporation's exploration and production activities were transferred to Empire, effective on January 1, 1994. Other Nonregulated operations are carried out by NFR, UCI, Highland, Seneca, Data-Track and Leidy Hub.
No single customer, or group of customers under common control, accounted for 10% or more of the System's consolidated revenues in 1994.
Financial information about the Company's business segments can be found in Note H - "Business Segment Information," on pages 79 to 81 of this report.
Distribution Corporation, a New York corporation, is a public utility that sells natural gas and provides gas transportation service in western New York and northwestern Pennsylvania. During 1994, Distribution Corporation served an average of 727,700 retail customers, compared with an average of 724,400 retail customers served during 1993. The principal metropolitan areas served are Buffalo, Niagara Falls and Jamestown, New York, and Erie and Sharon, Pennsylvania.
Supply Corporation, a Pennsylvania corporation, is engaged in the transportation and storage of natural gas for System and nonaffiliated companies. Supply Corporation owns and operates an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River. Supply Corporation owns and operates 30 underground storage fields in its operating area and four additional underground storage fields are operated jointly with certain major interstate pipeline companies.
ITEM 1. BUSINESS (Continued)
Seneca, a Pennsylvania corporation, is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the Gulf Coast of Texas and Louisiana, in California, and in the Appalachian region of the United States. Seneca's production is, for the most part, sold to purchasers located in the vicinity of its wells. In addition, Seneca is engaged in the marketing of timber from its Pennsylvania land holdings.
NFR, a New York corporation, is engaged in the marketing and brokerage of natural gas and performs energy management services for utilities and end-users.
UCI, a Pennsylvania corporation, is engaged in pipeline construction and other construction work for the System and nonaffiliated companies, and is headquartered in Linesville, Pennsylvania.
Highland, a Pennsylvania corporation, operates a sawmill and kiln in Kane, Pennsylvania.
Data-Track, a New York corporation, provides collection services for the subsidiaries of the Company, particularly Distribution Corporation, primarily through the issuance of collection notices.
Leidy Hub, a New York corporation, is a partner in the Ellisburg-Leidy Northeast Hub Company, which operates a natural gas market area hub in northeastern Pennsylvania serving the consuming regions of the Northeast, Mid-Atlantic and Canada. The hub offers services designed to simplify the complexities and the volatility of the gas market for gas buyers and sellers.
RATES AND REGULATION
All System companies are subject to regulation by the SEC under the broad regulatory provisions of the Holding Company Act, including provisions relating to issuance of securities, sales and acquisitions of securities and utility assets, intra-System transactions and limitations on diversification. Distribution Corporation is subject to regulation by the PSC and the PaPUC concerning rates and other matters. Supply Corporation is subject to regulation by the FERC, concerning rates and other matters. In addition, System companies are subject to federal, state and local laws and regulations concerning numerous other matters.
On November 2, 1994, the SEC issued a concept release soliciting comment on modernization of the Holding Company Act. The SEC has deemed that a reexamination of the need for, and role of, a federal holding company statute is necessary in light of recent utility and regulatory developments. The Company is unable to predict, at this time, what type of modernization may occur as a result of this reexamination and therefore what the impact will be on the Company.
ITEM 1. BUSINESS (Continued)
UTILITY OPERATION
Gas Sales and Transportation
The System's Utility Operation is conducted solely through Distribution Corporation. Substantially all of its sales are requirements sales (i.e., sales that vary and are not subject to significant minimum take obligations). In 1994, Distribution Corporation's sales and transportation volumes by customer class were 52% residential, 21% commercial and 27% industrial. In 1994, the Utility Operation accounted for approximately 52% of System operating income before income taxes. Information regarding the results of operations for the Utility Operation can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations," on pages 33 to 51 of this report.
On average, 97% of Distribution Corporation's retail customers use gas for space heating, which makes throughput, for the most part, weather-sensitive. In Distribution Corporation's New York jurisdiction, it was 3.6% colder than the prior year and 3.9% colder than normal, based upon the number of Degree Days for the year. In Distribution Corporation's Pennsylvania jurisdiction, it was 9.6% colder than the prior year and 8.4% colder than normal, based upon the number of Degree Days for the year.
Weather that was colder than the prior year contributed to a 5 Bcf increase in retail sales in 1994. Although industrial volumes sold remained level when compared with the prior year, they reflected a 2.5 Bcf switch from sales to transportation service, offset by increased gas sales to a new cogeneration customer.
The impact that major weather variances have on revenues and margins is tempered by a weather normalization clause that the PSC has authorized in Distribution Corporation's New York retail jurisdiction. This WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is more than 2.2% warmer than normal results in a surcharge being added to customers' current bills, while weather that is more than 2.2% colder than normal results in a refund being credited to customers' current bills. In 1994, the WNC was in effect for the period from October 1993 through May 1994. During this time, there were periods of both warmer than normal and colder than normal weather. Overall, the WNC resulted in a net reduction to customer bills of approximately $5.8 million in 1994.
Distribution Corporation requested a WNC in the Pennsylvania rate jurisdiction in its March 8, 1994 rate case filing. However, the PaPUC denied Distribution Corporation's request. This decision continues to subject Distribution Corporation's operating results to the impact of major weather variances.
Distribution Corporation offers large commercial and industrial customers transportation services and flexible rate designs. Transportation service, which allows end-users to purchase gas directly from a producer or marketer and transport it through the System's pipeline network, provides the
ITEM 1. BUSINESS (Continued)
customer with various options in buying gas and transportation services, thus providing the opportunity for cost savings to the customer. In 1994, 52.2 Bcf of gas were transported to such customers of Distribution Corporation, a 7% increase over the 48.9 Bcf transported in 1993. Transportation volumes represented 30% of the Utility segment's total throughput in 1994 and 29% in 1993.
The volume of gas transported by this segment increased 3.3 Bcf in 1994 mainly because of industrial and commercial boiler fuel sales customers switching to transportation service, which amounted to approximately 2.9 Bcf. In addition, transportation volumes increased by approximately 2 Bcf for large- and small-volume industrial customers. Partly offsetting these increases was a decline in transportation in the Pennsylvania jurisdiction of approximately 0.8 Bcf because of the shut down of three industrial customers and a decline of approximately 0.8 Bcf because of the bypass of the Company's pipeline system in favor of local producer gas service. Rates that became effective in December 1994, in the Pennsylvania rate jurisdiction, compensate for the loss of throughput related to these customers.
Distribution Corporation has a supplemental service rate in New York and a bypass rate in Pennsylvania which are intended to induce customers not to bypass the System. These rates are designed to recover Distribution Corporation's cost of providing back-up service to customers utilizing an alternative gas supply. In addition, Distribution Corporation has a flexible transportation tariff in Pennsylvania and New York, which allows it to negotiate a competitive rate to encourage customers to stay on the System.
The unbundling of services under the FERC's Order 636 has required transportation customers to incur storage service costs for use of storage facilities. These costs were previously bundled and charged only to sales customers. As a means of providing options to its customers, Distribution Corporation offers a Daily Metered Transportation rate in Pennsylvania. Customers using this rate would only incur storage charges for storage service utilized, as determined through a daily metering process, thus increasing the importance of each customer's management of its gas needs. Distribution Corporation has proposed a similar rate in its New York jurisdiction rate case filed in October 1994.
Through open dialogue with customers, utilization of the various rates discussed above and Distribution Corporation's in-house gas acquisition expertise which industrial customers and other end-users may not have, Distribution Corporation has been able to mitigate bypass of the System.
Distribution Corporation also offers competitive boiler fuel rates to large commercial and industrial customers in its New York rate jurisdiction. These rates allow Distribution Corporation to adjust rates monthly to compete against suppliers of No. 6 oil and other boiler fuels.
ITEM 1. BUSINESS (Continued)
If boiler fuel and supplemental service rates in New York, the bypass rate in Pennsylvania and flexible transportation rates in both jurisdictions were not available, Distribution Corporation could become vulnerable to losses in throughput since natural gas is, in many cases, directly replaceable by No. 6 oil in industrial boilers, or can be obtained through bypass of the System.
Distribution Corporation also offers rates in both its New York and Pennsylvania jurisdictions that provide competitive gas prices encouraging new technologies, such as the installation of small-packaged cogeneration and gas-fired cooling and dehumidification systems that utilize gas on an all-year or summerload basis.
The System continues to encourage the development of the natural gas vehicle market. The System operates over 400 NGVs along with four public-access refueling stations. A fifth public-access station is scheduled to open in 1995.
Distribution Corporation is not currently subject to any material restrictions upon the connection or service of new residential, commercial and industrial customers in its service territory. However, because of the high natural gas saturation and the maturity of Distribution Corporation's service territory, its focus will be on retaining existing customers through rate design initiatives and, in the longer term, through the development and marketing of new natural gas utilization technologies.
Gas Supply
One of the major effects of restructuring of the natural gas industry under the FERC's Order 636 was the transfer of responsibility for acquiring gas supply from pipeline companies to natural gas utility companies. This transfer of responsibility also carried with it the transfer to utility companies of the risks related to the purchasing of adequate and reliable gas supplies, transportation arrangements and storage arrangements. In addition, the role of the state public utility commissions in monitoring the prudency of purchasing practices of the utility has become more significant.
As a result of Supply Corporation's restructuring, which became effective August 1, 1993, gas supplies for the System are now obtained by Distribution Corporation in essentially the same manner operationally, as they were in recent years by Supply Corporation.
Distribution Corporation's basic gas acquisition objective is to obtain reliable, diversified, long-term sources of gas supply at competitive prices and to maintain appropriate levels of pipeline and storage capacity to transport and store its gas supply.
As a result of Order 636 restructuring, Distribution Corporation was provided a share of pipeline and storage capacity on Supply Corporation and on the upstream pipeline companies formerly serving Supply Corporation. Distribution Corporation has entered into contracts for the necessary capacity on Supply Corporation and on these upstream pipeline companies, to meet the requirements of its firm sales customers.
ITEM 1. BUSINESS (Continued)
Distribution Corporation has firm transportation capacity from Supply Corporation and the following pipeline companies: Tennessee Gas Pipeline Company, Texas Eastern Transmission Corporation, Transcontinental Gas Pipe Line Corporation, CNG Transmission Corporation (CNG) and Columbia Gas Transmission Corporation (Columbia). Total contracted capacity on these pipelines, in the aggregate, is approximately 155,916 MMcf annually.
Distribution Corporation has contracted storage capacity of 25.3 Bcf from Supply Corporation as well as contracted storage capacity, in the aggregate of 4.6 Bcf, from CNG and Columbia. At September 30, 1994, Distribution Corporation had 28.0 Bcf of gas in storage.
Pipeline companies' transportation and storage rates have been designed on a SFV basis, as mandated by Order 636. This rate design allows pipeline companies to recover all of their fixed costs through a demand or reservation charge. Thus, Distribution Corporation pays nearly all costs of its contracted pipeline transportation and storage through a demand charge. Distribution Corporation maintains its current level of firm capacity so it can continue to provide reliable service to its firm sales customers during peak winter months. Distribution Corporation must pay to reserve capacity year round even though the demand of the firm customers significantly decreases during the summer months. Distribution Corporation has reduced a small amount of its fixed costs by releasing unused capacity during off-peak periods and will continue to utilize capacity release programs.
In order to provide gas service to its customers and fill the pipeline capacity obtained in the Order 636 unbundling process, Distribution Corporation was assigned Supply Corporation's pre-Order 636 gas purchase agreements and has since entered into its own gas purchase agreements. Currently, approximately 92% of Distribution Corporation's daily winter capacity on upstream pipelines is supported by long-term gas supply contracts, primarily with Southwest producers. Distribution Corporation's firm gas supply portfolio is comprised of contracts, having an average six-year term, which supply gas from a variety of production areas and suppliers. Many of Distribution Corporation's long-term supply contracts are adjusted to reflect the seasonal variations in customer demand, thereby decreasing costs. Spot gas continues to be utilized when short-term gas supplies are plentiful and when it is economical to do so. During off-peak periods, Distribution Corporation is able to make off-system sales when supplies are not needed to provide service to its firm sales customers.
While Distribution Corporation's purchases of Appalachian produced gas has continued to decline, gas received from local producers and transported by Supply Corporation and Distribution Corporation for large industrial end-users, remains an important source of gas supply for these end-users.
For additional details on sources of gas supply, see the "Sources of Gas Supply - Regulated Operations" on page 13 of this report.
ITEM 1. BUSINESS (Continued)
Based on information currently available to the Company, Systemwide gas supply remains sufficient to meet anticipated demand.
In 1994, Distribution Corporation's average cost of purchased gas, including the cost of transportation and storage, was $3.74 per Mcf, a decrease of 3% from Distribution Corporation's average cost of $3.84 per Mcf in 1993. Regulation of gas prices at the wellhead is virtually nonexistent, and therefore, the market primarily dictates gas supply and gas prices.
The total quantity of gas purchased by Distribution Corporation in 1994 was 145.9 Bcf, compared with 131.5 Bcf purchased by Distribution Corporation and Supply Corporation (net of intersegment purchases) in 1993, an increase of 14.4 Bcf or 11%.
The 14.4 Bcf increase in purchases was the result of the following (refer to "Selected Statistics of the System's Regulated Operations" on page 16 of this report): (1) Net injections into storage in 1994 were 4.3 Bcf compared with net withdrawals from storage in 1993 of 3.0 Bcf. This accounts for a 7.3 Bcf increase in the amount of gas required to be purchased in 1994. (2) Gas used in operations, shrinkage and other increased 8.5 Bcf in 1994. Shrinkage represents a percentage of gas retained by pipeline companies for purposes such as fueling their compressors. Purchases reported by the System are gross amounts (i.e., prior to shrinkage). The amount of shrinkage is dependent upon where title to such gas is taken. The System has experienced a steady increase in the past several years in the amount of gas it has taken title to in the Southwest. In 1994, Distribution Corporation took title to approximately 95% of its gas purchases in the Southwest. Thus, amounts required to be purchased by Distribution Corporation were higher than amounts available for sale to Distribution Corporation's customers. (3) A 5.1 Bcf increase in Distribution Corporation's retail sales required increased purchases in 1994. (4) Elimination of Supply Corporation nonaffiliated wholesale sales under Order 636 restructuring, which amounted to 6.5 Bcf in 1993, resulted in decreased purchases in 1994.
Total System throughput increased 34.4 Bcf or 13% to 307.3 Bcf in 1994, from 272.9 Bcf in 1993. This increase is mainly attributable to higher volumes of gas transported through Supply Corporation's Canadian gas transportation facilities and higher retail sales by Distribution Corporation which were up primarily because of colder weather and increased gas sales to a new cogeneration customer.
The following table, "Sources of Gas Supply - Regulated Operations", sets forth the sources and quantities of gas purchases over the past three years. (System throughput volumes are contained in the table on page 16.)
ITEM 1. BUSINESS (Continued)
Sources of Gas Supply - Regulated Operations
Annual Contract Volumes Delivered-MMcf Volumes in Year Ended September 30, MMcf (1) 1994 1993 1992
Producers and Marketers:
Long-Term Contracts 124,471 (2) 107,487 60,664 28,819
Appalachian 4,595 (3) 4,595 7,366 11,883
Affiliated Production 2,474 (4) 2,474 4,265 5,067
Spot Market - (5) 31,319 52,785 86,142
Interstate Pipelines - (6) - 6,434 2,298
Total Gas Supply - Regulated Operations 131,540 145,875 131,514 134,209
(1) This column reflects annual volumes under currently existing contracts. Thermally-expressed annual contract quantities have been converted to their volumetric equivalent on a nominal 1,000 Btu per cubic foot basis.
(2) The producers and marketers from which Distribution Corporation purchases gas pursuant to long-term supply contracts (contracts with a term of two years or longer, the average length of Distribution Corporation's contracts being six years) are: Chevron U.S.A., Coastal Gas Marketing, Enron Gas Marketing, Inc., Enron Excess Corporation, Exxon Company U.S.A., Meridian Oil Trading, Inc., MidCon Gas Services, Corp., Mobil Natural Gas, Inc., Natural Gas Clearinghouse, Shell Oil Company, et al., Tejas Power Company, Texaco Gas Marketing, Transco Energy Marketing Company and Vastar Gas Marketing, Inc. (formerly Arco Natural Gas Marketing, Inc.). In addition, the amounts include Canadian gas under contract with Boundary Gas, Inc. and ANE Gas Marketing.
(3) The annual contract volume represents 1994 purchases from independent producers in the Appalachian region. The independent producer contracts generally continue until the reserves dedicated to them are economically depleted. The annual contract volumes applicable to these contracts vary as a function of the deliverability of the wells committed to them. The vast majority of this production is long-term dedicated supply.
(4) The annual contract volume represents supply from the System's own production in the Appalachian region. Volumes decreased significantly in 1994, as the System's own production is being sold to various end-users.
(5) No annual contract volume is shown here as, generally, spot contracts are very short-term.
ITEM 1. BUSINESS (Continued)
(6) No contract volumes are shown here as interstate pipeline companies have terminated their merchant function under the FERC's Order 636. Distribution Corporation has contracts with interstate pipeline companies for pipeline capacity to transport gas purchased under direct contracts.
For a discussion of Distribution Corporation's obligations under its nonaffiliated pipeline capacity, gas purchase and gas storage contracts, see Note G - "Commitments and Contingencies," on pages 77 to 79 of this report.
PIPELINE AND STORAGE
The System's Pipeline and Storage operations are conducted by Supply Corporation. In 1994, these operations accounted for approximately 36% of System operating income before income taxes. Information regarding the results of operations for the Pipeline and Storage operations can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" on pages 33 to 51 of this report.
Pipeline Capacity and Transportation
Supply Corporation currently has service agreements for substantially all of its pipeline capacity, which approximates 1,860 MMcf per day. Distribution Corporation has contracted for approximately 1,120 MMcf per day or 60% of this capacity.
Effective with Supply Corporation's restructuring under Order 636, most of its upstream pipeline contracts have been assigned to its former sales customers. Currently, there is a small amount of unallocated capacity on three upstream pipelines related to capacity which was not accepted by certain customers. The reservation charges related to the unallocated capacity are considered stranded transportation costs, a category of Order 636 transition costs. Supply Corporation is recovering these amounts from its customers pursuant to FERC authorization.
Supply Corporation's transportation throughput in 1994 was 295.3 Bcf compared with 138.6 Bcf in 1993. The increase in 1994 is primarily the result of unbundling of services under Order 636 under which Supply Corporation's former sales customers became transportation customers. Also, throughput increased as a result of weather that was colder than the prior year, increased utilization of Supply Corporation's Canadian gas transportation facilities and the expanded capacity of these facilities.
For a discussion of the impact of the Clean Air Act Amendments of 1990 on Supply Corporation's compressor stations, see Note G - "Commitments and Contingencies," on pages 77 to 79 of this report.
Underground Storage
To facilitate operational efficiencies, all of the System's natural gas storage services were consolidated into Supply Corporation through the July 1, 1994 merger of Penn-York into Supply Corporation. Supply Corporation owns and
ITEM 1. BUSINESS (Continued)
operates 30 underground storage fields in its operating area. Four additional underground storage fields are operated jointly with certain major interstate pipeline companies. All of these fields are former gas-producing reservoirs and are operated under FERC certification.
Supply Corporation has available Working Gas capacity of approximately 69.9 Bcf. Of this amount, approximately 7 Bcf has been retained by Supply Corporation in order to render no notice transportation service and meet other delivery obligations. Of the remaining available Working Gas capacity of approximately 62.9 Bcf, Distribution Corporation has contracted for 25.3 Bcf and nonaffiliated customers have contracted for 35.6 Bcf.
The primary terms of current storage service agreements representing 23.3 Bcf of the amount contracted for by nonaffiliated customers expire on March 31, 1995. Service continues year-to-year and can be terminated upon one years notice. None of these customers have elected to terminate service nor extend their term for ten years as provided under a settlement of a previous Penn-York rate case.
Supply Corporation's proposed Laurel Fields Storage Project is a 19 Bcf underground natural gas storage development project. Filings with the FERC were made in June 1994 to implement this project. An "open season" was held in August 1994 to identify prospective customers for this project with whom agreements are currently being negotiated. On November 4, 1994, a proposal was sent to the FERC to divide the project into two phases. Phase I would encompass the expansion of the Limestone storage field to accommodate approximately 7 Bcf of storage and phase II would consist of the development of the Callen Run storage field, a depleted gas production field. The estimated cost of both phases of this project, including related transmission facilities, is approximately $200 million. Timing of the project has not been finalized.
The Company believes that underground storage will have enhanced economic value in the post-Order 636 environment. Furthermore, the growing demand for natural gas for home heating in the Northeast and on the East Coast creates a demand for peak period gas supplies, which may require additional storage service. Supply Corporation's storage fields are strategically located between Southwest and Canadian gas supplies and the growing demand for natural gas in the Northeast and East Coast areas.
The magnitude of future expansion in the System's Regulated Operations depends, to a large degree, upon market conditions coupled with adequate rate relief.
ITEM 1. BUSINESS (Continued) SELECTED STATISTICS OF THE SYSTEM'S REGULATED OPERATIONS (Intra-System Sales Eliminated Where Appropriate)
Year Ended September 30, 1994 1993 1992 1991 1990 GAS AVAILABLE FOR SALE (MMcf): Natural Gas Purchased- Producers and Marketers 112,082 68,030 40,702 37,078 20,387 Spot Market Purchases 31,319 52,785 86,142 90,822 93,961 Interstate Pipelines - 6,434 2,298 3,103 22,377 143,401 127,249 129,142 131,003 136,725
Natural Gas Produced 2,474 4,265 5,067 5,088 4,823
Total Gas Supply 145,875 131,514 134,209 136,091 141,548 Gas Withdrawn from (delivered to) Storage - Net (4,306) 2,992 (2,449) (5,671) 2,320 Used in Operations, Shrinkage and Other (17,535) (8,986) (3,665) (2,446) (1,705) Total Gas Available for Sale 124,034 125,520 128,095 127,974 142,163
SYSTEM THROUGHPUT (MMcf): Retail Sales - Residential 90,565 86,854 84,762 79,299 85,761 Commercial 26,937 25,598 25,909 25,634 28,646 Industrial 6,532 6,528 9,131 9,893 10,872 Wholesale Sales - 6,540 8,293 13,148 16,884 Total Gas Sales 124,034 125,520 128,095 127,974 142,163 Transportation 183,255 147,357 172,505 128,731 101,512 Total System Throughput 307,289 272,877 300,600 256,705 243,675
GAS OPERATING REVENUES INCLUDING TRANSPORTATION (Thousands of Dollars): Retail - Residential $677,068 $613,039 $533,908 $494,332 $517,026 Commercial 177,249 156,851 139,662 135,718 150,637 Industrial 31,096 31,609 35,985 38,395 45,707 Wholesale 6,930* 27,451 30,150 43,917 47,773 Total Gas Operating Revenues 892,343 828,950 739,705 712,362 761,143 Transportation 68,695 64,641 61,204 42,308 35,192 Total Gas Operating Revenues Including Transportation $961,038 $893,591 $800,909 $754,670 $796,335
AVERAGE NUMBER OF UTILITY CUSTOMERS: Retail - Residential 680,043 676,876 672,877 668,240 663,697 Commercial 46,518 46,344 46,051 45,292 44,859 Industrial 1,181 1,188 1,201 1,202 1,207 Transportation 1,306 1,293 1,088 957 750 729,048 725,701 721,217 715,691 710,513
* 1994 wholesale revenues represent revenues from Distribution Corporation's off-system sales.
ITEM 1. BUSINESS (Continued)
EXPLORATION AND PRODUCTION
The System's Exploration and Production operations are carried out by Seneca. Seneca is engaged in the exploration for, and the development of, natural gas and oil reserves in the Gulf Coast of Texas and Louisiana, in California, and in the Appalachian region of the United States.
To facilitate operational efficiencies, all of the System's exploration and production operations were consolidated into Seneca through the July 1, 1994 merger of Empire into Seneca. Supply Corporation's exploration and production activities were transferred to Empire, effective January 1, 1994.
Exploration and production activities in 1994 accounted for approximately 13% of System operating income before income taxes. Information regarding the results of operations for the Exploration and Production operations can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" on pages 33 to 51 of this report.
Gulf Coast/West Coast Exploration and Production
Seneca's Gulf Coast activities in 1994 were directed toward continued offshore exploration for natural gas in the Gulf of Mexico and drilling of horizontal wells for gas production in the Austin Chalk formation in Seneca's Northeast Clay field in central Texas.
The offshore exploration program uses advanced computer and seismic technology in an attempt to identify low risk gas prospects which can be drilled and placed in production in less than one year. As of September 30, 1994, Seneca had acquired and evaluated new offshore seismic data covering an area of over 45,000 square miles. In 1994, Seneca drilled six gas wells in the Gulf of Mexico, five of which were successful. The most significant discovery was in West Cameron Block 552 where one gas well was drilled in 1994.
Seneca has continued to achieve its goal of placing new wells in production within one year. Two of the five successful wells in the Gulf of Mexico were in production by September 30, 1994. The other three wells are expected to be in production by March 31, 1995. Future offshore activity should continue to be strong with Seneca's acquisition of three blocks in the Federal Lease Sale and acquisition of one block through a farm out. These acquisitions have increased Seneca's inventory of offshore prospects to eleven, some of which will be evaluated in 1995.
In addition, Seneca actively pursued identifying and drilling gas reserves in the tight Austin Chalk formation in its Northeast Clay Field in central Texas. In 1994, Seneca drilled or participated in five horizontal wells, all of which were successful. The scope of Seneca's horizontal drilling is expected to expand in 1995. Seneca has acquired nearly 4,000 acres and 6,000 acres to the west and east of the Northeast Clay Field, respectively. Plans are to begin development of this acreage in 1995.
ITEM 1. BUSINESS (Continued)
As a result of this activity in the Gulf Coast Region, 93.4 Bcf of gas reserves and 1.1 million barrels of oil reserves were added in 1994.
Reserves related to the Gulf Coast Region at September 30, 1994 amounted to 3.8 million barrels of oil and 153.2 Bcf of gas, or approximately 22% and 62% of Seneca's total oil and gas reserves, respectively. This represents a decrease of approximately 0.3 million barrels of oil and an increase of 73.7 Bcf of gas compared with September 30, 1993.
Seneca's California activities in 1994 were concentrated primarily on cost control and improving production in the Sespe and Silverthread Fields in Ventura, California while continuing development drilling in the new Temescal Field. In 1994, Seneca drilled one additional successful well in the Temescal Field.
Reserves related to Seneca's California operations at September 30, 1994, amounted to 13.5 million barrels of oil and 32.0 Bcf of gas, or approximately 77% and 13% of Seneca's total oil and gas reserves, respectively. This is a decrease of 0.7 million barrels in oil reserves and 2.4 Bcf of gas compared with September 30, 1993.
During 1994, Seneca's combined Gulf Coast and California operations produced 1.0 million barrels of oil and 17.0 Bcf of gas compared to 0.8 million barrels of oil and 13.2 Bcf of gas produced in 1993. This represents an increase of 25% in oil production and 29% in gas production. In 1994, oil and gas sales were made to marketers and refiners under long-term agreements, which contain flexible pricing provisions.
Appalachian Exploration and Production
Most of the gas production Seneca owns in the Appalachian region, is transported to end-users by the System. A percentage of the production from these wells is dedicated to the System's Regulated Operations' gas supply. Seneca's drilling programs in this region depend, to a large degree, on gas prices. In 1994, Seneca drilled or participated in drilling 8 net gas wells, of which 5 were completed as producers and 3 were plugged and abandoned as dry holes. Approximately 0.7 Bcf of gas was discovered as a result of these efforts. This is compared with 1993's drilling program of 18 net wells, of which 11 were completed as producers, and 1.1 Bcf of gas discovered.
In 1994, Seneca's gas production from its Appalachian wells amounted to 6.3 Bcf compared with 6.6 Bcf in 1993. At September 30, 1994, Seneca had 1,998 net productive wells in the Appalachian Region. Seneca's gas reserves at September 30, 1994, located in this region amounted to 62.3 Bcf, or approximately 25% of Seneca's total gas reserves. This represents an increase in gas reserves of 1.0 Bcf compared with 1993, as current year discoveries from drilling activities, revisions of previous estimates and acquisitions of reserves in place more than offset current year production. Seneca's Appalachian oil production and oil reserves are not significant.
ITEM 1. BUSINESS (Continued)
Oil and Gas Prices
During 1994, the System's weighted average oil price at the wellhead was $14.86 per barrel, a decrease of $1.92 per barrel, or 11%, from 1993. The System's weighted average gas price at the wellhead was $2.18 per Mcf, a decrease of $.02 per Mcf, or 1%, from 1993. Nonetheless, efforts to stabilize prices through hedging activities contributed approximately $1.6 million of operating revenues for the year. See further discussion of hedging activities in Note A - Summary of Significant Accounting Policies on pages 58 to 62 of this report.
At September 30, 1994, Seneca did not experience an impairment of its oil and gas assets under the SEC full cost accounting rules. Wellhead price declines in the future, if material, could have a negative impact on Seneca's oil and gas assets.
OTHER NONREGULATED
The Systems's Other Nonregulated operations are carried out primarily by NFR, UCI, Highland and Leidy Hub, which are engaged in natural gas marketing and brokerage operations and energy management services; pipeline construction operations; sawmill and dry kiln operations; and natural gas market hub activities, respectively. Other Nonregulated operations also include the marketing of timber. In 1994, these operations accounted for 1% of System operating income before income taxes. Corporate operations reduced System operating income before income taxes by 2%. Information regarding the results of operations for the Other Nonregulated operations can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" on pages 33 to 51 of this report.
In 1994, Leidy Hub received SEC approval to enter into a partnership with a subsidiary of Natural Gas Clearinghouse (Clearinghouse) to develop a market area hub in north central Pennsylvania, where, in order to manage their gas supply, customers such as pipelines, marketers and utilities can store or borrow gas short-term, move gas from one pipeline to another, and buy or sell gas. The partnership became effective September 1, 1994. Leidy Hub has a 50% interest in this partnership.
COMPETITION
The natural gas industry was a competitive one in 1994 and is expected to become more competitive in the future. Competition existed among providers of natural gas, as well as between natural gas and other sources of energy.
Management continues to believe that there will be increased usage of natural gas nationwide over the longer-term and, therefore, opportunities exist for increased sales, transportation and storage of natural gas, primarily on behalf of off-system end-users. This increased use of natural gas nationwide is expected to result mainly from the increased use of natural gas as an electric generation and cogeneration fuel, conversion of home heating load from oil to gas, economic and population growth and competitive
ITEM 1. BUSINESS (Continued)
prices. Nonetheless, there is currently downward pressure on gas prices due to milder than normal weather and increased supply because of the continued growth of Canadian imports and increasing domestic supplies attributable to more efficient exploration and production technology. While seasonal swings in gas prices between the heating and nonheating season are expected to continue, the longer term trend in natural gas prices is dependent upon the balance of demand and supply. Current estimates of the United States demand growth rate range from 1 - 4%, while estimates for increases in available supply range from 2 - 5%.
The continuing deregulation of the gas industry should also enhance the competitive position of gas relative to other energy sources by removing some of the regulatory impediments to adding customers and responding to market forces. In addition, the environmental advantages of natural gas compared with other fuels should increase the role of natural gas as an energy source. The potential environmental role of natural gas was enhanced by the passage of the Clean Air Act in 1990. Moreover, natural gas, which is abundantly available in North America, is a dependable domestic alternative to foreign oil.
The electric utility industry is moving toward a more competitive environment as a result of the Energy Policy Act of 1992 and actions of various regulatory commissions. It is unclear at this point what impact this restructuring will have on the natural gas industry.
System companies compete on the basis of price, service, quality and reliability, product performance and other factors.
Utility Operations
The changes precipitated by the FERC's Order 636 are redefining the roles of the utility industry and the state regulatory commissions. Competition has arrived for utilities, and it is anticipated that, similar to what was done in the pipeline sector of the natural gas industry, regulators will require utilities to unbundle their services. The anticipated result is that utility service will divide into "core" markets consisting of the traditional residential and commercial customers, as well as customers taking firm transportation service and "non-core" markets consisting of competitive commercial and industrial markets. It is anticipated that competition for the "non-core" market will continue from parties desiring to bypass the System by selling and/or transporting gas directly to Distribution Corporation's industrial and commercial customers. Furthermore, the FERC, in its recent Bypass Policy, appears to be unwilling to shield local distribution companies from bypass. In addition, competition will exist with fuel oil suppliers and electric utilities in making retail energy sales. Distribution will attempt to retain, and if possible expand, its most vulnerable markets, such as the large industrial market, through favorable rate design, business development and related efforts. Distribution Corporation continues to (a) develop or
ITEM 1. BUSINESS (Continued)
promote new sources and uses of natural gas and/or new services, rates and contracts; (b) purchase gas from lowest cost suppliers consistent with operating and long-term gas supply needs; and (c) emphasize and provide high quality service to its customers.
Pipeline and Storage Operations
The Pipeline and Storage segment competes for market growth in the natural gas market with other pipeline companies transporting gas in the Northeast and with other companies providing gas storage service. The System has some unique characteristics which enhance its competitive position. Its service area, which is located adjacent to Canada and the Northeast United States, and partially connects the Northeast with the South, Southwest and Midwest, is advantageous for the provision of increased transportation and storage service in the future. The Company will continue to evaluate ways to take advantage of its location to open up new markets and expand existing ones, especially in the gas storage business. There will, however, be increased competition to provide services due to a number of recent large pipeline expansions in the Northeast. Likewise, new storage projects face competition from existing storage facilities and a number of planned storage projects which have been announced as a result of Order 636.
Exploration and Production
The Exploration and Production segment competes with other gas and oil producers and with fuel oil and electricity wholesalers and producers. Seneca competes with other oil and gas exploration and production companies of various sizes for leases and drilling rights for exploration and development prospects, and competes with other producers for markets to sell its production based on price and deliverability.
To compete in this environment, Seneca acts as operator on most prospects, sheds risk of exploratory efforts through partnerships, applies the latest technology for both exploratory studies and drilling operations and focuses on market niches that suit its size, operating expertise and financial criteria.
Other Nonregulated
In the Other Nonregulated segment, NFR competes with other gas marketers and energy management services providers. Leidy Hub competes with other gas market service providers. Highland competes with other sawmills in northwestern Pennsylvania, and UCI competes with other pipeline construction companies in its area of operation. Sources and providers of energy, other than those described above, do not compete with System companies to any significant extent.
ITEM 1. BUSINESS (Continued)
CAPITAL EXPENDITURES
A discussion of capital expenditures by business segment is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations," on pages 33 to 51 of this report.
ENVIRONMENTAL MATTERS
Supply Corporation is engaged in discussions, but not formal proceedings, with the New York Department of Environmental Conservation (NYDEC) concerning the 71 plugged and abandoned gas wells located within the boundaries of the Bennington and Holland, New York, underground natural gas storage fields. Supply Corporation voluntarily agreed to re-plug 30 wells which were believed to be venting small amounts of natural gas to the atmosphere. Twenty-seven of those wells have been plugged, at a cost of approximately $3.1 million, and the other 3 have been found not to be venting gas anymore. There are on-going discussions regarding the NYDEC's determination that Supply Corporation should also re-plug 37 plugged and abandoned wells which are not venting any natural gas to the atmosphere. Re-plugging those additional 37 wells, plus the 3 wells which were formerly venting small amounts of gas to the atmosphere, would cost an additional amount of approximately $5.1 million.
For additional discussion of environmental matters involving the Company, see Note G - "Commitment and Contingencies" on pages 77 to 79 of this report.
MISCELLANEOUS
The System had 3,148 regular employees at September 30, 1994, a decrease of 5.4% from the 3,329 employed at September 30, 1993.
Agreements covering employees in collective bargaining units in the State of New York were renegotiated in calendar 1994 and are scheduled to expire in calendar 1998. Agreements covering most employees in collective bargaining units in the Commonwealth of Pennsylvania were renegotiated in calendar 1993 and are scheduled to expire in calendar 1996.
System companies have numerous county and municipal franchises under which they use public roads and certain other rights-of-way and public property for the location of facilities. System companies have regularly renewed such franchises at expiration and expect no difficulty in continuing to renew them.
ITEM 1. BUSINESS (Concluded)
EXECUTIVE OFFICERS OF THE COMPANY (1)
Age as of Date Elected Name 9/30/94 Position To Position
Bernard J. Kennedy 63 Chairman of the Board of Directors. March 21, 1989 Chief Executive Officer. August 1, 1988 President. January 1, 1987 Director. March 29, 1978 Executive Vice President and General Counsel from 1976 to 1986. Chairman of the Board of certain subsidiaries of the Company since August 1988. President and Chief Executive Officer of Supply Corporation and an officer of certain other subsidiaries of the Company from prior to 1989 until June 1, 1989.
Philip C. Ackerman 50 Director March 16, 1994 Senior Vice President. June 1, 1989 Vice President from July 1, 1980 until June 1, 1989. President of certain of the Company's subsidiaries from prior to 1989.
Richard Hare 56 President of Supply Corporation. June 1, 1989 An executive officer of certain of the Company's subsidiaries from prior to 1989.
William J. Hill 64 President of Distribution June 1, 1989 Corporation. An executive officer of Distribution Corporation from prior to 1989.
(1) The Company has been advised that there are no family relationships among any of the officers listed, and that there is no arrangement or understanding among any one of them and any other persons pursuant to which he was elected as an officer.
ITEM 2.
ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES
The investment of the System in net property, plant and equipment was $1,542,739,000 at September 30, 1994. Approximately 80% of this investment is in the System's Utility and Pipeline and Storage segments, which are primarily located in western New York and western Pennsylvania. The remaining investment in property, plant and equipment is mainly in the Exploration and Production Segment, which is primarily located in the Gulf Coast, southwestern, western and Appalachian regions of the United States.
The Utility Operation has the largest net investment in property, plant and equipment, compared with the System's other business segments. Most of this net investment represents its gas distribution network. These properties include 14,592 miles of pipeline (exclusive of service pipe), which represent approximately 55% of the Utility Operation's net investment of $787,794,000.
The Pipeline and Storage segment represents a net investment of $440,810,000 in transmission and storage facilities at September 30, 1994. Transmission pipeline, with a net cost of $132,591,000, represents 30% of this segment's total net investment and includes 2,786 miles of pipeline required to move large volumes of gas throughout the System's service area. Storage facilities consist of 34 storage fields, four of which are jointly operated with certain pipeline suppliers, and 512 miles of pipeline. Included in the storage facilities net investment is $80,942,000 of base gas. The Pipeline and Storage segment has 31 compressor stations with 72,100 installed compressor horsepower.
The Exploration and Production segment had a net investment in properties amounting to $295,419,000 at September 30, 1994. Of this amount, Seneca's net investment in oil and gas properties in the Gulf Coast/West Coast regions was $238,175,000, and Seneca's net investment in oil and gas properties in the Appalachian region aggregated $57,244,000.
During the past five years, the System has made significant additions to plant in order to expand and improve transmission and distribution facilities for both retail and wholesale customers and to augment the reserve base of oil and gas. Net plant has increased $455,276,000, or 42%, since 1989.
The System's facilities provided the capacity to meet the System's 1994 peak day sendout, including transportation service, of 1,988 MMcf, which occurred on January 19, 1994. Withdrawals from storage provided approximately 47% of the requirements on that day.
System maps are included as Exhibit 99.2 to this report.
EXPLORATION AND PRODUCTION ACTIVITIES
The information that follows is disclosed in accordance with SEC regulations, and relates to the System's oil and gas producing activities. For a further discussion of oil and gas producing activities, refer to Note K - - "Supplementary Information for Oil and Gas Producing Activities," on pages 84 to 88 of this report, and to Exploration and Production on pages 17 to 19 of this report.
ITEM 2. PROPERTIES (Continued)
Supply Corporation files Form 2 "Annual Report of Natural Gas Companies" and Form 15 "Annual Report of Gas Supply" with the FERC. The reserve disclosures in these reports were filed as of December 31, 1993, whereas the reserve disclosures included in Note K are reported as of September 30, 1994.
The gas reserves of Supply Corporation reported as of December 31, 1993, in Forms 2 and 15, were in-house estimates arrived at by qualified Supply Corporation geologists and engineers. Seneca is not regulated by the FERC, and thus is not required to file Forms 2 and 15. As discussed in Item 1, Supply Corporation's exploration and production activities were transferred to Empire effective January 1, 1994. Subsequently, on July 1, 1994, Empire was merged into Seneca. Seneca's oil and gas reserves reported in Note K as of September 30, 1994, were estimated for Seneca by independent petroleum engineers from Ralph E. Davis, Inc.
The following is a summary of certain oil and gas information taken from System records:
Production
For the Year Ended September 30 1994 1993 1992
Average sales price per Mcf of gas $ 2.18 $ 2.20 $ 1.97
Average sales price per barrel of oil $14.86 $16.78 $17.11
Average production (lifting) cost per Mcf equivalent of gas and oil produced $ .45 $ .54 $ .62
Productive Wells
At September 30, 1994 Gas Oil
Productive Wells - gross 2,153 201 - net 2,013 172
Developed And Undeveloped Acreage
At September 30, 1994
Developed Acreage - gross 568,736 - net 508,753
Undeveloped Acreage - gross 516,743 - net 476,482
ITEM 2. PROPERTIES (Concluded)
Drilling Activity
Productive Dry For the Year Ended September 30 1994 1993 1992 1994 1993 1992
Net Wells Completed - Exploratory 5 9 5 5 6 5 - Development 7 16 11 1 3 3
Present Activities
At September 30, 1994
Wells in Process of Drilling - gross 1 - net 1
There are currently no waterflood projects or pressure maintenance operations of material importance.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
PARAGON/TGX PROCEEDINGS
A. New York Litigation
On November 30, 1984, Distribution Corporation commenced an action against Paragon Resources, Inc. (Paragon) and TGX Corp. (collectively Paragon/TGX), in the United States District Court for the Western District of New York (the District Court) seeking a declaratory judgment concerning the contract effect of a December 20, 1983 PSC order (the Disapproval Order) which, among other things, disapproved a 1974 gas purchase agreement between Distribution Corporation's predecessor in interest, Iroquois Gas Corporation, and Paragon (the Paragon Contract). Paragon/TGX counterclaimed for (i) a declaration that the Disapproval Order did not affect the Paragon Contract in any way, whatsoever, (ii) approximately $4,400,000 in respect of take-or-pay claims, and (iii) unquantified amounts in respect of other alleged breaches of the Paragon Contract. Commencing with its payment for production received in September 1984, Distribution Corporation has paid Paragon/TGX for Paragon Contract gas at prices below those developed by the Paragon Contract's price formula, as the same have been impacted, from time to time, by the Natural Gas Policy Act of 1978 (NGPA).
On the basis of a Memorandum and Order dated December 10, 1988, the District Court in January 1991 issued a partial summary judgment which declared that, whereas the Disapproval Order abrogated only the Paragon Contract's price term, the legal consequence of such abrogation was to render the Paragon Contract "void and no longer of any force or effect" as of December 20, 1983.
On December 3, 1991 the U. S. Court of Appeals for the Second Circuit (the Second Circuit) reversed the District Court's partial summary judgment and remanded the case to the District Court for further proceedings. The Second Circuit agreed with the District Court that the Disapproval Order had "voided the Contract's price term," but did not agree that the Paragon Contract as a whole was "voided by the cancellation of the price term." Rather, the Second Circuit found that Paragon/TGX had elected an option available to it under the Paragon Contract to continue that contract, in the aftermath of the Disapproval Order, at "a price consistent with" that order.
In a letter dated December 13, 1991, TGX demanded that Distribution Corporation pay it $21,874,042 (including interest), alleged to represent the difference between the amount received by Paragon/TGX in respect of Paragon Contract gas delivered during the period September 1984 through October 1991, and the amount allegedly due TGX in respect of such gas during such period. Distribution Corporation rejected TGX's demand.
By Order entered March 23, 1992, the District Court granted Distribution Corporation permission to amend its reply to Paragon/TGX's counterclaims to allege, among other things, (i) Distribution Corporation's "termination" of the Paragon Contract by letter effective February 1, 1988; (ii) Paragon's pre- September 1984 repudiation of the Paragon Contract; and (iii) the PSC's "primary jurisdiction" to interpret the Disapproval Order as respects "a price consistent" therewith. With respect to (iii) above, Distribution Corporation
ITEM 3. LEGAL PROCEEDINGS - (Continued)
notes that the New York State Public Service Law provides that no charge for gas made pursuant to a contract with a New York gas utility shall exceed the "just and reasonable charge" for such gas. In response to Distribution Corporation's motion for partial summary judgment in respect of the defense denominated (ii) above, the District Court, in a Memorandum and Order entered July 10, 1992, as revised by a Memorandum and Order entered March 1, 1993, denied Distribution Corporation's summary judgment motion (due to a perceived question of fact as to the occurrence of a condition precedent to Paragon's pre-September 1984 contract repudiation), but confirmed Distribution Corporation's right to assert the repudiation defense upon the trial of the action.
On January 4, 1993, the District Court entered a non-final order purportedly responsive to a February 13, 1992 Paragon/TGX motion. The order purports to declare that, by voiding the Paragon Contract price escalation mechanism effective December 31, 1983, the PSC's 1983 Disapproval Order effectively capped the Paragon Contract price, at the lesser, from time to time, of (i) the 1983 Paragon Contract summer/winter "base prices," or (ii) the applicable "Natural Gas Ceiling Prices" set forth in 18 CFR paragraph 271.101 Table I. Under date of January 19, 1993 Distribution Corporation sought rehearing, reargument, reconsideration and clarification of the January 4, 1993 order. On July 12, 1993, the District Court filed a Memorandum and Order granting in part the January 19, 1993 motion. The July 12, 1993 Order stated that, while the January 4, 1993 Memorandum and Order did determine that an obligation on Distribution Corporation's part to pay for gas purchased pursuant to the gas purchase agreement at the applicable NGPA ceiling price arose out of the conduct of the parties after the NGPA became effective and that the Disapproval Order did not relieve Distribution Corporation of such obligation, it did not determine the just and reasonable price for the gas pursuant to Public Service Law section 110(4), set a contract price for the duration of the contract, resolve any defenses presented by Distribution Corporation, determine whether such obligation continues until the present time, or rule on any deregulation issues.
Effective January 14, 1994, TGX purportedly effected a partial assignment of its interest under the Paragon Contract to an unaffiliated third-party, with whom Distribution Corporation subsequently negotiated agreements to supersede the terms of the Paragon Contract, prospectively. These transactions did not materially increase (and potentially may have decreased) Distribution Corporation's exposure in the New York Litigation.
On September 29, 1994, Paragon/TGX served an amended answer and counterclaim. That pleading restates Paragon/TGX's claims for unquantified money damages respecting Distribution Corporation's alleged (i) breach of contract price and "take-or-pay" provisions, (ii) "lack of good faith...material breach" of the contract, and (iii) repudiation of the contract. The pleading also adds two new, but unquantified claims - (i) consequential damages suffered upon the sale of properties and assignment of the Paragon Contract at less than full value, and (ii) damages related to the allegation that Distribution Corporation "tortiously and with intent injured
ITEM 3. LEGAL PROCEEDINGS - (Continued)
TGX in the conduct of its business." Distribution Corporation filed a timely reply to Paragon/TGX's claims.
The parties are awaiting a scheduling order from the magistrate regarding discovery and the trial of this proceeding.
B. Louisiana Litigation
On February 22, 1990, TGX, the purported assignee of the Paragon Contract, filed a voluntary petition pursuant to Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Western District of Louisiana (the Bankruptcy Court). Thereafter TGX commenced a "turnover" proceeding against Distribution Corporation, premised upon TGX's December 13, 1991 payment demand described above under "New York Litigation." Pursuant to a partial settlement agreement between TGX and Distribution Corporation, approved by the Bankruptcy Court in August 1992, TGX has withdrawn the "turnover" proceeding and Distribution Corporation has paid to TGX $2,940,000 in consideration of, among other things, TGX's release of Distribution Corporation from the cause of action asserted in the "turnover" proceeding. TGX is still free to pursue its breach of contract counterclaims in the New York Litigation. However, the $2,940,000 paid by Distribution Corporation to TGX will be credited against the amount, if any, which is ultimately adjudged due TGX and/or Paragon in the New York Litigation.
C. State Commission Proceedings
By its "Order Instituting Proceeding," issued in Case 93-G-0352, et al., and effective April 28, 1993, the PSC granted Distribution Corporation deferral authority in respect of the New York allocable share ($2,006,000) of the partial settlement payment described above under "Louisiana Litigation" and instituted a proceeding designed to address Distribution Corporation's request for recovery authority in respect of that amount. Distribution Corporation received authority to treat the Pennsylvania allocable share ($934,000) of the partial settlement payment as a gas cost experienced during the twelve (12) month period ending November 30, 1992.
The PSC proceeding is also expected to address Distribution Corporation's recovery in New York of gas costs incurred in respect of the Paragon Contract during the reconciliation period September 1, 1991 through August 30, 1992. Finally, the PSC proceeding is expected to include the review of the Paragon Contract in light of the "just and reasonable" standard of the New York Public Service Law.
Under date of October 25, 1994, the Administrative Law Judge (ALJ) in this proceeding issued a recommended decision (RD). The RD seemingly recommends that the maximum price Paragon/TGX should be authorized to receive for gas delivered in respect of the contract should be $3.714 per Mcf. The ALJ noted that Distribution Corporation might owe approximately $9.6 million more to Paragon/TGX under this scenario. The ALJ also found that payments previously made by Distribution Corporation were prudent and reasonable. Nonetheless, he recommended that Distribution Corporation be allowed to recover from ratepayers only one-half of the $2,006,000 payment referred to
ITEM 3 LEGAL PROCEEDINGS - (Concluded)
above and one-half of future amounts that might be paid to Paragon/TGX. The ALJ's recommendations are not binding on the PSC or the courts. All parties to the proceedings have taken exception to various portions of the RD. The PSC is expected to issue its decision in this proceeding during 1995.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter of 1994.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS
Information regarding the market for the Registrant's common stock and related shareholder matters appears in Note D - "Capitalization" and Note J - "Market for Common Stock and Related Shareholder Matters (unaudited)," on pages 67 to 71 and 83, respectively, of this report, and reference is made thereto.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For a graph of "The Revenue Dollar - 1994" see graph A. in the Appendix to this report.
Results of Operations
1994 Compared with 1993. National Fuel's consolidated earnings were $85.7 million, or $2.32 per common share, in 1994. This included $3.2 million, or $.09 per common share, related to the cumulative effect of the mandated changes in accounting for income taxes and post-employment benefits (as adopted in accordance with the Financial Accounting Standards Board's (FASB) Statements of Financial Accounting Standards (SFAS) No. 109 and No. 112, respectively). Earnings before these accounting changes amounted to $82.4 million, an increase of approximately 10% over 1993 earnings of $75.2 million. On a per-common-share basis, earnings before the accounting changes were $2.23 for 1994, up 4% from 1993 earnings of $2.15. Share amounts reflect a greater number of weighted average shares outstanding in the current year, principally because of the sale of 2.5 million shares of common stock in May 1993.
Earnings growth in 1994 was primarily due to the Company's nonregulated operations. The Exploration and Production segment's successes have continued in 1994, with record oil and gas production more than compensating for a decline in oil and gas prices. Earnings from Other Nonregulated operations increased because of the improved performance of the Company's natural gas marketing, pipeline construction and timber operations.
Earnings from the Company's regulated operations, in total, increased in 1994. The Utility Operation's earnings were up slightly over last year because of higher throughput due to colder weather, as well as State of New York Public Service Commission (PSC) and Pennsylvania Public Utility Commission (PaPUC) authorization to earn a return on increased capital investment. The Pipeline and Storage segment's earnings decreased in 1994 compared with 1993, mainly because of two nonrecurring items in 1993: the settlement of a Supply Corporation rate case which resulted in a partial reduction of a provision for refund due customers; and a change in rate design, effective August 1, 1993, which boosted 1993 earnings.
1993 Compared with 1992. Earnings were $75.2 million in 1993, up $14.9 million, or 25%, over 1992 earnings of $60.3 million. Earnings per common share in 1993 were $2.15, an 11% increase from the $1.94 earned in 1992. Share amounts reflect a greater number of weighted average shares outstanding in 1993, principally because of the sale of 2.5 million shares of common stock in each of May 1993 and September 1992.
The earnings increase in 1993 resulted from improvements in both the Pipeline and Storage and Exploration and Production segments' earnings which, in the aggregate, more than offset a decline in the earnings of the Utility Operation and the Company's Other Nonregulated operations. New rates, coupled with a change in rate design, were the major reasons for the Pipeline and Storage segment's improved results, while increased natural gas production and higher prices improved the Exploration and Production segment's performance.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Operating Income (Loss) Before Income Taxes Year Ended September 30 (in thousands) 1994 1993 1992 Utility Operation $ 90,584 $ 86,690 $ 90,025 Pipeline and Storage 62,302 67,375 49,796 Exploration and Production 21,767 12,980 7,021 Other Nonregulated 2,505 (986) 4,229 24,272 11,994 11,250 Corporate (3,463) (2,730) (2,279)
Total Operating Income Before Income Taxes $173,695 $163,329 $148,792
Operating Revenues Year Ended September 30 (in thousands) 1994 1993 1992 Utility Operation Retail Revenues: Residential $ 677,068 $ 613,039 $533,908 Commercial 177,249 156,851 139,662 Industrial 31,096 31,609 35,985 885,413 801,499 709,555 Off-System Sales 6,930 945 - Transportation 34,419 30,213 27,424 Other 4,911 3,961 3,685 931,673 836,618 740,664 Pipeline and Storage Wholesale Revenues - 444,142 425,931 Storage Service 58,971 41,041 36,064 Transportation 90,416 45,313 33,821 Other 3,734 4,072 3,054 153,121 534,568 498,870 Exploration and Production 70,261 58,636 36,303 Other Nonregulated 72,036 42,099 47,479 142,297 100,735 83,782 Less: Intersegment Revenues 85,767 451,539 402,866
Total Operating Revenues $1,141,324 $1,020,382 $920,450
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
UTILITY OPERATION
Operating Revenues
1994 Compared with 1993. Operating revenues increased $95.1 million in 1994 compared with 1993. This increase reflects recovery of increased gas costs mainly due to higher throughput, as well as general rate increases in the New York rate jurisdiction effective in both July 1993 and 1994 and in the Pennsylvania rate jurisdiction in December 1993 and higher revenues from off-system sales. Distribution Corporation, in each of its jurisdictions, has a mechanism whereby it has the opportunity to recover certain costs and retain a portion of the margin on these off-system sales.
Higher retail sales of 5 billion cubic feet (Bcf) resulted primarily from weather in Distribution Corporation's service territory that was, on average, 6.5% colder than last year. Although industrial volumes sold remained level when compared with last year, they reflected a 2.5 Bcf switch from sales to transportation service, offset by increased gas sales to a new cogeneration customer.
Transportation throughput was up 3.3 Bcf mainly because of the above noted 2.5 Bcf switch, as well as a similar switch from sales to transportation service by commercial customers of .4 Bcf. In addition, there was increased transportation of 2 Bcf to large- and small-volume industrial customers. The shut-down of three industrial customers and the bypass of National Fuel's pipeline system by three customers in the Pennsylvania jurisdiction partially offset the total increase by approximately 1.6 Bcf. Rates that go into effect in December 1994 in the Pennsylvania rate jurisdiction compensate for the loss of throughput related to these customers.
1993 Compared with 1992. Operating revenue increased $96 million in 1993 compared with 1992, although throughput remained relatively unchanged. The flow-through of higher gas costs, as well as rate increases in the New York rate jurisdiction in both July 1992 and 1993, and a rate increase in the Pennsylvania rate jurisdiction effective in December 1991, resulted in increased revenues. Weather-sensitive residential throughput increased 2.1 Bcf as a result of weather that was, on average, 1.9% colder than last year in Distribution Corporation's service territory. Combined industrial and end-user transportation throughput decreased 2.4 Bcf as a result of the bankruptcy of a major customer in Pennsylvania and a decrease in boiler fuel sales. These declines were partially mitigated by a significant increase attributable to a full year's throughput for a cogeneration project that came on line in May 1992.
Operating Income
1994 Compared with 1993. Operating income before income taxes increased $3.9 million in 1994 compared with 1993. This increase reflects higher revenues, discussed above, partly offset by increased operating expenses. The severe cold weather during January and February 1994 necessitated an unusually high number of system repairs and related site restoration work, which increased maintenance expense.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
The impact of weather on Distribution Corporation's New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on pretax operating income and earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits Distribution Corporation's New York customers. In 1994, the WNC in New York resulted in a benefit to customers of $5.8 million. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact pretax operating income and earnings. In the Pennsylvania service territory, weather was 9.6% colder than last year and 8.4% colder than normal. The colder weather in 1994 compared with 1993 had a positive impact on pretax operating income and earnings for the Pennsylvania rate jurisdiction.
1993 Compared with 1992. Operating income before income taxes decreased $3.3 million in 1993 compared with 1992. This decline reflects the impact of lower average gas use per residential account in the New York rate jurisdiction compared with that imputed in rates resulting in a lower margin on gas sales which was not adequate to cover the increase in operating expenses. This problem was remedied by reflecting a lower usage per account in Distribution Corporation's rates that went into effect on July 23, 1993, in New York. In 1993, the WNC in New York preserved pretax operating income of $1.2 million and earnings per share of $.02. In the Pennsylvania service territory, weather was 2.5% colder in 1993 than 1992, although it was 5.4% warmer than normal. This colder weather had a positive impact on pretax operating income and earnings for the Pennsylvania rate jurisdiction.
Degree Days
Percent Colder (Warmer) Than Year Ended September 30 Normal Actual Normal Last Year 1994: Buffalo 6,710 6,975 3.9% 3.6% Erie 6,202 6,726 8.4% 9.6% 1993: Buffalo 6,723 6,730 0.1% 1.3% Erie 6,484 6,135 (5.4%) 2.5% 1992: Buffalo 6,778 6,644 (2.0%) 15.9% Erie 6,556 5,983 (8.7%) 13.1%
Purchased Gas. The cost of purchased gas is by far the Company's single largest operating expense. Annual variations in purchased gas costs can be attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and five upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers and for storage service with Supply Corporation and two nonaffiliated companies. In addition, Distribution Corporation can satisfy a portion of its gas requirements through spot market purchases. Distribution Corporation's average cost of purchased gas, including the cost of transportation, was $3.74 per thousand cubic feet (Mcf) in 1994, a decrease of 3% from the average cost of $3.84 per Mcf in 1993. The average cost of purchased gas in 1993 was 22% higher than the $3.15 per Mcf in 1992.
System Throughput (billion cubic feet) Year Ended September 30 1994 1993 1992 Utility Operation Retail Sales: Residential 90.6 86.9 84.8 Commercial 26.9 25.6 25.9 Industrial 6.5 6.5 9.1 124.0 119.0 119.8
Transportation- End-Users 52.2 48.9 48.7 176.2 167.9 168.5 Pipeline and Storage Wholesale Sales - 118.7 130.3 Transportation 295.3 138.6 157.0 295.3 257.3 287.3 Less Intersegment Throughput: Sales - 112.2 122.0 Transportation 164.2 40.1 33.2 164.2 152.3 155.2 Total System Throughput 307.3 272.9 300.6
PIPELINE AND STORAGE
Operating Revenues
1994 Compared with 1993. Operating revenues decreased $381.4 million in 1994 compared with 1993. This decline reflects Supply Corporation's restructured operations under the Federal Energy Regulatory Commission's (FERC) Order 636, which became effective August 1, 1993. Under Order 636, Supply Corporation's gas purchasing and sales functions were discontinued and replaced with new transportation and storage services, thus the recovery of purchased gas costs has been eliminated from Supply Corporation's revenues.
1993 Compared with 1992. Operating revenues increased $35.7 million in 1993 compared with 1992, despite a 30 Bcf decline in throughput. New rates that became effective in July 1992, subject to refund, significantly increased
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
revenues in 1993. Supply Corporation filed a Stipulation and Agreement (the Settlement) with the FERC on October 15, 1993, respecting these new rates. As a result of the Settlement, Supply Corporation reversed approximately $15 million of its previously accrued refund provision. Approximately $2.8 million of the amount reversed related to 1992. Additionally, as the Settlement included full recovery of Supply Corporation's portion of the net periodic post-retirement benefit costs under SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Supply Corporation recorded $3.6 million of related post-retirement benefit expense. These adjustments relate to rates that were in effect since July 1, 1992, subject to refund. The change to the straight fixed-variable (SFV) rate design mandated by Order 636, which provides for recovery of Supply Corporation's fixed costs in the demand, or reservation charge, contributed additional revenues of approximately $2.7 million for August and September 1993 when compared to Supply Corporation's former rate design. All of these items were reflected in earnings in the fourth quarter of 1993.
Operating Income
1994 Compared with 1993. Operating income before income taxes decreased $5.1 million in 1994 compared with 1993. This decrease was principally because of two nonrecurring items reflected in 1993. The favorable Settlement in 1993, discussed above, resulted in Supply Corporation recording approximately $2.8 million of revenues in 1993 that related to 1992. In addition, the change to the SFV rate design contributed additional revenues of approximately $2.7 million for August and September 1993, when compared to Supply Corporation's former rate design.
Throughput increased 38 Bcf in 1994 and can be attributed to increased utilization of Supply Corporation's Canadian gas transportation facilities, the expanded capacity of these facilities and weather that was colder than last year. However, because of the SFV rate design, the increase in throughput did not have a significant impact on pretax operating income.
1993 Compared with 1992. Operating income before income taxes increased $17.6 million in 1993 compared with 1992. This increase was mainly the result of higher revenues, discussed above, which were partly offset by higher gas costs and operation and maintenance (O & M) expenses, primarily for labor and employee benefits.
EXPLORATION AND PRODUCTION
Operating Revenues
1994 Compared with 1993. Operating revenues increased $11.6 million in 1994 compared with 1993. This increase was primarily attributable to Seneca's Gulf Coast operations and reflects the continued success of both its offshore drilling program in the Gulf of Mexico and its horizontal drilling program in central Texas. Gas production and oil production (mainly condensate from gas wells) hit record levels in 1994 and were up 34% and 59%, respectively, in the
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Gulf Coast Region and 17% and 24%, respectively, for all geographic regions combined.
Systemwide, the average price received for gas and oil production in 1994 was $2.18 per Mcf and $14.86 per barrel (bbl), respectively. This is a decline of $.02 per Mcf in gas prices and $1.92 per bbl in oil prices compared with 1993. Nonetheless, efforts to stabilize prices through hedging activities contributed approximately $1.6 million of operating revenues for the year. At present, Seneca's goal is to hedge approximately 60% of its Gulf Coast gas and oil production.
1993 Compared with 1992. Operating revenues increased $22.3 million in 1993 compared with 1992. This increase was also primarily attributable to Seneca's Gulf Coast operations. Natural gas production from the Gulf Coast operations increased 217% to 12.1 Bcf from 3.8 Bcf in 1992. In total, from all geographic areas, production rose by 7.8 Bcf to 19.9 Bcf. Lower natural gas production was realized from Appalachian and West Coast properties. Systemwide, the average price received for gas production in 1993 was $2.20 per Mcf, an increase of $.23 per Mcf from $1.97 per Mcf in 1992. Oil production (mainly condensate from gas wells) also increased in 1993 by 188,000 bbls compared with 1992. Systemwide, the average price received for oil production in 1993 was $16.78 per bbl, a decrease of $.33 per bbl from $17.11 per bbl in 1992.
Production Volumes Year Ended September 30 1994 1993 1992
Gas Production (million cubic feet) Gulf Coast 16,296 12,134 3,828 West Coast 706 1,059 1,234 Appalachia 6,271 6,681 7,008 23,273 19,874 12,070
Oil Production (thousands of barrels) Gulf Coast 615 387 172 West Coast 404 431 454 Appalachia 11 13 17 1,030 831 643
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Operating Income
1994 Compared with 1993. Operating income before income taxes increased $8.8 million in 1994 compared with 1993. This increase reflects the higher revenues discussed above, partly offset by higher depletion expense which is directly related to higher revenues. O & M expense remained basically level in 1994 compared with 1993. Although O & M expense related to increased production activity in the Gulf Coast operations was higher in 1994 than 1993, it was offset by a charge to O & M in 1993 for work performed on Appalachian wells that did not recur in 1994.
1993 Compared with 1992. Operating income before income taxes increased $6 million in 1993 compared with 1992. This increase was also the result of the increase in operating revenues, discussed above, partly offset by increases in depletion and O & M expenses. The increase in O & M expenses is related to the increased production activity in the Gulf Coast operations. Additionally, a charge to O & M expense of $2.3 million was recorded in the fourth quarter of 1993 for work performed on Appalachian wells.
OTHER NONREGULATED
Operating Revenues
1994 Compared with 1993. Operating revenues increased $29.9 million in 1994 compared with 1993. This increase is almost entirely due to higher revenues from NFR, the Company's gas marketing subsidiary, as its gas marketing volumes more than doubled to 18.2 Bcf in 1994 from 7.3 Bcf in 1993.
1993 Compared with 1992. Operating revenues decreased $5.4 million in 1993 compared with 1992. This decline reflected lower revenues from UCI, the Company's pipeline construction subsidiary, partly offset by higher revenues from NFR. UCI had an exceptionally productive year in 1992, completing several projects in Virginia and New York for nonaffiliated pipeline companies that were expanding their systems. The lack of large projects in 1993 negatively impacted UCI's revenues. NFR's revenues increased in 1993, as gas marketing volumes increased to 7.3 Bcf from 5.4 Bcf in 1992.
Operating Income
1994 Compared with 1993. Operating income before income taxes increased $3.5 million in 1994 compared with 1993. This increase is due to the improved performance of UCI, which, although still operating at a loss, had higher margins than in 1993. In addition, the improved performance of NFR and the Company's timber operations enhanced operating income before income taxes of this segment.
1993 Compared with 1992. Operating income before income taxes decreased $5.2 million in 1993 compared with 1992. This decline was mainly the result of the lack of a contribution by UCI to operating income before income taxes. The lack of large projects, coupled with tight margins contributed to poor performance in 1993. This more than offset the increase in NFR's operating income before income taxes resulting from increased marketing activities.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
INCOME TAXES, OTHER INCOME AND INTEREST CHARGES
Income Taxes. Income taxes increased in 1994 and 1993, mainly because of increases in pretax income as well as higher income tax rates. In addition, the increase in income taxes in 1994 reflects lower Section 29 nonconventional fuel tax credits. These credits, which relate to production from qualified gas wells, decreased to $1.7 million in 1994, down from $2.6 million in 1993. These credits are a direct reduction of income tax expense.
Other Income. Other income decreased $1.2 million and $1 million in 1994 and 1993, respectively. A portion of the decrease in 1994 and 1993 was because Distribution Corporation discontinued the accrual of interest income on deferred contract reformation costs (CRC) in April 1993, in accordance with a settlement with the PSC for full recovery of CRC. In addition, the decrease in 1994 reflects lower interest income on temporary cash investments.
Other income also decreased in 1993 because of lower income associated with funds used during construction by the Pipeline and Storage segment resulting from lower construction balances. The decreases in 1993 were partly offset by higher interest income on temporary cash investments related to the proceeds from the September 1992 issuance of 2.5 million shares of common stock.
Interest Charges. Interest on long-term debt decreased $1.8 million and $1.4 million in 1994 and 1993, respectively. This was mainly due to refinancing activities, whereby higher-interest long-term debt was replaced with lower-interest long-term debt and with equity.
Other interest charges decreased $3 million and $5.7 million in 1994 and 1993, respectively. The declines in both 1994 and 1993 reflect lower interest on short-term borrowings because of lower average amounts outstanding. A lower weighted average interest rate in 1993 also contributed to the decline in short-term interest. However, 1994 reflects an increase in the weighted average interest rate.
1995 OUTLOOK
The coming year will be one of transition for the Company as it works through the impact of the FERC's Order 636 on the state level. As a result, 1995 earnings are expected to be lower than the record earnings of 1994. However, management continues to believe that the integrated strength of the Company places it on a course for growth in 1996 and beyond.
When reviewing 1994 earnings it is important to note that $.09 per share was due to the cumulative effect of mandated accounting changes which will not recur in 1995. In addition, allowed returns on pipeline equity are expected to decrease as a result of allegedly lower risks associated with that business. Supply Corporation, therefore, anticipates a lower return on equity for rates to become effective in 1995. Further, in the Utility Operation, Distribution Corporation saw its allowed return on equity in its New York rate jurisdiction fall from 12.0% to 10.7% in July. The Company expects allowed returns on equity at the state level to increase in future years as a result of the state
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
commission recognition of increased risks under the FERC's Order 636, as well as the rise in interest rates. Nevertheless, such a rise will not significantly benefit 1995 earnings.
Our Exploration and Production segment, and our Other Nonregulated operations should increase their earnings contribution in 1995. However, the current low prices received for natural gas production will temper the increase and, therefore, it is unlikely that increased contributions for our nonregulated operations will cause consolidated earnings to increase in 1995.
CAPITAL RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
Sources and (Uses) of Cash Year Ended September 30 (in millions) 1994 1993 1992 Provided by Operating Activities $199.2 $123.7 $ 93.0 Capital Expenditures (135.1) (131.9) (157.9) Short-Term Debt (84.3) (30.2) 20.5 Long-Term Debt, Net Change 80.1 (51.1) 74.3 Issuance of Common Stock 9.1 78.8 73.7 Common Dividends (57.2) (52.2) (45.6) All Other-Net 3.6 .2 (2.1) Net Increase (Decrease) in Cash and Temporary Cash Investments $ 15.4 $(62.7) $ 55.9
OPERATING CASH FLOW
Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, deferred income taxes and allowance for funds used during construction. In 1994, noncash items also included the cumulative effect of required changes in accounting for income taxes and post-employment benefits in accordance with SFAS 109 and SFAS 112, respectively.
Cash provided by operating activities in the Utility Operation and Pipeline and Storage segment may vary substantially from year to year because of fluctuations in weather, supplier refunds, the impact of rate cases, and for the Utility Operation, fluctuations in over- or under-recovered purchased gas costs. The impact of weather on cash flow is tempered in the Utility Operation's New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation's SFV rate design.
For a graph of "Book Value Per Common Share" see graph B. in the Appendix of this report.
Net cash provided by operating activities totalled $199.2 million in 1994, an increase of $75.5 million compared with the $123.7 million provided by
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
operating activities in 1993. This increase reflected higher revenues and earnings in the Exploration and Production segment, mainly from its Gulf Coast operations. The Utility Operation had an increase in cash flow from operations mainly because Distribution Corporation had over-recovered purchased gas costs at September 30, 1994, while it was in an under-recovery position at September 30, 1993. In addition, the Pipeline and Storage segment had an increase in upstream pipeline company refunds received in 1994, thus increasing its cash flow from operations.
INVESTING CASH FLOW
Capital Expenditures. Capital expenditures totalled $138.3 million in 1994. The table below presents these expenditures by business segment:
Year Ended September 30 (in millions) 1994 Percentage Utility Operation $ 61.7 44.6% Pipeline and Storage 20.5 14.8 Exploration and Production 52.5* 38.0 Other Nonregulated 3.6 2.6 $138.3* 100%
* Includes noncash acquisition of $3.2 million in a stock-for-asset swap.
Most of the Utility Operation's capital expenditures were for the replacement of mains and main extensions, as well as for the replacement of service lines and the installation of new services.
Pipeline and Storage capital expenditures included an increase in compression at two locations, other additions, improvements and replacements to the Company's transmission and storage systems.
The majority of the Exploration and Production segment's capital expenditures were made for the exploration for and development of oil and gas properties located offshore in the Gulf of Mexico, and in Seneca's Northeast Clay Field in central Texas. As a result of activity in the Gulf Coast Region, reserves included 93.4 Bcf of new gas reserves and 1.1 million barrels of new oil reserves at September 30, 1994. In addition, capital expenditures in the Appalachian Region included $3.2 million for the acquisition of natural gas production assets in exchange for Company common stock. This acquisition added approximately 3 Bcf of gas reserves.
Other Nonregulated capital expenditures included timberland and equipment purchases.
The Company's estimated capital expenditures for the next three years are:
Year Ended September 30 (in millions) 1995 1996 1997 Utility Operation $ 63.6 $ 59.1 $ 58.1 Pipeline and Storage 38.0 17.6 18.3 Exploration and Production 74.3 78.2 80.8 Other Nonregulated 7.1 1.2 1.3 $183.0 $156.1 $158.5
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Estimated expenditures for the Utility Operation during the next three years will be concentrated in the areas of main replacements and extensions, service line replacements and, to a minor extent, the installation of new services.
Included in the Pipeline and Storage segment's capital expenditures for 1995 is approximately $5.6 million to be spent in connection with several expansion projects, the most significant of which is a link with the Empire State Pipeline at Grand Island, New York. This will greatly increase the reliability, flexibility and efficiency of service to the Company's service territory in the areas north of Buffalo and to Grand Island, New York.
Also included in the 1995 capital expenditures is approximately $4.3 million for compressor engine emission controls necessary to comply with the standards of the Clean Air Act Amendments of 1990 (the Act). Approximately $.6 million of capital expenditures were incurred in 1994 to comply with the Act. The Company does not anticipate incurring significant additional capital expenditures to comply with the current standards of the Act. However, changes in standards may require additional expenditures in the future. Management expects that all related capital expenditures will be recoverable through rates.
Significant capital expenditures related to Supply Corporation's Laurel Fields Storage Project (which is pending the FERC's approval) are not expected to be incurred until 1996. Since the timing of expenditures related to this project are not finalized, the preceding table does not include significant amounts for this project. Laurel Fields is a 19 Bcf underground natural gas storage development project, which entails the development of Supply Corporation's Callen Run (a depleted gas field) and expansion of its Limestone Storage Field. Filings with the FERC were made in June 1994 to implement this project. An "open season" was held in August 1994 to identify prospective customers for this project. Precedent agreements are currently being negotiated with interested customers. On November 4, 1994, a proposal was sent to the FERC to divide the project into two phases. Phase I would encompass the expansion of the Limestone Storage Field to accommodate approximately 7 Bcf of storage and phase II would consist of the development of the Callen Run Storage Field. The potential cost of the project is approximately $200 million.
For a graph of "Capital Expenditures" see graph C. in the Appendix to this report.
Estimated capital expenditures in 1995 for the Exploration and Production segment are approximately 40% higher than capital spending in 1994 as the Company sees significant opportunities for growth in this segment. These expenditures will be directed mainly toward developing Seneca's Gulf Coast offshore prospects, evaluating reserve acquisitions and significantly expanding exploration activities. Capital expenditures for Other Nonregulated operations will primarily be used for timberland.
The Company's capital expenditure program is under continuous review. The amounts are subject to modification for opportunities in the natural gas industry such as the acquisition of attractive oil and gas properties or storage
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
facilities and the expansion of transmission line capacities. The magnitude of future capital expenditures in the regulated segments depends, to a large degree, upon market conditions coupled with adequate rate relief.
Other. Cash received on the sale of the Company's investment in property, plant and equipment is reflected as a cash flow from investing activities. Approximately $2.3 million of cash was received in the first quarter of fiscal 1994, related to the fiscal 1993 sale of Seneca's interest in its Alberta, Canada, gas reserves.
FINANCING CASH FLOW
In order to meet the Company's capital requirements, cash from external sources must periodically be obtained through short-term bank loans and commercial paper, as well as through issuances of long-term debt and equity securities. The Company expects these traditional sources of cash to continue to supplement its internally generated cash during the next several years.
On July 1, 1994, the Company redeemed $19.9 million remaining outstanding principal amount of 9-1/2% debentures due July 1, 2019, for $21.3 million, including redemption premium.
On July 14, 1994, the Company issued $50 million of medium-term notes due July 1999, at an interest rate of 7.25%. Also on July 14, 1994, the Company issued $50 million of medium-term notes due July 2024, at an interest rate of 8.48%. These latter notes are callable beginning July 1999. After reflecting underwriting discounts and commissions, the combined proceeds to the Company of these two issuances amounted to $99.4 million. The proceeds were used to reduce outstanding short-term borrowings.
The Company's embedded cost of long-term debt was 7.3% at both September 30, 1994 and 1993.
At September 30, 1994, the Company has Securities and Exchange Commission (SEC) authority remaining under a shelf registration filed in March 1993 to issue and sell up to $220 million of debentures and/or medium-term notes. The amounts and timing of the issuance and sale of these debentures and/or medium-term notes will depend on market conditions and the requirements of the Company.
For a graph of "Embedded Cost of Long-Term Debt" see graph D. in the Appendix to this report.
Consolidated short-term debt decreased $84.3 million during 1994. The Company continues to consider short-term bank loans and commercial paper important sources of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, exploration and development expenditures and other working capital needs.
The Company, through Seneca and NFR, is engaged in certain natural gas and crude oil price swap agreements and in the gas futures market as a means of
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
hedging a portion of the market risk associated with fluctuations in the market price of natural gas and crude oil. In addition, the Company has SEC authority to enter into interest rate swap agreements. For further discussion, see disclosure under "Financial Instruments" in Note A - Summary of Significant Accounting Policies.
The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation nor these other regulatory matters are expected to materially change the Company's present liquidity position.
The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company's covenants contained in its indenture covering long-term debt, at September 30, 1994, the Company would have been permitted to issue up to a maximum of $434.5 million in additional long-term unsecured indebtedness, subject to maturity and long-term interest rates. In addition, at September 30, 1994, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $287.5 million of short-term debt.
For a graph of "Capitalization Ratios" see graph E. in the Appendix to this report.
RATE MATTERS
Utility Operation
New York Jurisdiction
In October 1994, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $56.5 million, or 8.9%, with a requested return on equity of 12.85%. New rates are expected to become effective in August or September 1995. On November 17, 1994, Distribution Corporation presented the PSC staff with a preliminary proposal for a multi-year settlement.
In August 1993, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $55.4 million, or 8.5%, with a return on equity of 12.16%. Included in the requested rate increase was an initial amount of $24.9 million for the recovery of transition costs arising from the FERC's Order 636, which represented 3.8% of the total 8.5% requested increase.
On July 19, 1994, the PSC issued an order authorizing a base rate increase of $11.1 million, or 1.7%, with a return on equity of 10.7%. In addition, the PSC authorized recovery of transition costs arising from the FERC's Order 636
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
of up to $11 million annually from sales customers through the monthly Gas Adjustment Clause (GAC). Distribution Corporation will defer, for recovery in future periods, any amounts that may exceed the $11 million annual amount. New rates became effective July 24, 1994.
The recovery of transition costs from transportation customers in New York remains unresolved. The PSC has postponed its decision on transportation customers' allocable share of transition costs pending further consideration of the issue in a generic restructuring case (the Generic Case) which began in October 1993. The PSC staff's position in the Generic Case is that transportation customers should be assigned a per-unit charge that is equal to 50% of the per-unit charge being collected from sales customers for gas supply realignment (GSR) costs and stranded costs. The PSC has authorized Distribution Corporation's continued deferral of transition costs relating to transportation customers until resolution in the Generic Case. At September 30, 1994, deferred transition costs related to transportation customers amounted to approximately $2 million.
In July 1993, in connection with a previously approved two-year settlement, Distribution Corporation received PSC approval for the second year of the settlement. The approval was for a rate increase of $13.3 million, or 2.1%, for the 12-month period ended July 31, 1994. This rate increase went into effect on July 23, 1993.
Pennsylvania Jurisdiction
On March 8, 1994, Distribution Corporation filed in its Pennsylvania jurisdiction a request for an annual rate increase of $16 million, or 6.8%, with a return on equity of 12.25%. A proposal for a WNC was included in this filing. On December 6, 1994, an order was issued by the PaPUC authorizing an annual rate increase of $4.8 million, or 2.0 %, with a return on equity of 11.0% and without a WNC. New rates are scheduled to become effective as of December 7, 1994.
In March 1993, Distribution Corporation filed with the PaPUC for an annual rate increase in its Pennsylvania jurisdiction of $33.4 million, or 16.2%, with a return on equity of 12.4%. Included in the requested rate increase was an initial amount of $8.2 million for the recovery of transition costs arising from the FERC's Order 636. On December 1, 1993, an order was issued by the PaPUC authorizing an annual rate increase of $11.4 million, or 4.9%, exclusive of transition costs. The new rates became effective as of December 1, 1993.
The PaPUC's December 1, 1993 order also addressed certain issues concerning recovery of GSR costs and stranded costs resulting from the implementation of the FERC's Order 636. Under this order, Distribution Corporation began collecting, effective December 1, 1993, GSR and stranded costs from its customers through a separate surcharge. Distribution Corporation is allowed to update this surcharge on a quarterly basis. Distribution Corporation is recovering under-recovered purchased gas transition costs from its Pennsylvania sales customers through its gas cost recovery rates.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
General rate increases do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses.
State Regulatory Environment
The seeds of change precipitated by the FERC's Order 636 are redefining the roles of the utility industry and the state regulatory commissions. Competition has arrived for utilities, and it is anticipated that, similar to what was done in the pipeline sector of the natural gas industry, regulators will require utilities to unbundle their services. The anticipated result is that utility service will divide into "core" markets consisting of the typical residential and commercial customers, as well as customers taking firm transportation service and the "non-core" markets consisting of competitive commercial and industrial markets. It is anticipated that non-core services will be lightly regulated and, with respect to core customers, regulators are expected to focus on increased utility efficiency.
Many state regulators believe that utilities can gain efficiency through performance-based incentive ratemaking. Such ratemaking is intended to enhance the traditional cost-of-service ratemaking formula, which many believe does not provide incentives to operate efficiently. Distribution Corporation has proposed several customer service performance incentives in its New York rate case filed in October 1994. If these incentives are accepted, the mechanisms would allow the PSC to administer financial penalties or rewards determined by the utility's ability to meet or exceed required performance levels. The proposed incentives relate to: response time to customer inquiries and complaints; billing accuracy; keeping appointments for service; and efficiency in the installation of new service lines.
The New York and Pennsylvania regulatory commissions have instituted several generic proceedings related, among other things, to restructuring in response to the FERC's Order 636. The more significant ones, all of which are still pending, are discussed below:
New York
Finance Proceeding. The purpose of this proceeding is to develop a uniform method for calculating a utility's rate of return on equity.
Ratesetting Proceeding. This proceeding is intended to develop guidelines for settlements, incentive ratemaking and multi-year rate filings, in addition to the traditional single-year procedure. Thus, a menu of options would be available for each utility to select the appropriate ratemaking proposal.
Generic Restructuring Proceeding. This proceeding is examining the appropriate retail or end-use impacts resulting from the FERC's Order 636 pipeline restructuring. It is expected that the PSC will issue an order addressing key issues such as unbundling, rate design and the extent of state regulation. Implementation will likely be achieved by each utility on a case-by-case basis.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Pennsylvania
Settlement Guidelines. This proceeding is intended to develop orders addressing specific rules of procedure to accomplish settlement of complex proceedings, including rate cases.
FERC Order 636 Proceedings. The PaPUC has thus far responded to the FERC's Order 636 with three generic proceedings addressing different operational areas. They are proceedings on transportation services, gas procurement practices (including a gas purchase incentive mechanism) and capacity release. Distribution Corporation has already implemented many of the proposed changes in previous rate cases and expects that additional changes will not significantly alter current operations.
Distribution Corporation is working closely with the state regulatory commissions to resolve the complexities of industry restructuring.
Pipeline and Storage
For a discussion of Supply Corporation's gathering rates, refer to Note B - Regulatory Matters.
On October 31, 1994, Supply Corporation filed for an annual rate increase of $21 million, with a requested return on equity of 12.6%. This rate case was filed as a result of the FERC's order issued on October 28, 1994, rejecting Supply Corporation's rate case filed on September 30, 1994. The FERC rejected the September 30, 1994 filing because it disagreed with the proposed method of rolling-in rates for the storage service previously offered by Penn-York (Penn-York was merged into Supply Corporation effective July 1, 1994).
On December 30, 1993, the FERC issued an order approving, with slight modification the Settlement, which was filed with the FERC on October 15, 1993, respecting two Supply Corporation rate proceedings. As modified, the Settlement provided for rates that produced annual revenues of approximately $125 million between July 1, 1992, and July 31, 1993. Rates for the period beginning August 1, 1993, reflect reduced costs after restructuring plus certain settlement concessions, and will produce revenues of approximately $121 million annually. As a result of the Settlement, Supply Corporation refunded to its customers $13.6 million, including interest, during the second quarter of 1994.
OTHER MATTERS
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures.
Distribution Corporation has been identified by the Environmental Protection Agency or the New York State Department of Environmental Conservation (DEC) as one of a number of companies that are considered to be potentially
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
responsible parties (PRPs) with respect to several waste disposal sites in New York that were operated by unrelated third parties. These PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to Distribution Corporation with respect to the remediation of these sites will be dependent on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion attributed, if any, to Distribution Corporation. Distribution Corporation's estimated share of the clean-up costs has been accrued for four of these sites.
One of these four sites was formerly used for a manufactured gas plant. Distribution Corporation is currently involved in litigation regarding this site. The current owner of the site has submitted a claim against Distribution Corporation for contribution of a share of approximately $1.6 million of removal/remediation costs that have been incurred. It is anticipated that future remedial costs will be incurred and on the basis of a Record of Decision issued by the DEC, as amended on September 19, 1994, the estimated future remedial costs for the site are approximately $5.7 million. Management believes that the ultimate outcome of these matters will not have a material impact on the financial condition, results of operations or cash flows of the Company.
Distribution Corporation has incurred clean-up costs at two additional sites in New York and one site in Pennsylvania related to former manufactured gas plant sites. Supply Corporation is involved in a remediation program of certain of its measuring and regulating stations in Pennsylvania. Estimated clean-up costs have been accrued for these sites.
It is the Company's policy to accrue estimated clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated that clean-up costs related to the above noted sites are in the range of $6.7 million to $10.1 million. At September 30, 1994, the Company has recorded the minimum liability of $6.7 million. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.
In New York, Distribution Corporation has received approval from the PSC to defer and amortize both former manufactured gas and non-manufactured gas site investigation and remediation costs over a three-year period for each site. These costs are then included in rate cases for recovery through base rates. Distribution Corporation is currently recovering such costs in this manner. In Pennsylvania, Distribution Corporation and Supply Corporation expect to recover such costs in rates, as the PaPUC and the FERC, respectively, have allowed recovery of other environmental clean-up costs in rate cases. Accordingly, the Consolidated Balance Sheets at September 30, 1994, include related regulatory assets in the amount of approximately $7.3 million, $.6 million of which relates to costs that have already been incurred.
Effects of Inflation. Although the rate of inflation has been relatively low over the past few years, and thus has benefited both the Company and its
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Concluded)
customers, the Company's operations remain sensitive to increases in the rate of inflation because of the capital-intensive and regulated nature of its major operating segments.
Delays inherent in the ratemaking process prevent the Company from obtaining immediate recovery of increased operating costs. Also, while the ratemaking process gives no recognition to the current cost of replacing property, plant and equipment, based on past practices the Company believes that it will be allowed to earn on the increased cost of its net investment when replacement of facilities occurs.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page Financial Statements:
Report of Independent Accountants 53
Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 1994 54
Consolidated Balance Sheets at September 30, 1994 and 1993 55 - 56
Consolidated Statement of Cash Flows, three years ended September 30, 1994 57
Notes to Consolidated Financial Statements 58 - 88
Financial Statement Schedules: For the three years ended September 30, 1994
V -Property, Plant and Equipment 89 and 91
VI -Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment 90 - 91
VIII-Valuation and Qualifying Accounts and Reserves 92
IX -Short-Term Borrowings 93
X -Supplementary Income Statement Information 94
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
Supplementary Data
Supplementary data that is included in Note I - "Quarterly Financial Data (unaudited)" and Note K - "Supplementary Information For Oil and Gas Producing Activities," appears on page 82 and pages 84 to 88, respectively, of this report, and reference is made thereto.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Report of Independent Accountants
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
As discussed in Notes A and F to the consolidated financial statements, the Company adopted the new accounting standards for postretirement benefits other than pensions, income taxes and other postemployment benefits in fiscal 1994.
PRICE WATERHOUSE LLP
Buffalo, New York October 28, 1994
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
National Fuel Gas Company Consolidated Statements of Income and Earnings Reinvested in the Business
Year Ended September 30 1994 1993 1992 (Thousands of Dollars) INCOME Operating Revenues $1,141,324 $1,020,382 $920,450
Operating Expenses Purchased Gas 497,687 409,005 363,690 Operation Expense 260,411 258,918 240,645 Maintenance 30,979 24,312 22,439 Property, Franchise and Other Taxes 103,788 95,393 89,158 Depreciation, Depletion and Amortization 74,764 69,425 55,726 Income Taxes - Net 47,792 41,046 35,231 1,015,421 898,099 806,889
Operating Income 125,903 122,283 113,561 Other Income 3,656 4,833 5,790 Income Before Interest Charges 129,559 127,116 119,351
Interest Charges Interest on Long-Term Debt 36,699 38,507 39,949 Other Interest 10,425 13,392 19,092 47,124 51,899 59,041
Income Before Cumulative Effect 82,435 75,217 60,310 Cumulative Effect of Changes in Accounting 3,237 - -
Net Income Available for Common Stock 85,672 75,217 60,310
EARNINGS REINVESTED IN THE BUSINESS Balance at Beginning of Year 335,907 314,334 301,066 421,579 389,551 361,376
Dividends on Common Stock 57,725 53,644 47,042
Balance at End of Year $ 363,854 $ 335,907 $314,334
Earnings Per Common Share Income Before Cumulative Effect $2.23 $2.15 $1.94 Cumulative Effect of Changes in Accounting .09 - -
Net Income Available for Common Stock $2.32 $2.15 $1.94
Weighted Average Common Shares Outstanding 37,046,249 34,938,722 31,152,635
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
National Fuel Gas Company Consolidated Balance Sheets
At September 30 1994 1993 (Thousands of Dollars) ASSETS Property, Plant and Equipment $2,166,256 $2,039,436 Less - Accumulated Depreciation, Depletion and Amortization 623,517 561,433 1,542,739 1,478,003 Current Assets Cash and Temporary Cash Investments 29,016 13,595 Receivables - Net 95,993 86,957 Unbilled Utility Revenue 17,311 27,210 Gas Stored Underground 34,711 22,120 Materials and Supplies - at average cost 23,796 20,848 Unrecovered Purchased Gas Costs - 20,772 Prepayments 20,111 17,094 220,938 208,596
Other Assets Recoverable Future Taxes 99,742 - Unamortized Debt Expense 28,396 28,735 Other Regulatory Assets 47,737 43,644 Deferred Charges 15,796 21,255 Other 26,309 21,307 217,980 114,941
$1,981,657 $1,801,540
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
National Fuel Gas Company Consolidated Balance Sheets
At September 30 1994 1993 (Thousands of Dollars) CAPITALIZATION AND LIABILITIES Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized - 100,000,000 Shares; Issued and Outstanding - 37,278,409 Shares and 36,661,008 Shares, Respectively $ 37,278 $ 36,661 Paid In Capital 379,156 363,677 Earnings Reinvested in the Business 363,854 335,907 Total Common Stock Equity 780,288 736,245 Long-Term Debt, Net of Current Portion 462,500 478,417 Total Capitalization 1,242,788 1,214,662
Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 112,500 196,800 Current Portion of Long-Term Debt 96,000 - Accounts Payable 66,667 42,893 Amounts Payable to Customers 38,714 40,776 Other Accruals and Current Liabilities 61,368 69,523 375,249 349,992 Deferred Credits Accumulated Deferred Income Taxes 273,560 188,793 Taxes Refundable to Customers 31,688 - Unamortized Investment Tax Credit 14,057 14,743 Other Deferred Credits 44,315 33,350 363,620 236,886 Commitments and Contingencies - -
$1,981,657 $1,801,540
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note A - Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned. All significant intercompany balances and transactions have been eliminated where appropriate.
Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation.
Regulation. Two of the Company's principal subsidiaries, National Fuel Gas Distribution Corporation (Distribution Corporation) and National Fuel Gas Supply Corporation (Supply Corporation) are subject to regulation by state and federal authorities having jurisdiction. The Company accounts for these regulated operations in accordance with Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulation." This statement sets forth the application of generally accepted accounting principles for those companies whose rates are established by or are subject to approval by an independent third-party regulator. Under SFAS 71, regulated companies defer costs as assets on the balance sheet (regulatory assets) when these costs have been or are expected to be allowed in the ratesetting process in a period different from the period in which the costs would be charged to expense by an unregulated company. These deferred regulatory assets are then flowed through the income statement in the period in which the same amounts are recovered in revenues through rates.
Costs deferred in accordance with SFAS 71 include "Recoverable Future Taxes," "Unamortized Debt Expense" and "Other Regulatory Assets." Refer to the separate Income Taxes and Unamortized Debt Expense sections of this Note for further discussion. Other regulatory assets are shown below:
At September 30 (in thousands) 1994 1993
Pension and Post-Retirement Benefit Costs (Note F) $17,199 $ 8,125 Order 636 Transition Costs* (Note B) 8,417 200 Deferred Contract Reformation Costs (Note B) 7,736 24,862 Environmental Clean-up (Note G) 7,310 4,873 All Other 7,075 5,584
$47,737 $43,644
* Exclusive of amounts being collected through gas costs. Such amounts are included in unrecovered purchased gas costs.
Revenues. Revenues are recorded as bills are rendered, except that service supplied but not billed is reported as "Unbilled Utility Revenue" and is included in operating revenues for the year in which service is furnished.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Unrecovered Purchased Gas Costs and Refunds. Distribution Corporation's rate schedules contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers.
Supply Corporation collects revenues subject to refund if rates in effect are pending a final rate case determination by the Federal Energy Regulatory Commission (FERC). Estimated rate refund liabilities are recorded which reflect management's current estimate as to the ultimate outcome of each rate case.
Property, Plant and Equipment. The principal assets, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities. Such cost includes an Allowance for Funds Used During Construction (AFUDC), which is defined in applicable regulatory systems of accounts as the net cost of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. The rates used in the calculation of AFUDC are determined in accordance with guidelines established by regulatory authorities.
Included in property, plant and equipment is the cost of gas stored underground - noncurrent, representing the volume of gas required to maintain pressure levels for normal operating purposes.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries' property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Oil and gas exploration and development costs are capitalized under the full-cost method of accounting as prescribed by the Securities and Exchange Commission (SEC). All costs directly associated with property acquisition, exploration and development activities are capitalized, with the principal limitation that such capitalized amounts not exceed the present value of estimated future net revenues from the production of proved gas and oil reserves plus the lower of cost or market of unevaluated properties, net of related income tax effect. The present value of estimated future net revenues was computed based on end-of-year prices adjusted for contracted price changes.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization are computed by application of either the straight-line method or the gross revenue method, in amounts sufficient to recover costs over the estimated service lives of property in service, and for oil and gas properties, over the period of estimated gross revenues from proved reserves. The costs of unevaluated oil and gas properties are excluded from this calculation. The provisions for depreciation, depletion and amortization, including amounts capitalized or charged to other operating accounts, were $75,686,000 in 1994,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
$70,629,000 in 1993 and $56,506,000 in 1992, and were equivalent to 3.9% in 1994, 3.8% in 1993 and 3.3% in 1992 of average depreciable property, plant and equipment for those years.
Gas Stored Underground - Current. Gas stored is carried at cost, on a last-in, first-out (LIFO) basis. Under present regulatory practice, the liquidation of a LIFO layer is reflected in future gas cost adjustment clauses. Based upon the average price of spot market gas purchased in September 1994, including transportation costs, the current cost of replacing the inventory of gas stored underground-current exceeded the amount stated on a LIFO basis by approximately $19,300,000 at September 30, 1994.
Unamortized Debt Expense. Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related issues. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment.
Income Taxes. The Company and its wholly-owned subsidiaries file a consolidated federal income tax return. Prior to its repeal in 1986, Investment Tax Credit was either reflected currently in income or deferred and amortized to income over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
On October 1, 1993, the Company adopted SFAS 109, "Accounting for Income Taxes" (SFAS 109). The adoption of SFAS 109 changed the Company's method of accounting for income taxes from the deferred method to an asset and liability approach. Previously, deferred taxes were provided for the tax effects of timing differences between financial reporting purposes and tax reporting purposes except where not permitted by regulatory authorities. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences attributable to temporary differences between the carrying amounts of assets and liabilities and their tax bases. In addition, such deferred tax assets and liabilities will be adjusted for the effects of enacted changes in tax laws and rates.
The cumulative effect of this change increased net income by $3,826,000 as a result of the reduction in deferred income taxes associated with the Company's nonregulated operations. The effect on the recorded deferred income taxes associated with rate-regulated activities was to reclassify a portion to a regulatory liability since such amounts are expected to be refundable to customers under regulatory procedures. This liability amounted to $31,688,000 at September 30, 1994.
In addition, under SFAS 109, the Company is required to recognize additional deferred taxes for timing differences on which deferred tax treatment was not permitted by regulatory authorities. The recognition of these deferred tax balances had no effect on earnings due to the recording of corresponding regulatory assets representing future amounts collectible from customers in the ratemaking process. Substantially all of these deferred taxes relate to property, plant and equipment and related investment tax credits and will be amortized consistent with the depreciation and amortization of these accounts. The additional deferred taxes amounted to $99,742,000 at September 30, 1994.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Financial Instruments. In October 1994, the Financial Accounting Standards Board (FASB) issued SFAS 119, "Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments" (SFAS 119). This statement requires disclosures about amounts, nature, and terms of derivative financial instruments. It also requires that a distinction be made between financial instruments held or issued for trading purposes and those held or issued for purposes other than trading. The Company's disclosure is in accordance with the provisions of SFAS 119.
Seneca Resources Corporation (Seneca) has entered into certain price swap agreements that effectively hedge a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These agreements are not held for trading purposes. The price swap agreements call for Seneca to receive monthly payments from (or make payments to) other parties based upon the differential between a fixed and a variable price as specified by the agreement. At September 30, 1994, Seneca had natural gas price swap agreements which run through December 1996 and have an aggregate notional amount of approximately 16.2 billion cubic feet (Bcf) of natural gas equivalent. In October 1994, Seneca entered into natural gas price swap agreements for an additional aggregate notional amount of approximately 3.6 Bcf of natural gas equivalent. These agreements cover the period from March 1995 through February 1996. Seneca also had crude oil price swap agreements at September 30, 1994, which run through September 1997 and have an aggregate notional amount of 773,000 barrels of crude oil equivalent. Gains or losses from these price swap agreements are reflected in operating revenues on the Consolidated Statement of Income at the time of settlement with the other parties, which is when the underlying hedged commodity transaction occurs.
National Fuel Resources, Inc. (NFR) participates in the natural gas futures market to lock in natural gas prices to decrease volatility related to fluctuations in market prices. Futures are not held for trading purposes. At September 30, 1994, NFR had short positions on futures amounting to approximately 1.1 Bcf of natural gas. It also had long positions on futures amounting to approximately .1 Bcf of natural gas. Gains or losses resulting from changes in the market value of these transactions are deferred until the hedged commodity transaction occurs, at which point they are reflected in operating revenues on the Consolidated Statement of Income.
Seneca and NFR are at risk in the event of nonperformance by counterparties on natural gas and crude oil price swap agreements and natural gas futures, respectively, but Seneca and NFR do not anticipate nonperformance by any of these counterparties.
The Company currently has authorization from the SEC to enter into interest rate swap agreements and certain other derivative instruments up to a notional amount of $350,000,000. Currently, no such agreements are outstanding.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents. Interest paid in 1994, 1993 and 1992 was $46,183,000,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
$48,282,000 and $58,530,000, respectively. Net income taxes paid in 1994, 1993 and 1992 were $37,573,000, $19,872,000 and $15,282,000, respectively.
In December 1993, the Company entered into a non-cash investing activity whereby it issued 108,396 shares of Company common stock to Empire Exploration, Inc. (Empire), which in turn exchanged those shares for $3,184,000 of natural gas production assets, $167,000 of other current assets and $280,000 of cash. On July 1, 1994, Empire was merged into Seneca.
Earnings Per Common Share. Earnings per common share are calculated using the weighted average number of shares outstanding during each fiscal year. Common stock equivalents in the form of stock options do not have a material dilutive effect on earnings per common share.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note B - Regulatory Matters
Order 636 Transition Costs. As a result of the industrywide restructuring under the FERC's Order 636, Distribution Corporation is incurring transition costs billed by Supply Corporation and other upstream pipeline companies.
At September 30, 1994, Distribution Corporation's estimate of its exposure to outstanding transition cost claims is in the range of $4,600,000 to $80,700,000. The majority of these costs relate to gas supply realignment (GSR) costs and stranded costs and is exclusive of any potential stranded costs related to production plant or gathering facilities which pipeline companies, including Supply Corporation, may file for at a future date, and any potential GSR costs claimed by an upstream supplier, which are subject to the outcome of its bankruptcy and FERC proceedings. At September 30, 1994, the Company has recorded the minimum liability and corresponding regulatory asset of $4,600,000.
Distribution Corporation has authorization from the State of New York Public Service Commission (PSC) to recover up to $11,000,000 annually of transition costs from sales customers in New York through the monthly Gas Adjustment Clause (GAC). Distribution Corporation will defer, for recovery in future periods, any amounts that may exceed the $11,000,000 annual amount.
The recovery of transition costs from transportation customers in New York remains unresolved. The PSC has postponed its decision on transportation customers' allocable share of transition costs pending further consideration of the issue in a generic restructuring case (the Generic Case) which began in October 1993. The PSC staff's position in the Generic Case is that transportation customers should be assigned a per-unit charge that is equal to 50% of the per-unit charge being collected from sales customers for GSR and stranded costs. The PSC has authorized Distribution Corporation's continued deferral of transition costs relating to transportation customers until resolution in the Generic Case. At September 30, 1994, deferred transition costs related to transportation customers amounted to $2,031,000.
In its Pennsylvania jurisdiction, Distribution Corporation is recovering GSR and stranded costs from its customers through a separate surcharge. At September 30, 1994, Distribution Corporation had deferred GSR and stranded costs of $900,000. Distribution Corporation will recover these costs through a true-up mechanism whereby it is allowed to update its surcharge on a quarterly basis. Distribution Corporation is recovering under-recovered purchased gas transition costs from its Pennsylvania sales customers through its gas cost recovery rates.
Distribution Corporation will continue to actively challenge relevant FERC filings made by the upstream pipeline companies to ensure the eligibility and prudency of all transition cost claims. This industrywide issue will potentially involve years of rate proceedings before the FERC, state commissions and the courts. Management believes that any transition costs resulting from the implementation of Order 636 which have been determined to
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
be both eligible and prudently incurred should be fully recoverable from the respective customers of Supply Corporation and Distribution Corporation.
Gathering Rates. Supply Corporation has approximately $19,000,000 of production and gathering facilities used, in part, to gather natural gas of local producers, including the Company's production in the Appalachian Region. Currently, Supply Corporation has a gathering rate in place under an interim settlement with customers and local producers. In its restructuring orders, the FERC has directed Supply Corporation to fully unbundle its gathering rate effective July 1, 1995. Supply Corporation submitted an offer of settlement (the Settlement) which if approved would provide for a ten-year transition to fully unbundle rates beginning July 1, 1995. Comments on the Settlement have been filed by the parties. Such comments were generally favorable. However, opposition came largely from offsystem customers claiming that they should not have any cost responsibility for the production and gathering plant because it is not necessary to provide service to them. The Settlement currently awaits a FERC decision. The FERC has, however, also directed Supply Corporation to file a fully unbundled rate by December 31, 1994, that would become immediately effective on July 1, 1995. Supply Corporation has requested an extension of the December deadline to April 28, 1995, since approval of the Settlement in the meantime would make further filings unnecessary.
Contract Reformation Issues. As a result of the FERC's Orders 436 and 528 issued in October 1985 and November 1990, respectively, pipeline companies have made, and have agreed to make, payments to producers in exchange for reformation of the price and/or take-or-pay provisions of their long-term wellhead gas supply arrangements, also referred to as contract reformation costs (CRC). The Company is currently recovering from its customers substantially all CRC billed to it.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note C - Income Taxes
Deferred tax liabilities (assets) were comprised of the following:
At September 30, 1994 (in thousands) Accumulated Deferred Deferred Income Taxes Income Taxes Current* Deferred Tax Liabilities: Excess of Tax Over Book Depreciation $174,006 $ - Exploration and Intangible Well Drilling Costs 78,224 - Other 64,181 - Total Deferred Tax Liabilities 316,411 -
Deferred Tax Assets: Deferred Investment Tax Credits (8,388) - Overheads Capitalized for Tax Purposes (9,238) - Provisions for Rate Contingencies and Refunds - (686) Unrecovered Purchased Gas Costs - (3,762) Other (25,225) - Total Deferred Tax Assets (42,851) (4,448)
Total Net Deferred Income Taxes $273,560 $( 4,448)
* Included on the Consolidated Balance Sheets in "Other Accruals and Current Liabilities."
The components of federal and state income taxes included in the Consolidated Statement of Income are as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Expenses: Current Income Taxes - Federal $36,630 $21,148 $17,680 State 6,309 2,979 3,426
Deferred Income Taxes 4,853 16,919 14,125 47,792 41,046 35,231
Other Income: Deferred Investment Tax Credit (682) (693) (706)
Cumulative Effect of Changes in Accounting: Adoption of SFAS 109 (3,826) - - Tax Effect of Adoption of SFAS 112 (425) - -
Total Income Taxes $42,859 $40,353 $34,525
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
Year Ended September 30 (in thousands) 1994 1993 1992
Net Income Available for Common Stock $ 85,672 $ 75,217 $60,310 Total Income Taxes 42,859 40,353 34,525
Income Before Income Taxes $128,531 $115,570 $94,835
Income Tax Expense, Computed at Statutory Rate of 35% in 1994 and 34.75% in 1993 and 34% in 1992 $ 44,986 $40,161 $32,244 Increase (Reduction) in Taxes Resulting from: Current State Income Taxes 4,101 1,944 2,261 Depreciation 2,174 2,221 1,893 Production Tax Credits (1,658) (2,608) (520) Adoption of SFAS 109 (3,826) - - Miscellaneous (2,918) (1,365) (1,353)
Total Income Taxes $42,859 $40,353 $34,525
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note D - Capitalization
Common Stock. The Company issued 2,500,000 shares of common stock in each of May 1993 and September 1992. The shares issued in May 1993 were sold to the public at a price of $30.50 per share, and the net proceeds to the Company after underwriting discounts and commissions were $29.57 per share, or $73,925,000. The shares issued in September 1992 were sold to the public at a price of $27.625 per share, and the net proceeds to the Company after underwriting discounts and commissions were $26.715 per share, or $66,787,500.
Through the Company's Dividend Reinvestment and Stock Purchase Plan (DRP), holders of shares of the Company's common stock may reinvest cash dividends and/or make cash investments in the common stock of the Company. In 1994 and 1993, open market shares were utilized for issuance under the DRP. In 1992, 65,015 new shares as well as open market shares were issued under the DRP.
Under the Company's section 401(k) plans, the Company issued 136,100 shares, 115,300 shares and 108,700 shares of common stock during 1994, 1993 and 1992, respectively.
The Company's Customer Stock Purchase Plan (CSPP) provides residential customers the opportunity to acquire shares of Company common stock without the payment of any brokerage commission or service charges in connection with such acquisitions. At the discretion of the Company, the shares purchased under the CSPP are original issue shares purchased directly from the Company or shares purchased on the open market by an agent. The Company issued 208,990 shares, 139,986 shares and 156,607 shares of common stock under the CSPP during 1994, 1993 and 1992, respectively.
Effective March 17, 1992, after having received shareholder approval, the Company amended its Restated Certificate of Incorporation, as amended, to change the designation of its authorized and issued common stock from shares having no par value to shares having a par value of $1 per share. Accordingly, $214,461,000 was transferred from Common Stock to Paid In Capital. This change eliminated unnecessary additional qualification and licensing fees incurred by the Company in certain states as a result of having no par value common stock. This change has no effect on the rights and privileges of Company stockholders.
Stock Options and Stock Award Plans. The Company's 1993 Award and Option Plan (1993 Plan) provides for the issuance of incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, performance units and performance shares to key employees. The 1983 Incentive Stock Option Plan (1983 Plan) provided for the issuance of incentive stock options to key employees, and the 1984 Stock Plan (1984 Plan) provided for awards of restricted stock, nonqualified stock options and stock appreciation rights to key employees. Stock options under all three plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
In 1993, the authorized maximum number of shares of common stock under the 1983 Plan and 1984 Plan was reached, and therefore no further options or restricted stock have been awarded under these plans. Under the 1993 Plan, the maximum number of shares of common stock available for option grants and stock awards is 1,600,000 shares. Stock options outstanding do not have a materially dilutive effect on earnings per common share.
Transactions involving option shares for all three plans are summarized as follows: Number of Shares Subject Option Price to Option Per Share
Outstanding at September 30, 1991 516,260 $13.19 to $23.81 Granted in 1992 206,500 $23.88 Exercised in 1992* (100,664) $13.19 to $23.81 Forfeited in 1992 (4,000) $23.81 Outstanding at September 30, 1992 618,096 $15.59 to $23.88 Granted in 1993 416,500 $25.19 and $31.50 Exercised in 1993* (78,750) $15.59 to $23.88 Outstanding at September 30, 1993 955,846 $15.59 to $31.50 Granted in 1994 272,000 $31.63 Exercised in 1994* (60,509) $18.00 to $25.19 Outstanding at September 30, 1994 1,167,337 $15.59 to $31.63
Shares Exercisable at September 30, 1994 895,337
Shares Reserved for Future Grant at September 30, 1994 1,159,072
*In connection with exercising these options, 18,088, 36,797 and 35,532 shares were surrendered and/or cancelled during 1994, 1993 and 1992, respectively.
As of September 30, 1994, a total of 286,308 shares of restricted stock had been awarded under the 1984 Plan and 1993 Plan, since inception. Restrictions have lapsed respecting 148,814 of these shares. Of the remaining 137,494 shares of restricted stock, restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 1999 through 2002. Restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 2000 through 2003. Restrictions on 113,494 shares will lapse respecting approximately one-sixth of such shares on each January 2, 1996 through 2001. Restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 2001 through 2004. The market value of the restricted stock on the date the award was made is being recorded as compensation expense over the periods over which the restrictions lapse. During the restriction period, share certificates are held by the Company.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Redeemable Preferred Stock. As of September 30, 1994, there were 3,200,000 shares of $25 par value Cumulative Preferred Stock authorized but unissued.
Summary of Changes in Common Stock Equity Earnings Paid Reinvested Common Stock In in the (in thousands) Shares Amount Capital Business
Balance at September 30, 1991 30,926 $241,043 $301,066 Net Income Available for Common Stock 60,310 Dividends Declared on Common Stock ($1.48 Per Share) (47,042) Transfer from Common Stock to Paid In Capital (214,461) $214,461 Common Stock Issued: Sale of Common Stock 2,500 2,500 64,288 DRP, Incentive Compensation Plans and 401(k) Plans 273 3,314 3,065 CSPP 157 1,460 2,614 Common Stock Issuance Costs (285)
Balance at September 30, 1992 33,856 33,856 284,143 314,334 Net Income Available for Common Stock 75,217 Dividends Declared on Common Stock ($1.52 Per Share) (53,644) Common Stock Issued: Sale of Common Stock 2,500 2,500 71,425 Incentive Compensation Plans and 401(k) Plans 165 165 4,255 CSPP 140 140 4,101 Common Stock Issuance Costs (247)
Balance at September 30, 1993 36,661 36,661 363,677 335,907 Net Income Available for Common Stock 85,672 Dividends Declared on Common Stock ($1.56 Per Share) (57,725) Common Stock Issued: Acquisition of Natural Gas Production Assets 108 108 3,523 Incentive Compensation Plans and 401(k) Plans 300 300 5,397 CSPP 209 209 6,559
Balance at September 30, 1994 37,278 $ 37,278 $379,156 $363,854*
* The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 1994, $289,470,000 of accumulated earnings was free of such limitations. However, substantially all of this amount has been reinvested in the business.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Long-Term Debt. The outstanding long-term debt is as follows:
At September 30 (in thousands) 1994 1993
Debentures: 7-3/4% due February 2004 $125,000 $125,000 9-1/2% due July 2019 - 19,917
Medium-Term Notes: 6.07% due May 1995 55,000 55,000 6.10% due May 1995 20,000 20,000 6.10% due June 1995 1,000 1,000 9.32% due June 1995 20,000 20,000 8.875% due December 1995 20,000 20,000 8.90% due December 1995 38,500 38,500 4.53% due September 1996 30,000 30,000 6.42% due November 1997 50,000 50,000 7.25% due July 1999 50,000 - 6.60% due February 2000 50,000 50,000 7.395% due March 2023 49,000 49,000 8.48% due July 2024* 50,000 -
558,500 478,417 Less Current Portion 96,000 -
$462,500 $478,417 * Callable beginning July 1999.
The aggregate principal amounts of long-term debt maturing for the next five years, including amounts classified as Current Portion of Long-Term Debt, are: $96,000,000 in 1995, $88,500,000 in 1996, none in 1997, $50,000,000 in 1998 and $50,000,000 in 1999.
The fair market value of the Company's long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, is $541,327,000 and $513,107,000 at September 30, 1994 and 1993, respectively. Such value is not intended to reflect principal amounts that the Company will ultimately be required to repay.
During 1994, the Company redeemed $19,917,000 remaining outstanding principal amount of 9-1/2% debentures due July 1, 2019, for $21,337,000, including redemption premium. Also during 1994, the Company issued $50,000,000 of medium-term notes due July 1999, at an interest rate of 7.25% and $50,000,000 of medium-term notes due July 2024, at an interest rate of 8.48%. The 8.48% notes are callable beginning July 1999. After reflecting underwriting discounts and commissions, the combined proceeds to the Company of these issuances amounted to $99,415,500. The proceeds were used to reduce outstanding short-term borrowings.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
In March 1993, the Company filed a shelf registration with the SEC for $350,000,000 of debentures and/or medium-term notes that became effective on March 30, 1993. The Company has authority remaining under this shelf registration to issue and sell up to $220,000,000 of debentures and/or medium-term notes. The amounts and timing of the issuance and sale of these debentures and/or medium-term notes will depend on market conditions and the requirements of the Company.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note E - Short-Term Borrowings
The Company maintains uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. These lines are utilized primarily as a means of financing, on an interim basis, various working capital requirements and capital expenditures of the Company, including the Company's oil and gas exploration and development program, pipeline construction and the purchase and storage of gas. Borrowings under these lines of credit are made at competitive money market rates, and the Company currently is authorized to borrow up to $400,000,000 thereunder. These credit lines, which are callable at the option of the financial institutions, are reviewed on an annual basis and are expected to remain in place through 1995.
The Company may also issue as much as $150,000,000 of commercial paper from time to time, but in no event may its borrowings under its discretionary lines of credit, or through the issuance of commercial paper, exceed $400,000,000 in the aggregate.
Additionally, the Company has entered into an agreement that establishes a 364-day committed revolving credit arrangement with seven commercial banks, under which it may borrow as much as $105,000,000. This arrangement may be utilized for general corporate purposes, including to support the issuance of commercial paper. The Company pays a fee to maintain this arrangement, and may borrow through this arrangement under four interest rate options. If amounts are borrowed under this arrangement, the $400,000,000 available for borrowing under the discretionary lines of credit is correspondingly reduced. No borrowings under this arrangement were outstanding at September 30, 1994. The arrangement expires on September 20, 1995, and the Company expects to renew or replace all or most of this arrangement before then.
At September 30, 1994, the Company had outstanding notes payable to banks and commercial paper of $102,500,000 and $10,000,000, respectively. At September 30, 1993, the Company had outstanding notes payable to banks and commercial paper of $125,800,000 and $71,000,000, respectively.
The weighted average interest rate on notes payable to banks was 5.13% and 3.29% at September 30, 1994 and 1993, respectively. The weighted average interest rate on commercial paper was 5.09% and 3.32% at September 30, 1994 and 1993, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note F - Retirement Plan and Other Post-Employment Benefits
Retirement Plan. The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Plan) that covers substantially all employees of the Company. The Plan uses years of service, age at retirement and earnings of employees to determine benefits.
The Company's policy is to fund at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. Plan funding is subject to annual review by management and its consulting actuary. Plan assets primarily consist of equity and fixed income investments and units in commingled funds. A plan amendment was adopted which provided for an early retirement window program which is accounted for under the rules prescribed by SFAS 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Plans and for Termination Benefits." For ratemaking purposes, pension expense equals the amount funded less amounts capitalized. Since Plan funding has not been required in recent years, the Company deferred the pension expense associated with its regulated subsidiaries. The amounts deferred are expected to be recovered in rates as contributions are made to the Plan.
The components of net periodic pension expense were as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Service Cost for Benefits Earned During the Period $10,441 $ 9,181 $ 8,816 Interest Cost on Projected Benefit Obligation 26,532 24,258 22,446 Actual Return on Plan Assets (16,212) (35,657) (37,107) Net Amortization and Deferral (16,603) 4,287 7,077 Early Retirement Window 2,855 - - Net Periodic Pension Cost 7,013 2,069 1,232 Deferred for Regulatory Purposes (6,875) (2,012) (1,192) Pension Cost Recognized in Consolidated Statement of Income $ 138 $ 57 $ 40
The projected benefit obligation was determined using an assumed discount rate of 8.5% in 1994, 7.75% in 1993 and 8.5% in 1992. The assumed rate of compensation increase was 5% for all three years. The expected long-term rate of return on Plan assets was 8.5% for all three years. The unrecognized net asset that arose from the initial application of SFAS 87, "Employers' Accounting for Pensions," is being amortized on a straight-line basis over the future working lifetime of those expected to receive benefits under the Plan.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
A reconciliation of the Plan's funded status as determined by the Company's consulting actuary is presented in the following table:
At September 30 (in thousands) 1994 1993
Actuarial Present Value of: Vested Benefit Obligation $245,095 $241,676
Accumulated Benefit Obligation $282,340 $278,843
Projected Benefit Obligation $342,050 $346,634
Plan Assets at Fair Value 370,150 369,920 Plan Assets in Excess of Projected Benefit Obligation 28,100 23,286 Unrecognized Net Asset (37,502) (42,688) Unrecognized Prior Service Cost 13,339 14,418 Unrecognized Net Gain (19,959) (4,025) Pension Liability (16,022) (9,009) Deferred for Regulatory Purposes 15,001 8,126 Pension Liability Recognized on Consolidated Balance Sheets $ (1,021) $ (883)
Other Post-Retirement Benefits. In addition to providing retirement plan benefits, the Company currently provides health care and life insurance benefits for substantially all retired employees under a post-retirement benefit plan (Post-Retirement Plan).
The Company has adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), effective October 1, 1993. This statement required the Company to change its accounting for these post-retirement benefits from the "pay-as-you-go" (cash) basis to the accrual basis.
The Company has established Voluntary Employees' Beneficiary Association (VEBA) trusts for collectively bargained employees and non-bargaining employees. The VEBA trusts are similar to the Company's Retirement Plan trust. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations. Contributions to the VEBA trusts are made to fund employees' post-retirement health care and life insurance benefits, as well as benefits as they are paid to current retirees. The Company's current policy is to invest Post-Retirement Plan assets primarily in equity securities and municipal bonds.
The Company has elected to amortize the initial accumulated liability (transition obligation) to net periodic post-retirement benefit cost on a straight-line basis over a 20-year period. Total post-retirement benefit cost under SFAS 106 was $23,530,000 in 1994 compared with the costs based on cash payments for retiree health care and life insurance benefits of $5,974,000 and $4,945,000 in 1993 and 1992, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The components of net periodic post-retirement benefit cost were as follows:
Year Ended September 30 (in thousands) 1994
Service Cost $ 3,974 Interest Cost 13,714 Expected Return on Post-Retirement Plan Assets (1,035) Amortization of Transition Obligation 8,628 Net Periodic Post-Retirement Benefit Cost 25,281 Deferred for Regulatory Purposes, Net (1,751) Post-Retirement Benefit Cost Recognized in Consolidated Statement of Income $ 23,530
The weighted-average assumed discount rate used in determining the accumulated post-retirement benefit obligation was 8.5% in 1994. The average assumed annual rate of salary increase for the applicable life insurance plans was 5%.
The annual rate of increase in the per capita cost of covered medical care benefits for the active participants and medical plans available to new retirees was assumed to be 13% for 1994; this rate was assumed to decrease gradually to 5.5% by the year 2002 and remain at that level thereafter. The annual rate of increase in the per capita cost of covered medical care benefits for the medical plans not available to new retirees was assumed to be 8% for 1994, 7% for 1995, 6% for 1996 and 5.5% for each year after 1996. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed t o be 14% for 1994. This rate was assumed to decrease gradually to 5.5% by the year 2003 and remain level thereafter.
A reconciliation of the Post-Retirement Plan's funded status as determined by the Company's consulting actuary is in the following table:
At September 30 (in thousands) 1994
Accumulated Post-Retirement Benefit Obligation $ 155,976 Fair Value of Post-Retirement Plan Assets 29,035 Accumulated Benefit Obligation in excess of Plan Assets (126,941)
Unrecognized Transition Obligation 156,210 Unrecognized Net (Gain)/Loss (31,776) Post-Retirement Liability (2,507) Deferred for Regulatory Purposes, Net 1,751 Post-Retirement Benefit Liability Recognized on Consolidated Balance Sheets $ (756)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the accumulated post-retirement benefit obligation as of October 1, 1993, would be increased by $26,600,000. This 1% change would also increase the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 1994 by $3,100,000.
Distribution Corporation and Supply Corporation represent virtually all of the Company's total post-retirement benefit costs. Distribution Corporation and Supply Corporation are fully recovering their net periodic post-retirement benefit costs in accordance with PSC and the Pennsylvania Public Utility Commission (PaPUC) and FERC authorization, respectively.
Post-Employment Benefits. In November 1992, the FASB issued SFAS 112, "Employers' Accounting for Postemployment Benefits" (SFAS 112), which establishes standards of financial accounting and reporting for benefits, such as salary continuation, severance pay, workers' compensation and other disability-related benefits, provided to former or inactive employees subsequent to employment but prior to retirement. The Company adopted SFAS 112 in the fourth quarter of 1994. Essentially, the new standard required the Company to change its accounting for significant post-employment benefits from the "pay-as-you-go" (cash) to the accrual basis. The only significant post-employment benefit that the Company has relates to workers' compensation. In the Company's regulated operations, workers' compensation is recovered in rates on a cash basis and is not material. Workers' compensation claims related to the Company's nonregulated operations at September 30, 1994, is approximately $1,014,000 ($589,000 net of income taxes) using a discount rate of 8.5%. As required by SFAS 112, the adoption of the standard is reflected on the Consolidated Statement of Income as a cumulative effect of a change in accounting principle.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note G - Commitments and Contingencies
Leases. System companies have entered into lease agreements, principally for the use of office space, business machines, transportation and construction equipment and meters. The Company's policy is to treat all leases as operating leases for both accounting and ratemaking purposes. Total lease expense approximated $17,190,000 in 1994, $16,864,000 in 1993 and $17,570,000 in 1992. At September 30, 1994, the future minimum payments under the Company's lease agreements for the next five years are: $13,075,000 in 1995, $9,779,000 in 1996, $6,959,000 in 1997, $5,021,000 in 1998 and $3,650,000 in 1999. The future minimum lease payments attributable to later years is $6,059,000.
Obligations Under Firm Contracts. Distribution Corporation has agreements with five nonaffiliated upstream pipeline companies that provide for the availability of needed pipeline transportation capacity for periods that extend through 2004. These agreements provide for payment of a demand or reservation charge, at FERC-approved rates, for contracted capacity. Distribution Corporation has various gas purchase agreements with nonaffiliated gas producers that require payment of fixed monthly charges. These charges are tied to various indices. These agreements have an average term of six years. Additionally, Distribution Corporation has agreements with two nonaffiliated companies for gas storage services through 2004 that require payment of a demand charge, at FERC-approved rates, for contracted storage. At September 30, 1994, the projected aggregate amounts of such required future payments, based on current FERC-approved rates and current indices, where applicable, are approximately $88,600,000, $12,500,000 and $6,900,000 annually for the next five years, for pipeline capacity, gas purchases and storage service, respectively. Additionally, these agreements call for the payment of commodity charges based upon actual quantities shipped, purchased and stored.
These obligations under firm contracts are considered purchased gas costs, subject to state commission review, and are being recovered in customer rates through the inclusion in Distribution Corporation's rate schedules.
For the fiscal year ended September 30, 1994, total gross costs incurred under these contracts, including commodity charges on actual quantities shipped, purchased and stored, amounted to $347,100,000.
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures.
Distribution Corporation has been identified by the Environmental Protection Agency or the New York State Department of Environmental Conservation (DEC) as one of a number of companies that are considered to be potentially responsible parties (PRPs) with respect to several waste disposal sites in New York that were operated by unrelated third parties. These PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to Distribution
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Corporation with respect to the remediation of these sites will be dependent on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion attributed, if any, to Distribution Corporation. Distribution Corporation's estimated share of the clean-up costs has been accrued for four of these sites.
One of these four sites was formerly used for a manufactured gas plant. Distribution Corporation is currently involved in litigation regarding this site. The current owner of the site has submitted a claim against Distribution Corporation for contribution of a share of approximately $1,600,000 of removal/remediation costs that have been incurred. It is anticipated that future remedial costs will be incurred and on the basis of a Record of Decision issued by the DEC, as amended on September 19, 1994, the estimated future remedial costs for the site are approximately $5,700,000. Management believes that the ultimate outcome of these matters will not have a material impact on the financial condition, results of operations or cash flows of the Company.
Distribution Corporation has incurred clean-up costs at two additional sites in New York and one site in Pennsylvania related to former manufactured gas plant sites. Supply Corporation is involved in a remediation program of certain of its measuring and regulating stations in Pennsylvania. Estimated clean-up costs have been accrued for these sites.
It is the Company's policy to accrue estimated clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated that clean-up costs related to the above noted sites are in the range of $6,700,000 to $10,100,000. At September 30, 1994, the Company has recorded the minimum liability of $6,700,000. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.
In New York, Distribution Corporation has received approval from the PSC to defer and amortize both former manufactured gas and non-manufactured gas plant site investigation and remediation costs over a three-year period for each site. These costs are then included in rate cases for recovery through base rates. Distribution Corporation is currently recovering such costs in this manner. In Pennsylvania, Distribution Corporation and Supply Corporation expect to recover such costs in rates, as the PaPUC and the FERC, respectively, have allowed recovery of other environmental clean-up costs in rate cases. Accordingly, the Consolidated Balance Sheets at September 30, 1994, include related regulatory assets in the amount of approximately $7,300,000, $600,000 of which relates to costs that have already been incurred.
The Company has begun a program to comply with the Clean Air Act Amendments of 1990 (the Act). This program focuses on emission controls for Supply Corporation's compressor stations in New York and Pennsylvania. These facilities are affected by the nitrogen oxide emission standards of the Act. Supply Corporation incurred capital expenditures for emission controls of approximately $623,000 in 1994 and expects to incur approximately $4,300,000 in 1995. The Company does not anticipate incurring significant additional capital
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
expenditures to comply with the current standards of the Act, however, changes in the standards may require additional expenditures in the future. Management expects that all related capital expenditures will be recoverable through rates.
Other. The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are expected to have a material adverse effect on the financial condition of the Company at this time.
Note H - Business Segment Information
The System includes operations which are rate-regulated (regulated) and operations which are not regulated as to their rates (nonregulated). The regulated operations fall primarily within two business segments: Utility Operation and Pipeline and Storage. The nonregulated operations consist principally of the Exploration and Production business segment. Other Nonregulated operations consist primarily of the Company's pipeline construction operations, sawmill and dry kiln operations, natural gas marketing operations and natural gas market area hub operations.
The Utility Operation is regulated by the PSC and the PaPUC and is carried out by Distribution Corporation. Distribution Corporation sells and transports gas to retail customers located in western New York and northwestern Pennsylvania. Pipeline and Storage operations are regulated by the FERC and are carried out by Supply Corporation. In 1994, 52% of Supply Corporation's revenue was from affiliated companies, mainly Distribution Corporation.
Seneca is engaged in exploration for, and development and purchase of, oil and natural gas reserves in the Gulf Coast, and southwestern, western and Appalachian regions of the United States. Utility Constructors, Inc. is engaged in the Company's pipeline construction operations, Highland Land & Minerals, Inc. is engaged in the Company's sawmill and dry kiln operations, NFR is engaged in the Company's natural gas marketing operations and Leidy Hub, Inc. is engaged in the Company's natural gas market area hub opreations.
The data presented in the tables below reflect the Company's regulated and nonregulated business segments for the years ended September 30, 1994, 1993 and 1992. Total operating revenues by segment include both revenues from nonaffiliated customers and intersegment revenues. Operating income is total operating revenues less operating expenses, not including income taxes. The elimination of significant intercompany balances and transactions, if appropriate, is made in order to reconcile segment information with consolidated amounts. Identifiable assets of a segment are those assets that are used in the operations of that segment. Corporate assets are principally cash and temporary cash investments, receivables and deferred charges.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Revenues Regulated: Utility Operation $ 931,673 $ 836,618 $ 740,664 Pipeline and Storage 153,121 534,568 498,870 1,084,794 1,371,186 1,239,534
Nonregulated: Exploration and Production 70,261 58,636 36,303 Other 72,036 42,099 47,479 142,297 100,735 83,782
Intersegment Revenues* (85,767) (451,539) (402,866) $1,141,324 $1,020,382 $ 920,450
Operating Income (Loss) Before Income Taxes Regulated: Utility Operation $ 90,584 $ 86,690 $ 90,025 Pipeline and Storage 62,302 67,375 49,796 152,886 154,065 139,821
Nonregulated: Exploration and Production 21,767 12,980 7,021 Other 2,505 (986) 4,229 24,272 11,994 11,250
Corporate (3,463) (2,730) (2,279)
$ 173,695 $ 163,329 $ 148,792
Identifiable Assets At September 30
Regulated: Utility Operation $1,106,053 $ 961,990 $ 874,101 Pipeline and Storage** 498,798 491,291 495,626 1,604,851 1,453,281 1,369,727
Nonregulated: Exploration and Production** 311,037 290,346 271,444 Other 33,357 27,867 27,808 344,394 318,213 299,252 Corporate 32,412 30,046 91,851
$1,981,657 $1,801,540 $1,760,830
* Represents revenue primarily from Pipeline and Storage to Utility Operation.
** Prior year amounts have been reclassified to eliminate an intersegment receivable and to conform with current year presentation.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Year Ended September 30 (in thousands) 1994 1993 1992
Depreciation, Depletion and Amortization Regulated: Utility Operation $ 28,216 $ 27,137 $ 25,001 Pipeline and Storage 17,516 16,347 16,202 45,732 43,484 41,203
Nonregulated: Exploration and Production 27,496 24,249 13,257 Other 1,530 1,686 1,260 29,026 25,935 14,517 Corporate 6 6 6
$ 74,764 $ 69,425 $ 55,726
Capital Expenditures Regulated: Utility Operation $ 61,715 $ 61,803 $ 65,650 Pipeline and Storage 20,472 27,420 58,646 82,187 89,223 124,296
Nonregulated: Exploration and Production 52,458 36,473 26,328 Other 3,603 6,229 7,225 56,061 42,702 33,553 Corporate 20 1 7
$138,268 $131,926 $ 157,856
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note I - Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Earnings per common share are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the earnings per common share shown on the Consolidated Statement of Income, which is based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company's heating business, there are substantial variations in operations reported on a quarterly basis.
Financial data for the quarters ended December 31, 1993, and September 30, 1994, reflect the Company's adoption of SFAS 109 and SFAS 112, respectively. As discussed in Note A - Summary of Significant Accounting Policies, the Company adopted SFAS 109 during the quarter ended December 31, 1993. The cumulative effect of this change increased net income by $3,826,000. As discussed in Note F - Retirement Plan and Other Post-Employment Benefits, the Company adopted SFAS 112 during the quarter ended September 30, 1994. The cumulative effect of this change decreased net income by $589,000.
Income Net Income Earnings Before Available for Per Quarter Operating Operating Cumulative Common Common Ended Revenues Income Effect Stock Share
1994 (in thousands, except earnings per common share)
12/31/93 $310,131 $38,745 $27,800 $31,626* $ .86* 3/31/94 $473,722 $54,686 $43,839 $43,839 $1.18 6/30/94 $216,281 $19,782 $ 9,833 $ 9,833 $ .26 9/30/94 $141,190 $12,690 $ 963 $ 374* $ .01*
1993 (in thousands, except earnings per common share)
12/31/92 $294,220 $38,452 $25,941 $25,941 $ .77 3/31/93 $391,790 $57,195 $45,160 $45,160 $1.33 6/30/93 $185,525 $14,993 $ 3,228 $ 3,228 $ .09 9/30/93 $148,847 $11,643 $ 888 $ 888 $ .02
* Includes Cumulative Effect of Changes in Accounting as discussed above.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note J - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 1994, there were 22,465 holders of National Fuel Gas Company common stock. The market for the common stock is the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note D - Capitalization. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 1993 and 1994, are shown below:
Price Range Dividends Quarter Ended High Low Declared
12/31/92 $30-1/2 $24-5/8 $.375 3/31/93 $33-1/2 $29-1/4 $.375 6/30/93 $33-1/2 $28-3/4 $.385 9/30/93 $36-7/8 $32-1/4 $.385
12/31/93 $36-5/8 $32-1/2 $.385 3/31/94 $36-1/4 $29-7/8 $.385 6/30/94 $32-7/8 $28-3/8 $.395 9/30/94 $31-7/8 $28-7/8 $.395
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note K - Supplementary Information for Oil and Gas Producing Activities
The following supplementary information is presented in accordance with SFAS 69, "Disclosures about Oil and Gas Producing Activities," and related SEC accounting rules.
Capitalized Costs Relating to Oil and Gas Producing Activities
At September 30 (in thousands) 1994 1993
Capitalized Costs Subject to Amortization $442,224 $399,781 Capitalized Acquisition Costs Excluded from Amortization 16,636 15,849 458,860 415,630
Less - Accumulated Depreciation, Depletion and Amortization 167,592 145,553
$291,268 $270,077
Certain costs excluded from amortization represent unevaluated properties that require additional drilling to determine the existence of oil and gas reserves. The remaining costs, incurred during and prior to 1994, consist of individually insignificant oil and gas leases still early in their primary terms and individually insignificant unproved perpetual oil and gas rights.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Year Ended September 30 (in thousands) 1994 1993 1992
Property Acquisition Costs $ 8,215 $ 9,027 $ 5,260 Exploration Costs 17,855 10,140 4,552 Development Costs 25,102 16,258 11,172 Other 259 25 3,284 $51,431 $35,450 $24,268
Results of Operations for Producing Activities
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $5,456, $11,474 and $10,945, respectively) $50,803 $43,679 $24,022 Oil, Condensate and Other Liquids 15,307 13,943 10,974
Total Operating Revenues 66,110 57,622 34,996
Production/Lifting Costs 13,177 13,452 9,828
Depreciation, Depletion and Amortization ($.41, $.42 and $.37, respectively, per dollar of operating revenues) 26,992 23,995 13,049
Income Tax Expense 7,907 4,311 3,874
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $18,034 $15,864 $ 8,245
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Reserve Quantity Information (unaudited)
The Company's proved oil and gas reserves are located in the United States. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by the Company's independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions.
Gas Oil Year Ended MMcf Mbbl September 30 1994 1993 1992 1994 1993 1992
Proved Developed and Undeveloped Reserves:
Beginning of Year 175,051 179,811 176,772 18,519 19,805 20,316
Extensions and Discoveries 94,733 26,416 21,645 1,666 1,713 270
Revisions of Previous Estimates (2,075) (3,962) (3,391) (1,660) (1,995) (85)
Production (23,273) (19,874)(12,070) (1,030) (831) (643)
Sales of Minerals in Place (32) (7,401) (3,377) - (173) (53)
Purchases of Minerals in Place and Other 3,043 61 232 - - -
End of Year 247,447 175,051 179,811 17,495 18,519 19,805
Proved Developed Reserves:
Beginning of Year 134,712 126,176 131,035 10,801 11,437 12,210
End of Year 179,291 134,712 126,176 10,110 10,801 11,437
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited)
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company's oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under the widely fluctuating political and economic conditions of today's world.
The standardized measure is intended instead to provide a somewhat better means for comparing the value of the Company's proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
Year Ended September 30 (in thousands) 1994 1993 1992
Future Cash Inflows $705,874 $689,198 $772,017 Less: Future Production and Development Costs 252,901 240,417 217,654 Future Income Tax Expense at Applicable Statutory Rate 131,060 132,528 159,888 Future Net Cash Flows 321,913 316,253 394,475 Less: 10% Annual Discount for Estimated Timing of Cash Flows 106,647 106,598 154,184 Standardized Measure of Discounted Future Net Cash Flows $215,266 $209,655 $240,291
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $209,655 $240,291 $183,512 Sales, Net of Production Costs (52,933) (44,170) (25,168) Net Changes in Prices, Net of Production Costs (48,149) (52,266) 41,322 Purchases of Minerals in Place 2,793 61 398 Sales of Minerals in Place (29) (7,286) (6,454) Extensions and Discoveries 96,134 61,476 38,874 Changes in Estimated Future Development Costs (36,466) (30,555) (15,186) Previously Estimated Development Costs Incurred 22,941 30,888 17,793 Net Change in Income Taxes at Applicable Statutory Rate 3,098 5,476 (11,662) Revisions of Previous Quantity Estimates (11,042) (25,891) (8,893) Accretion of Discount and Other 29,264 31,631 25,755 Standardized Measure of Discounted Future Net Cash Flows at End of Year $215,266 $209,655 $240,291
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE V - Property, Plant and Equipment (Note 1)
(THOUSANDS OF DOLLARS)
Balance at Balance at Beginning of Additions Other Charges End of Classification Period at Cost Retirements Add (Deduct) Period
Year Ended September 30, 1994
Utility Operation $ 983,417 $ 59,652 $ 6,844 $ - $1,036,225 Pipeline and Storage (Note 2) 618,917 20,380 4,132 4,959 640,124 Exploration and Production 415,642 52,181 3,098 - 464,725 Other Nonregulated 21,237 4,033 332 - 24,938 Corporate 223 21 - - 244 $2,039,436 $136,267 $14,406 $4,959 $2,166,256
Year Ended September 30, 1993
Utility Operation $ 929,601 $ 60,001 $6,185 $ - $ 983,417 Pipeline and Storage (Note 2) 594,580 27,004 2,667 - 618,917 Exploration and Production 378,815 37,145 318 - 415,642 Other Nonregulated 15,170 6,235 168 - 21,237 Corporate 223 - - - 223 $1,918,389 $130,385 $9,338 $ - $2,039,436
Year Ended September 30, 1992
Utility Operation $ 871,102 $ 64,624 $ 6,125 $ - $ 929,601 Pipeline and Storage (Note 2) 539,904 58,210 3,534 - 594,580 Exploration and Production 353,090 25,769 44 - 378,815 Other Nonregulated 8,202 7,222 254 - 15,170 Corporate 216 7 - - 223 $1,772,514 $155,832 $ 9,957 $ - $1,918,389
Notes to Schedule V and VI appear on page 91 of this report.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment
(THOUSANDS OF DOLLARS)
Additions Balance at Charged to Beginning Costs and Balance at of Expenses Other Changes End of Description Period (Note 3) Retirements Add (Deduct) Period
Year Ended September 30, 1994
Utility Operation $228,951 $28,270 $ 8,790 $ - $248,431 Pipeline and Storage 185,181 18,436 4,304 - 199,313 Exploration and Production 142,172 27,443 308 - 169,307 Other Nonregulated 5,028 1,531 200 - 6,359 Corporate 101 6 - - 107 $561,433 $75,686 $13,602 $ - $623,517
Year Ended September 30, 1993
Utility Operation $209,846 $27,209 $ 8,104 $ - $228,951 Pipeline and Storage 171,197 17,479 3,495 - 185,181 Exploration and Production 117,369 24,250 119 672 142,172 Other Nonregulated 3,500 1,685 157 - 5,028 Corporate 95 6 - - 101 $502,007 $70,629 $11,875 $ 672 $561,433
Year Ended September 30, 1992
Utility Operation $192,169 $25,076 $ 7,399 $ - $209,846 Pipeline and Storage 159,896 16,900 5,599 - 171,197 Exploration and Production 104,303 13,264 - (198) 117,369 Other Nonregulated 2,306 1,260 66 - 3,500 Corporate 89 6 - - 95 $458,763 $56,506 $13,064 $ (198) $502,007
Notes to Schedule V and VI appear on page 91 of this report.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
Notes to Schedules V and VI:
(1) Because of the variety of properties and the large number of depreciation rates utilized by System companies, it is considered impractical to set forth the rates used in computing provisions. However, the total provisions for depreciation, depletion and amortization of System property, plant and equipment for the three years ended September 30, 1994, including amounts charged to accounts other than depreciation, depletion and amortization expense, were equivalent to approximately 3.9% in 1994, 3.8% in 1993 and 3.3% in 1992 of average depreciable property, plant and equipment for the respective years.
(2) Includes gas stored underground costing $80,942,000 at September 30, 1994, and $75,983,000 at September 30, 1993 and 1992. The cost of gas stored underground in the amount of $4,959,000 was transferred to property, plant and equipment from deferred changes in 1994.
(3) Additions Charged to Costs and Expenses differs from Depreciation, Depletion and Amortization (D,D & A) as reported in the Consolidated Statement of Income, due to D,D & A provisions charged to other income and expense accounts.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE VIII - Valuation and Qualifying Accounts and Reserves
(THOUSANDS OF DOLLARS)
Additions Balance at Charged to Charged to Balance at Beginning Costs and Other Deductions End of Description of Period Expenses Accounts (Note) Period
Year Ended September 30, 1994
Reserve for Doubtful Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055
Year Ended September 30, 1993
Reserve for Doubtful Accounts $ 5,900 $ 8,713 $ - $8,874 $ 5,739
Year Ended September 30, 1992
Reserve for Doubtful Accounts $ 5,876 $ 9,723 $ - $9,699 $ 5,900
Note - Amounts represent net accounts receivable written-off.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE IX - Short-Term Borrowings
(THOUSANDS OF DOLLARS)
Maximum Average Weighted Balance at Weighted Amount Amount Average Category End of Average Outstanding Outstanding Interest of Aggregate Period Interest During the During the Rate During Short-Term September 30 Rate Period Period the Period Borrowings (Note 1) (Note 2) (Note 3) (Note 4) (Note 5)
Year 1994
Bank Loans $102,500 5.13% $ 182,100 $107,907 3.75%
Commercial Paper $ 10,000 5.09% $ 76,000 $ 42,000 3.67%
Year 1993
Bank Loans $125,800 3.29% $ 217,000 $115,159 3.58%
Commercial Paper $ 71,000 3.32% $ 128,000 $ 87,427 3.56%
Year 1992
Bank Loans $149,100 3.60% $ 207,200 $165,191 4.81%
Commercial Paper $127,900 3.52% $ 127,900 $ 84,096 4.62%
Notes:
(1) At September 30, 1992, the Company reclassified $50,000,000 of short-term borrowings on the Consolidated Balance Sheet to "Long-Term Debt, Net of Current Portion" because the Company, on November 5, 1992, issued $50,000,000 of medium-term notes and used the proceeds to reduce outstanding short-term borrowings.
(2) The interest rate for bank loans is the weighted average of the rates in effect at the respective banks at September 30 of each year. The interest rate for commercial paper is the weighted average of the discount rate on those commercial paper notes outstanding at September 30 of each year.
(3) Represents the maximum amount outstanding during any month of the period.
(4) Represents the average amount outstanding on a daily basis.
(5) Represents the weighted average interest rate on a daily basis.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Concluded)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE X - Supplementary Income Statement Information
(THOUSANDS OF DOLLARS)
Charged to Costs and Expenses
Item Year Ended September 30 1994 1993 1992
1. Maintenance and Repairs $30,979 $24,312 $22,439
2. Depreciation and Amortization of Intangible Assets, Preoperating Costs and Similar Deferrals (1) (1) (1)
3. Taxes, other than Payroll and Income Taxes: Gross Receipts Taxes $53,271 $48,876 $44,400
Real and Other Property Taxes 35,287 33,216 31,320
Other 7,017 5,500 6,127
$95,575 $87,592 $81,847
4. Royalties (1) (1) (1)
5. Advertising Costs (1) (1) (1)
Note (1) Amount is not in excess of one percent of total operating revenues as reported in the Consolidated Statements of Income and Earnings Reinvested in the Business.
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
The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 1995 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994. The information provided in such definitive Proxy Statement is incorporated herein by reference.
Information concerning the Company's executive officers can be found in Part I, Item 1, of this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 1995 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994. The information provided in such definitive Proxy Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 1995 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994. The information provided in such definitive Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
At September 30, 1994, the Company knows of no relationships or transactions required to be disclosed pursuant to Item 404 of Regulation S-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statement Schedules All financial statement schedules filed as part of this report are included in Item 8 and reference is made to the index on page 52 of this report.
(b) Reports on Form 8-K None
(c) Exhibits.
Exhibit Number Description of Exhibits
3(i) Articles of Incorporation:
* Restated Certificate of Incorporation of National Fuel Gas Company, dated March 15, 1985 (Exhibit 10-OO, Form 10-K for fiscal year ended September 30, 1991)
* Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated March 9, 1987 (Exhibit A-3 in File No. 70-7334)
* Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated February 22, 1988 (Exhibit B-5 in File No. 70-7478)
* Certificate of Amendment of Restated Certificate of Incorporation, dated March 17, 1992 (Exhibit EX-3(a), Form 10-K for fiscal year ended September 30, 1992)
3(ii) By-Laws:
3.1 National Fuel Gas Company By-Laws as amended through June 9, 1994
(4) Instruments Defining the Rights of Security Holders, Including Indentures:
* Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b), File No. 2-51796)
* Eighth Supplemental Indenture dated as of July 1, 1989, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit EX-4.3, Form 10-K for fiscal year ended September 30, 1992) (The Debentures issued thereunder were redeemed on March 16, 1993, July 7, 1993 and July 1, 1994)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
* Ninth Supplemental Indenture dated as of January 1, 1990, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit EX-4.4, Form 10-K for fiscal year ended September 30, 1992)
* Tenth Supplemental Indenture dated as of February 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a), Form 8-K dated February 14, 1992, in File No. 1-3880)
* Eleventh Supplemental Indenture dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992, in File No. 1-3880)
* Twelfth Supplemental Indenture dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992, in File No. 1-3880)
* Thirteenth Supplemental Indenture dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401)
* Fourteenth Supplemental Indenture dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1993)
(10) Material Contracts:
(ii) (B) Contracts upon which Registrant's business is substantially dependent:
10.1 Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FTS, dated November 1, 1993 and executed February 13, 1994.
10.2 Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FSS, dated November 1, 1993 and executed February 13, 1994.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
10.3 Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule SST, dated November 1, 1993 and executed February 13, 1994.
* Gas Transportation Agreement with Tennessee Gas Pipeline Company under rate schedule FT-A (Zone 4), dated September 1, 1993 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1993)
* Gas Transportation Agreement with Tennessee Gas Pipeline Company under rate schedule FT-A (Zone 5), dated September 1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1993)
* Service Agreement with Texas Eastern Transmission Corporation under rate schedule CDS, dated June 1, 1993 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1993)
* Service Agreement with Texas Eastern Transmission Corporation under rate schedule FT-1, dated June 1, 1993 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1993)
* Service Agreement with CNG Transmission Corporation under Rate Schedule FT, dated October 1, 1993 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1993)
* Service Agreement with CNG Transmission Corporation under Rate Schedule GSS, dated October 1, 1993 (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1993)
(iii) Compensatory plans for officers:
10.4 Employment Agreement, dated September 17, 1981, with Bernard J. Kennedy.
* National Fuel Gas Company 1983 Incentive Stock Option Plan, as amended and restated through February 18, 1993. (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 1993)
* National Fuel Gas Company 1984 Stock Plan, as amended and restated through February 18, 1993 (Exhibit 10.3, Form 10-Q for the quarterly period ended March 31, 1993)
* National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993. (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1993)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
* Change in Control Agreement, dated May 1, 1992, with Philip C. Ackerman. (Exhibit EX-10.4, Form 10-K for fiscal year ended September 30, 1992)
* Change in Control Agreement, dated May 1, 1992, with Richard Hare. (Exhibit EX-10.5, Form 10-K for fiscal year ended September 30, 1992)
* Change in Control Agreement, dated May 1, 1992 with William J. Hill. (Exhibit EX-10.6, Form 10-K for fiscal year ended September 30, 1992)
* Agreement, dated August 1, 1989, with Richard Hare. (Exhibit 10-Q, Form 10-K for fiscal year ended September 30, 1989)
* Executive Death Benefits Agreement dated April 1, 1991 with William J. Hill. (Exhibit EX-10.8, Form 10-K for fiscal year ended September 30, 1992)
10.5 Amendment to Death Benefits Agreement dated March 15, 1994 with Richard Hare.
10.6 Amendment to Death Benefits Agreement dated March 15, 1994 with Philip C. Ackerman.
10.7 National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994.
10.8 National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through February 17, 1994
10.9 Split Dollar Death Benefits Agreement dated April 1, 1991 with Richard Hare (errata).
10.10 Split Dollar Death Benefits Agreement dated April 1, 1991 with Philip C. Ackerman (errata)
* Eighth Extension to Employment Agreement with Bernard J. Kennedy, dated September 20, 1991. (Exhibit 10-SS, Form 10-K for fiscal year ended September 30, 1991)
* Executive Death Benefits Agreement dated August 28, 1991 with Bernard J. Kennedy. (Exhibit 10-TT, Form 10-K for fiscal year ended September 30, 1991)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
* Summary of Annual at Risk Compensation Incentive Program (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1993)
* Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of December 5, 1991. (Exhibit 10-UU, Form 10-K for fiscal year ended September 30, 1991)
(12) Computation of Ratio of Earnings to Fixed Charges
(21) Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K
Consents of Experts and Counsel: 23.1 Consent of Ralph E. Davis Associates, Inc. 23.2 Consent of Independent Accountants
(27) Financial Data Schedule
Additional Exhibits: 99.1 Report of Ralph E. Davis Associates, Inc. 99.2 System Maps (Not included in EDGAR filing. See narrative description in the Appendix to this report.)
All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report on Form 10-K.
*Incorporated herein by reference as indicated.
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.
NATIONAL FUEL GAS COMPANY (Registrant)
By/s/B. J. Kennedy B. J. Kennedy Chairman of the Board, President Date December 22, 1994 and Chief Executive 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.
Signature Title
/s/ B. J. Kennedy Chairman of the Board, B. J. Kennedy President, Chief Executive Officer and Director Date December 22, 1994
/s/ P. C. Ackerman Senior Vice President, Principal P. C. Ackerman Financial Officer and Director
Date December 22, 1994
/s/ J. M. Brown Director J. M. Brown
Date December 22, 1994
/s/ D. N. Campbell Director D. N. Campbell
Date December 22, 1994
/s/ L. F. Kahl Director L. F. Kahl
Date December 22, 1994
/s/ B. S. Lee Director B. S. Lee
Date December 22, 1994
/s/ E. T. Mann Director E. T. Mann
Date December 22, 1994
/s/ L. Rochwarger Director L. Rochwarger
Date December 22, 1994
/s/ G. H. Schofield Director G. H. Schofield
Date December 22, 1994
/s/ J. P. Pawlowski Treasurer and Principal J. P. Pawlowski Accounting Officer
Date December 22, 1994
/s/ R. M. DiValerio Secretary R. M. DiValerio
Date December 22, 1994
/s/ G. T. Wehrlin Controller G. T. Wehrlin
Date December 22, 1994
APPENDIX TO ITEM 2 - PROPERTIES
Three maps outlining the System's operating areas at September 30, 1994, are inlcuded in the paper format version of this Form 10-K as exhibit 99.2 and are not included in this electronic filing. The first map identifies the System's Utility Operating area (i.e., Distribution Corporation's service area). The second map identified the System's Pipeline and Storage operating area (i.e., Supply Corporation's storage areas and pipelines). The third map identifies the System's Exploration and Production operating area (i.e., Seneca Resources' operating area).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 1994
Two pie graphs detailing the revenue dollar in 1994; where it came from and where it went to, broken down as follows:
Where it came from:
$ .592 Residential Sales .182 Commercial and Industrial Sales .060 Transportaion Revenues .053 Oil and Gas Revenues .044 Natural Gas Marketing Revenues .034 Storage Service Revenues .035 Other Revenues $1.000 Total
Where it went to:
$ .435 Gas Purchased .165 Wages, Including Benefits .128 Taxes .091 Other Materials and Services .065 Depreciation .051 Dividends - Common Stock .041 Interest .024 Reinvested in the Business $1.000 Total
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS (Concluded)
B. Book Value Per Common Share
A bar graph detailing book value per common share (dollars) for the years 1990 through 1994, broken down as follows:
1990 - $16.97 1991 - 17.53 1992 - 18.68 1993 - 20.08 1994 - 20.93
C. Capital Expenditures
A bar graph detailing capital expenditures (millions of dollars) for the years 1990 through 1994, broken down as follows:
1990 1991 1992 1993 1994 Other Nonregulated $ 2.6 $ 1.0 $ 7.2 $ 6.2 $ 3.6 Pipeline and Storage 42.0 58.6 58.7 27.4 20.5 Exploration and Production 50.8 31.7 26.3 36.5 52.5 Utility Operation 66.1 64.9 65.7 61.8 61.7 $161.5 $156.2 $157.9 $131.9 $138.3
D. Embedded Cost of Long-Term Debt
A line graph detailing the embedded cost of long-term debt for the years 1990 through 1994, broken down as follows:
Percent 1990 9.4 1991 9.3 1992 8.1 1993 7.3 1994 7.3
E. Capitalization Ratios
A bar graph detailing capitalization (percentage) for the years 1990 through 1994, broken down as follows: Debt (%) Equity (%) 1990 56.2 43.8 1991 55.0 45.0 1992 54.5 45.5 1993 47.8 52.2 1994 46.2 53.8
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For a graph of "The Revenue Dollar - 1994" see graph A. in the Appendix to this report.
Results of Operations
1994 Compared with 1993. National Fuel's consolidated earnings were $85.7 million, or $2.32 per common share, in 1994. This included $3.2 million, or $.09 per common share, related to the cumulative effect of the mandated changes in accounting for income taxes and post-employment benefits (as adopted in accordance with the Financial Accounting Standards Board's (FASB) Statements of Financial Accounting Standards (SFAS) No. 109 and No. 112, respectively). Earnings before these accounting changes amounted to $82.4 million, an increase of approximately 10% over 1993 earnings of $75.2 million. On a per-common-share basis, earnings before the accounting changes were $2.23 for 1994, up 4% from 1993 earnings of $2.15. Share amounts reflect a greater number of weighted average shares outstanding in the current year, principally because of the sale of 2.5 million shares of common stock in May 1993.
Earnings growth in 1994 was primarily due to the Company's nonregulated operations. The Exploration and Production segment's successes have continued in 1994, with record oil and gas production more than compensating for a decline in oil and gas prices. Earnings from Other Nonregulated operations increased because of the improved performance of the Company's natural gas marketing, pipeline construction and timber operations.
Earnings from the Company's regulated operations, in total, increased in 1994. The Utility Operation's earnings were up slightly over last year because of higher throughput due to colder weather, as well as State of New York Public Service Commission (PSC) and Pennsylvania Public Utility Commission (PaPUC) authorization to earn a return on increased capital investment. The Pipeline and Storage segment's earnings decreased in 1994 compared with 1993, mainly because of two nonrecurring items in 1993: the settlement of a Supply Corporation rate case which resulted in a partial reduction of a provision for refund due customers; and a change in rate design, effective August 1, 1993, which boosted 1993 earnings.
1993 Compared with 1992. Earnings were $75.2 million in 1993, up $14.9 million, or 25%, over 1992 earnings of $60.3 million. Earnings per common share in 1993 were $2.15, an 11% increase from the $1.94 earned in 1992. Share amounts reflect a greater number of weighted average shares outstanding in 1993, principally because of the sale of 2.5 million shares of common stock in each of May 1993 and September 1992.
The earnings increase in 1993 resulted from improvements in both the Pipeline and Storage and Exploration and Production segments' earnings which, in the aggregate, more than offset a decline in the earnings of the Utility Operation and the Company's Other Nonregulated operations. New rates, coupled with a change in rate design, were the major reasons for the Pipeline and Storage segment's improved results, while increased natural gas production and higher prices improved the Exploration and Production segment's performance.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Operating Income (Loss) Before Income Taxes Year Ended September 30 (in thousands) 1994 1993 1992 Utility Operation $ 90,584 $ 86,690 $ 90,025 Pipeline and Storage 62,302 67,375 49,796 Exploration and Production 21,767 12,980 7,021 Other Nonregulated 2,505 (986) 4,229 24,272 11,994 11,250 Corporate (3,463) (2,730) (2,279)
Total Operating Income Before Income Taxes $173,695 $163,329 $148,792
Operating Revenues Year Ended September 30 (in thousands) 1994 1993 1992 Utility Operation Retail Revenues: Residential $ 677,068 $ 613,039 $533,908 Commercial 177,249 156,851 139,662 Industrial 31,096 31,609 35,985 885,413 801,499 709,555 Off-System Sales 6,930 945 - Transportation 34,419 30,213 27,424 Other 4,911 3,961 3,685 931,673 836,618 740,664 Pipeline and Storage Wholesale Revenues - 444,142 425,931 Storage Service 58,971 41,041 36,064 Transportation 90,416 45,313 33,821 Other 3,734 4,072 3,054 153,121 534,568 498,870 Exploration and Production 70,261 58,636 36,303 Other Nonregulated 72,036 42,099 47,479 142,297 100,735 83,782 Less: Intersegment Revenues 85,767 451,539 402,866
Total Operating Revenues $1,141,324 $1,020,382 $920,450
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
UTILITY OPERATION
Operating Revenues
1994 Compared with 1993. Operating revenues increased $95.1 million in 1994 compared with 1993. This increase reflects recovery of increased gas costs mainly due to higher throughput, as well as general rate increases in the New York rate jurisdiction effective in both July 1993 and 1994 and in the Pennsylvania rate jurisdiction in December 1993 and higher revenues from off-system sales. Distribution Corporation, in each of its jurisdictions, has a mechanism whereby it has the opportunity to recover certain costs and retain a portion of the margin on these off-system sales.
Higher retail sales of 5 billion cubic feet (Bcf) resulted primarily from weather in Distribution Corporation's service territory that was, on average, 6.5% colder than last year. Although industrial volumes sold remained level when compared with last year, they reflected a 2.5 Bcf switch from sales to transportation service, offset by increased gas sales to a new cogeneration customer.
Transportation throughput was up 3.3 Bcf mainly because of the above noted 2.5 Bcf switch, as well as a similar switch from sales to transportation service by commercial customers of .4 Bcf. In addition, there was increased transportation of 2 Bcf to large- and small-volume industrial customers. The shut-down of three industrial customers and the bypass of National Fuel's pipeline system by three customers in the Pennsylvania jurisdiction partially offset the total increase by approximately 1.6 Bcf. Rates that go into effect in December 1994 in the Pennsylvania rate jurisdiction compensate for the loss of throughput related to these customers.
1993 Compared with 1992. Operating revenue increased $96 million in 1993 compared with 1992, although throughput remained relatively unchanged. The flow-through of higher gas costs, as well as rate increases in the New York rate jurisdiction in both July 1992 and 1993, and a rate increase in the Pennsylvania rate jurisdiction effective in December 1991, resulted in increased revenues. Weather-sensitive residential throughput increased 2.1 Bcf as a result of weather that was, on average, 1.9% colder than last year in Distribution Corporation's service territory. Combined industrial and end-user transportation throughput decreased 2.4 Bcf as a result of the bankruptcy of a major customer in Pennsylvania and a decrease in boiler fuel sales. These declines were partially mitigated by a significant increase attributable to a full year's throughput for a cogeneration project that came on line in May 1992.
Operating Income
1994 Compared with 1993. Operating income before income taxes increased $3.9 million in 1994 compared with 1993. This increase reflects higher revenues, discussed above, partly offset by increased operating expenses. The severe cold weather during January and February 1994 necessitated an unusually high number of system repairs and related site restoration work, which increased maintenance expense.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
The impact of weather on Distribution Corporation's New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on pretax operating income and earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits Distribution Corporation's New York customers. In 1994, the WNC in New York resulted in a benefit to customers of $5.8 million. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact pretax operating income and earnings. In the Pennsylvania service territory, weather was 9.6% colder than last year and 8.4% colder than normal. The colder weather in 1994 compared with 1993 had a positive impact on pretax operating income and earnings for the Pennsylvania rate jurisdiction.
1993 Compared with 1992. Operating income before income taxes decreased $3.3 million in 1993 compared with 1992. This decline reflects the impact of lower average gas use per residential account in the New York rate jurisdiction compared with that imputed in rates resulting in a lower margin on gas sales which was not adequate to cover the increase in operating expenses. This problem was remedied by reflecting a lower usage per account in Distribution Corporation's rates that went into effect on July 23, 1993, in New York. In 1993, the WNC in New York preserved pretax operating income of $1.2 million and earnings per share of $.02. In the Pennsylvania service territory, weather was 2.5% colder in 1993 than 1992, although it was 5.4% warmer than normal. This colder weather had a positive impact on pretax operating income and earnings for the Pennsylvania rate jurisdiction.
Degree Days
Percent Colder (Warmer) Than Year Ended September 30 Normal Actual Normal Last Year 1994: Buffalo 6,710 6,975 3.9% 3.6% Erie 6,202 6,726 8.4% 9.6% 1993: Buffalo 6,723 6,730 0.1% 1.3% Erie 6,484 6,135 (5.4%) 2.5% 1992: Buffalo 6,778 6,644 (2.0%) 15.9% Erie 6,556 5,983 (8.7%) 13.1%
Purchased Gas. The cost of purchased gas is by far the Company's single largest operating expense. Annual variations in purchased gas costs can be attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and five upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers and for storage service with Supply Corporation and two nonaffiliated companies. In addition, Distribution Corporation can satisfy a portion of its gas requirements through spot market purchases. Distribution Corporation's average cost of purchased gas, including the cost of transportation, was $3.74 per thousand cubic feet (Mcf) in 1994, a decrease of 3% from the average cost of $3.84 per Mcf in 1993. The average cost of purchased gas in 1993 was 22% higher than the $3.15 per Mcf in 1992.
System Throughput (billion cubic feet) Year Ended September 30 1994 1993 1992 Utility Operation Retail Sales: Residential 90.6 86.9 84.8 Commercial 26.9 25.6 25.9 Industrial 6.5 6.5 9.1 124.0 119.0 119.8
Transportation- End-Users 52.2 48.9 48.7 176.2 167.9 168.5 Pipeline and Storage Wholesale Sales - 118.7 130.3 Transportation 295.3 138.6 157.0 295.3 257.3 287.3 Less Intersegment Throughput: Sales - 112.2 122.0 Transportation 164.2 40.1 33.2 164.2 152.3 155.2 Total System Throughput 307.3 272.9 300.6
PIPELINE AND STORAGE
Operating Revenues
1994 Compared with 1993. Operating revenues decreased $381.4 million in 1994 compared with 1993. This decline reflects Supply Corporation's restructured operations under the Federal Energy Regulatory Commission's (FERC) Order 636, which became effective August 1, 1993. Under Order 636, Supply Corporation's gas purchasing and sales functions were discontinued and replaced with new transportation and storage services, thus the recovery of purchased gas costs has been eliminated from Supply Corporation's revenues.
1993 Compared with 1992. Operating revenues increased $35.7 million in 1993 compared with 1992, despite a 30 Bcf decline in throughput. New rates that became effective in July 1992, subject to refund, significantly increased
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
revenues in 1993. Supply Corporation filed a Stipulation and Agreement (the Settlement) with the FERC on October 15, 1993, respecting these new rates. As a result of the Settlement, Supply Corporation reversed approximately $15 million of its previously accrued refund provision. Approximately $2.8 million of the amount reversed related to 1992. Additionally, as the Settlement included full recovery of Supply Corporation's portion of the net periodic post-retirement benefit costs under SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Supply Corporation recorded $3.6 million of related post-retirement benefit expense. These adjustments relate to rates that were in effect since July 1, 1992, subject to refund. The change to the straight fixed-variable (SFV) rate design mandated by Order 636, which provides for recovery of Supply Corporation's fixed costs in the demand, or reservation charge, contributed additional revenues of approximately $2.7 million for August and September 1993 when compared to Supply Corporation's former rate design. All of these items were reflected in earnings in the fourth quarter of 1993.
Operating Income
1994 Compared with 1993. Operating income before income taxes decreased $5.1 million in 1994 compared with 1993. This decrease was principally because of two nonrecurring items reflected in 1993. The favorable Settlement in 1993, discussed above, resulted in Supply Corporation recording approximately $2.8 million of revenues in 1993 that related to 1992. In addition, the change to the SFV rate design contributed additional revenues of approximately $2.7 million for August and September 1993, when compared to Supply Corporation's former rate design.
Throughput increased 38 Bcf in 1994 and can be attributed to increased utilization of Supply Corporation's Canadian gas transportation facilities, the expanded capacity of these facilities and weather that was colder than last year. However, because of the SFV rate design, the increase in throughput did not have a significant impact on pretax operating income.
1993 Compared with 1992. Operating income before income taxes increased $17.6 million in 1993 compared with 1992. This increase was mainly the result of higher revenues, discussed above, which were partly offset by higher gas costs and operation and maintenance (O & M) expenses, primarily for labor and employee benefits.
EXPLORATION AND PRODUCTION
Operating Revenues
1994 Compared with 1993. Operating revenues increased $11.6 million in 1994 compared with 1993. This increase was primarily attributable to Seneca's Gulf Coast operations and reflects the continued success of both its offshore drilling program in the Gulf of Mexico and its horizontal drilling program in central Texas. Gas production and oil production (mainly condensate from gas wells) hit record levels in 1994 and were up 34% and 59%, respectively, in the
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Gulf Coast Region and 17% and 24%, respectively, for all geographic regions combined.
Systemwide, the average price received for gas and oil production in 1994 was $2.18 per Mcf and $14.86 per barrel (bbl), respectively. This is a decline of $.02 per Mcf in gas prices and $1.92 per bbl in oil prices compared with 1993. Nonetheless, efforts to stabilize prices through hedging activities contributed approximately $1.6 million of operating revenues for the year. At present, Seneca's goal is to hedge approximately 60% of its Gulf Coast gas and oil production.
1993 Compared with 1992. Operating revenues increased $22.3 million in 1993 compared with 1992. This increase was also primarily attributable to Seneca's Gulf Coast operations. Natural gas production from the Gulf Coast operations increased 217% to 12.1 Bcf from 3.8 Bcf in 1992. In total, from all geographic areas, production rose by 7.8 Bcf to 19.9 Bcf. Lower natural gas production was realized from Appalachian and West Coast properties. Systemwide, the average price received for gas production in 1993 was $2.20 per Mcf, an increase of $.23 per Mcf from $1.97 per Mcf in 1992. Oil production (mainly condensate from gas wells) also increased in 1993 by 188,000 bbls compared with 1992. Systemwide, the average price received for oil production in 1993 was $16.78 per bbl, a decrease of $.33 per bbl from $17.11 per bbl in 1992.
Production Volumes Year Ended September 30 1994 1993 1992
Gas Production (million cubic feet) Gulf Coast 16,296 12,134 3,828 West Coast 706 1,059 1,234 Appalachia 6,271 6,681 7,008 23,273 19,874 12,070
Oil Production (thousands of barrels) Gulf Coast 615 387 172 West Coast 404 431 454 Appalachia 11 13 17 1,030 831 643
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Operating Income
1994 Compared with 1993. Operating income before income taxes increased $8.8 million in 1994 compared with 1993. This increase reflects the higher revenues discussed above, partly offset by higher depletion expense which is directly related to higher revenues. O & M expense remained basically level in 1994 compared with 1993. Although O & M expense related to increased production activity in the Gulf Coast operations was higher in 1994 than 1993, it was offset by a charge to O & M in 1993 for work performed on Appalachian wells that did not recur in 1994.
1993 Compared with 1992. Operating income before income taxes increased $6 million in 1993 compared with 1992. This increase was also the result of the increase in operating revenues, discussed above, partly offset by increases in depletion and O & M expenses. The increase in O & M expenses is related to the increased production activity in the Gulf Coast operations. Additionally, a charge to O & M expense of $2.3 million was recorded in the fourth quarter of 1993 for work performed on Appalachian wells.
OTHER NONREGULATED
Operating Revenues
1994 Compared with 1993. Operating revenues increased $29.9 million in 1994 compared with 1993. This increase is almost entirely due to higher revenues from NFR, the Company's gas marketing subsidiary, as its gas marketing volumes more than doubled to 18.2 Bcf in 1994 from 7.3 Bcf in 1993.
1993 Compared with 1992. Operating revenues decreased $5.4 million in 1993 compared with 1992. This decline reflected lower revenues from UCI, the Company's pipeline construction subsidiary, partly offset by higher revenues from NFR. UCI had an exceptionally productive year in 1992, completing several projects in Virginia and New York for nonaffiliated pipeline companies that were expanding their systems. The lack of large projects in 1993 negatively impacted UCI's revenues. NFR's revenues increased in 1993, as gas marketing volumes increased to 7.3 Bcf from 5.4 Bcf in 1992.
Operating Income
1994 Compared with 1993. Operating income before income taxes increased $3.5 million in 1994 compared with 1993. This increase is due to the improved performance of UCI, which, although still operating at a loss, had higher margins than in 1993. In addition, the improved performance of NFR and the Company's timber operations enhanced operating income before income taxes of this segment.
1993 Compared with 1992. Operating income before income taxes decreased $5.2 million in 1993 compared with 1992. This decline was mainly the result of the lack of a contribution by UCI to operating income before income taxes. The lack of large projects, coupled with tight margins contributed to poor performance in 1993. This more than offset the increase in NFR's operating income before income taxes resulting from increased marketing activities.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
INCOME TAXES, OTHER INCOME AND INTEREST CHARGES
Income Taxes. Income taxes increased in 1994 and 1993, mainly because of increases in pretax income as well as higher income tax rates. In addition, the increase in income taxes in 1994 reflects lower Section 29 nonconventional fuel tax credits. These credits, which relate to production from qualified gas wells, decreased to $1.7 million in 1994, down from $2.6 million in 1993. These credits are a direct reduction of income tax expense.
Other Income. Other income decreased $1.2 million and $1 million in 1994 and 1993, respectively. A portion of the decrease in 1994 and 1993 was because Distribution Corporation discontinued the accrual of interest income on deferred contract reformation costs (CRC) in April 1993, in accordance with a settlement with the PSC for full recovery of CRC. In addition, the decrease in 1994 reflects lower interest income on temporary cash investments.
Other income also decreased in 1993 because of lower income associated with funds used during construction by the Pipeline and Storage segment resulting from lower construction balances. The decreases in 1993 were partly offset by higher interest income on temporary cash investments related to the proceeds from the September 1992 issuance of 2.5 million shares of common stock.
Interest Charges. Interest on long-term debt decreased $1.8 million and $1.4 million in 1994 and 1993, respectively. This was mainly due to refinancing activities, whereby higher-interest long-term debt was replaced with lower-interest long-term debt and with equity.
Other interest charges decreased $3 million and $5.7 million in 1994 and 1993, respectively. The declines in both 1994 and 1993 reflect lower interest on short-term borrowings because of lower average amounts outstanding. A lower weighted average interest rate in 1993 also contributed to the decline in short-term interest. However, 1994 reflects an increase in the weighted average interest rate.
1995 OUTLOOK
The coming year will be one of transition for the Company as it works through the impact of the FERC's Order 636 on the state level. As a result, 1995 earnings are expected to be lower than the record earnings of 1994. However, management continues to believe that the integrated strength of the Company places it on a course for growth in 1996 and beyond.
When reviewing 1994 earnings it is important to note that $.09 per share was due to the cumulative effect of mandated accounting changes which will not recur in 1995. In addition, allowed returns on pipeline equity are expected to decrease as a result of allegedly lower risks associated with that business. Supply Corporation, therefore, anticipates a lower return on equity for rates to become effective in 1995. Further, in the Utility Operation, Distribution Corporation saw its allowed return on equity in its New York rate jurisdiction fall from 12.0% to 10.7% in July. The Company expects allowed returns on equity at the state level to increase in future years as a result of the state
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
commission recognition of increased risks under the FERC's Order 636, as well as the rise in interest rates. Nevertheless, such a rise will not significantly benefit 1995 earnings.
Our Exploration and Production segment, and our Other Nonregulated operations should increase their earnings contribution in 1995. However, the current low prices received for natural gas production will temper the increase and, therefore, it is unlikely that increased contributions for our nonregulated operations will cause consolidated earnings to increase in 1995.
CAPITAL RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
Sources and (Uses) of Cash Year Ended September 30 (in millions) 1994 1993 1992 Provided by Operating Activities $199.2 $123.7 $ 93.0 Capital Expenditures (135.1) (131.9) (157.9) Short-Term Debt (84.3) (30.2) 20.5 Long-Term Debt, Net Change 80.1 (51.1) 74.3 Issuance of Common Stock 9.1 78.8 73.7 Common Dividends (57.2) (52.2) (45.6) All Other-Net 3.6 .2 (2.1) Net Increase (Decrease) in Cash and Temporary Cash Investments $ 15.4 $(62.7) $ 55.9
OPERATING CASH FLOW
Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, deferred income taxes and allowance for funds used during construction. In 1994, noncash items also included the cumulative effect of required changes in accounting for income taxes and post-employment benefits in accordance with SFAS 109 and SFAS 112, respectively.
Cash provided by operating activities in the Utility Operation and Pipeline and Storage segment may vary substantially from year to year because of fluctuations in weather, supplier refunds, the impact of rate cases, and for the Utility Operation, fluctuations in over- or under-recovered purchased gas costs. The impact of weather on cash flow is tempered in the Utility Operation's New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation's SFV rate design.
For a graph of "Book Value Per Common Share" see graph B. in the Appendix of this report.
Net cash provided by operating activities totalled $199.2 million in 1994, an increase of $75.5 million compared with the $123.7 million provided by
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
operating activities in 1993. This increase reflected higher revenues and earnings in the Exploration and Production segment, mainly from its Gulf Coast operations. The Utility Operation had an increase in cash flow from operations mainly because Distribution Corporation had over-recovered purchased gas costs at September 30, 1994, while it was in an under-recovery position at September 30, 1993. In addition, the Pipeline and Storage segment had an increase in upstream pipeline company refunds received in 1994, thus increasing its cash flow from operations.
INVESTING CASH FLOW
Capital Expenditures. Capital expenditures totalled $138.3 million in 1994. The table below presents these expenditures by business segment:
Year Ended September 30 (in millions) 1994 Percentage Utility Operation $ 61.7 44.6% Pipeline and Storage 20.5 14.8 Exploration and Production 52.5* 38.0 Other Nonregulated 3.6 2.6 $138.3* 100%
* Includes noncash acquisition of $3.2 million in a stock-for-asset swap.
Most of the Utility Operation's capital expenditures were for the replacement of mains and main extensions, as well as for the replacement of service lines and the installation of new services.
Pipeline and Storage capital expenditures included an increase in compression at two locations, other additions, improvements and replacements to the Company's transmission and storage systems.
The majority of the Exploration and Production segment's capital expenditures were made for the exploration for and development of oil and gas properties located offshore in the Gulf of Mexico, and in Seneca's Northeast Clay Field in central Texas. As a result of activity in the Gulf Coast Region, reserves included 93.4 Bcf of new gas reserves and 1.1 million barrels of new oil reserves at September 30, 1994. In addition, capital expenditures in the Appalachian Region included $3.2 million for the acquisition of natural gas production assets in exchange for Company common stock. This acquisition added approximately 3 Bcf of gas reserves.
Other Nonregulated capital expenditures included timberland and equipment purchases.
The Company's estimated capital expenditures for the next three years are:
Year Ended September 30 (in millions) 1995 1996 1997 Utility Operation $ 63.6 $ 59.1 $ 58.1 Pipeline and Storage 38.0 17.6 18.3 Exploration and Production 74.3 78.2 80.8 Other Nonregulated 7.1 1.2 1.3 $183.0 $156.1 $158.5
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Estimated expenditures for the Utility Operation during the next three years will be concentrated in the areas of main replacements and extensions, service line replacements and, to a minor extent, the installation of new services.
Included in the Pipeline and Storage segment's capital expenditures for 1995 is approximately $5.6 million to be spent in connection with several expansion projects, the most significant of which is a link with the Empire State Pipeline at Grand Island, New York. This will greatly increase the reliability, flexibility and efficiency of service to the Company's service territory in the areas north of Buffalo and to Grand Island, New York.
Also included in the 1995 capital expenditures is approximately $4.3 million for compressor engine emission controls necessary to comply with the standards of the Clean Air Act Amendments of 1990 (the Act). Approximately $.6 million of capital expenditures were incurred in 1994 to comply with the Act. The Company does not anticipate incurring significant additional capital expenditures to comply with the current standards of the Act. However, changes in standards may require additional expenditures in the future. Management expects that all related capital expenditures will be recoverable through rates.
Significant capital expenditures related to Supply Corporation's Laurel Fields Storage Project (which is pending the FERC's approval) are not expected to be incurred until 1996. Since the timing of expenditures related to this project are not finalized, the preceding table does not include significant amounts for this project. Laurel Fields is a 19 Bcf underground natural gas storage development project, which entails the development of Supply Corporation's Callen Run (a depleted gas field) and expansion of its Limestone Storage Field. Filings with the FERC were made in June 1994 to implement this project. An "open season" was held in August 1994 to identify prospective customers for this project. Precedent agreements are currently being negotiated with interested customers. On November 4, 1994, a proposal was sent to the FERC to divide the project into two phases. Phase I would encompass the expansion of the Limestone Storage Field to accommodate approximately 7 Bcf of storage and phase II would consist of the development of the Callen Run Storage Field. The potential cost of the project is approximately $200 million.
For a graph of "Capital Expenditures" see graph C. in the Appendix to this report.
Estimated capital expenditures in 1995 for the Exploration and Production segment are approximately 40% higher than capital spending in 1994 as the Company sees significant opportunities for growth in this segment. These expenditures will be directed mainly toward developing Seneca's Gulf Coast offshore prospects, evaluating reserve acquisitions and significantly expanding exploration activities. Capital expenditures for Other Nonregulated operations will primarily be used for timberland.
The Company's capital expenditure program is under continuous review. The amounts are subject to modification for opportunities in the natural gas industry such as the acquisition of attractive oil and gas properties or storage
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
facilities and the expansion of transmission line capacities. The magnitude of future capital expenditures in the regulated segments depends, to a large degree, upon market conditions coupled with adequate rate relief.
Other. Cash received on the sale of the Company's investment in property, plant and equipment is reflected as a cash flow from investing activities. Approximately $2.3 million of cash was received in the first quarter of fiscal 1994, related to the fiscal 1993 sale of Seneca's interest in its Alberta, Canada, gas reserves.
FINANCING CASH FLOW
In order to meet the Company's capital requirements, cash from external sources must periodically be obtained through short-term bank loans and commercial paper, as well as through issuances of long-term debt and equity securities. The Company expects these traditional sources of cash to continue to supplement its internally generated cash during the next several years.
On July 1, 1994, the Company redeemed $19.9 million remaining outstanding principal amount of 9-1/2% debentures due July 1, 2019, for $21.3 million, including redemption premium.
On July 14, 1994, the Company issued $50 million of medium-term notes due July 1999, at an interest rate of 7.25%. Also on July 14, 1994, the Company issued $50 million of medium-term notes due July 2024, at an interest rate of 8.48%. These latter notes are callable beginning July 1999. After reflecting underwriting discounts and commissions, the combined proceeds to the Company of these two issuances amounted to $99.4 million. The proceeds were used to reduce outstanding short-term borrowings.
The Company's embedded cost of long-term debt was 7.3% at both September 30, 1994 and 1993.
At September 30, 1994, the Company has Securities and Exchange Commission (SEC) authority remaining under a shelf registration filed in March 1993 to issue and sell up to $220 million of debentures and/or medium-term notes. The amounts and timing of the issuance and sale of these debentures and/or medium-term notes will depend on market conditions and the requirements of the Company.
For a graph of "Embedded Cost of Long-Term Debt" see graph D. in the Appendix to this report.
Consolidated short-term debt decreased $84.3 million during 1994. The Company continues to consider short-term bank loans and commercial paper important sources of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, exploration and development expenditures and other working capital needs.
The Company, through Seneca and NFR, is engaged in certain natural gas and crude oil price swap agreements and in the gas futures market as a means of
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
hedging a portion of the market risk associated with fluctuations in the market price of natural gas and crude oil. In addition, the Company has SEC authority to enter into interest rate swap agreements. For further discussion, see disclosure under "Financial Instruments" in Note A - Summary of Significant Accounting Policies.
The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation nor these other regulatory matters are expected to materially change the Company's present liquidity position.
The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company's covenants contained in its indenture covering long-term debt, at September 30, 1994, the Company would have been permitted to issue up to a maximum of $434.5 million in additional long-term unsecured indebtedness, subject to maturity and long-term interest rates. In addition, at September 30, 1994, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $287.5 million of short-term debt.
For a graph of "Capitalization Ratios" see graph E. in the Appendix to this report.
RATE MATTERS
Utility Operation
New York Jurisdiction
In October 1994, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $56.5 million, or 8.9%, with a requested return on equity of 12.85%. New rates are expected to become effective in August or September 1995. On November 17, 1994, Distribution Corporation presented the PSC staff with a preliminary proposal for a multi-year settlement.
In August 1993, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $55.4 million, or 8.5%, with a return on equity of 12.16%. Included in the requested rate increase was an initial amount of $24.9 million for the recovery of transition costs arising from the FERC's Order 636, which represented 3.8% of the total 8.5% requested increase.
On July 19, 1994, the PSC issued an order authorizing a base rate increase of $11.1 million, or 1.7%, with a return on equity of 10.7%. In addition, the PSC authorized recovery of transition costs arising from the FERC's Order 636
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
of up to $11 million annually from sales customers through the monthly Gas Adjustment Clause (GAC). Distribution Corporation will defer, for recovery in future periods, any amounts that may exceed the $11 million annual amount. New rates became effective July 24, 1994.
The recovery of transition costs from transportation customers in New York remains unresolved. The PSC has postponed its decision on transportation customers' allocable share of transition costs pending further consideration of the issue in a generic restructuring case (the Generic Case) which began in October 1993. The PSC staff's position in the Generic Case is that transportation customers should be assigned a per-unit charge that is equal to 50% of the per-unit charge being collected from sales customers for gas supply realignment (GSR) costs and stranded costs. The PSC has authorized Distribution Corporation's continued deferral of transition costs relating to transportation customers until resolution in the Generic Case. At September 30, 1994, deferred transition costs related to transportation customers amounted to approximately $2 million.
In July 1993, in connection with a previously approved two-year settlement, Distribution Corporation received PSC approval for the second year of the settlement. The approval was for a rate increase of $13.3 million, or 2.1%, for the 12-month period ended July 31, 1994. This rate increase went into effect on July 23, 1993.
Pennsylvania Jurisdiction
On March 8, 1994, Distribution Corporation filed in its Pennsylvania jurisdiction a request for an annual rate increase of $16 million, or 6.8%, with a return on equity of 12.25%. A proposal for a WNC was included in this filing. On December 6, 1994, an order was issued by the PaPUC authorizing an annual rate increase of $4.8 million, or 2.0 %, with a return on equity of 11.0% and without a WNC. New rates are scheduled to become effective as of December 7, 1994.
In March 1993, Distribution Corporation filed with the PaPUC for an annual rate increase in its Pennsylvania jurisdiction of $33.4 million, or 16.2%, with a return on equity of 12.4%. Included in the requested rate increase was an initial amount of $8.2 million for the recovery of transition costs arising from the FERC's Order 636. On December 1, 1993, an order was issued by the PaPUC authorizing an annual rate increase of $11.4 million, or 4.9%, exclusive of transition costs. The new rates became effective as of December 1, 1993.
The PaPUC's December 1, 1993 order also addressed certain issues concerning recovery of GSR costs and stranded costs resulting from the implementation of the FERC's Order 636. Under this order, Distribution Corporation began collecting, effective December 1, 1993, GSR and stranded costs from its customers through a separate surcharge. Distribution Corporation is allowed to update this surcharge on a quarterly basis. Distribution Corporation is recovering under-recovered purchased gas transition costs from its Pennsylvania sales customers through its gas cost recovery rates.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
General rate increases do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses.
State Regulatory Environment
The seeds of change precipitated by the FERC's Order 636 are redefining the roles of the utility industry and the state regulatory commissions. Competition has arrived for utilities, and it is anticipated that, similar to what was done in the pipeline sector of the natural gas industry, regulators will require utilities to unbundle their services. The anticipated result is that utility service will divide into "core" markets consisting of the typical residential and commercial customers, as well as customers taking firm transportation service and the "non-core" markets consisting of competitive commercial and industrial markets. It is anticipated that non-core services will be lightly regulated and, with respect to core customers, regulators are expected to focus on increased utility efficiency.
Many state regulators believe that utilities can gain efficiency through performance-based incentive ratemaking. Such ratemaking is intended to enhance the traditional cost-of-service ratemaking formula, which many believe does not provide incentives to operate efficiently. Distribution Corporation has proposed several customer service performance incentives in its New York rate case filed in October 1994. If these incentives are accepted, the mechanisms would allow the PSC to administer financial penalties or rewards determined by the utility's ability to meet or exceed required performance levels. The proposed incentives relate to: response time to customer inquiries and complaints; billing accuracy; keeping appointments for service; and efficiency in the installation of new service lines.
The New York and Pennsylvania regulatory commissions have instituted several generic proceedings related, among other things, to restructuring in response to the FERC's Order 636. The more significant ones, all of which are still pending, are discussed below:
New York
Finance Proceeding. The purpose of this proceeding is to develop a uniform method for calculating a utility's rate of return on equity.
Ratesetting Proceeding. This proceeding is intended to develop guidelines for settlements, incentive ratemaking and multi-year rate filings, in addition to the traditional single-year procedure. Thus, a menu of options would be available for each utility to select the appropriate ratemaking proposal.
Generic Restructuring Proceeding. This proceeding is examining the appropriate retail or end-use impacts resulting from the FERC's Order 636 pipeline restructuring. It is expected that the PSC will issue an order addressing key issues such as unbundling, rate design and the extent of state regulation. Implementation will likely be achieved by each utility on a case-by-case basis.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Pennsylvania
Settlement Guidelines. This proceeding is intended to develop orders addressing specific rules of procedure to accomplish settlement of complex proceedings, including rate cases.
FERC Order 636 Proceedings. The PaPUC has thus far responded to the FERC's Order 636 with three generic proceedings addressing different operational areas. They are proceedings on transportation services, gas procurement practices (including a gas purchase incentive mechanism) and capacity release. Distribution Corporation has already implemented many of the proposed changes in previous rate cases and expects that additional changes will not significantly alter current operations.
Distribution Corporation is working closely with the state regulatory commissions to resolve the complexities of industry restructuring.
Pipeline and Storage
For a discussion of Supply Corporation's gathering rates, refer to Note B - Regulatory Matters.
On October 31, 1994, Supply Corporation filed for an annual rate increase of $21 million, with a requested return on equity of 12.6%. This rate case was filed as a result of the FERC's order issued on October 28, 1994, rejecting Supply Corporation's rate case filed on September 30, 1994. The FERC rejected the September 30, 1994 filing because it disagreed with the proposed method of rolling-in rates for the storage service previously offered by Penn-York (Penn-York was merged into Supply Corporation effective July 1, 1994).
On December 30, 1993, the FERC issued an order approving, with slight modification the Settlement, which was filed with the FERC on October 15, 1993, respecting two Supply Corporation rate proceedings. As modified, the Settlement provided for rates that produced annual revenues of approximately $125 million between July 1, 1992, and July 31, 1993. Rates for the period beginning August 1, 1993, reflect reduced costs after restructuring plus certain settlement concessions, and will produce revenues of approximately $121 million annually. As a result of the Settlement, Supply Corporation refunded to its customers $13.6 million, including interest, during the second quarter of 1994.
OTHER MATTERS
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures.
Distribution Corporation has been identified by the Environmental Protection Agency or the New York State Department of Environmental Conservation (DEC) as one of a number of companies that are considered to be potentially
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
responsible parties (PRPs) with respect to several waste disposal sites in New York that were operated by unrelated third parties. These PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to Distribution Corporation with respect to the remediation of these sites will be dependent on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion attributed, if any, to Distribution Corporation. Distribution Corporation's estimated share of the clean-up costs has been accrued for four of these sites.
One of these four sites was formerly used for a manufactured gas plant. Distribution Corporation is currently involved in litigation regarding this site. The current owner of the site has submitted a claim against Distribution Corporation for contribution of a share of approximately $1.6 million of removal/remediation costs that have been incurred. It is anticipated that future remedial costs will be incurred and on the basis of a Record of Decision issued by the DEC, as amended on September 19, 1994, the estimated future remedial costs for the site are approximately $5.7 million. Management believes that the ultimate outcome of these matters will not have a material impact on the financial condition, results of operations or cash flows of the Company.
Distribution Corporation has incurred clean-up costs at two additional sites in New York and one site in Pennsylvania related to former manufactured gas plant sites. Supply Corporation is involved in a remediation program of certain of its measuring and regulating stations in Pennsylvania. Estimated clean-up costs have been accrued for these sites.
It is the Company's policy to accrue estimated clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated that clean-up costs related to the above noted sites are in the range of $6.7 million to $10.1 million. At September 30, 1994, the Company has recorded the minimum liability of $6.7 million. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.
In New York, Distribution Corporation has received approval from the PSC to defer and amortize both former manufactured gas and non-manufactured gas site investigation and remediation costs over a three-year period for each site. These costs are then included in rate cases for recovery through base rates. Distribution Corporation is currently recovering such costs in this manner. In Pennsylvania, Distribution Corporation and Supply Corporation expect to recover such costs in rates, as the PaPUC and the FERC, respectively, have allowed recovery of other environmental clean-up costs in rate cases. Accordingly, the Consolidated Balance Sheets at September 30, 1994, include related regulatory assets in the amount of approximately $7.3 million, $.6 million of which relates to costs that have already been incurred.
Effects of Inflation. Although the rate of inflation has been relatively low over the past few years, and thus has benefited both the Company and its
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Concluded)
customers, the Company's operations remain sensitive to increases in the rate of inflation because of the capital-intensive and regulated nature of its major operating segments.
Delays inherent in the ratemaking process prevent the Company from obtaining immediate recovery of increased operating costs. Also, while the ratemaking process gives no recognition to the current cost of replacing property, plant and equipment, based on past practices the Company believes that it will be allowed to earn on the increased cost of its net investment when replacement of facilities occurs.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page Financial Statements:
Report of Independent Accountants 53
Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 1994 54
Consolidated Balance Sheets at September 30, 1994 and 1993 55 - 56
Consolidated Statement of Cash Flows, three years ended September 30, 1994 57
Notes to Consolidated Financial Statements 58 - 88
Financial Statement Schedules: For the three years ended September 30, 1994
V -Property, Plant and Equipment 89 and 91
VI -Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment 90 - 91
VIII-Valuation and Qualifying Accounts and Reserves 92
IX -Short-Term Borrowings 93
X -Supplementary Income Statement Information 94
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
Supplementary Data
Supplementary data that is included in Note I - "Quarterly Financial Data (unaudited)" and Note K - "Supplementary Information For Oil and Gas Producing Activities," appears on page 82 and pages 84 to 88, respectively, of this report, and reference is made thereto.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Report of Independent Accountants
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
As discussed in Notes A and F to the consolidated financial statements, the Company adopted the new accounting standards for postretirement benefits other than pensions, income taxes and other postemployment benefits in fiscal 1994.
PRICE WATERHOUSE LLP
Buffalo, New York October 28, 1994
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
National Fuel Gas Company Consolidated Statements of Income and Earnings Reinvested in the Business
Year Ended September 30 1994 1993 1992 (Thousands of Dollars) INCOME Operating Revenues $1,141,324 $1,020,382 $920,450
Operating Expenses Purchased Gas 497,687 409,005 363,690 Operation Expense 260,411 258,918 240,645 Maintenance 30,979 24,312 22,439 Property, Franchise and Other Taxes 103,788 95,393 89,158 Depreciation, Depletion and Amortization 74,764 69,425 55,726 Income Taxes - Net 47,792 41,046 35,231 1,015,421 898,099 806,889
Operating Income 125,903 122,283 113,561 Other Income 3,656 4,833 5,790 Income Before Interest Charges 129,559 127,116 119,351
Interest Charges Interest on Long-Term Debt 36,699 38,507 39,949 Other Interest 10,425 13,392 19,092 47,124 51,899 59,041
Income Before Cumulative Effect 82,435 75,217 60,310 Cumulative Effect of Changes in Accounting 3,237 - -
Net Income Available for Common Stock 85,672 75,217 60,310
EARNINGS REINVESTED IN THE BUSINESS Balance at Beginning of Year 335,907 314,334 301,066 421,579 389,551 361,376
Dividends on Common Stock 57,725 53,644 47,042
Balance at End of Year $ 363,854 $ 335,907 $314,334
Earnings Per Common Share Income Before Cumulative Effect $2.23 $2.15 $1.94 Cumulative Effect of Changes in Accounting .09 - -
Net Income Available for Common Stock $2.32 $2.15 $1.94
Weighted Average Common Shares Outstanding 37,046,249 34,938,722 31,152,635
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
National Fuel Gas Company Consolidated Balance Sheets
At September 30 1994 1993 (Thousands of Dollars) ASSETS Property, Plant and Equipment $2,166,256 $2,039,436 Less - Accumulated Depreciation, Depletion and Amortization 623,517 561,433 1,542,739 1,478,003 Current Assets Cash and Temporary Cash Investments 29,016 13,595 Receivables - Net 95,993 86,957 Unbilled Utility Revenue 17,311 27,210 Gas Stored Underground 34,711 22,120 Materials and Supplies - at average cost 23,796 20,848 Unrecovered Purchased Gas Costs - 20,772 Prepayments 20,111 17,094 220,938 208,596
Other Assets Recoverable Future Taxes 99,742 - Unamortized Debt Expense 28,396 28,735 Other Regulatory Assets 47,737 43,644 Deferred Charges 15,796 21,255 Other 26,309 21,307 217,980 114,941
$1,981,657 $1,801,540
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
National Fuel Gas Company Consolidated Balance Sheets
At September 30 1994 1993 (Thousands of Dollars) CAPITALIZATION AND LIABILITIES Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized - 100,000,000 Shares; Issued and Outstanding - 37,278,409 Shares and 36,661,008 Shares, Respectively $ 37,278 $ 36,661 Paid In Capital 379,156 363,677 Earnings Reinvested in the Business 363,854 335,907 Total Common Stock Equity 780,288 736,245 Long-Term Debt, Net of Current Portion 462,500 478,417 Total Capitalization 1,242,788 1,214,662
Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 112,500 196,800 Current Portion of Long-Term Debt 96,000 - Accounts Payable 66,667 42,893 Amounts Payable to Customers 38,714 40,776 Other Accruals and Current Liabilities 61,368 69,523 375,249 349,992 Deferred Credits Accumulated Deferred Income Taxes 273,560 188,793 Taxes Refundable to Customers 31,688 - Unamortized Investment Tax Credit 14,057 14,743 Other Deferred Credits 44,315 33,350 363,620 236,886 Commitments and Contingencies - -
$1,981,657 $1,801,540
See Notes to Consolidated Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note A - Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned. All significant intercompany balances and transactions have been eliminated where appropriate.
Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation.
Regulation. Two of the Company's principal subsidiaries, National Fuel Gas Distribution Corporation (Distribution Corporation) and National Fuel Gas Supply Corporation (Supply Corporation) are subject to regulation by state and federal authorities having jurisdiction. The Company accounts for these regulated operations in accordance with Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulation." This statement sets forth the application of generally accepted accounting principles for those companies whose rates are established by or are subject to approval by an independent third-party regulator. Under SFAS 71, regulated companies defer costs as assets on the balance sheet (regulatory assets) when these costs have been or are expected to be allowed in the ratesetting process in a period different from the period in which the costs would be charged to expense by an unregulated company. These deferred regulatory assets are then flowed through the income statement in the period in which the same amounts are recovered in revenues through rates.
Costs deferred in accordance with SFAS 71 include "Recoverable Future Taxes," "Unamortized Debt Expense" and "Other Regulatory Assets." Refer to the separate Income Taxes and Unamortized Debt Expense sections of this Note for further discussion. Other regulatory assets are shown below:
At September 30 (in thousands) 1994 1993
Pension and Post-Retirement Benefit Costs (Note F) $17,199 $ 8,125 Order 636 Transition Costs* (Note B) 8,417 200 Deferred Contract Reformation Costs (Note B) 7,736 24,862 Environmental Clean-up (Note G) 7,310 4,873 All Other 7,075 5,584
$47,737 $43,644
* Exclusive of amounts being collected through gas costs. Such amounts are included in unrecovered purchased gas costs.
Revenues. Revenues are recorded as bills are rendered, except that service supplied but not billed is reported as "Unbilled Utility Revenue" and is included in operating revenues for the year in which service is furnished.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Unrecovered Purchased Gas Costs and Refunds. Distribution Corporation's rate schedules contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers.
Supply Corporation collects revenues subject to refund if rates in effect are pending a final rate case determination by the Federal Energy Regulatory Commission (FERC). Estimated rate refund liabilities are recorded which reflect management's current estimate as to the ultimate outcome of each rate case.
Property, Plant and Equipment. The principal assets, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities. Such cost includes an Allowance for Funds Used During Construction (AFUDC), which is defined in applicable regulatory systems of accounts as the net cost of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. The rates used in the calculation of AFUDC are determined in accordance with guidelines established by regulatory authorities.
Included in property, plant and equipment is the cost of gas stored underground - noncurrent, representing the volume of gas required to maintain pressure levels for normal operating purposes.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries' property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Oil and gas exploration and development costs are capitalized under the full-cost method of accounting as prescribed by the Securities and Exchange Commission (SEC). All costs directly associated with property acquisition, exploration and development activities are capitalized, with the principal limitation that such capitalized amounts not exceed the present value of estimated future net revenues from the production of proved gas and oil reserves plus the lower of cost or market of unevaluated properties, net of related income tax effect. The present value of estimated future net revenues was computed based on end-of-year prices adjusted for contracted price changes.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization are computed by application of either the straight-line method or the gross revenue method, in amounts sufficient to recover costs over the estimated service lives of property in service, and for oil and gas properties, over the period of estimated gross revenues from proved reserves. The costs of unevaluated oil and gas properties are excluded from this calculation. The provisions for depreciation, depletion and amortization, including amounts capitalized or charged to other operating accounts, were $75,686,000 in 1994,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
$70,629,000 in 1993 and $56,506,000 in 1992, and were equivalent to 3.9% in 1994, 3.8% in 1993 and 3.3% in 1992 of average depreciable property, plant and equipment for those years.
Gas Stored Underground - Current. Gas stored is carried at cost, on a last-in, first-out (LIFO) basis. Under present regulatory practice, the liquidation of a LIFO layer is reflected in future gas cost adjustment clauses. Based upon the average price of spot market gas purchased in September 1994, including transportation costs, the current cost of replacing the inventory of gas stored underground-current exceeded the amount stated on a LIFO basis by approximately $19,300,000 at September 30, 1994.
Unamortized Debt Expense. Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related issues. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment.
Income Taxes. The Company and its wholly-owned subsidiaries file a consolidated federal income tax return. Prior to its repeal in 1986, Investment Tax Credit was either reflected currently in income or deferred and amortized to income over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
On October 1, 1993, the Company adopted SFAS 109, "Accounting for Income Taxes" (SFAS 109). The adoption of SFAS 109 changed the Company's method of accounting for income taxes from the deferred method to an asset and liability approach. Previously, deferred taxes were provided for the tax effects of timing differences between financial reporting purposes and tax reporting purposes except where not permitted by regulatory authorities. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences attributable to temporary differences between the carrying amounts of assets and liabilities and their tax bases. In addition, such deferred tax assets and liabilities will be adjusted for the effects of enacted changes in tax laws and rates.
The cumulative effect of this change increased net income by $3,826,000 as a result of the reduction in deferred income taxes associated with the Company's nonregulated operations. The effect on the recorded deferred income taxes associated with rate-regulated activities was to reclassify a portion to a regulatory liability since such amounts are expected to be refundable to customers under regulatory procedures. This liability amounted to $31,688,000 at September 30, 1994.
In addition, under SFAS 109, the Company is required to recognize additional deferred taxes for timing differences on which deferred tax treatment was not permitted by regulatory authorities. The recognition of these deferred tax balances had no effect on earnings due to the recording of corresponding regulatory assets representing future amounts collectible from customers in the ratemaking process. Substantially all of these deferred taxes relate to property, plant and equipment and related investment tax credits and will be amortized consistent with the depreciation and amortization of these accounts. The additional deferred taxes amounted to $99,742,000 at September 30, 1994.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Financial Instruments. In October 1994, the Financial Accounting Standards Board (FASB) issued SFAS 119, "Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments" (SFAS 119). This statement requires disclosures about amounts, nature, and terms of derivative financial instruments. It also requires that a distinction be made between financial instruments held or issued for trading purposes and those held or issued for purposes other than trading. The Company's disclosure is in accordance with the provisions of SFAS 119.
Seneca Resources Corporation (Seneca) has entered into certain price swap agreements that effectively hedge a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These agreements are not held for trading purposes. The price swap agreements call for Seneca to receive monthly payments from (or make payments to) other parties based upon the differential between a fixed and a variable price as specified by the agreement. At September 30, 1994, Seneca had natural gas price swap agreements which run through December 1996 and have an aggregate notional amount of approximately 16.2 billion cubic feet (Bcf) of natural gas equivalent. In October 1994, Seneca entered into natural gas price swap agreements for an additional aggregate notional amount of approximately 3.6 Bcf of natural gas equivalent. These agreements cover the period from March 1995 through February 1996. Seneca also had crude oil price swap agreements at September 30, 1994, which run through September 1997 and have an aggregate notional amount of 773,000 barrels of crude oil equivalent. Gains or losses from these price swap agreements are reflected in operating revenues on the Consolidated Statement of Income at the time of settlement with the other parties, which is when the underlying hedged commodity transaction occurs.
National Fuel Resources, Inc. (NFR) participates in the natural gas futures market to lock in natural gas prices to decrease volatility related to fluctuations in market prices. Futures are not held for trading purposes. At September 30, 1994, NFR had short positions on futures amounting to approximately 1.1 Bcf of natural gas. It also had long positions on futures amounting to approximately .1 Bcf of natural gas. Gains or losses resulting from changes in the market value of these transactions are deferred until the hedged commodity transaction occurs, at which point they are reflected in operating revenues on the Consolidated Statement of Income.
Seneca and NFR are at risk in the event of nonperformance by counterparties on natural gas and crude oil price swap agreements and natural gas futures, respectively, but Seneca and NFR do not anticipate nonperformance by any of these counterparties.
The Company currently has authorization from the SEC to enter into interest rate swap agreements and certain other derivative instruments up to a notional amount of $350,000,000. Currently, no such agreements are outstanding.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents. Interest paid in 1994, 1993 and 1992 was $46,183,000,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
$48,282,000 and $58,530,000, respectively. Net income taxes paid in 1994, 1993 and 1992 were $37,573,000, $19,872,000 and $15,282,000, respectively.
In December 1993, the Company entered into a non-cash investing activity whereby it issued 108,396 shares of Company common stock to Empire Exploration, Inc. (Empire), which in turn exchanged those shares for $3,184,000 of natural gas production assets, $167,000 of other current assets and $280,000 of cash. On July 1, 1994, Empire was merged into Seneca.
Earnings Per Common Share. Earnings per common share are calculated using the weighted average number of shares outstanding during each fiscal year. Common stock equivalents in the form of stock options do not have a material dilutive effect on earnings per common share.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note B - Regulatory Matters
Order 636 Transition Costs. As a result of the industrywide restructuring under the FERC's Order 636, Distribution Corporation is incurring transition costs billed by Supply Corporation and other upstream pipeline companies.
At September 30, 1994, Distribution Corporation's estimate of its exposure to outstanding transition cost claims is in the range of $4,600,000 to $80,700,000. The majority of these costs relate to gas supply realignment (GSR) costs and stranded costs and is exclusive of any potential stranded costs related to production plant or gathering facilities which pipeline companies, including Supply Corporation, may file for at a future date, and any potential GSR costs claimed by an upstream supplier, which are subject to the outcome of its bankruptcy and FERC proceedings. At September 30, 1994, the Company has recorded the minimum liability and corresponding regulatory asset of $4,600,000.
Distribution Corporation has authorization from the State of New York Public Service Commission (PSC) to recover up to $11,000,000 annually of transition costs from sales customers in New York through the monthly Gas Adjustment Clause (GAC). Distribution Corporation will defer, for recovery in future periods, any amounts that may exceed the $11,000,000 annual amount.
The recovery of transition costs from transportation customers in New York remains unresolved. The PSC has postponed its decision on transportation customers' allocable share of transition costs pending further consideration of the issue in a generic restructuring case (the Generic Case) which began in October 1993. The PSC staff's position in the Generic Case is that transportation customers should be assigned a per-unit charge that is equal to 50% of the per-unit charge being collected from sales customers for GSR and stranded costs. The PSC has authorized Distribution Corporation's continued deferral of transition costs relating to transportation customers until resolution in the Generic Case. At September 30, 1994, deferred transition costs related to transportation customers amounted to $2,031,000.
In its Pennsylvania jurisdiction, Distribution Corporation is recovering GSR and stranded costs from its customers through a separate surcharge. At September 30, 1994, Distribution Corporation had deferred GSR and stranded costs of $900,000. Distribution Corporation will recover these costs through a true-up mechanism whereby it is allowed to update its surcharge on a quarterly basis. Distribution Corporation is recovering under-recovered purchased gas transition costs from its Pennsylvania sales customers through its gas cost recovery rates.
Distribution Corporation will continue to actively challenge relevant FERC filings made by the upstream pipeline companies to ensure the eligibility and prudency of all transition cost claims. This industrywide issue will potentially involve years of rate proceedings before the FERC, state commissions and the courts. Management believes that any transition costs resulting from the implementation of Order 636 which have been determined to
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
be both eligible and prudently incurred should be fully recoverable from the respective customers of Supply Corporation and Distribution Corporation.
Gathering Rates. Supply Corporation has approximately $19,000,000 of production and gathering facilities used, in part, to gather natural gas of local producers, including the Company's production in the Appalachian Region. Currently, Supply Corporation has a gathering rate in place under an interim settlement with customers and local producers. In its restructuring orders, the FERC has directed Supply Corporation to fully unbundle its gathering rate effective July 1, 1995. Supply Corporation submitted an offer of settlement (the Settlement) which if approved would provide for a ten-year transition to fully unbundle rates beginning July 1, 1995. Comments on the Settlement have been filed by the parties. Such comments were generally favorable. However, opposition came largely from offsystem customers claiming that they should not have any cost responsibility for the production and gathering plant because it is not necessary to provide service to them. The Settlement currently awaits a FERC decision. The FERC has, however, also directed Supply Corporation to file a fully unbundled rate by December 31, 1994, that would become immediately effective on July 1, 1995. Supply Corporation has requested an extension of the December deadline to April 28, 1995, since approval of the Settlement in the meantime would make further filings unnecessary.
Contract Reformation Issues. As a result of the FERC's Orders 436 and 528 issued in October 1985 and November 1990, respectively, pipeline companies have made, and have agreed to make, payments to producers in exchange for reformation of the price and/or take-or-pay provisions of their long-term wellhead gas supply arrangements, also referred to as contract reformation costs (CRC). The Company is currently recovering from its customers substantially all CRC billed to it.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note C - Income Taxes
Deferred tax liabilities (assets) were comprised of the following:
At September 30, 1994 (in thousands) Accumulated Deferred Deferred Income Taxes Income Taxes Current* Deferred Tax Liabilities: Excess of Tax Over Book Depreciation $174,006 $ - Exploration and Intangible Well Drilling Costs 78,224 - Other 64,181 - Total Deferred Tax Liabilities 316,411 -
Deferred Tax Assets: Deferred Investment Tax Credits (8,388) - Overheads Capitalized for Tax Purposes (9,238) - Provisions for Rate Contingencies and Refunds - (686) Unrecovered Purchased Gas Costs - (3,762) Other (25,225) - Total Deferred Tax Assets (42,851) (4,448)
Total Net Deferred Income Taxes $273,560 $( 4,448)
* Included on the Consolidated Balance Sheets in "Other Accruals and Current Liabilities."
The components of federal and state income taxes included in the Consolidated Statement of Income are as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Expenses: Current Income Taxes - Federal $36,630 $21,148 $17,680 State 6,309 2,979 3,426
Deferred Income Taxes 4,853 16,919 14,125 47,792 41,046 35,231
Other Income: Deferred Investment Tax Credit (682) (693) (706)
Cumulative Effect of Changes in Accounting: Adoption of SFAS 109 (3,826) - - Tax Effect of Adoption of SFAS 112 (425) - -
Total Income Taxes $42,859 $40,353 $34,525
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
Year Ended September 30 (in thousands) 1994 1993 1992
Net Income Available for Common Stock $ 85,672 $ 75,217 $60,310 Total Income Taxes 42,859 40,353 34,525
Income Before Income Taxes $128,531 $115,570 $94,835
Income Tax Expense, Computed at Statutory Rate of 35% in 1994 and 34.75% in 1993 and 34% in 1992 $ 44,986 $40,161 $32,244 Increase (Reduction) in Taxes Resulting from: Current State Income Taxes 4,101 1,944 2,261 Depreciation 2,174 2,221 1,893 Production Tax Credits (1,658) (2,608) (520) Adoption of SFAS 109 (3,826) - - Miscellaneous (2,918) (1,365) (1,353)
Total Income Taxes $42,859 $40,353 $34,525
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note D - Capitalization
Common Stock. The Company issued 2,500,000 shares of common stock in each of May 1993 and September 1992. The shares issued in May 1993 were sold to the public at a price of $30.50 per share, and the net proceeds to the Company after underwriting discounts and commissions were $29.57 per share, or $73,925,000. The shares issued in September 1992 were sold to the public at a price of $27.625 per share, and the net proceeds to the Company after underwriting discounts and commissions were $26.715 per share, or $66,787,500.
Through the Company's Dividend Reinvestment and Stock Purchase Plan (DRP), holders of shares of the Company's common stock may reinvest cash dividends and/or make cash investments in the common stock of the Company. In 1994 and 1993, open market shares were utilized for issuance under the DRP. In 1992, 65,015 new shares as well as open market shares were issued under the DRP.
Under the Company's section 401(k) plans, the Company issued 136,100 shares, 115,300 shares and 108,700 shares of common stock during 1994, 1993 and 1992, respectively.
The Company's Customer Stock Purchase Plan (CSPP) provides residential customers the opportunity to acquire shares of Company common stock without the payment of any brokerage commission or service charges in connection with such acquisitions. At the discretion of the Company, the shares purchased under the CSPP are original issue shares purchased directly from the Company or shares purchased on the open market by an agent. The Company issued 208,990 shares, 139,986 shares and 156,607 shares of common stock under the CSPP during 1994, 1993 and 1992, respectively.
Effective March 17, 1992, after having received shareholder approval, the Company amended its Restated Certificate of Incorporation, as amended, to change the designation of its authorized and issued common stock from shares having no par value to shares having a par value of $1 per share. Accordingly, $214,461,000 was transferred from Common Stock to Paid In Capital. This change eliminated unnecessary additional qualification and licensing fees incurred by the Company in certain states as a result of having no par value common stock. This change has no effect on the rights and privileges of Company stockholders.
Stock Options and Stock Award Plans. The Company's 1993 Award and Option Plan (1993 Plan) provides for the issuance of incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, performance units and performance shares to key employees. The 1983 Incentive Stock Option Plan (1983 Plan) provided for the issuance of incentive stock options to key employees, and the 1984 Stock Plan (1984 Plan) provided for awards of restricted stock, nonqualified stock options and stock appreciation rights to key employees. Stock options under all three plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
In 1993, the authorized maximum number of shares of common stock under the 1983 Plan and 1984 Plan was reached, and therefore no further options or restricted stock have been awarded under these plans. Under the 1993 Plan, the maximum number of shares of common stock available for option grants and stock awards is 1,600,000 shares. Stock options outstanding do not have a materially dilutive effect on earnings per common share.
Transactions involving option shares for all three plans are summarized as follows: Number of Shares Subject Option Price to Option Per Share
Outstanding at September 30, 1991 516,260 $13.19 to $23.81 Granted in 1992 206,500 $23.88 Exercised in 1992* (100,664) $13.19 to $23.81 Forfeited in 1992 (4,000) $23.81 Outstanding at September 30, 1992 618,096 $15.59 to $23.88 Granted in 1993 416,500 $25.19 and $31.50 Exercised in 1993* (78,750) $15.59 to $23.88 Outstanding at September 30, 1993 955,846 $15.59 to $31.50 Granted in 1994 272,000 $31.63 Exercised in 1994* (60,509) $18.00 to $25.19 Outstanding at September 30, 1994 1,167,337 $15.59 to $31.63
Shares Exercisable at September 30, 1994 895,337
Shares Reserved for Future Grant at September 30, 1994 1,159,072
*In connection with exercising these options, 18,088, 36,797 and 35,532 shares were surrendered and/or cancelled during 1994, 1993 and 1992, respectively.
As of September 30, 1994, a total of 286,308 shares of restricted stock had been awarded under the 1984 Plan and 1993 Plan, since inception. Restrictions have lapsed respecting 148,814 of these shares. Of the remaining 137,494 shares of restricted stock, restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 1999 through 2002. Restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 2000 through 2003. Restrictions on 113,494 shares will lapse respecting approximately one-sixth of such shares on each January 2, 1996 through 2001. Restrictions on 8,000 shares will lapse respecting approximately one-fourth of such shares on each January 2, 2001 through 2004. The market value of the restricted stock on the date the award was made is being recorded as compensation expense over the periods over which the restrictions lapse. During the restriction period, share certificates are held by the Company.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Redeemable Preferred Stock. As of September 30, 1994, there were 3,200,000 shares of $25 par value Cumulative Preferred Stock authorized but unissued.
Summary of Changes in Common Stock Equity Earnings Paid Reinvested Common Stock In in the (in thousands) Shares Amount Capital Business
Balance at September 30, 1991 30,926 $241,043 $301,066 Net Income Available for Common Stock 60,310 Dividends Declared on Common Stock ($1.48 Per Share) (47,042) Transfer from Common Stock to Paid In Capital (214,461) $214,461 Common Stock Issued: Sale of Common Stock 2,500 2,500 64,288 DRP, Incentive Compensation Plans and 401(k) Plans 273 3,314 3,065 CSPP 157 1,460 2,614 Common Stock Issuance Costs (285)
Balance at September 30, 1992 33,856 33,856 284,143 314,334 Net Income Available for Common Stock 75,217 Dividends Declared on Common Stock ($1.52 Per Share) (53,644) Common Stock Issued: Sale of Common Stock 2,500 2,500 71,425 Incentive Compensation Plans and 401(k) Plans 165 165 4,255 CSPP 140 140 4,101 Common Stock Issuance Costs (247)
Balance at September 30, 1993 36,661 36,661 363,677 335,907 Net Income Available for Common Stock 85,672 Dividends Declared on Common Stock ($1.56 Per Share) (57,725) Common Stock Issued: Acquisition of Natural Gas Production Assets 108 108 3,523 Incentive Compensation Plans and 401(k) Plans 300 300 5,397 CSPP 209 209 6,559
Balance at September 30, 1994 37,278 $ 37,278 $379,156 $363,854*
* The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 1994, $289,470,000 of accumulated earnings was free of such limitations. However, substantially all of this amount has been reinvested in the business.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Long-Term Debt. The outstanding long-term debt is as follows:
At September 30 (in thousands) 1994 1993
Debentures: 7-3/4% due February 2004 $125,000 $125,000 9-1/2% due July 2019 - 19,917
Medium-Term Notes: 6.07% due May 1995 55,000 55,000 6.10% due May 1995 20,000 20,000 6.10% due June 1995 1,000 1,000 9.32% due June 1995 20,000 20,000 8.875% due December 1995 20,000 20,000 8.90% due December 1995 38,500 38,500 4.53% due September 1996 30,000 30,000 6.42% due November 1997 50,000 50,000 7.25% due July 1999 50,000 - 6.60% due February 2000 50,000 50,000 7.395% due March 2023 49,000 49,000 8.48% due July 2024* 50,000 -
558,500 478,417 Less Current Portion 96,000 -
$462,500 $478,417 * Callable beginning July 1999.
The aggregate principal amounts of long-term debt maturing for the next five years, including amounts classified as Current Portion of Long-Term Debt, are: $96,000,000 in 1995, $88,500,000 in 1996, none in 1997, $50,000,000 in 1998 and $50,000,000 in 1999.
The fair market value of the Company's long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, is $541,327,000 and $513,107,000 at September 30, 1994 and 1993, respectively. Such value is not intended to reflect principal amounts that the Company will ultimately be required to repay.
During 1994, the Company redeemed $19,917,000 remaining outstanding principal amount of 9-1/2% debentures due July 1, 2019, for $21,337,000, including redemption premium. Also during 1994, the Company issued $50,000,000 of medium-term notes due July 1999, at an interest rate of 7.25% and $50,000,000 of medium-term notes due July 2024, at an interest rate of 8.48%. The 8.48% notes are callable beginning July 1999. After reflecting underwriting discounts and commissions, the combined proceeds to the Company of these issuances amounted to $99,415,500. The proceeds were used to reduce outstanding short-term borrowings.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
In March 1993, the Company filed a shelf registration with the SEC for $350,000,000 of debentures and/or medium-term notes that became effective on March 30, 1993. The Company has authority remaining under this shelf registration to issue and sell up to $220,000,000 of debentures and/or medium-term notes. The amounts and timing of the issuance and sale of these debentures and/or medium-term notes will depend on market conditions and the requirements of the Company.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note E - Short-Term Borrowings
The Company maintains uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. These lines are utilized primarily as a means of financing, on an interim basis, various working capital requirements and capital expenditures of the Company, including the Company's oil and gas exploration and development program, pipeline construction and the purchase and storage of gas. Borrowings under these lines of credit are made at competitive money market rates, and the Company currently is authorized to borrow up to $400,000,000 thereunder. These credit lines, which are callable at the option of the financial institutions, are reviewed on an annual basis and are expected to remain in place through 1995.
The Company may also issue as much as $150,000,000 of commercial paper from time to time, but in no event may its borrowings under its discretionary lines of credit, or through the issuance of commercial paper, exceed $400,000,000 in the aggregate.
Additionally, the Company has entered into an agreement that establishes a 364-day committed revolving credit arrangement with seven commercial banks, under which it may borrow as much as $105,000,000. This arrangement may be utilized for general corporate purposes, including to support the issuance of commercial paper. The Company pays a fee to maintain this arrangement, and may borrow through this arrangement under four interest rate options. If amounts are borrowed under this arrangement, the $400,000,000 available for borrowing under the discretionary lines of credit is correspondingly reduced. No borrowings under this arrangement were outstanding at September 30, 1994. The arrangement expires on September 20, 1995, and the Company expects to renew or replace all or most of this arrangement before then.
At September 30, 1994, the Company had outstanding notes payable to banks and commercial paper of $102,500,000 and $10,000,000, respectively. At September 30, 1993, the Company had outstanding notes payable to banks and commercial paper of $125,800,000 and $71,000,000, respectively.
The weighted average interest rate on notes payable to banks was 5.13% and 3.29% at September 30, 1994 and 1993, respectively. The weighted average interest rate on commercial paper was 5.09% and 3.32% at September 30, 1994 and 1993, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note F - Retirement Plan and Other Post-Employment Benefits
Retirement Plan. The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Plan) that covers substantially all employees of the Company. The Plan uses years of service, age at retirement and earnings of employees to determine benefits.
The Company's policy is to fund at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. Plan funding is subject to annual review by management and its consulting actuary. Plan assets primarily consist of equity and fixed income investments and units in commingled funds. A plan amendment was adopted which provided for an early retirement window program which is accounted for under the rules prescribed by SFAS 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Plans and for Termination Benefits." For ratemaking purposes, pension expense equals the amount funded less amounts capitalized. Since Plan funding has not been required in recent years, the Company deferred the pension expense associated with its regulated subsidiaries. The amounts deferred are expected to be recovered in rates as contributions are made to the Plan.
The components of net periodic pension expense were as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Service Cost for Benefits Earned During the Period $10,441 $ 9,181 $ 8,816 Interest Cost on Projected Benefit Obligation 26,532 24,258 22,446 Actual Return on Plan Assets (16,212) (35,657) (37,107) Net Amortization and Deferral (16,603) 4,287 7,077 Early Retirement Window 2,855 - - Net Periodic Pension Cost 7,013 2,069 1,232 Deferred for Regulatory Purposes (6,875) (2,012) (1,192) Pension Cost Recognized in Consolidated Statement of Income $ 138 $ 57 $ 40
The projected benefit obligation was determined using an assumed discount rate of 8.5% in 1994, 7.75% in 1993 and 8.5% in 1992. The assumed rate of compensation increase was 5% for all three years. The expected long-term rate of return on Plan assets was 8.5% for all three years. The unrecognized net asset that arose from the initial application of SFAS 87, "Employers' Accounting for Pensions," is being amortized on a straight-line basis over the future working lifetime of those expected to receive benefits under the Plan.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
A reconciliation of the Plan's funded status as determined by the Company's consulting actuary is presented in the following table:
At September 30 (in thousands) 1994 1993
Actuarial Present Value of: Vested Benefit Obligation $245,095 $241,676
Accumulated Benefit Obligation $282,340 $278,843
Projected Benefit Obligation $342,050 $346,634
Plan Assets at Fair Value 370,150 369,920 Plan Assets in Excess of Projected Benefit Obligation 28,100 23,286 Unrecognized Net Asset (37,502) (42,688) Unrecognized Prior Service Cost 13,339 14,418 Unrecognized Net Gain (19,959) (4,025) Pension Liability (16,022) (9,009) Deferred for Regulatory Purposes 15,001 8,126 Pension Liability Recognized on Consolidated Balance Sheets $ (1,021) $ (883)
Other Post-Retirement Benefits. In addition to providing retirement plan benefits, the Company currently provides health care and life insurance benefits for substantially all retired employees under a post-retirement benefit plan (Post-Retirement Plan).
The Company has adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), effective October 1, 1993. This statement required the Company to change its accounting for these post-retirement benefits from the "pay-as-you-go" (cash) basis to the accrual basis.
The Company has established Voluntary Employees' Beneficiary Association (VEBA) trusts for collectively bargained employees and non-bargaining employees. The VEBA trusts are similar to the Company's Retirement Plan trust. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations. Contributions to the VEBA trusts are made to fund employees' post-retirement health care and life insurance benefits, as well as benefits as they are paid to current retirees. The Company's current policy is to invest Post-Retirement Plan assets primarily in equity securities and municipal bonds.
The Company has elected to amortize the initial accumulated liability (transition obligation) to net periodic post-retirement benefit cost on a straight-line basis over a 20-year period. Total post-retirement benefit cost under SFAS 106 was $23,530,000 in 1994 compared with the costs based on cash payments for retiree health care and life insurance benefits of $5,974,000 and $4,945,000 in 1993 and 1992, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The components of net periodic post-retirement benefit cost were as follows:
Year Ended September 30 (in thousands) 1994
Service Cost $ 3,974 Interest Cost 13,714 Expected Return on Post-Retirement Plan Assets (1,035) Amortization of Transition Obligation 8,628 Net Periodic Post-Retirement Benefit Cost 25,281 Deferred for Regulatory Purposes, Net (1,751) Post-Retirement Benefit Cost Recognized in Consolidated Statement of Income $ 23,530
The weighted-average assumed discount rate used in determining the accumulated post-retirement benefit obligation was 8.5% in 1994. The average assumed annual rate of salary increase for the applicable life insurance plans was 5%.
The annual rate of increase in the per capita cost of covered medical care benefits for the active participants and medical plans available to new retirees was assumed to be 13% for 1994; this rate was assumed to decrease gradually to 5.5% by the year 2002 and remain at that level thereafter. The annual rate of increase in the per capita cost of covered medical care benefits for the medical plans not available to new retirees was assumed to be 8% for 1994, 7% for 1995, 6% for 1996 and 5.5% for each year after 1996. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed t o be 14% for 1994. This rate was assumed to decrease gradually to 5.5% by the year 2003 and remain level thereafter.
A reconciliation of the Post-Retirement Plan's funded status as determined by the Company's consulting actuary is in the following table:
At September 30 (in thousands) 1994
Accumulated Post-Retirement Benefit Obligation $ 155,976 Fair Value of Post-Retirement Plan Assets 29,035 Accumulated Benefit Obligation in excess of Plan Assets (126,941)
Unrecognized Transition Obligation 156,210 Unrecognized Net (Gain)/Loss (31,776) Post-Retirement Liability (2,507) Deferred for Regulatory Purposes, Net 1,751 Post-Retirement Benefit Liability Recognized on Consolidated Balance Sheets $ (756)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the accumulated post-retirement benefit obligation as of October 1, 1993, would be increased by $26,600,000. This 1% change would also increase the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 1994 by $3,100,000.
Distribution Corporation and Supply Corporation represent virtually all of the Company's total post-retirement benefit costs. Distribution Corporation and Supply Corporation are fully recovering their net periodic post-retirement benefit costs in accordance with PSC and the Pennsylvania Public Utility Commission (PaPUC) and FERC authorization, respectively.
Post-Employment Benefits. In November 1992, the FASB issued SFAS 112, "Employers' Accounting for Postemployment Benefits" (SFAS 112), which establishes standards of financial accounting and reporting for benefits, such as salary continuation, severance pay, workers' compensation and other disability-related benefits, provided to former or inactive employees subsequent to employment but prior to retirement. The Company adopted SFAS 112 in the fourth quarter of 1994. Essentially, the new standard required the Company to change its accounting for significant post-employment benefits from the "pay-as-you-go" (cash) to the accrual basis. The only significant post-employment benefit that the Company has relates to workers' compensation. In the Company's regulated operations, workers' compensation is recovered in rates on a cash basis and is not material. Workers' compensation claims related to the Company's nonregulated operations at September 30, 1994, is approximately $1,014,000 ($589,000 net of income taxes) using a discount rate of 8.5%. As required by SFAS 112, the adoption of the standard is reflected on the Consolidated Statement of Income as a cumulative effect of a change in accounting principle.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note G - Commitments and Contingencies
Leases. System companies have entered into lease agreements, principally for the use of office space, business machines, transportation and construction equipment and meters. The Company's policy is to treat all leases as operating leases for both accounting and ratemaking purposes. Total lease expense approximated $17,190,000 in 1994, $16,864,000 in 1993 and $17,570,000 in 1992. At September 30, 1994, the future minimum payments under the Company's lease agreements for the next five years are: $13,075,000 in 1995, $9,779,000 in 1996, $6,959,000 in 1997, $5,021,000 in 1998 and $3,650,000 in 1999. The future minimum lease payments attributable to later years is $6,059,000.
Obligations Under Firm Contracts. Distribution Corporation has agreements with five nonaffiliated upstream pipeline companies that provide for the availability of needed pipeline transportation capacity for periods that extend through 2004. These agreements provide for payment of a demand or reservation charge, at FERC-approved rates, for contracted capacity. Distribution Corporation has various gas purchase agreements with nonaffiliated gas producers that require payment of fixed monthly charges. These charges are tied to various indices. These agreements have an average term of six years. Additionally, Distribution Corporation has agreements with two nonaffiliated companies for gas storage services through 2004 that require payment of a demand charge, at FERC-approved rates, for contracted storage. At September 30, 1994, the projected aggregate amounts of such required future payments, based on current FERC-approved rates and current indices, where applicable, are approximately $88,600,000, $12,500,000 and $6,900,000 annually for the next five years, for pipeline capacity, gas purchases and storage service, respectively. Additionally, these agreements call for the payment of commodity charges based upon actual quantities shipped, purchased and stored.
These obligations under firm contracts are considered purchased gas costs, subject to state commission review, and are being recovered in customer rates through the inclusion in Distribution Corporation's rate schedules.
For the fiscal year ended September 30, 1994, total gross costs incurred under these contracts, including commodity charges on actual quantities shipped, purchased and stored, amounted to $347,100,000.
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures.
Distribution Corporation has been identified by the Environmental Protection Agency or the New York State Department of Environmental Conservation (DEC) as one of a number of companies that are considered to be potentially responsible parties (PRPs) with respect to several waste disposal sites in New York that were operated by unrelated third parties. These PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to Distribution
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Corporation with respect to the remediation of these sites will be dependent on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion attributed, if any, to Distribution Corporation. Distribution Corporation's estimated share of the clean-up costs has been accrued for four of these sites.
One of these four sites was formerly used for a manufactured gas plant. Distribution Corporation is currently involved in litigation regarding this site. The current owner of the site has submitted a claim against Distribution Corporation for contribution of a share of approximately $1,600,000 of removal/remediation costs that have been incurred. It is anticipated that future remedial costs will be incurred and on the basis of a Record of Decision issued by the DEC, as amended on September 19, 1994, the estimated future remedial costs for the site are approximately $5,700,000. Management believes that the ultimate outcome of these matters will not have a material impact on the financial condition, results of operations or cash flows of the Company.
Distribution Corporation has incurred clean-up costs at two additional sites in New York and one site in Pennsylvania related to former manufactured gas plant sites. Supply Corporation is involved in a remediation program of certain of its measuring and regulating stations in Pennsylvania. Estimated clean-up costs have been accrued for these sites.
It is the Company's policy to accrue estimated clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated that clean-up costs related to the above noted sites are in the range of $6,700,000 to $10,100,000. At September 30, 1994, the Company has recorded the minimum liability of $6,700,000. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.
In New York, Distribution Corporation has received approval from the PSC to defer and amortize both former manufactured gas and non-manufactured gas plant site investigation and remediation costs over a three-year period for each site. These costs are then included in rate cases for recovery through base rates. Distribution Corporation is currently recovering such costs in this manner. In Pennsylvania, Distribution Corporation and Supply Corporation expect to recover such costs in rates, as the PaPUC and the FERC, respectively, have allowed recovery of other environmental clean-up costs in rate cases. Accordingly, the Consolidated Balance Sheets at September 30, 1994, include related regulatory assets in the amount of approximately $7,300,000, $600,000 of which relates to costs that have already been incurred.
The Company has begun a program to comply with the Clean Air Act Amendments of 1990 (the Act). This program focuses on emission controls for Supply Corporation's compressor stations in New York and Pennsylvania. These facilities are affected by the nitrogen oxide emission standards of the Act. Supply Corporation incurred capital expenditures for emission controls of approximately $623,000 in 1994 and expects to incur approximately $4,300,000 in 1995. The Company does not anticipate incurring significant additional capital
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
expenditures to comply with the current standards of the Act, however, changes in the standards may require additional expenditures in the future. Management expects that all related capital expenditures will be recoverable through rates.
Other. The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are expected to have a material adverse effect on the financial condition of the Company at this time.
Note H - Business Segment Information
The System includes operations which are rate-regulated (regulated) and operations which are not regulated as to their rates (nonregulated). The regulated operations fall primarily within two business segments: Utility Operation and Pipeline and Storage. The nonregulated operations consist principally of the Exploration and Production business segment. Other Nonregulated operations consist primarily of the Company's pipeline construction operations, sawmill and dry kiln operations, natural gas marketing operations and natural gas market area hub operations.
The Utility Operation is regulated by the PSC and the PaPUC and is carried out by Distribution Corporation. Distribution Corporation sells and transports gas to retail customers located in western New York and northwestern Pennsylvania. Pipeline and Storage operations are regulated by the FERC and are carried out by Supply Corporation. In 1994, 52% of Supply Corporation's revenue was from affiliated companies, mainly Distribution Corporation.
Seneca is engaged in exploration for, and development and purchase of, oil and natural gas reserves in the Gulf Coast, and southwestern, western and Appalachian regions of the United States. Utility Constructors, Inc. is engaged in the Company's pipeline construction operations, Highland Land & Minerals, Inc. is engaged in the Company's sawmill and dry kiln operations, NFR is engaged in the Company's natural gas marketing operations and Leidy Hub, Inc. is engaged in the Company's natural gas market area hub opreations.
The data presented in the tables below reflect the Company's regulated and nonregulated business segments for the years ended September 30, 1994, 1993 and 1992. Total operating revenues by segment include both revenues from nonaffiliated customers and intersegment revenues. Operating income is total operating revenues less operating expenses, not including income taxes. The elimination of significant intercompany balances and transactions, if appropriate, is made in order to reconcile segment information with consolidated amounts. Identifiable assets of a segment are those assets that are used in the operations of that segment. Corporate assets are principally cash and temporary cash investments, receivables and deferred charges.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Revenues Regulated: Utility Operation $ 931,673 $ 836,618 $ 740,664 Pipeline and Storage 153,121 534,568 498,870 1,084,794 1,371,186 1,239,534
Nonregulated: Exploration and Production 70,261 58,636 36,303 Other 72,036 42,099 47,479 142,297 100,735 83,782
Intersegment Revenues* (85,767) (451,539) (402,866) $1,141,324 $1,020,382 $ 920,450
Operating Income (Loss) Before Income Taxes Regulated: Utility Operation $ 90,584 $ 86,690 $ 90,025 Pipeline and Storage 62,302 67,375 49,796 152,886 154,065 139,821
Nonregulated: Exploration and Production 21,767 12,980 7,021 Other 2,505 (986) 4,229 24,272 11,994 11,250
Corporate (3,463) (2,730) (2,279)
$ 173,695 $ 163,329 $ 148,792
Identifiable Assets At September 30
Regulated: Utility Operation $1,106,053 $ 961,990 $ 874,101 Pipeline and Storage** 498,798 491,291 495,626 1,604,851 1,453,281 1,369,727
Nonregulated: Exploration and Production** 311,037 290,346 271,444 Other 33,357 27,867 27,808 344,394 318,213 299,252 Corporate 32,412 30,046 91,851
$1,981,657 $1,801,540 $1,760,830
* Represents revenue primarily from Pipeline and Storage to Utility Operation.
** Prior year amounts have been reclassified to eliminate an intersegment receivable and to conform with current year presentation.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Year Ended September 30 (in thousands) 1994 1993 1992
Depreciation, Depletion and Amortization Regulated: Utility Operation $ 28,216 $ 27,137 $ 25,001 Pipeline and Storage 17,516 16,347 16,202 45,732 43,484 41,203
Nonregulated: Exploration and Production 27,496 24,249 13,257 Other 1,530 1,686 1,260 29,026 25,935 14,517 Corporate 6 6 6
$ 74,764 $ 69,425 $ 55,726
Capital Expenditures Regulated: Utility Operation $ 61,715 $ 61,803 $ 65,650 Pipeline and Storage 20,472 27,420 58,646 82,187 89,223 124,296
Nonregulated: Exploration and Production 52,458 36,473 26,328 Other 3,603 6,229 7,225 56,061 42,702 33,553 Corporate 20 1 7
$138,268 $131,926 $ 157,856
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note I - Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Earnings per common share are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the earnings per common share shown on the Consolidated Statement of Income, which is based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company's heating business, there are substantial variations in operations reported on a quarterly basis.
Financial data for the quarters ended December 31, 1993, and September 30, 1994, reflect the Company's adoption of SFAS 109 and SFAS 112, respectively. As discussed in Note A - Summary of Significant Accounting Policies, the Company adopted SFAS 109 during the quarter ended December 31, 1993. The cumulative effect of this change increased net income by $3,826,000. As discussed in Note F - Retirement Plan and Other Post-Employment Benefits, the Company adopted SFAS 112 during the quarter ended September 30, 1994. The cumulative effect of this change decreased net income by $589,000.
Income Net Income Earnings Before Available for Per Quarter Operating Operating Cumulative Common Common Ended Revenues Income Effect Stock Share
1994 (in thousands, except earnings per common share)
12/31/93 $310,131 $38,745 $27,800 $31,626* $ .86* 3/31/94 $473,722 $54,686 $43,839 $43,839 $1.18 6/30/94 $216,281 $19,782 $ 9,833 $ 9,833 $ .26 9/30/94 $141,190 $12,690 $ 963 $ 374* $ .01*
1993 (in thousands, except earnings per common share)
12/31/92 $294,220 $38,452 $25,941 $25,941 $ .77 3/31/93 $391,790 $57,195 $45,160 $45,160 $1.33 6/30/93 $185,525 $14,993 $ 3,228 $ 3,228 $ .09 9/30/93 $148,847 $11,643 $ 888 $ 888 $ .02
* Includes Cumulative Effect of Changes in Accounting as discussed above.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note J - Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 1994, there were 22,465 holders of National Fuel Gas Company common stock. The market for the common stock is the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note D - Capitalization. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 1993 and 1994, are shown below:
Price Range Dividends Quarter Ended High Low Declared
12/31/92 $30-1/2 $24-5/8 $.375 3/31/93 $33-1/2 $29-1/4 $.375 6/30/93 $33-1/2 $28-3/4 $.385 9/30/93 $36-7/8 $32-1/4 $.385
12/31/93 $36-5/8 $32-1/2 $.385 3/31/94 $36-1/4 $29-7/8 $.385 6/30/94 $32-7/8 $28-3/8 $.395 9/30/94 $31-7/8 $28-7/8 $.395
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Note K - Supplementary Information for Oil and Gas Producing Activities
The following supplementary information is presented in accordance with SFAS 69, "Disclosures about Oil and Gas Producing Activities," and related SEC accounting rules.
Capitalized Costs Relating to Oil and Gas Producing Activities
At September 30 (in thousands) 1994 1993
Capitalized Costs Subject to Amortization $442,224 $399,781 Capitalized Acquisition Costs Excluded from Amortization 16,636 15,849 458,860 415,630
Less - Accumulated Depreciation, Depletion and Amortization 167,592 145,553
$291,268 $270,077
Certain costs excluded from amortization represent unevaluated properties that require additional drilling to determine the existence of oil and gas reserves. The remaining costs, incurred during and prior to 1994, consist of individually insignificant oil and gas leases still early in their primary terms and individually insignificant unproved perpetual oil and gas rights.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Year Ended September 30 (in thousands) 1994 1993 1992
Property Acquisition Costs $ 8,215 $ 9,027 $ 5,260 Exploration Costs 17,855 10,140 4,552 Development Costs 25,102 16,258 11,172 Other 259 25 3,284 $51,431 $35,450 $24,268
Results of Operations for Producing Activities
Year Ended September 30 (in thousands) 1994 1993 1992
Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $5,456, $11,474 and $10,945, respectively) $50,803 $43,679 $24,022 Oil, Condensate and Other Liquids 15,307 13,943 10,974
Total Operating Revenues 66,110 57,622 34,996
Production/Lifting Costs 13,177 13,452 9,828
Depreciation, Depletion and Amortization ($.41, $.42 and $.37, respectively, per dollar of operating revenues) 26,992 23,995 13,049
Income Tax Expense 7,907 4,311 3,874
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $18,034 $15,864 $ 8,245
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Reserve Quantity Information (unaudited)
The Company's proved oil and gas reserves are located in the United States. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by the Company's independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions.
Gas Oil Year Ended MMcf Mbbl September 30 1994 1993 1992 1994 1993 1992
Proved Developed and Undeveloped Reserves:
Beginning of Year 175,051 179,811 176,772 18,519 19,805 20,316
Extensions and Discoveries 94,733 26,416 21,645 1,666 1,713 270
Revisions of Previous Estimates (2,075) (3,962) (3,391) (1,660) (1,995) (85)
Production (23,273) (19,874)(12,070) (1,030) (831) (643)
Sales of Minerals in Place (32) (7,401) (3,377) - (173) (53)
Purchases of Minerals in Place and Other 3,043 61 232 - - -
End of Year 247,447 175,051 179,811 17,495 18,519 19,805
Proved Developed Reserves:
Beginning of Year 134,712 126,176 131,035 10,801 11,437 12,210
End of Year 179,291 134,712 126,176 10,110 10,801 11,437
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited)
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company's oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under the widely fluctuating political and economic conditions of today's world.
The standardized measure is intended instead to provide a somewhat better means for comparing the value of the Company's proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
Year Ended September 30 (in thousands) 1994 1993 1992
Future Cash Inflows $705,874 $689,198 $772,017 Less: Future Production and Development Costs 252,901 240,417 217,654 Future Income Tax Expense at Applicable Statutory Rate 131,060 132,528 159,888 Future Net Cash Flows 321,913 316,253 394,475 Less: 10% Annual Discount for Estimated Timing of Cash Flows 106,647 106,598 154,184 Standardized Measure of Discounted Future Net Cash Flows $215,266 $209,655 $240,291
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
Year Ended September 30 (in thousands) 1994 1993 1992
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $209,655 $240,291 $183,512 Sales, Net of Production Costs (52,933) (44,170) (25,168) Net Changes in Prices, Net of Production Costs (48,149) (52,266) 41,322 Purchases of Minerals in Place 2,793 61 398 Sales of Minerals in Place (29) (7,286) (6,454) Extensions and Discoveries 96,134 61,476 38,874 Changes in Estimated Future Development Costs (36,466) (30,555) (15,186) Previously Estimated Development Costs Incurred 22,941 30,888 17,793 Net Change in Income Taxes at Applicable Statutory Rate 3,098 5,476 (11,662) Revisions of Previous Quantity Estimates (11,042) (25,891) (8,893) Accretion of Discount and Other 29,264 31,631 25,755 Standardized Measure of Discounted Future Net Cash Flows at End of Year $215,266 $209,655 $240,291
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE V - Property, Plant and Equipment (Note 1)
(THOUSANDS OF DOLLARS)
Balance at Balance at Beginning of Additions Other Charges End of Classification Period at Cost Retirements Add (Deduct) Period
Year Ended September 30, 1994
Utility Operation $ 983,417 $ 59,652 $ 6,844 $ - $1,036,225 Pipeline and Storage (Note 2) 618,917 20,380 4,132 4,959 640,124 Exploration and Production 415,642 52,181 3,098 - 464,725 Other Nonregulated 21,237 4,033 332 - 24,938 Corporate 223 21 - - 244 $2,039,436 $136,267 $14,406 $4,959 $2,166,256
Year Ended September 30, 1993
Utility Operation $ 929,601 $ 60,001 $6,185 $ - $ 983,417 Pipeline and Storage (Note 2) 594,580 27,004 2,667 - 618,917 Exploration and Production 378,815 37,145 318 - 415,642 Other Nonregulated 15,170 6,235 168 - 21,237 Corporate 223 - - - 223 $1,918,389 $130,385 $9,338 $ - $2,039,436
Year Ended September 30, 1992
Utility Operation $ 871,102 $ 64,624 $ 6,125 $ - $ 929,601 Pipeline and Storage (Note 2) 539,904 58,210 3,534 - 594,580 Exploration and Production 353,090 25,769 44 - 378,815 Other Nonregulated 8,202 7,222 254 - 15,170 Corporate 216 7 - - 223 $1,772,514 $155,832 $ 9,957 $ - $1,918,389
Notes to Schedule V and VI appear on page 91 of this report.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment
(THOUSANDS OF DOLLARS)
Additions Balance at Charged to Beginning Costs and Balance at of Expenses Other Changes End of Description Period (Note 3) Retirements Add (Deduct) Period
Year Ended September 30, 1994
Utility Operation $228,951 $28,270 $ 8,790 $ - $248,431 Pipeline and Storage 185,181 18,436 4,304 - 199,313 Exploration and Production 142,172 27,443 308 - 169,307 Other Nonregulated 5,028 1,531 200 - 6,359 Corporate 101 6 - - 107 $561,433 $75,686 $13,602 $ - $623,517
Year Ended September 30, 1993
Utility Operation $209,846 $27,209 $ 8,104 $ - $228,951 Pipeline and Storage 171,197 17,479 3,495 - 185,181 Exploration and Production 117,369 24,250 119 672 142,172 Other Nonregulated 3,500 1,685 157 - 5,028 Corporate 95 6 - - 101 $502,007 $70,629 $11,875 $ 672 $561,433
Year Ended September 30, 1992
Utility Operation $192,169 $25,076 $ 7,399 $ - $209,846 Pipeline and Storage 159,896 16,900 5,599 - 171,197 Exploration and Production 104,303 13,264 - (198) 117,369 Other Nonregulated 2,306 1,260 66 - 3,500 Corporate 89 6 - - 95 $458,763 $56,506 $13,064 $ (198) $502,007
Notes to Schedule V and VI appear on page 91 of this report.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
Notes to Schedules V and VI:
(1) Because of the variety of properties and the large number of depreciation rates utilized by System companies, it is considered impractical to set forth the rates used in computing provisions. However, the total provisions for depreciation, depletion and amortization of System property, plant and equipment for the three years ended September 30, 1994, including amounts charged to accounts other than depreciation, depletion and amortization expense, were equivalent to approximately 3.9% in 1994, 3.8% in 1993 and 3.3% in 1992 of average depreciable property, plant and equipment for the respective years.
(2) Includes gas stored underground costing $80,942,000 at September 30, 1994, and $75,983,000 at September 30, 1993 and 1992. The cost of gas stored underground in the amount of $4,959,000 was transferred to property, plant and equipment from deferred changes in 1994.
(3) Additions Charged to Costs and Expenses differs from Depreciation, Depletion and Amortization (D,D & A) as reported in the Consolidated Statement of Income, due to D,D & A provisions charged to other income and expense accounts.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE VIII - Valuation and Qualifying Accounts and Reserves
(THOUSANDS OF DOLLARS)
Additions Balance at Charged to Charged to Balance at Beginning Costs and Other Deductions End of Description of Period Expenses Accounts (Note) Period
Year Ended September 30, 1994
Reserve for Doubtful Accounts $ 5,739 $11,443 $ - $12,127 $ 5,055
Year Ended September 30, 1993
Reserve for Doubtful Accounts $ 5,900 $ 8,713 $ - $8,874 $ 5,739
Year Ended September 30, 1992
Reserve for Doubtful Accounts $ 5,876 $ 9,723 $ - $9,699 $ 5,900
Note - Amounts represent net accounts receivable written-off.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Continued)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE IX - Short-Term Borrowings
(THOUSANDS OF DOLLARS)
Maximum Average Weighted Balance at Weighted Amount Amount Average Category End of Average Outstanding Outstanding Interest of Aggregate Period Interest During the During the Rate During Short-Term September 30 Rate Period Period the Period Borrowings (Note 1) (Note 2) (Note 3) (Note 4) (Note 5)
Year 1994
Bank Loans $102,500 5.13% $ 182,100 $107,907 3.75%
Commercial Paper $ 10,000 5.09% $ 76,000 $ 42,000 3.67%
Year 1993
Bank Loans $125,800 3.29% $ 217,000 $115,159 3.58%
Commercial Paper $ 71,000 3.32% $ 128,000 $ 87,427 3.56%
Year 1992
Bank Loans $149,100 3.60% $ 207,200 $165,191 4.81%
Commercial Paper $127,900 3.52% $ 127,900 $ 84,096 4.62%
Notes:
(1) At September 30, 1992, the Company reclassified $50,000,000 of short-term borrowings on the Consolidated Balance Sheet to "Long-Term Debt, Net of Current Portion" because the Company, on November 5, 1992, issued $50,000,000 of medium-term notes and used the proceeds to reduce outstanding short-term borrowings.
(2) The interest rate for bank loans is the weighted average of the rates in effect at the respective banks at September 30 of each year. The interest rate for commercial paper is the weighted average of the discount rate on those commercial paper notes outstanding at September 30 of each year.
(3) Represents the maximum amount outstanding during any month of the period.
(4) Represents the average amount outstanding on a daily basis.
(5) Represents the weighted average interest rate on a daily basis.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTAL DATA (Concluded)
NATIONAL FUEL GAS COMPANY AND SUBSIDIARIES
SCHEDULE X - Supplementary Income Statement Information
(THOUSANDS OF DOLLARS)
Charged to Costs and Expenses
Item Year Ended September 30 1994 1993 1992
1. Maintenance and Repairs $30,979 $24,312 $22,439
2. Depreciation and Amortization of Intangible Assets, Preoperating Costs and Similar Deferrals (1) (1) (1)
3. Taxes, other than Payroll and Income Taxes: Gross Receipts Taxes $53,271 $48,876 $44,400
Real and Other Property Taxes 35,287 33,216 31,320
Other 7,017 5,500 6,127
$95,575 $87,592 $81,847
4. Royalties (1) (1) (1)
5. Advertising Costs (1) (1) (1)
Note (1) Amount is not in excess of one percent of total operating revenues as reported in the Consolidated Statements of Income and Earnings Reinvested in the Business.
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
The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 1995 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994. The information provided in such definitive Proxy Statement is incorporated herein by reference.
Information concerning the Company's executive officers can be found in Part I, Item 1, of this report.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 1995 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994. The information provided in such definitive Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company's definitive Proxy Statement for its February 16, 1995 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1994. The information provided in such definitive Proxy Statement is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
At September 30, 1994, the Company knows of no relationships or transactions required to be disclosed pursuant to Item 404 of Regulation S-K.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statement Schedules All financial statement schedules filed as part of this report are included in Item 8 and reference is made to the index on page 52 of this report.
(b) Reports on Form 8-K None
(c) Exhibits.
Exhibit Number Description of Exhibits
3(i) Articles of Incorporation:
* Restated Certificate of Incorporation of National Fuel Gas Company, dated March 15, 1985 (Exhibit 10-OO, Form 10-K for fiscal year ended September 30, 1991)
* Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated March 9, 1987 (Exhibit A-3 in File No. 70-7334)
* Certificate of Amendment of Restated Certificate of Incorporation of National Fuel Gas Company, dated February 22, 1988 (Exhibit B-5 in File No. 70-7478)
* Certificate of Amendment of Restated Certificate of Incorporation, dated March 17, 1992 (Exhibit EX-3(a), Form 10-K for fiscal year ended September 30, 1992)
3(ii) By-Laws:
3.1 National Fuel Gas Company By-Laws as amended through June 9, 1994
(4) Instruments Defining the Rights of Security Holders, Including Indentures:
* Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b), File No. 2-51796)
* Eighth Supplemental Indenture dated as of July 1, 1989, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit EX-4.3, Form 10-K for fiscal year ended September 30, 1992) (The Debentures issued thereunder were redeemed on March 16, 1993, July 7, 1993 and July 1, 1994)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
* Ninth Supplemental Indenture dated as of January 1, 1990, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit EX-4.4, Form 10-K for fiscal year ended September 30, 1992)
* Tenth Supplemental Indenture dated as of February 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a), Form 8-K dated February 14, 1992, in File No. 1-3880)
* Eleventh Supplemental Indenture dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992, in File No. 1-3880)
* Twelfth Supplemental Indenture dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992, in File No. 1-3880)
* Thirteenth Supplemental Indenture dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401)
* Fourteenth Supplemental Indenture dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1993)
(10) Material Contracts:
(ii) (B) Contracts upon which Registrant's business is substantially dependent:
10.1 Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FTS, dated November 1, 1993 and executed February 13, 1994.
10.2 Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FSS, dated November 1, 1993 and executed February 13, 1994.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
10.3 Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule SST, dated November 1, 1993 and executed February 13, 1994.
* Gas Transportation Agreement with Tennessee Gas Pipeline Company under rate schedule FT-A (Zone 4), dated September 1, 1993 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1993)
* Gas Transportation Agreement with Tennessee Gas Pipeline Company under rate schedule FT-A (Zone 5), dated September 1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1993)
* Service Agreement with Texas Eastern Transmission Corporation under rate schedule CDS, dated June 1, 1993 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1993)
* Service Agreement with Texas Eastern Transmission Corporation under rate schedule FT-1, dated June 1, 1993 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1993)
* Service Agreement with CNG Transmission Corporation under Rate Schedule FT, dated October 1, 1993 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1993)
* Service Agreement with CNG Transmission Corporation under Rate Schedule GSS, dated October 1, 1993 (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1993)
(iii) Compensatory plans for officers:
10.4 Employment Agreement, dated September 17, 1981, with Bernard J. Kennedy.
* National Fuel Gas Company 1983 Incentive Stock Option Plan, as amended and restated through February 18, 1993. (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 1993)
* National Fuel Gas Company 1984 Stock Plan, as amended and restated through February 18, 1993 (Exhibit 10.3, Form 10-Q for the quarterly period ended March 31, 1993)
* National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993. (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1993)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
* Change in Control Agreement, dated May 1, 1992, with Philip C. Ackerman. (Exhibit EX-10.4, Form 10-K for fiscal year ended September 30, 1992)
* Change in Control Agreement, dated May 1, 1992, with Richard Hare. (Exhibit EX-10.5, Form 10-K for fiscal year ended September 30, 1992)
* Change in Control Agreement, dated May 1, 1992 with William J. Hill. (Exhibit EX-10.6, Form 10-K for fiscal year ended September 30, 1992)
* Agreement, dated August 1, 1989, with Richard Hare. (Exhibit 10-Q, Form 10-K for fiscal year ended September 30, 1989)
* Executive Death Benefits Agreement dated April 1, 1991 with William J. Hill. (Exhibit EX-10.8, Form 10-K for fiscal year ended September 30, 1992)
10.5 Amendment to Death Benefits Agreement dated March 15, 1994 with Richard Hare.
10.6 Amendment to Death Benefits Agreement dated March 15, 1994 with Philip C. Ackerman.
10.7 National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994.
10.8 National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through February 17, 1994
10.9 Split Dollar Death Benefits Agreement dated April 1, 1991 with Richard Hare (errata).
10.10 Split Dollar Death Benefits Agreement dated April 1, 1991 with Philip C. Ackerman (errata)
* Eighth Extension to Employment Agreement with Bernard J. Kennedy, dated September 20, 1991. (Exhibit 10-SS, Form 10-K for fiscal year ended September 30, 1991)
* Executive Death Benefits Agreement dated August 28, 1991 with Bernard J. Kennedy. (Exhibit 10-TT, Form 10-K for fiscal year ended September 30, 1991)
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
* Summary of Annual at Risk Compensation Incentive Program (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1993)
* Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of December 5, 1991. (Exhibit 10-UU, Form 10-K for fiscal year ended September 30, 1991)
(12) Computation of Ratio of Earnings to Fixed Charges
(21) Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K
Consents of Experts and Counsel: 23.1 Consent of Ralph E. Davis Associates, Inc. 23.2 Consent of Independent Accountants
(27) Financial Data Schedule
Additional Exhibits: 99.1 Report of Ralph E. Davis Associates, Inc. 99.2 System Maps (Not included in EDGAR filing. See narrative description in the Appendix to this report.)
All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report on Form 10-K.
*Incorporated herein by reference as indicated.
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.
NATIONAL FUEL GAS COMPANY (Registrant)
By/s/B. J. Kennedy B. J. Kennedy Chairman of the Board, President Date December 22, 1994 and Chief Executive 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.
Signature Title
/s/ B. J. Kennedy Chairman of the Board, B. J. Kennedy President, Chief Executive Officer and Director Date December 22, 1994
/s/ P. C. Ackerman Senior Vice President, Principal P. C. Ackerman Financial Officer and Director
Date December 22, 1994
/s/ J. M. Brown Director J. M. Brown
Date December 22, 1994
/s/ D. N. Campbell Director D. N. Campbell
Date December 22, 1994
/s/ L. F. Kahl Director L. F. Kahl
Date December 22, 1994
/s/ B. S. Lee Director B. S. Lee
Date December 22, 1994
/s/ E. T. Mann Director E. T. Mann
Date December 22, 1994
/s/ L. Rochwarger Director L. Rochwarger
Date December 22, 1994
/s/ G. H. Schofield Director G. H. Schofield
Date December 22, 1994
/s/ J. P. Pawlowski Treasurer and Principal J. P. Pawlowski Accounting Officer
Date December 22, 1994
/s/ R. M. DiValerio Secretary R. M. DiValerio
Date December 22, 1994
/s/ G. T. Wehrlin Controller G. T. Wehrlin
Date December 22, 1994
APPENDIX TO ITEM 2 - PROPERTIES
Three maps outlining the System's operating areas at September 30, 1994, are inlcuded in the paper format version of this Form 10-K as exhibit 99.2 and are not included in this electronic filing. The first map identifies the System's Utility Operating area (i.e., Distribution Corporation's service area). The second map identified the System's Pipeline and Storage operating area (i.e., Supply Corporation's storage areas and pipelines). The third map identifies the System's Exploration and Production operating area (i.e., Seneca Resources' operating area).
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS
A. The Revenue Dollar - 1994
Two pie graphs detailing the revenue dollar in 1994; where it came from and where it went to, broken down as follows:
Where it came from:
$ .592 Residential Sales .182 Commercial and Industrial Sales .060 Transportaion Revenues .053 Oil and Gas Revenues .044 Natural Gas Marketing Revenues .034 Storage Service Revenues .035 Other Revenues $1.000 Total
Where it went to:
$ .435 Gas Purchased .165 Wages, Including Benefits .128 Taxes .091 Other Materials and Services .065 Depreciation .051 Dividends - Common Stock .041 Interest .024 Reinvested in the Business $1.000 Total
APPENDIX TO ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION - GRAPHS (Concluded)
B. Book Value Per Common Share
A bar graph detailing book value per common share (dollars) for the years 1990 through 1994, broken down as follows:
1990 - $16.97 1991 - 17.53 1992 - 18.68 1993 - 20.08 1994 - 20.93
C. Capital Expenditures
A bar graph detailing capital expenditures (millions of dollars) for the years 1990 through 1994, broken down as follows:
1990 1991 1992 1993 1994 Other Nonregulated $ 2.6 $ 1.0 $ 7.2 $ 6.2 $ 3.6 Pipeline and Storage 42.0 58.6 58.7 27.4 20.5 Exploration and Production 50.8 31.7 26.3 36.5 52.5 Utility Operation 66.1 64.9 65.7 61.8 61.7 $161.5 $156.2 $157.9 $131.9 $138.3
D. Embedded Cost of Long-Term Debt
A line graph detailing the embedded cost of long-term debt for the years 1990 through 1994, broken down as follows:
Percent 1990 9.4 1991 9.3 1992 8.1 1993 7.3 1994 7.3
E. Capitalization Ratios
A bar graph detailing capitalization (percentage) for the years 1990 through 1994, broken down as follows: Debt (%) Equity (%) 1990 56.2 43.8 1991 55.0 45.0 1992 54.5 45.5 1993 47.8 52.2 1994 46.2 53.8