Item 1. Business
(a)Equitable Resources, Inc. ("Equitable" or the "Company") was formed under the laws of Pennsylvania by the consolidation and merger in 1925 of two constituent companies, the older of which was organized in 1888. The Company owns all the capital stock of subsidiary companies. Principal subsidiaries are Equitable Resources Energy Company ("Equitable Resources Energy") and Kentucky West Virginia Gas Company ("Kentucky West"). Equitable Resources Energy owns all the capital stock of Equitable Resources Marketing Company ("ERMCO") and Andex Energy, Inc. ("Andex"). Kentucky West owns all the capital stock of Equitrans, Inc. ("Equitrans") and Nora Transmission, Inc. ("Nora"). ERMCO owns all the capital stock of Louisiana Intrastate Gas Company ("LIG"). The Company and all such subsidiaries are referred to as the "Company and its Subsidiaries" or the "Companies." The Companies operate in the Appalachian area and, to a lesser extent, in the Rocky Mountain, Southwest, Louisiana and Gulf Coast offshore areas, the Canadian Rockies and has interests in Colombia, South America. The Companies engage primarily in the exploration for, development, production, purchase, transmission, storage, distribution and marketing of natural gas, the extraction of natural gas liquids, the exploration for, development, production and sale of oil and contract drilling.
LIG was acquired by the Company on June 30, 1993 as described in Note L to the consolidated financial statements in Part II. LIG owns a 1,900 mile intrastate pipeline system in Louisiana, four natural gas processing plants and is also engaged in gas marketing. Hershey Oil Corporation ("Hershey") was acquired on July 8, 1993. Hershey owns natural gas and oil reserves and acreage in Alberta, Canada. These subsidiaries are included in the Energy Resource segment.
(b)The Company's business is comprised of two business segments, Energy Resources and Utility Services. Financial information by business segment is presented in Note K to the consolidated financial statements contained in Part II.
(b) (1)Not applicable.
(b) (2)Not applicable.
(c) (1)ENERGY RESOURCES. Energy Resources activities are conducted by Equitable Resources Energy Company through its divisions and subsidiaries. Its activities are principally in the Appalachian area where it explores for, develops, produces and markets natural gas and oil, performs contract drilling and well maintenance services, and extracts and markets natural gas liquids.
Energy Resources also conducts operations in the Rocky Mountain area including the Canadian Rockies where it explores for, develops and produces oil, and to a lesser extent natural gas.
In Louisiana, the segment provides intrastate transportation of gas and extracts and markets natural gas liquids.
Item 1. Business (Continued)
In the Southwest and Gulf Coast offshore areas, this segment participates in exploration and development of gas and oil projects. Energy Resources also owns an interest in two natural gas liquids plants in Texas.
Andex participates in ventures to explore for and develop oil in Colombia, South America.
ERMCO operates nationwide as a full-service natural gas marketing and supply company. ERMCO provides a full range of energy services, including monthly "spot" and longer term contracts, peak shaving and transportation arrangements.
UTILITY SERVICES. Utility Services activities are conducted by Equitable Gas Company ("Equitable Gas"), a division of the Company, and three wholly-owned subsidiaries: Kentucky West, Equitrans and Nora.
Equitable Gas is a natural gas utility, regulated by state public utility commissions in Pennsylvania, West Virginia and Kentucky and is engaged in the purchase, distribution, marketing and transportation of natural gas. The territory served by Equitable Gas embraces principally the city of Pittsburgh and surrounding municipalities in southwestern Pennsylvania, a few municipalities in northern West Virginia and field line sales in eastern Kentucky.
Kentucky West, regulated by the Federal Energy Regulatory Commission (FERC), is an open access natural gas pipeline company. Prior to restructuring pursuant to FERC Order 636, Kentucky West purchased gas from the Energy Resource segment and independent producers in Kentucky. Most of Kentucky West's sales were to Equitrans and, to a lesser extent, to industrial customers and other utilities. Kentucky West also transported gas independently marketed by Energy Resources. With the FERC Order 636 restructuring, which was effective July 1, 1993, Kentucky West provides only open-access transportation service. Transportation service is provided to Equitable Gas, Equitrans, Energy Resources and other industrial end-users. Kentucky West's pipelines are not physically connected with those of Equitrans or Equitable Gas and deliveries are made to Columbia Gas Transmission Corporation, a nonaffiliate, which in turn delivers like quantities to Equitrans in West Virginia and Pennsylvania under a Transportation and Exchange Agreement.
Equitrans is a FERC regulated open access pipeline company with production, storage and transmission facilities in Pennsylvania and West Virginia. Prior to FERC Order 636 restructuring, Equitrans produced, purchased and sold gas and provided transportation and underground storage services. With the FERC Order 636 restructuring, which was effective September 1, 1993, Equitrans provides transportation and storage services. Equitrans provides transportation service for Equitable Gas Company and nonaffiliates including customers in off-system markets. Storage services are provided for Equitable Gas Company and nine nonaffiliated customers.
Nora is a FERC regulated pipeline company which transports Energy Resources' gas produced in Virginia and Kentucky.
Utility services, principally gas service, are provided to more than 265,000 customers located mainly in the city of Pittsburgh and its environs. Residential and commercial sales volumes reflect annual variations which are primarily related to weather. In addition, commercial and industrial sales volumes have decreased mainly as the result of customers acquiring gas directly from third parties. However, this gas is transported and delivered by Utility Services.
Item 1. Business (Continued)
(c) (1) (i)Operating revenues as a percentage of total operating revenues for each of the two business segments during the years 1991 through 1993 are as follows:
1993 1992 1991
Energy Resources: Natural gas - production 10% 10% 8% - marketing 45 32 26 Natural gas liquids 4 3 3 Contract drilling 1 2 2 Oil 3 5 6 Intrastate transportation 1 - - Other 1 1 1
Total Energy Resources 65 53 46
Utility Services: Residential 23 30 34 Commercial 5 7 9 Industrial 1 2 2 Transportation 4 6 7 Marketed gas 1 - - Utilities and Other 1 2 2
Total Utility Services 35 47 54
Total Revenues 100% 100% 100%
(c) (1) (ii)Not applicable.
(c) (1) (iii)The following pages (4, 5 and 6) summarize gas and oil supply and disposition for the years 1991 through 1993.
Item 1. Business (Continued)
Item 1. Business (Continued)
Item 1. Business (Continued)
Item 1. Business (Continued)
During 1993, a total of 325,377,000 Mcf of gas was produced and purchased by the Companies compared with 225,627,000 Mcf in 1992. The increase reflects greater marketing activity, including the consolidation of LIG, and increased production.
GAS PURCHASES. Total purchases in 1993 amounted to 269,855,000 Mcf, of which 222,037,000 Mcf was applicable to marketing operations and 47,818,000 Mcf was for system supply, compared with 131,711,000 Mcf for marketing operations and 42,975,000 Mcf for system supply in 1992. Through gas purchase contracts for system supply, the Company controls proved reserves on acreage developed by independent producers. The majority of these contracts cover the productive lives of the wells.
NATURAL GAS AND OIL PRODUCTION. Natural gas production by Energy Resources in 1993 of 53,550,000 Mcf increased over the 1992 total of 48,243,000 Mcf. Utility Services production in 1993 of 1,972,000 Mcf decreased from the 1992 total of 2,698,000 Mcf.
Production of crude oil in 1993 was 2,112,000 barrels, compared with 2,406,000 barrels in 1992.
In 1993, Energy Resources drilled 212 gross wells (152.7 net wells). The primary focus of drilling activity was in Kentucky and Virginia. Drilling in this area was for development of oil in the Big Lime formation and coalbed methane.
The Company has been able to develop gas reserves at costs which make it very competitive in marketing its gas to pipeline and commercial buyers. As a result, even in periods of surplus gas supply, the Company has been able to sell gas produced by energy resource operations at a profit.
NATURAL GAS AND OIL RESERVES. The Company's estimate of proved developed and undeveloped gas reserves for the Energy Resource segment comprised 822.6 Bcf as of December 31, 1993. These reserves included 759.3 Bcf of proved developed reserves. The Company's oil reserves at December 31, 1993 consisted of 16.5 million barrels of proved developed and undeveloped reserves; proved developed oil reserves amounted to 16.4 million barrels. Substantially all of the gas and approximately one half of the oil reserves are located in the Appalachian area. See Note P to the Consolidated Financial Statements in Part II for details of gas and oil producing activities.
STORAGE. Net storage withdrawals for system use during the 1992-93 heating season were 11.0 Bcf, compared with 9.8 Bcf the previous heating season. Net withdrawals of 12.8 Bcf were made during the 1992-93 heating season for storage service customers compared with 13.4 Bcf the previous heating season.
SUPPLY OUTLOOK. The Company's near-term utility gas supply is excellent. The long-range gas supply outlook also is very favorable. Annual gas supply is forecasted to exceed demand at least for the next decade.
Item 1. Business (Continued)
Energy Resources has also been in a favorable supply position and reserves have continued to increase. However, the development or purchase of future supplies will depend largely on energy prices.
(c) (1) (iv) Equitable Gas is regulated by the Pennsylvania Public Utility Commission and the Public Service Commissions of West Virginia and Kentucky; LIG is regulated by the Louisiana Public Service Commission; Kentucky West, Equitrans, Nora, LIG and Equitable Resources Energy are regulated by the Federal Energy Regulatory Commission under the Natural Gas Act and the Natural Gas Policy Act. Equitable Gas, Kentucky West, Equitrans, Nora, LIG and Equitable Resources Energy are also subject to regulation by the Department of Transportation under the Natural Gas Pipeline Safety Act of 1968 with respect to safety requirements in the design, construction, operation and maintenance of pipelines and related facilities.
(c) (1) (v) and (vi) Approximately 65 percent of annual Utility Service revenue is recorded during the winter heating season from November through March. Significant quantities of purchased gas are placed in underground storage inventory during the off-peak season to accommodate high customer demands during the winter heating season. Funds required to finance this inventory are obtained through short-term loans.
Energy Resource's revenues are not subject to seasonal variation to the same degree as Utility Service revenues.
(c) (1) (vii)Not applicable.
(c) (1) (viii)Not applicable.
(c) (1) (ix)Not applicable.
(c) (1) (x)Equitable Gas is in competition with others for the purchase of natural gas and Equitable Resources Energy is in competition with others for the acquisition of gas and oil leases.
Equitable Gas competes for gas sales with other utilities in its service area, as well as with other fuels and forms of energy and other sources of natural gas available to existing or potential customers.
Utility Services has been successful in meeting competition with aggressive marketing which retained load and added new residential, commercial and off-system customers in areas served by two or more energy suppliers. This has been achieved by responding to market requirements with a portfolio of firm and interruptible services at competitive prices.
See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations contained in Part II regarding FERC Order 636 and its impact on the operations of the Utility Service companies.
(c) (1) (xi) Not material.
Item 1. Business (Continued)
(c) (1) (xii)The Company and its subsidiaries are subject to federal, state and local environmental laws and regulations. Principal concerns are with respect to oil and thermal pollution of waterways, storage and disposal of hazardous wastes and liquids and erosion and sedimentation control in pipeline construction work. For further discussion of environmental matters, see Management's Discussion and Analysis of Financial Condition and Results of Operations and Note N to the consolidated financial statements in Part II.
(c) (1) (xiii)The Companies had 2,454 regular employees at the end of 1993.
(d) Not material.
Item 2.
Item 2. Properties
Principal facilities are owned by the Company's business segments with the exception of several office locations and warehouse buildings. The terms of the leases on these facilities expire at various times from 1994 through 2014. All leases contain renewal options for various periods. A minor portion of equipment is also leased. With few exceptions, utility transmission, storage and distribution pipelines are located on or under (1) public highways under franchises or permits from various governmental authorities, or (2) private properties owned in fee, or occupied under perpetual easements or other rights acquired for the most part without examination of underlying land titles. The Company's facilities have adequate capacity, are well maintained and, where necessary, are replaced or expanded to meet operating requirements.
UTILITY SERVICES. Equitable Gas owns and operates natural gas distribution properties as well as other general property and equipment in Pennsylvania, West Virginia and Kentucky. Equitrans owns and operates production, underground storage and transmission facilities as well as other general property and equipment in Pennsylvania and West Virginia. Kentucky West owns and operates gathering and transmission properties as well as other general property and equipment in Kentucky.
ENERGY RESOURCES. This business segment owns or controls and operates substantially all of the Company's gas and oil production properties, the majority of which are located in the Appalachian area. This segment also owns an intrastate pipeline system and four hydrocarbon extraction plants in Louisiana, hydrocarbon extraction facilities in Kentucky with a 100-mile liquid products pipeline which extends into West Virginia and an interest in two hydrocarbon extraction plants in Texas.
This business segment owns or controls acreage of proved developed and undeveloped gas and oil lands located principally in the Appalachian area and, to a lesser extent, in the Rocky Mountain area including the Canadian Rockies, the Southwest and Gulf Coast offshore areas and in Colombia, South America. The acquisition of Canadian properties in 1993 is described in Note L to the consolidated financial statements and significant purchases of oil and gas properties in 1991 are described in Note M to the consolidated financial statements contained in Part II. Information relating to Company estimates of natural gas and oil reserves and future net cash flows is summarized in Note P to the consolidated financial statements in Part II.
No report has been filed with any Federal authority or agency reflecting a five percent or more difference from the Company's estimated total reserves.
Item 2. Properties (Continued)
Gas and Oil Production (Energy Resources):
1993 1992 1991
Gas - MMcf 53,550 48,243 40,022 Oil - Thousands of Barrels 2,112 2,406 2,006
Natural Gas:
Average field sales price of natural gas produced during 1993, 1992 and 1991 was $2.27, $1.93 and $1.81 per Mcf, respectively.
Average production cost (lifting cost) of natural gas during 1993, 1992 and 1991 was $.458, $.443 and $.460 per Mcf, respectively.
Oil: Average sales price of oil produced during 1993, 1992 and 1991 was $16.18, $18.07 and $18.98 per barrel, respectively. Average production cost (lifting cost) of oil during 1993, 1992 and 1991 was $4.30, $3.75 and $3.77 per barrel, respectively.
Gas Oil
Total productive wells at December 31, 1993: Total gross productive wells 5,838 876 Total net productive wells 4,301 535
Total acreage at December 31, 1993: Total gross productive acres 725,000 Total net productive acres 596,000 Total gross undeveloped acres 3,192,000 Total net undeveloped acres 2,341,000
Number of net productive and dry exploratory wells and number of net productive and dry development wells drilled:
1993 1992 1991
Exploratory wells: Productive 12.0 11.6 12.4 Dry 6.7 6.3 8.6 Development wells: Productive 123.4 134.1 120.4 Dry 10.6 12.0 12.6
As of December 31, 1993, the Company had 4 gross wells (2.16 net wells) in the process of being drilled.
Item 3.
Item 3. Legal Proceedings
LIG is a party to certain claims involving its gas purchase contracts, including take-or-pay liabilities. As more fully described in Note L to the consolidated financial statements in Part II, the seller, and/or the previous owner of LIG, have provided indemnifications for the Company.
There are no other material pending legal proceedings, other than those which are adequately covered by insurance, to which the Company or any of its subsidiaries is a party, or to which any of their property is subject. The Company is claimant as a creditor in Columbia Gas Transmission Company's bankruptcy proceeding as described in Notes B and N to the consolidated financial statements in Part II.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the Company's security holders during the last quarter of its fiscal year ended December 31, 1993.
Item 10. Directors and Executive Officers of the Registrant
(b) Identification of executive officers
Name and Age Title Business Experience
First elected to present position Donald I. Moritz Chairman and Chief December 17, 1993; (66) Executive Officer President and Chief Executive Officer from August 1, 1978.
First elected to present position December 17, 1993; Executive Vice President and Chief Operating Officer Frederick H. President and from June 1, 1992; Abrew (56) Chief Operating Officer Executive Vice President from June 1, 1991; Executive Vice President - Utility Services from June 1, 1988.
First elected to Senior Vice present position Jeremiah J. Ayres President - February 1, 1991; (61) Environment and Vice President - Technology Corporate Services from March 26, 1987.
Augustine A. Senior Vice First elected to Mazzei, Jr. (57) President and present position General Counsel June 1, 1988.
First elected to Robert E. Daley Vice President and present position (54) Treasurer May 22, 1986.
First elected to present position June 1, 1992; President - Equitable Harry E. Gardner, Vice President - Resources Energy Jr. (56) Energy Resources Company since January 1, 1991; President Equitable Resources Exploration Division from July 1, 1987.
Joseph L. Giebel Vice President - First elected to (63) Accounting and present position Administration February 1, 1991; Vice President - Accounting from May 1, 1981.
Name and Age Title Business Experience
First elected to present position January 1, 1994; Vice President - Utility Services from June 1, John C. Gongas, Vice President - 1992; President of Jr. (49) Utility Group Kentucky West Virginia Gas Company since April 20, 1992; President of Equitrans, Inc. from February 26, 1988.
Vice President and First elected to Audrey C. Moeller Corporate present position May (58) Secretary 22, 1986.
First elected to present position January 1, 1994; Vice President - Corporate Development from August 1, 1991; Director - Special Projects from October Richard Riazzi Vice President - 1, 1990; President - (39) Energy Group Equitable Resources Marketing Company from February 27, 1989; Vice President - Strategic Planning for Equitable Resources Energy Company from July 1, 1987.
Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified. Except as indicated, the officers listed above were elected on May 21, 1993.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
(a) The Company's common stock is listed on the New York Stock Exchange and the Philadelphia Stock Exchange. The high and low sales prices reflected in the New York Stock Exchange Composite Transactions as reported by The Wall Street Journal and the dividends declared and paid per share are summarized as follows:
(b)As of December 31, 1993, there were 8,994 shareholders of record of the Company's common stock.
(c)(1)The indentures under which the Company's long-term debt is outstanding contain provisions limiting the Company's right to declare or pay dividends and make certain other distributions on, and to purchase any shares of, its common stock. Under the most restrictive of such provisions, $387,755,000 of the Company's consolidated retained earnings at December 31, 1993, was available for declarations or payments of dividends on, or purchases of its common stock.
(c)(2)The Company anticipates dividends will continue to be paid on a regular quarterly basis.
Item 6.
Item 6. Selected Financial Data
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
Equitable's consolidated net income for 1993 of $73.5 million, or $2.27 per share, was the second highest in the Company's history. The 1993 results represent a 22 percent increase over 1992 net income of $60.0 million, or $1.92 per share, and a 14 percent increase over 1991 net income of $64.2 million, or $2.05 per share.
Earnings for all three years include income from regulatory approvals for the recovery of higher wellhead prices for natural gas produced and sold in prior years as more fully described in Note B to the consolidated financial statements. The recovery increased income by approximately $4.7 million for both 1993 and 1992 and $14.9 million for 1991.
The increase in net income for 1993 compared to 1992 is due primarily to increases in production and average wellhead prices for natural gas and increased margins from utility service operations. These increases were partially offset by a $5 million increase in 1993 federal income taxes as a result of a one percent increase in the federal corporate income tax rate as more fully described in Note C to the consolidated financial statements. The increase in net income for 1992 compared to 1991, excluding the effect of the direct billing settlements, is the result of increased sales of produced gas and oil, higher average wellhead prices for natural gas and increased retail gas sales reflecting colder weather in 1992.
RESULTS OF OPERATIONS
This discussion supplements the detailed financial information by business segment presented in Note K to the consolidated financial statements.
ENERGY RESOURCES
Operating revenues were $743.1 million in 1993 compared with $461.6 million in 1992 and $367.3 million in 1991. The increase in revenues between the periods is due primarily to increases in gas marketing activity, production and average wellhead prices for natural gasand increased production of natural gas liquids in 1993. The increase in marketed natural gas and production of natural gas liquids for 1993 is due primarily to the acquisition of Louisiana Intrastate Gas Company (LIG) on June 30, 1993 as more fully described in Note L to the consolidated financial statements. Increased production of natural gas and oil for 1992 compared to 1991 reflects the full-year impact of 1991 acquisitions.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued)
Energy Resources 1993 1992 1991
Operating Revenues (thousands): Natural Gas: Production . . . . . . . . $121,360 $ 92,864 $ 72,498 Marketing . . . . . . . . . 505,830 269,182 185,901 Oil . . . . . . . . . . . . 34,176 43,469 38,074 Natural Gas Liquids . . . . . 47,121 21,256 23,573 Direct Billing Settlements . 7,815 7,815 24,960 Other . . . . . . . . . . . . 26,762 27,056 22,291 Total Revenues . . . . . $743,064 $461,642 $367,297
Sales Quantities: Natural Gas (MMcf): Production . . . . . . . . 53,550 48,243 40,022 Marketing . . . . . . . . . 218,031 131,711 102,456 Oil (MBls) . . . . . . . . . 2,112 2,406 2,006 Natural Gas Liquids (thousands of gallons) . . . 162,191 64,938 64,200
Gas purchased amounted to $533.7 million in 1993 compared with $277.0 million in 1992 and $193.1 million in 1991. The increased cost in 1993 reflects the increase in volume of marketed natural gas and requirements for the higher production level of natural gas liquids. The increase for 1992 is due to the increase in volume of marketed natural gas.
Other operating expenses were $155.2 million in 1993, $143.4 million in 1992 and $127.6 million in 1991. Increases for the respective years are attributed to increased production expenses, depreciation and depletion related to the higher level of natural gas production and the consolidation of LIG in 1993.
Operating income, excluding income from direct billing settlements, was $46.4 million in 1993 compared with $33.4 million in 1992 and $21.6 million in 1991. The increase in operating income for 1993 compared to 1992 reflects primarily the increase in average wellhead prices and production of natural gas. The increase for 1992 compared to 1991 is due mainly to increased production of natural gas and oil and higher average wellhead prices for gas.
Energy resource operations accounted for more than half of consolidated net income in 1993. This was achieved through the combination of improved wellhead prices for natural gas and increased production realized from recent acquisitions as well as ongoing development activity. Average wellhead prices increased 18 percent in 1993 and reached a level that has not been experienced since 1988. Production was increased by 11 percent in 1993 and represents a 34 percent increase since 1991 when wellhead prices were at their lowest point in more than ten years.
Appalachian gas reserves and acreage position remain a firm foundation for the segment's strategy of traditional development and expanding diversification into other areas. The recent acquisition of LIG has enhanced expansion of marketing activities in the Gulf coast area where the Company has been active in natural gas production. LIG will serve as the nucleus for development of a "market hub" with broad access in this area of major production activity as well as interconnections with major pipelines serving substantially all regions of the country.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued)
In 1994, the segment's $90.5 million capital expenditure program includes $35.3 million for development of Appalachian holdings, $24.6 million for the Rocky Mountain area, $17.2 million for off-shore drilling in the Gulf of Mexico and $2.6 million for participation in exploration in South America. Bolstered by the frigid weather experienced in early 1994, the Company believes the market for natural gas will sustain recent price trends. Market and price trends will continue to be the principal factors for the economic justification of drilling investments under the 1994 program. In addition, $10.8 million in the 1994 capital program is earmarked for other projects, including further development of LIG. The Company is also proceeding with plans to fund and develop storage and interchange facilities which will interconnect with LIG and the Henry Hub. These facilities will establish the capability to provide services necessary for the creation of a separate market hub.
UTILITY SERVICES
Operating revenues, which are derived principally from the sale and transportation of natural gas, were $397.3 million in 1993 compared with $393.6 million in 1992 and $381.7 million in 1991. The increase in revenues for 1993 compared to 1992 is due to the full-year impact of a retail rate increase for Pennsylvania customers that went into effect in July of 1992, offset by lower retail rates to pass-through decreased purchased gas costs to customers. The increase in revenues for 1992 compared to 1991 is due primarily to increased retail gas sales resulting from colder weather which were offset somewhat by lower off-system sales and transportation.
Utility Services 1993 1992 1991
Operating Revenues (thousands): $314,312 $305,310 $291,955 Pipeline Gas Sales . . . . . 12,257 24,186 24,071 Transportation Service . . . 44,760 48,732 48,829 Storage Service . . . . . . . 6,927 5,553 5,935 Marketed Gas Sales . . . . . 10,200 - - Other . . . . . . . . . . . . 8,841 9,847 10,865 Total Revenues . . . . . . $397,297 $393,628 $381,655 Sales Quantities (MMcf): Retail Gas Sales . . . . . . 39,982 38,907 36,688 Pipeline Gas Sales . . . . . 2,814 5,779 5,823 Transportation . . . . . . . 66,272 71,166 70,897 Marketed Gas . . . . . . . . 4,052 - -
Heating Degree Days (Normal - 5,968) . . . . . . 5,628 5,629 5,030
Gas purchased amounted to $153.6 million in 1993, $170.6 million in 1992 and $163.4 million in 1991. The decrease in gas costs for 1993 reflects the pass-through of lower costs in rates to retail customers. The increase in 1992 is due primarily to the increase in retail sales volumes.
Other operating expenses amounted to $167.4 million in 1993, $149.8 million in 1992 and $148.3 million in 1991. The increase in other operating expenses for 1993 reflects increased labor and employee benefits, increased depreciation, higher taxes other than income, and recording of a reserve for possible refund of interstate billings.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued)
Operating income was $76.3 million in 1993 compared with $73.2 million in 1992 and $70.0 million in 1991. The increase in operating income for 1993 compared to 1992 is due primarily to the full-year impact of the retail rate increase that went into effect in July 1992. The increase in operating income for 1992 compared to 1991 is attributed to higher retail sales.
In May 1992, the Federal Energy Regulatory Commission (FERC) issued new regulations, in its Order 636, that significantly altered the manner in which natural gas is sold and transported in interstate commerce. The main feature of the new regulations requires pipelines to unbundle their services and rates by function and permit customers to select one or more of the services offered by the pipeline, i.e., transportation, storage, etc. Under the new structure, local distribution utilities, other marketers and end users will purchase their own gas supply and use pipeline services for handling and transporting the gas. The regulations require pipelines to establish new rates using a straight fixed variable design. Under this method, all fixed costs, including return on investment in facilities, are recovered through a fixed demand or capacity charge based on peak requirements reserved by customers. The vast majority of costs in pipeline rates are fixed costs. The remaining variable costs are recovered in commodity rates based on actual customer usage. The regulations also provide a rate mechanism for pipelines to recover prudently incurred transition costs as they move away from the merchant function.
The Company's interstate pipelines, Kentucky West and Equitrans, have successfully implemented their Order 636 restructured tariffs effective July 1, 1993 and September 1, 1993, respectively. All restructuring issues have been resolved for Kentucky West. On September 2, 1993, Equitrans filed a new rate case to address operational and transitional cost recovery issues which were severed from its Order 636 compliance filing by the FERC. On September 30, 1993, the FERC issued an order accepting and suspending certain tariff provisions and rejecting other conditions. The major area of difference was the timing and method of recovering some $60 million of transition costs. While Equitrans continues to recover other costs in restructured rates, it has filed a request for rehearing with the FERC regarding the recovery of transition costs.
CAPITAL RESOURCES AND LIQUIDITY
Operating Activities
Cash required for operations is impacted primarily by the seasonal nature of the Company's utility operations. Gas purchased for storage during the nonheating season is financed with short-term loans which are repaid as gas is withdrawn from storage and sold during the heating season. Short-term loans are also used to provide other working capital requirements during the nonheating season.
Investing Activities
The Company's business requires major ongoing expenditures for replacements, improvements and additions to utility plant and continuing development and expansion of its energy resources. Such expenditures during 1993 were $339.4 million including approximately $209 million for the purchase of LIG and Hershey Oil Corporation as described in Note L to the consolidated financial statements. A total of $151.2 million has been authorized for the 1994 capital expenditure program, including $90.5 million for energy resources.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued)
Short-term loans are used as interim financing for a portion of capital expenditures. The Company expects to finance its 1994 capital expenditures with cash generated from operations and temporarily with short-term loans.
Capital expenditures, including acquisitions, totaled about $865 million during the five- year period ended December 31, 1993, of which 45 percent was financed from operations.
Financing Activities
The Company believes it has adequate borrowing capacity to meet its financing requirements. Bank loans and commercial paper, supported by available credit, are used to meet short-term financing requirements. Interest rates on these short-term loans ranged from 2.94 percent to 3.78 percent during 1993. At December 31, 1993, $189.9 million of commercial paper and $64.0 million of bank loans were outstanding at an average interest rate of 3.30 percent. Lines of credit currently available to the Company total $325 million which require commitment fees averaging one-tenth of one percent. Adequate lines of credit are expected to continue to be available in the future.
On September 29, 1993, the Company issued 3 million shares of common stock at a price of $38.50 per share. Net proceeds of approximately $111.6 million, after underwriters' commissions and other issuance costs, were used to repay a portion of the short- term debt incurred to purchase the stock of LIG.
The Company filed a shelf-registration in March 1992 to issue $100 million of medium-term notes to be used primarily to retire short-term loans incurred to finance a portion of acquisitions made in 1991. Given the advantage of short-term interest rates during 1992 and 1993, the Company issued only $24.5 million of the medium-term notes during 1992 and an additional $32 million during 1993. It is anticipated that the remaining $43.5 million of medium-term notes will be issued in the first half of 1994.
As more fully described in Note H to the consolidated financial statements, the Company has redeemed $31.6 million of long-term debt during the past two years to further reduce interest costs. These redemptions were temporarily financed with short-term debt.
Accounting Developments
The Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109) effective January 1, 1993 and elected to restate its financial statements as of January 1, 1988. The Company also adopted SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" (OPEBS) effective January 1, 1993. The effect of adoption of SFAS No. 109 and SFAS No. 106 are more fully described in Notes C and E, respectively, to the consolidated financial statements.
The effect of adoption of both standards on net income was the deferral of increased expenses related to rate regulated utility operations. At December 31, 1993, regulatory assets related to deferred income taxes under SFAS No. 109 and accounting for OPEBS under SFAS No. 106 were approximately $76.4 million and $2.9 million, respectively.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (Continued)
Federal Income Tax Provisions
In August 1993, the Omnibus Budget Reconciliation Act of 1993 (OBRA) was signed into law. One of the provisions of OBRA was to raise the maximum corporate income tax rate from 34 percent to 35 percent. The effect of this tax rate change increased deferred tax liabilities by approximately $11 million and increased regulatory assets by approximately $6 million.
Cash flow has been affected by the Alternative Minimum Tax (AMT) since 1988. Despite the availability of nonconventional fuels tax credit, the Company has incurred an AMT liability in each of the years 1988 through 1993. Although AMT payments can be carried forward indefinitely and applied to income tax liabilities in future periods, they reduce cash generated from operations. At December 31, 1993, the Company has available $69.3 million of AMT credit carryforwards. The collection of revenues from direct billing settlements described in Note B to the consolidated financial statements will improve cash flow with the utilization of carryover credits. Nevertheless, the impact of AMT on cash flow will continue to depend on the future levels of energy prices. AMT is not expected to affect the Company's ability to finance future capital requirements.
Under current law, wells drilled after 1992 do not qualify for the nonconventional fuels tax credit. While production from qualified Energy Resources' wells drilled in the Appalachian area will generate tax credits through the year 2002, it is anticipated that the amount of such credits will decline after 1993 as the related reserves are depleted. The credits recorded in 1993, 1992 and 1991 reduced the Company's federal income tax provisions by $20.6 million, $14.1 million and $11.0 million, respectively.
Environmental Matters
Management does not know of any environmental liabilities that will have a material effect on the Company's financial position or results of operations. The Company has identified situations that require remedial action for which $6.0 million is accrued at December 31, 1993. The portion of amounts expensed through 1993 that have been deferred and included in regulatory assets amounts to $3.1 million. Environmental matters are described in Note N to the consolidated financial statements.
Balance Sheet Changes
The increase in deferred purchased gas cost is due to the timing of pass-through of gas costs to ratepayers. Changes in deferred purchased gas cost generally do not affect results of operations due to regulatory procedures for purchased gas cost recovery in rates. Gas stored underground--current inventory increased because all inventory is valued at average cost. See Note A to the consolidated financial statements. The increases in accounts receivable, accounts payable and other current liabilities reflect mainly the consolidation of LIG and increased marketing activities.
AUDIT COMMITTEE
The Audit Committee, composed entirely of outside directors, meets periodically with the Company's independent auditors, its internal auditor and management to review the Company's financial statements and the results of audit activities. The Audit Committee, in turn, reports to the Board of Directors on the results of its review and recommends the selection of independent auditors.
Item 8.
Item 8. Financial Statements and Supplementary Data
Page Reference
Report of Independent Auditors 23
Statements of Consolidated Income for each of the three years in the period ended December 31, 1993 24
Consolidated Balance Sheets December 31, 1993 and 1992 25 & 26
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1993 27
Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1993 28
Long-term Debt, December 31, 1993 and 1992 29
Notes to Consolidated Financial Statements 30 - 47
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders Equitable Resources, Inc.
We have audited the accompanying consolidated balance sheets and statements of long-term debt of Equitable Resources, Inc., and Subsidiaries at December 31, 1993 and 1992, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 1993. Our audits also included the financial statement schedules listed in the Index at Item 14(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Equitable Resources, Inc., and Subsidiaries at December 31, 1993 and 1992, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As described in Note C and Note E to the consolidated financial statements, the Company changed its method of accounting for income taxes and postretirement benefits in 1993.
s/ Ernst & Young ------------------------------- Ernst & Young
Pittsburgh, Pennsylvania February 22, 1994
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
See notes to consolidated financial statements Pages 30 to 47, inclusive
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, DECEMBER 31, 1993 AND 1992
See notes to consolidated financial statements Pages 30 to 47, inclusive
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, DECEMBER 31, 1993 AND 1992
See notes to consolidated financial statements Pages 30 to 47, inclusive
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
See notes to consolidated financial statements Pages 30 to 47, inclusive
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF COMMON STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
See notes to consolidated financial statements Pages 30 to 47, inclusive
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
LONG-TERM DEBT DECEMBER 31, 1993 AND 1992
See notes to consolidated financial statements Pages 30 to 47, inclusive
A. Summary of Significant Accounting Policies
(1)PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the accounts of Equitable Resources, Inc. and Subsidiaries (the "Company" or "Companies"). All subsidiaries are 100% owned.
(2)PROPERTIES, DEPRECIATION AND DEPLETION: The cost of property additions, replacements and improvements capitalized includes labor, material and overhead. The cost of property retired, plus removal costs less salvage, is charged to accumulated depreciation.
Depreciation for financial reporting purposes is provided on the straight-line method at composite rates based on estimated service lives, except for most gas and oil production properties as explained below. Depreciation rates are based on periodic studies.
The Company uses the successful efforts method of accounting for exploration and production activities. Under this method, the cost of productive wells and development dry holes, as well as productive acreage, are capitalized and depleted on the unit- of-production method. Capitalized acquisition costs of unproved properties are periodically assessed for impairment of value, and any loss is recognized at the time of impairment.
(3)ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: The Federal Energy Regulatory Commission (FERC) prescribes a formula to be used for computing overhead allowances for funds used during construction (AFC). AFC applicable to equity funds capitalized is included in other income and amounted to $1,022,000 in 1993, $1,297,000 in 1992 and $914,000 in 1991. AFC applicable to borrowed funds, as well as other interest capitalized for the nonregulated companies, is applied as a reduction of interest charges and amounted to $1,841,000 in 1993, $1,267,000 in 1992 and $1,263,000 in 1991
(4)INVENTORIES: Inventories are stated at cost which is below market. Gas stored underground--current inventory at December 31, 1993 of $18,059,000 is stated at cost under the average cost method. The December 31, 1992 balance includes $5,918,000, which is stated at cost under the last-in, first-out method (LIFO). As a result of FERC Order 636, certain gas stored underground has been transferred, at book value (LIFO), to property, plant and equipment. This gas represents cushion gas for the regulated interstate pipeline operations, a portion of which will be necessary to compensate for gas imbalances until replaced in-kind by customers. Material and supplies are stated generally at average cost.
(5)INCOME TAXES: The Companies file a consolidated federal income tax return. The current provision for income taxes represents amounts paid or payable. Deferred income tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities. Where deferred tax liabilities will be passed through to customers in regulated rates, the Company establishes a corresponding regulatory asset for the increase in future revenues that will result when the temporary differences reverse.
Investment tax credits realized in prior years were deferred and are being amortized over the estimated service lives of the related properties where required by ratemaking rules.
A. Summary of Significant Accounting Policies (Continued)
(6)DEFERRED PURCHASED GAS COST: Where permitted by regulatory authorities under purchased gas adjustment clauses or similar tariff provisions, the Companies defer the difference between purchased gas cost, less refunds, and the billing of such cost and amortize the deferral over subsequent periods in which billings either recover or repay such amounts.
(7)REGULATORY ASSETS: Certain costs, which will be passed through to customers under ratemaking rules for regulated operations, are deferred by the Company as regulatory assets. The amounts deferred relate primarily to the accounting for income taxes.
(8)CASH FLOWS: The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
(9)RECLASSIFICATION: Certain amounts contained in prior year comparative information have been reclassified to conform with the 1993 presentation.
B. Direct Billing Settlements
In 1990, a subsidiary, Kentucky West Virginia Gas Company, received FERC approval of settlement agreements with all customers, except Columbia Gas Transmission Company, for the direct billing to recover the higher Natural Gas Policy Act (NGPA) prices which the FERC had denied on natural gas produced from energy resource properties between 1978 and 1983. The settlements were individually negotiated and contain differing terms providing for the collection of $100.3 million over periods ranging from four to ten years. The recovery of $85 million of the $89 million settlement with the Equitable Gas division was subject to Pennsylvania Public Utility Commission (PUC) review as described below. The agreements that were fully approved were recorded at present value using a discount rate of 9%.
In 1991, the Equitable Gas division received PUC approval to recover $25 million of increased gas costs relating to the FERC settlement, including $4.9 million of additional carrying charges. The PUC also approved the recovery of $7.8 million relating to the settlement in each of the years 1993 and 1992. The amounts approved increased net income reported for the third quarter of 1993 and 1992 by $4.7 million and $14.9 million for the third quarter of 1991. Approximately $49 million from the settlement remains to be recovered in future gas cost filings with the PUC over the next seven years.
A final settlement proposal negotiated with Columbia for the recovery of $19 million was approved by the FERC in February 1993. The settlement agreement has been accepted in Columbia's bankruptcy proceeding. However, in view of Columbia's pending reorganization under Chapter 11 of the Bankruptcy Code, the amount of recovery from Columbia remains uncertain and therefore has not been recognized.
C. Income Taxes
The Company adopted the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109) effective January 1, 1993 and elected to restate prior period financial statements for the effect of the change. As of January 1, 1988, retained earnings was reduced by approximately $12 million; periodic net income since that date was not restated because the effect of the change in accounting on all periods reported was not material. Application of the new rules increased deferred income tax liabilities at January 1, 1992 by approximately $77 million and created regulatory assets of approximately $65 million.
The sources and tax effects of the temporary differences are as follows:
December 31, 1993 1992 (Thousands) Deferred tax liabilities (assets): Exploration and development costs expensed for income tax reporting $138,089 $124,254 Tax depreciation in excess of book depreciation . . . . . . 250,032 141,183 Regulatory temporary differences 36,841 28,710 Deferred purchased gas cost . . . 8,413 2,423 Alternative minimum tax . . . . . (69,333) (48,920) Investment tax credit . . . . . . (10,340) (10,121) Other . . . . . . . . . . . . . . (21,829) 4,958 Total (including amounts classified as current liabilities of $733 for 1993 and $182 for 1992) . $331,873 $242,487
As of December 31, 1993 and 1992, $76.4 million and $68.4 million, respectively, of the net deferred tax liabilities are related to rate regulated operations and have been deferred as regulatory assets.
Income tax expense is summarized as follows:
Years Ended December 31, 1993 1992 1991
(Thousands) Current: Federal . . . . . . . . $15,577 $13,540 $11,770 State . . . . . . . . . 3,687 7,245 4,192
Deferred: Federal . . . . . . . . (2,758) (4,547) 1,254 State . . . . . . . . . 3,514 2,532 2,720
Total . . . . . . . . $20,020 $18,770 $19,936
C. Income Taxes (Continued)
Provisions for income taxes are less than amounts computed at the federal statutory rate of 35% for 1993 and 34% for 1992 and 1991 on pretax income. The reasons for the difference are summarized as follows:
Years Ended December 31, 1993 1992 1991 (Thousands)
Tax at statutory rate . $ 32,716 $ 26,791 $28,595 State income taxes . . . 4,332 6,453 4,562
Increase in federal income tax rate . . . . 5,070 - -
Nonconventional fuels tax credit . . . . . . . . (20,600) (14,051) (10,998) Other . . . . . . . . . (1,498) (423) (2,223) Income tax expense . . $ 20,020 $ 18,770 $ 19,936 Effective tax rate . . . 21.4% 23.8% 23.7%
In August 1993, the Omnibus Budget Reconciliation Act of 1993 (Act) was signed into law. One of the provisions of the Act was to raise the maximum corporate income tax rate from 34% to 35%. The effect of this tax rate change increased deferred tax liabilities by approximately $11 million and increased regulatory assets by approximately $6 million.
The consolidated federal income tax liability of the Companies has been settled through 1990.
The Company has available $69.3 million of alternative minimum tax credit carryforward which has no expiration date. In addition, the Company has net operating loss carryforwards for federal income tax purposes of $13.8 million which begin to expire in 2006. The net operating loss carryforwards are the result of the acquisition of Louisiana Intrastate Gas Company as described in Note L.
Amortization of deferred investment tax credits amounted to $1,373,000 for 1993, $1,138,000 for 1992 and $850,000 for 1991.
D. Employee Pension Benefits
The Companies have several trusteed retirement plans covering substantially all employees. The Companies' annual contributions to the plans are based on a 25-year funding level. Plans covering union members generally provide benefits of stated amounts for each year of service. Plans covering salaried employees use a benefit formula which is based upon employee compensation and years of service to determine benefits to be provided. Plan assets consist principally of equity and debt securities.
D. Employee Pension Benefits (Continued)
The following table sets forth the plans' funded status and amounts recognized in the Company's consolidated balance sheets:
December 31, 1993 1992 (Thousands)
Actuarial present value of benefit obligations: Vested benefit obligation $132,402 $112,372 Accumulated benefit obligation $135,809 $115,192 Market value of plan assets $159,433 $149,351 Projected benefit obligation 148,265 124,100 Excess of plan assets over projected benefit obligation 11,168 25,251
Unrecognized net asset (3,237) (3,664)
Unrecognized net gain (16,732) (27,305)
Unrecognized prior service cost 10,403 8,246
Prepaid pension cost recognized in the consolidated balance sheets $ 1,602 $ 2,528
At year-end the discount rate used in determining the actuarial present value of benefit obligations was 7 1/4% for 1993, 8 1/4% for 1992 and 8 1/2% for 1991. The assumed rate of increase in compensation levels was 4 1/2% for 1993 and 5% for 1992 and 1991.
The Companies' pension cost, using a 9% average rate of return on plan assets at the beginning of 1993 and 1992 and 8 1/2% for 1991, comprised the following:
Years Ended December 31, 1993 1992 1991 (Thousands)
Service cost benefits earned during the period $ 2,806 $ 2,345 $ 2,726
Interest cost on projected benefit obligation 10,472 9,917 10,305
Actual return on assets (17,224) (18,214) (27,681)
Net amortization and deferral 5,486 7,069 16,946
Net periodic pension cost $ 1,540 $ 1,117 $ 2,296
E. Other Postretirement Benefits
In addition to providing pension benefits, the Companies provide certain health care and life insurance benefits for retired employees and their dependents. Substantially all employees are eligible for these benefits upon retirement from the Companies.
E. Other Postretirement Benefits (Continued)
SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" (OPEBS) requires, among other things, the accrual of retirement health care and life insurance benefits during the years an employee provides services. The new standard requires that the accumulated plan benefit obligation existing at the date of adoption (transition obligation) either be recognized immediately or deferred and amortized over future periods.
Historically, the Company recognized the cost of retiree health care and life insurance benefits as paid and has retained the right to modify or discontinue these benefits at any time. However, the Company was required to adopt the new standard effective January 1, 1993 and will amortize the resulting transition obligation over 20 years. In determining the accumulated postretirement benefit obligation at January 1, 1993, the Company used an inflation factor for medical costs beginning at 13% per year, which decreases gradually thereafter to 6% within 15 years and a discount rate of 8 1/4%. At December 31, 1993, the beginning inflation factor was 11% decreasing gradually to 4 3/4% within 17 years and the discount rate was 7 1/4%. The following summarizes the status of the Company's accrued OPEBS:
December 31, January 1, 1993 1993 (Thousands)
Accumulated postretirement benefit obligation: Retired employees $ 23,078 $ 24,971 Active employees: 8,942 7,361 Fully eligible Other 16,741 13,780
Total obligation 48,761 46,112
Unrecognized net gain 40 -0- Unrecognized transition obligation (43,806) (46,112)
Accrued postretirement benefit cost $ 4,995 $ -0-
The net periodic cost for postretirement health care and life insurance benefits for 1993 includes the following:
(Thousands)
Service cost . . . . . . . . . . . . . . . . . $1,065 Interest cost . . . . . . . . . . . . . . . . 3,936 Amortization of transition obligation . . . . 2,306 Periodic cost . . . . . . . . . . . . . . . . $7,307
E. Other Postretirement Benefits (Continued)
As of December 31, 1993, $2.9 million of the accrued OPEBS related to rate regulated operations have been deferred as regulatory assets. Rate filings will be made to seek full recovery of the costs accrued under SFAS No. 106 over periods of up to 20 years.
An increase of one percent in the assumed medical cost inflation rate would increase the accumulated postretirement benefit obligation by 8% and would increase the periodic cost by 10%.
The Company paid current claims for OPEBS of $3,421,000 in 1993. The cost of OPEBS for 1992 and 1991 was recognized as paid and amounted to $2,919,000 and $3,537,000, respectively.
F. Common Stock
(1) Common Stock Issuance
On September 29, 1993, the Company issued 3 million shares of common stock at a price of $38.50 per share. Net proceeds after underwriters' commissions and other issuance costs were approximately $111.6 million. The proceeds were used to repay a portion of the short-term debt incurred to purchase the stock of Louisiana Intrastate Gas Company as described in Note L.
(2) Restricted Stock Options and Awards
The Equitable Resources, Inc., Key Employee Restricted Stock Option and Stock Appreciation Rights Incentive Compensation Plan is nonqualified and provides for the granting of restricted stock awards or options to purchase common stock of the Company at prices ranging from 75% to 100% of market value on the date of grant. Stock options may be granted with or without stock appreciation units. Options expire five years from the date of grant. Stock awarded under the Plan or purchased through the exercise of options, and the value of certain stock appreciation units, are restricted and subject to risk of forfeiture should an optionee terminate employment prior to specified vesting dates. In 1991, restricted stock awards of 41,625 shares were made to key employees. The Company used treasury shares repurchased from plan participants for these awards.
F. Common Stock (Continued)
The following schedule summarizes the stock option activity:
Years Ended December 31, 1993 1992 1991
Options outstanding January 1 139,725 228,787 286,820 Granted 148,543 - 99,000 Exercised (33,325) (89,062) (152,158) Canceled, forfeited, surrendered or expired (1,875) - (4,875)
Options outstanding December 31 253,068 139,725 228,787
Average price of options $18.97 $17.07 $15.14
At December 31: Prices of options outstanding $17.50 $15.20 $15.20 to to to $36.50 $20.13 $21.59 Average option price $29.69 $19.76 $18.71
Shares reserved for issuance 671,349 705,209 794,558
(3)Dividend Reinvestment and Stock Purchase Plan
Pursuant to this plan, stockholders can reinvest dividends and make limited additional investments in shares of common stock. Shares issued through the plan have been acquired on the open market. Beginning in 1994, shares issued through the plan may continue to be acquired on the open market or by issuance of previously unissued shares. At December 31, 1993, 241,314 shares of common stock were reserved for issuance under the plan.
G. Short-Term Loans
Maximum lines of credit available to the Company were $360,000,000 during 1993, $140,000,000 during 1992 and $180,000,000 during 1991. The Company is not required to maintain compensating bank balances. Commitment fees averaging one-tenth of one percent are paid to maintain credit availability.
G. Short-Term Loans (Continued)
At December 31, 1993, short-term loans consisted of $189,900,000 of commercial paper and $64,000,000 of bank loans; and at December 31, 1992, $79,000,000 and $35,000,000, respectively. The maximum amounts of outstanding short-term loans were $339,000,000 in 1993, $130,500,000 in 1992 and $153,000,000 in 1991. The average daily total of short-term loans outstanding was approximately $174,900,000 during 1993, $107,389,000 during 1992 and $61,535,000 during 1991; weighted average annual interest rates applicable thereto were 3.3% in 1993, 3.8% in 1992 and 5.9% in 1991.
H. Long-Term Debt
The Company filed a shelf registration in March 1992 to issue $100 million of Medium-Term Notes--Series B to be used primarily to retire short-term loans incurred to temporarily finance a portion of 1991 acquisitions. Through December 31, 1993, the Company issued $56.5 million of Medium-Term Notes. These notes have maturity dates ranging from three to thirty years and a weighted average interest rate of 6.30%. Considering the advantage of lower short-term interest rates, the Company has delayed issuance of the remaining notes.
On March 31, 1993, the Company redeemed $16.4 million of First Mortgage Bonds, 8% series due June 15, 1997. The bonds were redeemed at 101.05 percent of the principal amount thereof, plus accrued interest through the date of redemption. On August 3, 1992, the Company redeemed $8.6 million of 9% Debentures due June 15, 1996. The debentures were redeemed at 100.79 percent of the principal amount thereof, plus accrued interest through the date of redemption. On March 2, 1992, the Company redeemed $6.6 million of First Mortgage Bonds, 6 1/4% series due September 1, 1992.
The 9 1/2% Convertible Subordinated Debentures are convertible at any time into common stock at a conversion price of $11.06 per share. During 1993, 1992 and 1991, $564,000, $259,000 and $1,084,000 of these debentures were converted into 50,983, 23,399 and 97,983 shares of common stock, respectively. At December 31, 1993, 240,918 shares of common stock were reserved for conversions.
Interest expense on long-term debt amounted to $33,161,000 in 1993, $31,899,000 in 1992 and $25,318,000 in 1991. Aggregate maturities of long-term debt will be $1,971,000 in 1994, $24,500,000 in 1995, $75,000,000 in 1996, none in 1997 and $5,000,000 in 1998.
I. Fair Value of Financial Instruments
The carrying value of cash and cash equivalents as well as short- term loans approximates fair value due to the short maturity of the instruments.
I. Fair Value of Financial Instruments (Continued)
The estimated fair value of long-term debt, including the portion due within one year, at December 31, 1993 and 1992 would be $433,048,000 and $388,642,000, respectively. The fair value was estimated based on the quoted market prices as well as the discounted values using a current discount rate reflective of the remaining maturity. The Company's 8 1/4% Debentures and 7 1/2% Debentures may not be redeemed prior to maturity. The 9.9% Debentures require payment of premiums for early redemption, exclusive of annual sinking fund requirements.
J. Concentrations of Credit Risk
Energy resources operating revenues and related accounts receivable are generated primarily from gas marketing activities, the sale of produced natural gas, natural gas liquids and oil and intrastate transportation of gas. The gas marketing activities are nationwide to large volume customers for resale or end use. Produced natural gas is sold primarily to utility and industrial customers located mainly in the Appalachian area. Produced natural gas liquids are sold to refinery customers in Louisiana and Kentucky. Produced oil is sold to refinery customers in the Rocky Mountain and Appalachian areas. The intrastate gas transportation is concentrated in Louisiana.
Utility services operating revenues and related accounts receivable are generated through regulated interstate pipeline and natural gas utility sales, transportation and storage services. Interstate natural gas sales, transportation and storage services are to the affiliated utility, Equitable Gas, as well as other utility and end-user customers located in nine mid-Atlantic and northeastern states. Utility sales and transportation services are provided to more than 265,000 residential, commercial and industrial customers located in southwest Pennsylvania and parts of West Virginia and Kentucky. Under state regulations, the utility is required to provide continuous gas service to residential customers during the winter heating season. In this regard, the Company continually reviews the credit worthiness of customers and, when necessary, requests deposits to secure future service.
The Company is not aware of any significant credit risks which have not been recognized in provisions for doubtful accounts.
K. Financial Information by Business Segment
The Company reports its operations in two business segments energy resources and utility services. Energy resource activities comprise exploration, development, production, gathering and marketing of natural gas and oil, intrastate transportation of natural gas, extraction and sale of natural gas liquids and contract drilling. Utility service activities comprise primarily a natural gas utility and three regulated gas pipelines.
K. Financial Information by Business Segment (Continued)
The following table sets forth financial information for each of the two business segments:
Years Ended December 31, 1993 1992 1991 (Thousands) Operating Revenues: Energy Resources $ 743,064 $ 461,642 $ 367,297 Utility Services 397,297 393,628 381,655 Sales between segments (45,567) (42,896) (69,321)
Total $1,094,794 $ 812,374 $ 679,631
Operating Income: Energy Resources $ 54,153 $ 41,198 $ 46,605 Utility Services 76,344 73,228 69,972
Total $ 130,497 $ 114,426 $ 116,577
Net Income: Energy Resources $ 38,000 $ 29,502 $ 31,929 Utility Services 35,455 30,524 32,239
Total $ 73,455 $ 60,026 $ 64,168
Identifiable Assets (a): Energy Resources $1,085,407 $ 696,801 $ 695,907 Utility Services 906,920 822,064 801,209 Eliminations (45,420) (50,441) (56,523)
Total $1,946,907 $1,468,424 $1,440,593
Depreciation and Depletion: Energy Resources $ 53,423 $ 45,638 $ 36,002 Utility Services 23,471 20,302 18,591
Total $ 76,894 $ 65,940 $ 54,593
Capital Expenditures: Energy Resources (including acquisitions) $ 296,245 $ 52,923 $ 189,472 Utility Services 43,166 46,666 45,717
Total $ 339,411 $ 99,589 $ 235,189
(a) Amounts for 1992 and 1991 have been restated for the effect of adoption of SFAS No. 109 as described in Note C.
L. Acquisitions
On June 30, 1993, the Company purchased the outstanding common stock of Louisiana Intrastate Gas Company (LIG) for $191 million. LIG owns a 1,900 mile intrastate pipeline system in Louisiana, four natural gas processing plants and is also engaged in gas marketing. The purchase was funded initially with short-term debt, a portion of which was repaid with the proceeds from the issuance of common stock as described in Note F to the consolidated financial statements. Under terms of the purchase agreement, the seller, and/or the previous owner of LIG, have indemnified the Company against losses resulting from claims of liability under gas purchase contracts and substantially all environmental liabilities attributable to operation of LIG prior to June 30, 1993.
On July 8, 1993, the Company purchased all of the outstanding stock of Hershey Oil Corporation (Hershey) for approximately $18 million. Hershey's assets consist primarily of approximately 68 billion cubic feet of proved natural gas reserves and 17,000 net undeveloped acres in Alberta, Canada.
The acquisitions were accounted for under the purchase method and are included in the energy resource segment. Had the purchases occurred as of the beginning of 1993 and 1992, unaudited proforma consolidated results for the Company would have been: revenues of $1.119 billion and $872 million; net income of $74.0 million and $68.6 million; and earnings per share of $2.29 and $2.19 for the years ended December 31, 1993 and 1992, respectively.
M. Purchase of Properties
On September 30, 1991, the Company purchased oil and gas properties in the Rocky Mountain area for approximately $64 million. The purchase, which was effective July 1, 1991, includes interests in approximately 400 wells and 438,000 net acres situated primarily in Wyoming, Montana, North Dakota and Utah. On November 25, 1991, the Company purchased gas properties and drilling programs in the Appalachian Basin for approximately $75 million. The purchase, which was effective September 1, 1991, includes properties located in western Virginia consisting of approximately 200 producing wells, 218,000 net acres and 205 miles of gathering and transmission lines which are connected to a major interstate pipeline. In both cases, the entire purchase price was attributed to the properties.
N. Commitments and Contingencies
Rent expense was $9,834,000 in 1993, $9,333,000 in 1992 and $8,353,000 in 1991. Long-term leases are principally for division operating headquarters and warehouse buildings and computer hardware and have renewal options ranging to 20 years from December 31, 1993. Future minimum rentals for all noncancelable long-term leases at December 31, 1993 are as follows: 1994, $5,448,000; 1995, $4,605,000; 1996, $3,622,000; 1997, $3,137,000; 1998, $2,803,000 and $15,424,000 thereafter for a total of $35,039,000.
Utility Services has annual commitments of approximately $43 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to 9 years at December 31, 1993. However, substantially all of these costs are recoverable in customer rates.
The Company is subject to federal, state and local environmental laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. 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.
On-going expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future.
The estimated costs associated with identified situations that require remedial action are accrued. However, certain of these costs are deferred when recoverable by claims against third parties or through regulated rates. Management does not know of any environmental liabilities that will have a material effect on the Company's financial position or results of operations.
As described in Note B, the Company has a claim in Columbia Gas Transmission Company's bankruptcy proceeding related to the direct billing settlements. In addition, the Company has various claims against Columbia for abrogation of contracts to purchase gas from the Company. The amount that may be realized, if any, under the claims cannot be estimated in view of Columbia's bankruptcy proceeding.
O. Interim Financial Information (Unaudited)
The following quarterly summary of operating results reflects variations due primarily to the seasonal nature of the Company's business and the activities of new subsidiaries from the date of acquisition as described in Note L.
March June September December 31 30 30 31 (Thousands except per share amounts)
Operating revenues $269,819 $207,782 $272,745 $344,448 Operating income 55,349 13,978 24,787 36,383 Net income 30,795 8,831 8,612 25,217 Earnings per share $.98 $.28 $.27 $.73
Operating revenues $245,208 $161,352 $144,429 $261,385 Operating income 50,351 8,678 14,358 41,039 Net income 26,105 3,626 7,161 23,134 Earnings per share $.83 $.12 $.23 $.74
P. Natural Gas and Oil Producing Activities
The supplementary information summarized below presents the results of natural gas and oil activities for the Energy Resource segment in accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing Activities."
The information presented excludes data associated with natural gas reserves related to rate regulated operations. These reserves (proved developed) are less than 5% of total Company proved reserves for the years presented.
P. Natural Gas and Oil Producing Activities (Continued)
(1)Production Costs
The following table presents the costs incurred relating to natural gas and oil production activities:
1993 1992 1991 (Thousands) At December 31: Capitalized costs . . . $836,638 $748,325 $718,140
Accumulated depreciation and depletion . . . . 256,508 216,005 187,321
Net capitalized costs . $580,130 $532,320 $530,819
Costs incurred : Property acquisition: Proved properties . . $29,345 $ 663 $119,308
Unproved properties . - - 20,806 Exploration . . . . . . 13,928 13,166 22,924 Development . . . . . . 62,336 46,321 37,498
(2) Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas and oil production:
1993 1992 1991
(Thousands)
Revenues: Affiliated . . . . . . $ 15,467 $ 8,964 $ 16,407 Nonaffiliated . . . . 140,380 127,369 94,165
Production costs . . . . 33,620 30,385 25,971
Exploration expenses . . 13,559 16,439 17,144
Depreciation and depletion 43,841 40,744 31,863
Income tax expense . . . 5,039 5,221 2,748
Results of operations from producing activities (excluding corporate overhead) . . . . . . . $ 59,788 $ 43,544 $ 32,846
P. Natural Gas and Oil Producing Activities (Continued)
(3) Reserve Information (Unaudited)
The information presented below represents estimates of proved gas and oil reserves prepared by Company engineers. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. Substantially all reserves are located in the United States.
Natural Gas 1993 1992 1991 (Millions of Cubic Feet)
Proved developed and undeveloped reserves: Beginning of year 720,032 695,898 620,755 Revision of previous estimates 9,399 25,736 (2,959) Purchase of natural gas in place - net 86,113(a) 434 89,925 Extensions, discoveries and other additions Production (53,550) (48,243) (40,022)
End of year 822,583(b) 720,032 695,898
Proved developed reserves: Beginning of year 665,194 621,846 528,573
End of year 759,282(c) 665,194 621,846
(a) Includes 68,000 MMcf purchased in Canada. (b) Includes 70,000 MMcf proved reserves in Canada. (c) Includes 46,000 MMcf proved developed reserves in Canada.
P. Natural Gas and Oil Producing Activities (Continued)
Oil 1993 1992 1991 (Thousands of Barrels)
Proved developed and undeveloped reserves: Beginning of year 20,023 19,427 12,253
Revision of previous estimates (4,876) 951 (309)
Purchase (sale) of oil in place - net 418(a) (138) 7,907
Extensions, discoveries and other additions 3,015 2,189 1,582
Production (2,112) (2,406) (2,006)
End of year 16,468(b) 20,023 19,427
Proved developed reserves: Beginning of year 18,540 17,072 11,166
End of year 16,442(c) 18,540 17,072
(a) Includes 68,000 barrels purchased in Canada. (b) Includes 65,000 barrels proved reserves in Canada. (c) Includes 39,000 barrels proved developed reserves in Canada.
(4) Standard Measure of Discounted Future Cash Flows (Unaudited)
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at an arbitrary rate of 10%. Estimated future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels are as follows:
1993 1992 1991 (Thousands)
Future cash inflows $2,140,151 $2,058,973 $1,835,380 Future production costs (598,707) (551,987) (462,367) Future development costs (24,579) (41,612) (63,243) Future income tax expenses (434,362) (409,970) (351,087) Future net cash flow 1,082,503 1,055,404 958,683 10% annual discount for estimated timing of cash flows (515,023) (507,082) (456,624)
Standardized measure of discounted future net cash flows $ 567,480(a) $ 548,322 $ 502,059
(a) Includes $31,267,000 in Canada.
Summary of changes in the standardized measure of discounted future net cash flows:
1993 1992 1991 (Thousands)
Sales and transfers of gas and oil produced - net $ (122,227) $ (105,948) $ (84,601)
Net changes in prices, production and development costs (80,256) 11,370 (141,414)
Extensions, discoveries, and improved recovery, less related costs 90,035 77,759 43,188
Development costs incurred 18,482 27,807 25,588
Purchase (sale) of minerals in place - net 62,843 (142) 120,533
Revisions of previous quantity estimates (14,910) 1,709 (4,440)
Accretion of discount 69,284 62,548 64,829
Net change in income taxes (8,584) (21,093) 49,691
Other 4,491 (7,747) (9,150)
Net increase 19,158 46,263 64,224
Beginning of year 548,322 502,059 437,835
End of year $ 567,480 $ 548,322 $ 502,059
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Information required by Item 10 with respect to directors is incorporated herein by reference to the section describing "Election of Directors" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 27, 1994, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 1993.
Information required by Item 10 with respect to executive officers is included herein after Item 4 at the end of Part I.
Item 11.
Item 11. Executive Compensation
Information required by Item 11 is incorporated herein by reference to the section describing "Executive Compensation", "Employment Contracts and Change-In-Control Arrangements" and "Pension Plan" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 27, 1994.
Item 12.
Item 12.Security Ownership of Certain Beneficial Owners and Management
Information required by Item 12 is incorporated herein by reference to the section describing "Voting Securities and Record Date" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 27, 1994.
Item 13.
Item 13. Certain Relationships and Related Transactions
Not applicable.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Financial statements
The financial statements listed in the accompanying index to financial statements and financial statement schedules (page 51) are filed as part of this annual report.
2. Financial statement schedules
The financial statement schedules listed in the accompanying index to financial statements and financial statement schedules (page 51) are filed as part of this annual report.
3. Exhibits
The exhibits listed on the accompanying index to exhibits (pages 62 through 65) are filed as part of this annual report.
(b) Reports on Form 8-K filed during the quarter ended December 31, 1993.
None
(c) Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*) in the Index to Exhibits.
EQUITABLE RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES COVERED BY REPORT OF INDEPENDENT AUDITORS
(Item 14 (a))
1. The following consolidated financial statements of Equitable Resources, Inc. and Subsidiaries are included in Item 8:
Page Reference
Statements of Consolidated Income for each of the three years in the period ended December 31, 1993 24 Consolidated Balance Sheets December 31, 1993 and 1992 25 & 26 Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1993 27 Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1993 28 Long-term Debt, December 31, 1993 and 1992 29 Notes to Consolidated Financial Statements 30 thru 47
2. Schedules for the Years Ended December 31, 1993, 1992 and 1991 included in Part IV:
V - Property, Plant and Equipment 52, 53 & 54 VI - Accumulated Depreciation, Depletion and Amortization 55, 56, 57, 58 of Property, Plant and Equipment & 59 VIII- Valuation and Qualifying Accounts and Reserves 60 X - Supplementary Income Statement Information 61
Schedules I, II, III, IV, VII, XI, XII, XIII and XIV are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules as permitted by Regulation S-X.
The information called for in Schedule IX is set forth in the consolidated balance sheet and notes to consolidated financial statements.
EQUITABLE RESOURCES, INC.
NOTES TO SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands)
A. Includes $1,859 depreciation of automotive equipment charged to transportation clearing account and then distributed principally to various operating expenses and construction accounts.
B. Net change in retirement work in progress.
C. Retirements shown in Schedule V, Property, Plant and Equipment are reconciled with the amounts shown in Column D of this schedule as deductions from accumulated retirement reserves, as follows:
Retirements or sales as shown in Schedule V $18,736 Add - Cost of removal 798 $19,534 Deduct: Salvage 1,276 Retirements not charged to reserve 5,235 Retirements, renewals and replacements as shown in Column D of this schedule $13,023
(Thousands)
A. Includes $2,022 depreciation of automotive equipment charged to transportation clearing account and then distributed principally to various operating expenses and construction accounts.
B. Net change in retirement work in progress.
C. Retirements shown in Schedule V, Property, Plant and Equipment are reconciled with the amounts shown in Column D of this schedule as deductions from accumulated retirement reserves, as follows:
Retirements or sales as shown in Schedule V $34,297 Add - Cost of removal 243 $34,540 Deduct: Salvage 2,311 Retirements not charged to reserve 10,291 Retirements, renewals and replacements as shown in Column D of this schedule $21,938
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
NOTES TO SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(Thousands)
A. Includes $1,791 depreciation of automotive equipment charged to transportation clearing account and then distributed principally to various operating expenses and construction accounts.
B. Net change in retirement work in progress.
C. Retirements shown in Schedule V, Property, Plant and Equipment are reconciled with the amounts shown in Column D of this schedule as deductions from accumulated retirement reserves, as follows:
Retirements or sales as shown in Schedule V $13,162 Add - Cost of removal 726 $13,888 Deduct: Salvage 914 Retirements not charged to reserve 938 Retirements, renewals and replacements as shown in Column D of this schedule $12,036
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE THREE YEARS ENDED DECEMBER 31, 1993
Column A Column B Column C Column D Column E
Balance At Additions Charged Balance Beginning To Costs At End Description Of Period and Expenses Deductions Of Period
(Thousands)
Accumulated Provision for Doubtful Accounts $9,503 $9,352 $8,749(A) $10,106
Accumulated Provision for Doubtful Accounts $8,722 $8,998 $8,217(A) $9,503
Accumulated Provision for Doubtful Accounts $7,531 $8,534 $7,343(A) $8,722
Note:
(A) Customer accounts written off, less recoveries.
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE THREE YEARS ENDED DECEMBER 31, 1993
Column A Column B
Charged to Item Costs and Expenses
1993 1992 1991
(Thousands)
1. Maintenance and repairs $29,024 $26,327 $24,441
2. Depreciation and amortization of intangible assets (Note A) (Note A) (Note A)
3. Taxes other than payroll and income taxes: Pennsylvania gross receipts $14,837 $12,233 $13,268 State severance taxes 8,970 8,581 6,853 Other 10,707 10,978 9,225
Total $34,514 $31,792 $29,346
4. Royalties (Note B) $14,978 $15,736 $13,780
5. Advertising costs (Note A) (Note A) (Note A)
Notes:
(A) Not material in amount.
(B) Substantially all royalties are reflected as a reduction of gas and oil revenues in the financial statements.
EXHIBITS DESCRIPTION METHOD OF FILING 2.01 (a) Stock Purchase Agreement Filed as Exhibit 2.1 (a) dated May 5, 1993 among to Form 8-K Dated June 30, Arkla, Inc., Arkla Finance 1993 Corporation and Equitable Pipeline Company for the purchase of Louisiana Intrastate Gas Company
2.01 (b) Schedule 4.1.11 to the Filed as Exhibit 2.1 (b) Stock Purchase Agreement to Form 8-K Dated June 30, pertaining to outstanding 1993 litigation claims
2.01 (c) Schedule 4.1.15 to the Filed as Exhibit 2.1 (c) Stock Purchase Agreement to Form 8-K Dated June 30, pertaining to environmental 1993 matters 2.01 (d) Letter Agreement Dated June Filed as Exhibit 2.1 (d) 30, 1993 amending the Stock to Form 8-K Dated June 30, Purchase Agreement 1993
3.01 Restated Articles of Filed herewith at page 68 Incorporation of the Company dated May 21, 1993 (effective May 27, 1993)
3.02 By-Laws of the Company Filed herewith at page 77 (amended through December 17, 1993 4.01 (a) Indenture dated as of April Filed as Exhibit 4.01 1, 1983 between the Company (Revised) to Post- and Pittsburgh National Effective Amendment No. 1 Bank relating to Debt to Registration Statement Securities (Registration No. 2-80575)
4.01 (b) Instrument appointing Refiled herewith at page Bankers Trust Company as 96 pursuant to Rule 24 of successor trustee to SEC's Rules of Practice Pittsburgh National Bank
4.01 (c) Resolution adopted June 26, Refiled herewith at page 1986 by the Finance 106 pursuant to Rule 24 of Committee of the Board of SEC's Rules of Practice Directors of the Company establishing the term of the $75,000,000 of debentures, 8 1/4% Series due July 1, 1996 4.01 (d) Resolutions adopted June Refiled herewith at page 22, 1987 by the Finance 109 pursuant to Rule 24 of Committee of the Board of SEC's Rules of Practice Directors of the Company establishing the terms of the 75,000 units (debentures with warrants) issued July 1, 1987
4.01 (e) Resolution adopted April 6, Refiled herewith at page 1988 by the Ad Hoc Finance 118 pursuant to Rule 24 of Committee of the Board of SEC's Rules of Practice Directors of the Company establishing the terms and provisions of the 9.9% Debentures issued April 14,
4.01 (f) Supplemental indenture Filed as Exhibit 4.3 to dated March 15, 1991 with Form S-3 (Registration Bankers Trust Company Statement 33-39505) filed eliminating limitations on August 21, 1991 liens and additional funded debt
4.01 (g) Resolution adopted August Filed as Exhibit 4.05 to 19, 1991 by the Ad Hoc Form 10-K for the year Finance Committee of the ended December 31, 1991 Board of Directors of the Company Addenda Nos. 1 thru 27, establishing the terms and provisions of the Series A Medium-Term Notes
EXHIBITS DESCRIPTION METHOD OF FILING
4.01 (h) Resolutions adopted July 6, Filed as Exhibit 4.05 to 1992 and February 19, 1993 Form 10-K for the year by the Ad Hoc Finance ended December 31, 1992 Committee of the Board of Directors of the Company and Addenda Nos. 1 thru 8, establishing the terms and provisions of the Series B Medium-Term Notes
*10.01 Equitable Resources, Inc. Filed as Exhibit 10.07 to Key Employee Restricted Form 10-K for the year Stock Option and Stock ended December 31, 1989 Appreciation Rights Incentive Compensation Plan (as amended through March 17, 1989) *10.02(a) Employment Agreement dated Refiled herewith at page as of March 18, 1988 with 126 pursuant to Rule 24 of Frederick H. Abrew SEC's Rules of Practice
*10.02(b) Amendment effective June 1, Refiled herewith at page 1989 to Employment 153 pursuant to Rule 24 of Agreement with Frederick H. SEC's Rules of Practice Abrew
*10.03(a) Employment Agreement dated Refiled herewith at page as of March 18, 1988 with 154 pursuant to Rule 24 of Augustine A. Mazzei, Jr. SEC's Rules of Practice
*10.03(b) Amendment effective June 1, Refiled herewith at page 1989 to Employment 181 pursuant to Rule 24 of Agreement with Augustine A. SEC's Rules of Practice Mazzei, Jr. *10.04(a) Agreement dated December Filed as Exhibit 10.16 to 15, 1989 with Barbara B. Form 10-K for the year Sullivan for deferred ended December 31, 1989 payment of 1990 director fees
*10.04(b) Agreement dated December Filed as Exhibit 10.16 to 21, 1990 with Barbara B. Form 10-K for the year Sullivan for deferred ended December 31, 1990 payment of 1991 director fees
*10.04(c) Agreement dated December Filed as Exhibit 10.16 to 13, 1991 with Barbara B. Form 10-K for the year Sullivan for deferred ended December 31, 1991 payment of 1992 director fees *10.04(d) Agreement dated December Filed herewith at page 182 28, 1993 with Barbara B. Sullivan for deferred payment of 1994 director fees
* 10.05 Supplemental Executive Filed herewith at page 187 Retirement Plan (as amended and restated through December 17, 1993)
*10.06 Retirement Program for the Filed as Exhibit 10.19 to Board of Directors of Form 10-K for the year Equitable Resources, Inc. ended December 31, 1989 (as amended through August 1, 1989)
*10.07 Supplemental Pension Plan Filed herewith at page 197 (as amended and restated through December 17, 1993) *10.08 Policy to Grant Filed as Exhibit 10.21 to Supplemental Deferred Form 10-K for the year Compensation Benefits in ended December 31, 1989 Selected Instances to a Select Group of Management or Highly Compensated Employees (as amended and restated through August 1, 1989)
EXHIBITS DESCRIPTION METHOD OF FILING
*10.09(a) Equitable Resources, Inc. Filed as Exhibit 10.22 to and Subsidiaries Short-Term Form 10-K for the year Incentive Compensation Plan ended December 31, 1987 dated January 18, 1988
*10.09(b) Amendment dated February Filed as Exhibit 10.22 to 17, 1993 to Equitable Form 10-K for the year Resources, Inc. and ended December 31, 1992 Subsidiaries Short-Term Incentive Compensation Plan *10.10(a) Agreement dated December Refiled herewith at page 31, 1987 with Malcolm M. 206 pursuant to Rule 24 of Prine for deferred payment SEC's Rules of Practice of 1988 director fees
*10.10(b) Agreement dated December Refiled herewith at page 30, 1988 with Malcolm M. 211 pursuant to Rule 24 of Prine for deferred payment SEC's Rules of Practice of 1989 director fees
*10.11(a) Agreement dated September Refiled herewith at page 30, 1986 with Daniel M. 216 pursuant to Rule 24 of Rooney for deferred payment SEC's Rules of Practice of 1986 and 1987 director fees
*10.11(b) Agreement dated December Refiled herewith at page 21, 1987 with Daniel M. 221 pursuant to Rule 24 of Rooney for deferred payment SEC's Rules of Practice of 1988 director fees *10.11(c) Agreement dated December Refiled herewith at page 30, 1988 with Daniel M. 226 pursuant to Rule 24 of Rooney for deferred payment SEC's Rules of Practice of 1989 director fees
*10.11(d) Agreement dated December Filed as Exhibit 10.27 to 15, 1989 with Daniel M. Form 10-K for the year Rooney for deferred payment ended December 31, 1989 of 1990 director fees
*10.11(e) Agreement dated December Filed as Exhibit 10.27 to 21, 1990 with Daniel M. Form 10-K for the year Rooney for deferred payment ended December 31, 1990 of 1991 director fees *10.11(f) Agreement dated December Filed as Exhibit 10.27 to 13, 1991 with Daniel M. Form 10-K for the year Rooney for deferred payment ended December 31, 1991 of 1992 director fees
*10.11(g) Agreement dated December Filed as Exhibit 10.27 to 18, 1992 with Daniel M. Form 10-k for the year Rooney for deferred payment ended December 31, 1992 of 1993 director fees
*10.11(h) Agreement dated December Filed herewith at page 231 14, 1993 with Daniel M. Rooney for deferred payment of 1994 director fees
10.12 Trust Agreement with Filed as Exhibit 10.28 to Pittsburgh National Bank to Form 10-K for the year act as Trustee for ended December 31, 1989 Supplemental Pension Plan, Supplemental Deferred Compensation Benefits, Retirement Program for Board of Directors, and Supplemental Executive Retirement Plan
EXHIBITS DESCRIPTION METHOD OF FILING
11.01 Statement re Computation of Filed herewith at page 236 Earnings Per Share
21 Schedule of Subsidiaries Filed herewith at page 237 23.01 Consent of Independent Filed herewith at page 238 Auditors
99.01 Equitable Resources, Inc. Filed herewith at page 239 Employees Savings Plan Form 11-K Annual Report
The Company agrees to furnish to the Commission, upon request, copies of instruments with respect to long-term debt which have not previously been filed.
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.
EQUITABLE RESOURCES, INC. (Registrant)
By: s/ Donald I. Moritz (Donald I. Moritz) Chairman and Chief Executive Officer
Date: March 18, 1994
Pursuant to the requirements of the Securities and 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.
Chairman and Chief Executive Officer and Director s/ Donald I. Moritz (Principal Executive Officer) March 18, 1994 Donald I. Moritz
Vice President and Treasurer s/ Robert E. Daley (Chief Financial Officer) March 18, 1994 Robert E. Daley
Vice President - Accounting and Administration s/ Joseph L. Giebel (Chief Accounting Officer) March 18, 1994 Joseph L. Giebel
President and Chief Operating Officer s/ Frederick H. Abrew and Director March 18, 1994 Frederick H. Abrew
Director March 18, 1994 Clifford L. Alexander, Jr.
s/ Merle E. Gilliand Director March 18, 1994 Merle E. Gilliand
SIGNATURES (Continued)
s/ E. Lawrence Keyes, Jr. Director March 18, 1994 E. Lawrence Keyes, Jr.
s/ Thomas A. McConomy Director March 18, 1994 Thomas A. McConomy
Director March 18, 1994 Malcolm M. Prine
s/ Daniel M. Rooney Director March 18, 1994 Daniel M. Rooney
Director March 18, 1994 David S. Shapira
s/ Barbara Boyle Sullivan Director March 18, 1994 Barbara Boyle Sullivan