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 operating 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.
(b) and (b) (1) Beginning in 1994, the Company expanded the reporting of its business operations to four business segments: exploration and production, natural gas marketing, natural gas distribution and natural gas transmission. Financial information by business segment is presented in Note L to the consolidated financial statements contained in Part II.
(b)(2) Not applicable.
(c)(1) EXPLORATION AND PRODUCTION. Exploration and production 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 sells natural gas and oil, extracts and markets natural gas liquids and performs contract drilling and well maintenance services.
The exploration and production segment 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 the Southwest and Gulf Coast offshore areas, this segment participates in exploration and development of gas and oil projects. Exploration and production 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.
NATURAL GAS MARKETING. Natural gas marketing activiites are conducted by ERMCO and its subsidiaries. Its activities include marketing of natural gas, extraction, and sale of natural gas liquids and intrastate transportation.
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. In 1994, ERMCO was granted a Federal Energy Regulatory Commission (FERC) certificate for electricity wholesaling.
In Louisiana, LIG provides intrastate transportation of gas and extracts and markets natural gas liquids.
NATURAL GAS DISTRIBUTION. Natural gas distribution activities comprise the operations of Equitable Gas Company, the Company's state- regulated natural gas utility.
Equitable Gas is 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.
Natural gas distribution services 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 the natural gas transmission segment.
NATURAL GAS TRANSMISSION. Natural gas transmission activities are conducted by three FERC-regulated gas pipelines: Kentucky West, Equitrans, and Nora. Activities include gas transportation, gathering, storage, and marketing activities.
Kentucky West is an open access natural gas pipeline company. Prior to restructuring pursuant to FERC Order 636, Kentucky West purchased gas from the exploration and production 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 the natural gas marketing segment. With the FERC Order 636 restructuring, which was effective July 1, 1993, Kentucky West provides open-access transportation service. Transportation service is provided to Equitable Gas, Equitrans, the exploration and production segment, 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 has 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 and markets natural gas. 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 transports the exploration and production segment's gas produced in Virginia and Kentucky.
(c) (1) (i) Operating revenues as a percentage of total operating revenues for each of the four business segments during the years 1992 through 1994 are as follows:
1994 1993 1992
Exploration and Production: Natural gas production 9 percent 10 percent 10 percent Oil 2 3 5 Natural gas liquids 1 2 3 Contract drilling 1 1 3 Other - 1 1 --- --- --- Total Exploration and Production 13 17 22 --- --- --- Natural Gas Marketing: Natural gas marketing 51 45 32 Natural gas liquids 4 2 - Transportation 1 1 - --- --- --- Total Natural Gas Marketing 56 48 32 --- --- --- Natural Gas Distribution: Residential 19 23 30 Commercial 5 5 7 Industrial and utility 2 1 1 Transportation 2 2 2 --- --- --- Total Natural Gas Distribution 28 31 40 --- --- --- Natural Gas Transmission: Industrial and utility - - 1 Marketed gas 1 1 - Transportation 1 2 4 Storage 1 1 1 --- --- --- Total Natural Gas Transmission 3 4 6 --- --- --- Total Revenues 100 percent 100 percent 100 percent === === ===
See Note L to the Consolidated Financial Statements in Part II regarding financial information by business segment.
(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 1992 through 1994.
During 1994, a total of 507,126 MMcf of gas was produced and purchased by the Companies compared with 325,377 MMcf in 1993. The increase reflects greater marketing activity, including the full-year effect of the LIG acquisition, and increased production.
GAS PURCHASES. Total purchases in 1994 amounted to 442,605 MMcf, of which 386,214 MMcf was applicable to marketing operations and 56,391 MMcf was for system supply, compared with 216,287 MMcf for marketing operations and 53,568 MMcf for system supply in 1993. 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 the exploration and production segment in 1994 of 62,507 MMcf increased 8,957 MMcf over the 1993 total of 53,550 MMcf. Other production by transmission and distribution segments in 1994 was 2,014 MMcf compared with the 1993 total of 1,972 MMcf.
Production of crude oil in 1994 was 1,986,000 barrels, compared with 2,112,000 barrels in 1993.
In 1994, the Company drilled 198 gross wells (144.9 net wells). The primary focus of drilling activity was in Virginia for gas and coalbed methane and in the Rockies for oil.
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 all gas production at a profit.
NATURAL GAS AND OIL RESERVES. The Company's estimate of proved developed and undeveloped gas reserves for the exploration and production segment comprised 875.0 Bcf as of December 31, 1994. These reserves included 771.7 Bcf of proved developed reserves. The Company's oil reserves at December 31, 1994 consisted of 18.3 million barrels of proved developed and undeveloped reserves; proved developed oil reserves amounted to 18.1 million barrels. Of the total reserves, 77 percent is in the Appalachian area, 18 percent in the Rockies and 5 percent in the Gulf. 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 1993-94 heating season were 7.1 Bcf, compared with 11.0 Bcf the previous heating season. Net withdrawals for storage service customers of 14.1 Bcf were made during the 1993-94 heating season compared with 12.8 Bcf the previous heating season.
SUPPLY OUTLOOK. The Company's near-term gas supply for distribution operations 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.
The natural gas marketing segment has also been in a favorable supply position and reserves for the exploration and production segment have continued to increase. However, the rate of purchase of future supplies or development of reserves 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 natural gas distribution 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.
The exploration and production and natural gas marketing segments' revenues are not subject to seasonal variation to the same degree as natural gas distribution revenues. However, they are subject to price fluctuations, particularly during the summer months.
(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 marketed natural gas available to existing or potential customers.
The natural gas distribution segment 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 natural gas transmission companies.
(c) (1) (xi) Not material.
(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 2,171 regular employees at the end of 1994.
(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 1995 through 2014. All leases contain adequate renewal options for various periods. A minor portion of equipment is also leased. With few exceptions, 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.
NATURAL GAS DISTRIBUTION. Equitable Gas owns and operates natural gas distribution properties as well as other general property and equipment in Pennsylvania, West Virginia and Kentucky.
NATURAL GAS TRANSMISSION. 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.
NATURAL GAS MARKETING. This segment owns an intrastate pipeline system and four hydrocarbon extraction plants in Louisiana. It also has a high-deliverability gas storage project under development in Louisiana.
EXPLORATION AND PRODUCTION. 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 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 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.
Gas and Oil Production (Exploration and Production):
1994 1993 1992
Gas - MMcf 62,507 53,550 48,243 Oil - Thousands of Barrels 1,986 2,112 2,406
Natural Gas: Average field sales price of natural gas produced during 1994, 1993 and 1992 was $1.95, $2.24 and $1.88 per Mcf, respectively. Average production cost (lifting cost) of natural gas during 1994, 1993 and 1992 was $.424, $.458 and $.443 per Mcf, respectively.
Oil: Average sales price of oil produced during 1994, 1993 and 1992 was $14.72, $16.18 and $18.07 per barrel, respectively. Average production cost (lifting cost) of oil during 1994, 1993 and 1992 was $3.73, $4.30 and $3.75 per barrel, respectively.
Gas Oil
Total productive wells at December 31, 1994: Total gross productive wells 5,542 952 Total net productive wells 4,085 489 Total acreage at December 31, 1994: Total gross productive acres 713,000 Total net productive acres 588,000 Total gross undeveloped acres 3,087,000 Total net undeveloped acres 2,217,000
Number of net productive and dry exploratory wells and number of net productive and dry development wells drilled:
1994 1993 1992
Exploratory wells: Productive 7.0 12.0 11.6 Dry 5.7 6.7 6.3 Development wells: Productive 126.9 123.4 134.1 Dry 5.3 10.6 12.0
As of December 31, 1994, the Company had 2 gross wells (1.8 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 M 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, 1994.
Item 10. Directors and Executive Officers of the Registrant
(b) Identification of executive officers
Name and Age Title Business Experience
Donald I. Moritz (67) Chairman and Chief Executive Officer (Retired December 31, 1994) First elected to present position December 17, 1993; President and Chief Executive Officer from August 1, 1978.
Frederick H. Abrew (57) President and Chief Operating Officer (Elected Chief Executive Officer effective January 1, 1995) First elected to present position December 17, 1993; Executive Vice President and Chief Operating Officer from June 1, 1992; Executive Vice President from June 1, 1991; Executive Vice President - Utility Services from June 1, 1988.
A. Mark Abramovic (46) Vice President and Chief Financial Officer First elected to present position November 1, 1994; Vice President - Corporate Development from June 1, 1994; Assistant to the President from November 1993; Vice President - - Finance and Chief Financial Officer of Connecticut Natural Gas Corporation, Hartford, CT, from January 1991; Vice President - Finance of the Peoples Natural Gas Company, Pittsburgh, PA, from September 1986.
Jeremiah J. Ayres (62) Senior Vice President - Environment and Technology (Retired July 1, 1994) First elected to present position February 1, 1991; Vice President - Corporate Services from March 26, 1987.
Robert E. Daley (55) Vice President and Treasurer First elected to present position May 22, 1986.
Harry E. Gardner, Jr. (57) Vice President - Energy Resources (Retired December 31, 1994) First elected to present position June 1, 1992; President - Equitable Resources Energy Company since January 1, 1991; President Equitable Resources Exploration Division from July 1, 1987.
Joseph L. Giebel (64) Vice President - Accounting and Administration First elected to present position February 1, 1991; Vice President - Accounting from May 1, 1981.
John C. Gongas, Jr. (50) Vice President - Utility Group First elected to present position January 1, 1994; Vice President - Utility Services from June 1, 1992; President of Kentucky West Virginia Gas Company since April 20, 1992; President of Equitrans, Inc. from February 26, 1988.
Augustine A. Mazzei, Jr. (58) Senior Vice President and General Counsel First elected to present position June 1, 1988.
Audrey C. Moeller (59) Vice President and Corporate Secretary First elected to present position May 22, 1986.
Richard Riazzi (40) Vice President - Energy Group First elected to present position January 1, 1994; Vice President - Corporate Development from August 1, 1991; Director - Special Projects from October 1, 1990; President - Equitable Resources Marketing Company from February 27, 1989.
Gregory R. Spencer (46) Vice President - Human Resources First elected to present position October 10, 1994; Vice President of Human Resources Administration of AMSCO International, Inc., Pittsburgh, PA, from May 1993 (integrated manufacturer of sterilization and decontamination equipment for health care and scientific customers); General Manager - Human Resources of U.S. Steel Group of USX Corporation, Pittsburgh, PA, from October 1991; Director - Personnel, U.S. Steel Group of USX Corporation, Pittsburgh, PA, from July 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 27, 1994.
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:
1994 1993 High Low Dividend High Low Dividend
1st Quarter 38 3/4 34 $.285 41 1/2 33 $.270 2nd Quarter 37 32 1/4 .285 * 40 3/4 36 7/8 .270 * 3rd Quarter 35 5/8 29 .285 44 1/4 35 1/4 .270 4th Quarter 31 1/8 25 1/2 .295 42 3/4 35 1/4 .285
* Actually declared near the end of the preceding quarter.
(b) As of December 31, 1994, there were 8,686 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, $408,797,000 of the Company's consolidated retained earnings at December 31, 1994, 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 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
Equitable's consolidated net income for 1994 was $60.7 million or $1.76 per share, compared with $73.5 million or $2.27 per share for 1993, and $60.0 million or $1.92 per share for 1992.
While natural gas production reached a record high for 1994, an increase of 17 percent over 1993, income was adversely impacted by a 13 percent decline in average wellhead prices for natural gas, increased operating and interest expense, and lower margins from the Company's Louisiana Intrastate Gas subsidiary. 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 natural gas distribution and transmission 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.
RESULTS OF OPERATIONS
Beginning in 1994, the Company expanded the reporting of operations to comprise four segments--Exploration and Production, Natural Gas Marketing, Natural Gas Distribution and Natural Gas Transmission. This discussion supplements the detailed financial information by business segment presented in Note L to the consolidated financial statements.
EXPLORATION AND PRODUCTION
Operating revenues, which are derived primarily from the sale of produced natural gas, oil and natural gas liquids and from contract drilling, were $195.8 million in 1994 compared with $202.4 million in 1993 and $191.5 million in 1992. The decrease in revenues for 1994 compared to 1993 is due primarily to lower wellhead prices for natural gas and oil, and lower selling prices and production of natural gas liquids which were partially offset by increased gas production. The increase in revenues for 1993 compared to 1992 is due primarily to increases in average wellhead prices and production of natural gas.
Exploration and Production 1994 1993 1992
Operating Revenues (thousands): Natural Gas . . . . . . . . . $121,810 $119,746 $ 90,886 Oil . . . . . . . . . . . 29,239 34,176 43,469 Natural Gas Liquids . . . . . 15,244 19,545 21,256 Contract Drilling . . . . . . 15,427 14,611 19,924 Direct Billing Settlements. . 7,815 7,815 7,815 Other . 6,260 6,529 8,128 ------- ------- ------- Total Revenues . . . . $195,795 $202,422 $191,478 ======= ======= ======= Sales Quantities: Natural Gas (MMcf). . . . . . 62,507 53,550 48,243 Oil (MBls). . . . . . . . . . 1,986 2,112 2,406 Natural Gas Liquids (thousands of gallons) . . . . . . . . 51,032 60,973 64,938
Gas purchased amounted to $10.6 million in 1994 compared with $17.0 million in 1993 and $15.3 million in 1992. The decrease in gas purchased for 1994 compared to 1993 is due to the lower requirements attributed to decreased production of natural gas liquids. The increase in gas purchased for 1993 compared to 1992 is due to higher costs for purchased gas.
Other operating expenses were $154.4 million in 1994, $142.9 million in 1993, and $139.8 million in 1992. Increases for the respective years are attributed to increased production expenses and depreciation and depletion related to the higher level of natural gas production.
Operating income was $30.8 million in 1994, $42.5 million in 1993, and $36.4 million in 1992. The decrease in operating income for 1994 compared to 1993 reflects lower wellhead prices for natural gas and oil, and lower selling prices and production of natural gas liquids which were partially offset by increased gas production. The increase in operating income for 1993 compared to 1992 reflects primarily the increase in average wellhead prices and production of natural gas.
Average wellhead natural gas prices for 1994 decreased 13 percent from the 1993 level, which was the highest level that had been experienced since 1988. Thus far in 1995, the wellhead prices have shown little sign of improving. Prices for oil and natural gas liquids continued the decline that began as far back as 1991. Natural gas production continued to increase in 1994 reflecting the on-going development of Appalachian properties, which are the foundation of the segment's activities, as well as expansion in the off-shore Gulf Coast area.
The 1995 capital expenditure program of $71.0 million for exploration and production includes $15.4 million for development of Appalachian holdings, $18.3 million for the Rocky Mountain area, $32.3 million for off-shore drilling in the Gulf of Mexico, and $2.7 million for exploration in South America. Market and price trends will continue to be the principal factors for the economic justification of drilling investments under the 1995 program.
NATURAL GAS MARKETING
Operating revenues, which are derived primarily from the marketing of natural gas, sale of produced natural gas liquids, and intrastate transportation of natural gas in Louisiana, were $890.8 million in 1994 compared with $599.6 million in 1993 and $314.6 million in 1992. The increase in revenues between the years is attributed primarily to the acquisition of Louisiana Intrastate Gas Company (LIG) on June 30, 1993, as more fully described in Note M to the consolidated financial statements.
Natural Gas Marketing 1994 1993 1992
Operating Revenues (thousands): Natural Gas Marketing . . . . $830,082 $565,605 $ 314,276 Natural Gas Liquids . . . . . 51,113 27,576 -- Transportation. . . . . . . . 9,266 6,247 -- Other . 317 196 350 ------- ------- ------- Total Revenues . . . . $890,778 $599,624 $314,626 ======= ======= ======= Sales Quantities: Marketed Natural Gas (MMcf) . 429,651 253,516 162,135 Natural Gas Liquids (thousands of gallons) . . . . . . . . 194,493 101,218 --
Gas purchased amounted to $857.4 million in 1994 compared with $575.7 million in 1993 and $305.9 million in 1992. The increased cost between the years reflects the increase in volume of marketed natural gas and requirements for the higher production levels of natural gas liquids.
Other operating expenses were $29.3 million in 1994, $12.2 million in 1993, and $3.8 million in 1992. Increases for the respective years reflect the acquisition of LIG.
Operating income was $4.1 million in 1994, $11.7 million in 1993, and $4.9 million in 1992. The decrease in operating income for 1994 compared to 1993 reflects lower prices for natural gas liquids. The increase in operating income for 1993 compared to 1992 reflects primarily the acquisition of LIG.
Gas marketing activities continued to expand during 1994. However, the impact of lower energy prices overshadowed the nearly seventy percent increase in marketed volumes. LIG, which contributed to the increase in marketed services, fell below profit expectations because of the substantial decline in liquids processing margins. This is attributed to the competitive pressure of lower oil prices during most of the year. Nevertheless, the acquisition of LIG has positioned the Company's marketing activities in the Gulf Coast area where it also has expanding exploration and production activities. The Company is developing gas storage and interchange facilities which will connect with the Henry Hub as well as LIG's system of pipelines, gas processing facilities, and multiple interconnections with major pipelines. This integration and expansion of services is the foundation for developing a Gulf Coast market center.
The 1995 capital expenditure program of $25.2 million for marketing operations includes $19.0 million for development of the gas storage system, $5.0 million for improvement of LIG's pipeline and gathering system, and $1.2 million for development of information systems to support the expanded services expected to be offered.
NATURAL GAS DISTRIBUTION
Operating revenues, which are derived from the sale and transportation of natural gas primarily to retail customers at state regulated rates, were $390.5 million in 1994 compared with $335.1 million in 1993 and $328.0 million in 1992. The increase in revenues for 1994 compared to 1993 is due primarily to higher retail rates to pass through increased purchased gas costs to customers, increased sales to utilities, and increased commercial and industrial sales reflecting some transportation customers switching service. The increase in revenues for 1993 compared to 1992 is due to the full-year impact of a retail rate increase for Pennsylvania customers, which went into , effect in July of 1992 offset by lower retail rates to pass through decreased purchased gas costs to customers.
Natural Gas Distribution 1994 1993 1992
Operating Revenues (thousands): Residential Gas Sales . . . . $265,356 $247,238 $241,331 Commercial Gas Sales. . . . . 66,956 59,057 59,386 Industrial and Utility Gas Sales . 31,853 8,017 4,593 Transportation Service. . . . 21,750 16,526 17,967 Other . 4,560 4,311 4,745 ------- ------- ------- Total Revenues. . . . . . . $390,475 $335,149 $328,022 ======= ======= ======= Sales Quantities (MMcf): Residential Gas Sales . . . . 29,570 29,980 30,089 Commercial Gas Sales. . . . 9,681 8,235 8,097 Industrial and Utility Gas Sales 12,855 1,767 721 Transportation Deliveries . . 8,611 10,986 13,080 Heating Degree Days (Normal - 5,968). . . . . . 5,607 5,628 5,629
Gas purchased amounted to $232.9 million in 1994, $182.8 million in 1993, and $179.4 million in 1992. The increase in gas costs for 1994 compared to 1993 reflects the pass-through of higher costs in rates to retail customers and the increase in sales to commercial, industrial, and utility customers. The increase in gas costs for 1993 compared to 1992 reflects increased sales to commercial, industrial, and utility customers partially offset by the pass-through of lower costs in rates to retail customers.
Other operating expenses amounted to $114.4 million in 1994, $106.6 million in 1993, and $97.2 million in 1992. The increase between the years is due principally to increased labor, sales and marketing, distribution, and uncollectible account expenses.
Operating income was $43.2 million in 1994 compared with $45.7 million in 1993 and $51.4 million in 1992. The decrease in operating income between the years is due primarily to increased operating expenses, which more than offset the higher margins being realized.
The operating results of the distribution operations continue to be impacted by the effects of weather on gas sales, primarily to residential customers. However, increased sales to utility customers and the continuing expansion of new gas-using technologies such as co-generation, natural gas vehicles, and natural gas-fired cooling have served to retain system throughput. In addition, new services for customers, such as energy management, have helped to offset the effects of weather that continues to be warmer than normal.
The 1995 capital expenditure program of $25.1 million for distribution operations includes $17.1 million for the distribution system, $5.7 million for development of information systems and $2.3 million for other items.
NATURAL GAS TRANSMISSION
Operating revenues, which are derived from the interstate transportation, storage and sale of natural gas subject to federal regulation, and the marketing of natural gas, were $116.8 million in 1994 compared with $188.9 million in 1993 and $203.4 million in 1992. The decrease in revenues between the years reflects the effects of FERC Order 636 restructuring which took effect in the middle of 1993.
Natural Gas Transmission 1994 1993 1992
Operating Revenues (thousands): Industrial and Utility Gas Sales . . . $ 2,309 $114,867 $155,271 Marketed Gas Sales. . . . . . 21,244 10,200 -- Transportation Service. . . . 69,958 47,534 34,779 Storage Service . . . . . . . 16,993 10,014 6,693 Other . 6,265 6,267 6,658 ------- ------- ------- Total Revenues. . . . . . . $116,769 $188,882 $203,401 ======= ======= ======= Sales Quantities (MMcf): Industrial and Utility Gas Sales . . . 388 26,345 36,697 Marketed Gas Sales. . . . . . 9,131 4,052 -- Transportation Deliveries . . 123,472 88,550 79,015
Gas purchased amounted to $18.2 million in 1994, $95.9 million in 1993, and $127.4 million in 1992. The decrease in gas costs between the years reflects the elimination of pipeline gas sales pursuant to FERC Order 636 restructuring.
Other operating expenses amounted to $66.4 million in 1994, $62.3 million in 1993, and $54.0 million in 1992. The increase in expenses between the years is due primarily to provisions for possible refunds to customers.
Operating income was $32.2 million in 1994 compared with $30.7 million in 1993 and $22.0 million in 1992. The increase in operating income between the years is due primarily to the restructuring of tariff rates pursuant to FERC Order 636 whereby all fixed costs are now recovered in the demand portion of pipeline rates.
The 1995 capital expenditure program of $19.6 million for transmission operations includes $12.3 million for maintaining and expanding the transmission system, $4.0 million for expansion of gas storage facilities, and $3.3 million for other items.
CAPITAL RESOURCES AND LIQUIDITY
Operating Activities
Cash required for operations is impacted primarily by the seasonal nature of the Company's distribution 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. In addition, short- term loans are 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 its distribution and transmission plant and continuing development and expansion of its resource production activities. Such expenditures during 1994 were $146.2 million. A total of $140.9 million has been authorized for the 1995 capital expenditure program.
Short-term loans are also used as interim financing for a portion of capital expenditures. The Company expects to finance its 1995 capital expenditures with cash generated from operations and temporarily with short-term loans.
Capital expenditures, including acquisitions, totaled about $922 million during the five-year period ended December 31, 1994, of which 45 percent was financed from operations.
Financing Activities
The Company 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 2.99 percent to 6.80 percent during 1994. At December 31, 1994, $256.0 million of commercial paper and $13.3 million of bank loans were outstanding at an average interest rate of 5.94 percent. In January 1995, the Company established a five-year revolving Credit Agreement with a group of banks providing $500 million of available credit. The agreement requires a facility fee of one-tenth of one percent. Adequate credit is 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.
During the first quarter of 1994, the Company issued the remaining $43.5 million of Medium-Term Notes--Series B which were available under a shelf registration filed in March 1992 covering $100 million of medium-term notes. The Company filed a new shelf registration effective June 9, 1994, for the issuance of $100 million of Medium-Term Notes--Series C to be used to retire short-term loans. No Series C Notes have been issued.
Federal Income Tax Provisions
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 1994. 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, 1994, the Company has available $82.9 million of AMT credit carryforwards. The impact of AMT on future cash flow will depend on the level of taxable income. 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 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 as the related reserves are depleted. The credits recorded in 1994, 1993, and 1992 reduced the Company's federal income tax provisions by $16.4 million, $20.6 million, and $14.1 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 $6.5 million is accrued at December 31, 1994. The portion of amounts expensed through 1994 that have been deferred, pending recovery in future rates, and included in regulatory assets amounts to $3.5 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 costs generally do not affect results of operations due to regulatory procedures for purchased gas cost recovery in rates. The increase in refunds due customers reflects provisions for refund of a portion of Equitrans' current rates that are in effect subject to approval by the FERC.
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. Financial Statements and Supplementary Data
Page Reference
Report of Independent Auditors 24
Statements of Consolidated Income for each of the three years in the period ended December 31, 1994 25
Consolidated Balance Sheets December 31, 1994 and 1993 26 & 27
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1994 28
Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1994 29
Long-term Debt, December 31, 1994 and 1993 30
Notes to Consolidated Financial Statements 31 - 48
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, 1994 and 1993, 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, 1994. Our audits also included the financial statement schedule listed in the Index at Item 14(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Equitable Resources, Inc., and Subsidiaries at December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As described in Note E to the consolidated financial statements, the Company changed its method of accounting for postretirement benefits in 1993.
s/ Ernst & Young LLP Ernst & Young LLP
Pittsburgh, Pennsylvania February 13, 1995
EQUITABLE RESOURCES, INC. Notes to Consolidated Financial Statements December 31, 1994
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 percent 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 $.9 million in 1994, $1.0 million in 1993 and $1.3 million in 1992. 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 $2.1 million in 1994, $1.8 million in 1993 and $1.3 million in 1992.
(4) INVENTORIES: Inventories are stated at cost which is below market. Gas stored underground--current inventory is stated at cost under the average cost method. 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 Companies establish 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.
(6) DEFERRED PURCHASED GAS COST: Where permitted by regulatory authority under purchased gas adjustment clauses or similar tariff provisions, the Company defers the difference between purchased gas cost, less refunds, and the billing of such cost and amortizes 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) DERIVATIVE FINANCIAL INSTRUMENTS: The Company uses exchange- traded natural gas and crude oil futures contracts to hedge exposures to energy price changes. To qualify for hedge accounting, the Company must be exposed to energy price risk and the futures contracts must be designated and effective as hedges. Realized gains and losses on futures contracts which qualify as hedges of firm commitments or anticipated transactions are deferred and recognized in income when the hedged transactions occur. The Company also trades natural gas futures. Realized and unrealized gains and losses on such transactions are recorded in other income in the period in which the changes occur. Margin requirements on futures contracts are recorded in other current assets on the balance sheet.
(9) CASH FLOWS: The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
(10) RECLASSIFICATION: Certain amounts contained in prior year comparative information have been reclassified to conform with the 1994 presentation.
B. Direct Billing Settlements
Kentucky West Virginia Gas Company received FERC approval of settlement agreements with all customers for the direct billing to recover the higher Natural Gas Policy Act (NGPA) prices, which the FERC had denied on natural gas produced from exploration and production properties between 1978 and 1983. The portion of the settlement with the Equitable Gas Division has been subject to Pennsylvania Public Utility Commission (PUC) review. The PUC approved the recovery of $7.8 million relating to the settlement in each of the years 1992 to 1994, which increased net income reported for the third quarter of each year by $4.7 million. Approximately $42 million from the settlement remains to be recovered in future gas cost filings with the PUC over the next six years.
The settlement with Columbia Gas Transmission Company for the recovery of $19 million 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 following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities:
December 31, 1994 1993 (Thousands) Deferred tax liabilities (assets): Exploration and development costs expensed for income tax reporting . . . . $141,479 $138,089 Tax depreciation in excess of book depreciation . . . . . . . 255,683 250,032 Regulatory temporary differences . . 37,319 36,841 Deferred purchased gas cost. . . . . 6,397 8,413 Alternative minimum tax. . . . . . . (82,925) (69,333) Investment tax credit. . . . . . . . (9,306) (10,340) Other. . . . . . . . . . . . . . . . (17,606) (21,829) ------- ------- Total (including amounts classified as current liabilities of $4,444 for 1994 and $733 for 1993) . . $331,041 $331,873 ======= =======
As of December 31, 1994 and 1993, $76.2 million and $76.4 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, 1994 1993 1992 (Thousands)
Current: Federal. . . . . . . . . . $11,196 $15,577 $13,540 State. . . . . . . . . . . 2,640 3,687 7,245 Deferred: Federal. . . . . . . . . . (6,848) (2,758) (4,547) State. . . . . . . . . . . 1,789 3,514 2,532 ----- ------ ------ Total . . . . . . . . $ 8,777 $20,020 $18,770 ====== ====== ======
Provisions for income taxes are less than amounts computed at the federal statutory rate of 35 percent for 1994 and 1993, and 34 percent for 1992 on pretax income. The reasons for the difference are summarized as follows:
Years Ended December 31, 1994 1993 1992 (Thousands)
Tax at statutory rate . $ 24,327 $ 32,716 $ 26,791 State income taxes . . . 3,069 4,332 6,453 Increase in federal income tax rate. . . . - 5,070 - Nonconventional fuels tax credit . . . . . . (16,442) (20,600) (14,051) Other . (2,177) (1,498) (423) ------- ------- ------- Income tax expense . . $ 8,777 $ 20,020 $ 18,770 ======= ======= ======= Effective tax rate . . . 12.6 percent 21.4 percent 23.8 percent
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 percent. 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 $82.9 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 $14.9 million which begin to expire in 2006. The net operating loss carryforwards apply to Louisiana Intrastate Gas.
Amortization of deferred investment tax credits amounted to $1.1 million for 1994, $1.4 million for 1993 and $1.1 million for 1992.
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.
The following table sets forth the plans' funded status and amounts recognized in the Company's consolidated balance sheets:
December 31, 1994 1993 (Thousands)
Actuarial present value of benefit obligations: Vested benefit obligation $120,763 $132,402 ======= ======= Accumulated benefit obligation $123,877 $135,809 ======= ======= Market value of plan assets $143,121 $159,433 Projected benefit obligation 134,111 148,265 ------- ------- Excess of plan assets over projected benefit obligation 9,010 11,168 Unrecognized net asset (2,905) (3,237) Unrecognized net gain (15,606) (16,732) Unrecognized prior service cost 9,512 10,403 ------- ------- Prepaid pension cost recognized in the consolidated balance sheets $ 11 $ 1,602 ======= =======
At year-end the discount rate used in determining the actuarial present value of benefit obligations was 8 1/4 percent for 1994, 7 1/4 percent for 1993 and 8 1/4 percent for 1992. The assumed rate of increase in compensation levels was 4 1/2 percent for 1994 and 1993 and 5 percent for 1992.
The Companies' pension cost, using a 9 percent average rate of return on plan assets, comprised the following:
Years Ended December 31, 1994 1993 1992 (Thousands)
Service cost benefits earned during the period. $ 3,916 $ 2,806 $ 2,345 Interest cost on projected benefit obligation 10,752 10,472 9,917 Actual loss (return) on assets. . . . . 2,757 (17,224) (18,214) Net amortization and deferral. (14,680) 5,486 7,069 ------ ------ ------ Net periodic pension cost . . $ 2,745 $ 1,540 $ 1,117 ====== ====== ======
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. The Company's transition obligation is being amortized over 20 years. In determining the accumulated postretirement benefit obligation at December 31, 1994, the Company used a beginning inflation factor of 10 1/2 percent decreasing gradually to 4 3/4 percent after 15 years and a discount rate of 8 1/4 percent. At December 31, 1993, the beginning inflation factor was 11 percent decreasing gradually to 4 3/4 percent after 16 years and the discount rate was 7 1/4 percent. The following summarizes the status of the Company's accrued postretirement benefit costs (OPEBS):
December 31, 1994 1993 (Thousands) Accumulated postretirement benefit obligation: Retired employees. . . . . . . . . $ 21,269 $ 23,078 Active employees: Fully eligible . . . . . . . . . 9,158 8,942 Other. . . . . . . . . . . . . . 13,459 16,741 ------- ------- Total obligation . . . . . . . 43,886 48,761 Unrecognized net gain . . . . . . . 5,160 40 Unrecognized transition obligation. (41,501) (43,806) ------- ------- Accrued postretirement benefit cost . $ 7,545 $ 4,995 ======= =======
The net periodic cost for postretirement health care and life insurance benefits includes the following: Years Ended December 31, 1994 1993 (Thousands)
Service cost. . . . . . . . . . . . $1,049 $1,065 Interest cost . . . . . . . . . . . 3,423 3,936 Amortization of transition obligation. . . 2,305 2,306 ----- ----- Periodic cost. . . . . . . . . . . $6,777 $7,307 ===== =====
As of December 31, 1994 and 1993, $3.5 million and $2.9 million, respectively, of the accrued OPEBS related to rate regulated operations have been deferred as regulatory assets. Rate filings have been undertaken to seek recovery of accrued costs 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 7 percent and would increase the periodic cost by 8 percent.
The cost of OPEBS for 1992 was recognized as paid and amounted to $2.9 million.
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 M.
(2) Key Employee Restricted Stock Option Plan
The Equitable Resources, Inc., Key Employee Restricted Stock Option and Stock Appreciation Rights Incentive Compensation Plan is nonqualified and provided for the granting of restricted stock awards or options to purchase common stock of the Company at prices ranging from 75 percent to 100 percent of market value on the date of grant. 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.
The following schedule summarizes the stock option activity:
Years Ended December 31, 1994 1993 1992
Options outstanding January 1 . . 253,068 139,725 228,787 Granted . . . . . . . . . . . . . - 148,543 - Exercised . . . . . . . . . . . . (7,650) (33,325) (89,062) Canceled, forfeited, surrendered or expired . . . . . . . . . . . (3,600) (1,875) - ------- ------- ------- Options outstanding December 31 . 241,818 253,068 139,725 ======= ======= ======= Average price of options exercised during the year . . . $22.48 $18.97 $17.07 At December 31: Prices of options outstanding . $18.81 $17.50 $15.20 to to to $36.50 $36.50 $20.13
Average option price . . . . . . $29.82 $29.69 $19.76
Shares reserved for issuance . . 663,699 671,349 705,209
No future grants may be made under the Plan which was replaced by the Long-Term Incentive Plan effective May 27, 1994 as described below.
(3) Long-Term Incentive Plan
On May 27, 1994, shareholders approved the Equitable Resources, Inc. Long-Term Incentive Plan which provides for the granting of shares of common stock to officers and key employees of the Company. These grants may be made in the form of stock options, restricted stock, stock appreciation rights and other types of stock-based or performance-based awards as determined by the Compensation Committee of the Board of Directors at the time of each grant. Stock awarded under the Plan, or purchased through the exercise of options, and the value of stock appreciation units, are restricted and subject to forfeiture should an optionee terminate employment prior to specified vesting dates. The maximum number of shares which could have been granted under the Plan during 1994 was 763,500 shares. In each subsequent year, an additional number of shares equal to 1 percent of the total outstanding shares as of the preceding December 31 will be available for grant. In no case may the number of shares granted under the Plan exceed 1,725,500 shares. No awards may be made under the Plan after May 27, 1999. In May 1994, 363,400 stock options were granted to purchase common stock at $33.81 per share, which was the mean of the high and the low trading prices of the common stock on the date of grant. These options expire five years from the date of grant. At December 31, 1994, 1,725,500 shares of common stock were reserved for issuance under the Plan.
(4) Non-Employee Directors' Stock Incentive Plan
On May 27, 1994, shareholders approved the Equitable Resources, Inc. Non-Employee Directors' Stock Incentive Plan which provides for the granting of up to 80,000 shares of common stock in the form of stock option grants and restricted stock awards to non-employee directors of the Company. Each Director received 450 shares of restricted stock on February 3, 1994. On June 1, 1994, each director was granted an option for 500 shares of common stock at $34.625 per share. On the first business day of June, in each year from 1995 through 1998, each Director will be granted an option for 500 additional shares of common stock. The exercise price for each share is 100 percent of the mean of the high and the low trading prices of the common stock on the date of grant. Each option is exercisable upon the earlier of three years from the date of grant or a Director's retirement, disability or death. No option may be exercised more than five years after date of grant. At December 31, 1994, 76,400 shares of common stock were reserved for issuance under the Plan.
(5) Dividend Reinvestment and Stock Purchase Plan
Pursuant to this plan, stockholders may reinvest dividends and make limited additional cash investments to purchase shares of common stock. Shares issued through the Plan may be acquired on the open market or by issuance of previously unissued shares. At December 31, 1994, 194,183 shares of common stock were reserved for issuance under the Plan.
G. Short-Term Loans
Maximum lines of credit available to the Company were $325 million during 1994, $360 million during 1993 and $140 million during 1992. The Company is not required to maintain compensating bank balances. Commitment fees averaging one-tenth of one percent were paid to maintain credit availability. In January 1995, the Company established a five-year revolving Credit Agreement with a group of banks providing $500 million of available credit. The agreement requires a facility fee of one-tenth of one percent.
At December 31, 1994, short-term loans consisted of $256.0 million of commercial paper and $13.3 million of bank loans at a weighted average annual interest rate of 5.94 percent; and at December 31, 1993, $189.9 million and $64.0 million, respectively, at a weighted average annual interest rate of 3.30 percent. The maximum amount of outstanding short-term loans was $269.3 million in 1994, $339.0 million in 1993 and $130.5 million in 1992. The average daily total of short-term loans outstanding was approximately $204.6 million during 1994, $174.9 million during 1993 and $107.4 million during 1992; weighted average annual interest rates applicable thereto were 4.4 percent in 1994, 3.3 percent in 1993 and 3.8 percent in 1992.
H. Long-Term Debt
The Company filed a shelf registration with the Securities and Exchange Commission effective June 9, 1994 to issue $100 million of Medium-Term Notes--Series C to be used to retire short-term loans. No Series C Notes have been issued.
During the first quarter of 1994, the Company issued the remaining $43.5 million of Medium Term Notes--Series B under a shelf registration filed with the Securities and Exchange Commission in March 1992. The Series B Notes have maturity dates ranging from three to thirty years from date of issuance and a weighted average interest rate of 6.60 percent.
The 9 1/2 percent Convertible Subordinated Debentures are convertible at any time into common stock at a conversion price of $11.06 per share. During 1994, 1993 and 1992, $345,000, $564,000 and $259,000 of these debentures were converted into 31,187 shares, 50,983 shares and 23,399 shares of common stock, respectively. At December 31, 1994, 209,731 shares of common stock were reserved for conversions.
Interest expense on long-term debt amounted to $35.5 million in 1994, $33.2 million in 1993 and $31.9 million in 1992. Aggregate maturities of long-term debt will be $24.5 million in 1995, $75.0 million in 1996, none in 1997, $5.0 million in 1998 and $78.8 million in 1999.
I. Derivative Financial Instruments
The Company is exposed to risk from fluctuations in energy prices in the normal course of business. The Company uses exchange-traded energy futures contracts to hedge exposures to changes in energy prices, primarily relating to its gas marketing operations. The Company also trades in energy futures. Energy futures contracts are commitments to either purchase or sell a designated commodity, generally natural gas or crude oil, at a future date for a specified price and may be settled in cash or through delivery. The contracts used by the Company cover one-month periods from one to eighteen months in the future. Initial margin requirements are met in cash or other instruments, and changes in contract values are settled daily. Energy futures contracts have minimal credit risk because futures exchanges are the counterparties.
At December 31, 1994, natural gas futures contracts for the purchase of 10.8 Bcf and the sale of 3.7 Bcf were outstanding as hedges on future transactions. At December 31, 1994, deferrals related to hedging activities include realized losses of $.2 million and unrealized losses of $1.5 million.
At December 31, 1994, there were no outstanding energy futures contracts held for trading purposes. During 1994, the average fair value of traded contracts was $30,000 and a net gain of $1.5 million was realized. The value of these financial instruments is subject to fluctuations in market prices for natural gas and crude oil. Exposure to this risk is managed by maintaining open positions within defined trading limits.
J. 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.
The estimated fair value of long-term debt, including the portion due within one year, at December 31, 1994 and 1993 would be $430.2 million and $433.0 million, 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 percent Debentures and 7 1/2 percent Debentures may not be redeemed prior to maturity. The 9.9 percent Debentures require payment of premiums for early redemption, exclusive of annual sinking fund requirements.
The futures described in Note I are reflected in other current assets at fair value of $(1.5) million.
K. Concentrations of Credit Risk
Revenues and related accounts receivable from exploration and production operations are generated primarily from the sale of produced natural gas to utility and industrial customers located mainly in the Appalachian area; the sale of produced oil to refinery customers in the Rocky Mountain and Appalachian areas; and the sale of produced natural gas liquids to a refinery customer in Kentucky.
Natural gas marketing operating revenues and related accounts receivable are generated from the nationwide marketing of natural gas to brokers and large volume utility and industrial customers; and the sale of produced natural gas liquids and intrastate transportation of natural gas in Louisiana.
Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation 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.
Natural gas transmission operating revenues and related accounts receivable are generated from FERC-regulated interstate pipeline transportation and storage service for the affiliated utility, Equitable Gas, as well as other utility and end-user customers located in nine mid- Atlantic and northeastern states.
The Company is not aware of any significant credit risks which have not been recognized in provisions for doubtful accounts.
L. Financial Information by Business Segment
Beginning in 1994, the Company expanded the reporting of operations to comprise four segments. Exploration and production acitivities comprise the exploration, development, production and sale of natural gas and oil, extraction and sale of natural gas liquids and contract drilling. Natural gas marketing activities comprise marketing of natural gas, extraction and sale of natural gas liquids and intrastate transportation. Natural gas distribution activities comprise the operations of the Company's state- regulated natural gas utility. Natural gas transmission activities comprise gas transportation, gathering, storage and marketing activities involving the Company's three FERC-regulated gas pipelines.
The following table sets forth financial information for each of the business segments:
Years Ended December 31, 1994 1993 1992 (Thousands)
Operating Revenues: Exploration and production $ 195,795 $ 202,422 $ 191,478 Natural gas marketing 890,778 599,624 314,626 Natural gas distribution 390,475 335,149 328,022 Natural gas transmission 116,769 188,882 203,401 Sales between segments (196,537) (231,283) (225,153) --------- --------- ---------- Total $1,397,280 $1,094,794 $ 812,374 ========= ========= ========== Operating Income: Exploration and production $ 30,843 $ 42,453 $ 36,348 Natural gas marketing 4,089 11,700 4,850 Natural gas distribution 43,180 45,714 51,372 Natural gas transmission 32,136 30,630 21,856 --------- --------- --------- Total $ 110,248 $ 130,497 $ 114,426 ========= ========= ========= Identifiable Assets: Exploration and production $ 724,144 $ 699,322 $ 666,924 Natural gas marketing 396,166 386,040 33,092 Natural gas distribution 690,068 660,889 610,830 Natural gas transmission 297,140 302,102 278,109 Eliminations (88,396) (101,446) (120,531) --------- --------- --------- Total $2,019,122 $1,946,907 $1,468,424 ========= ========= =========
Depreciation and Depletion: Exploration and production $ 57,196 $ 47,645 $ 45,569 Natural gas marketing 11,702 5,778 69 Natural gas distribution 15,196 14,624 12,425 Natural gas transmission 9,253 8,847 7,877 --------- --------- --------- Total $ 93,347 $ 76,894 $ 65,940 ========= ========= ========= Capital Expenditures: Exploration and production $ 84,460 $ 101,203 $ 52,719 Natural gas marketing 15,765 195,042 204 Natural gas distribution 32,712 26,077 22,593 Natural gas transmission 13,237 17,089 24,073 --------- --------- --------- Total $ 146,174 $ 339,411 $ 99,589 ========= ========= =========
M. 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 any losses resulting from claims of liability under the 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 natural gas marketing segment and exploration and production segment, respectively. 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 million 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.
N. Commitments and Contingencies
Rent expense was $9.7 million in 1994, $9.8 million in 1993 and $9.3 million in 1992. Long-term leases are principally for division operating headquarters and warehouse buildings and computer hardware and have renewal options ranging to 19 years from December 31, 1994. Future minimum rentals for all noncancelable long-term leases at December 31, 1994 are as follows: 1995, $5.9 million; 1996, $5.3 million; 1997, $4.6 million; 1998, $3.2 million; 1999, $2.6 million, and $15.7 million thereafter for a total of $37.3 million.
The Company has annual commitments of approximately $31 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to 8 years at December 31, 1994, which relate to gas distribution operations. 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. The estimated costs associated with identified situations that require remedial action are accrued.
However, certain of these costs are deferred as regulatory assets when recoverable through regulated rates. 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 and 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 M.
March June September December 31 30 30 31 (Thousands except per share amounts)
Operating revenues $439,538 $316,122 $297,712 $343,908 Operating income 60,979 10,054 12,847 26,368 Net income 36,359 6,057 2,381 15,932 Earnings per share $1.05 $.18 $.07 $.46
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
P. Natural Gas and Oil Producing Activities
The supplementary information summarized below presents the results of natural gas and oil activities for the exploration and production segment in accordance with Statement of Financial Accounting Standards 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 percent of total Company proved reserves for the years presented.
(1) Production Costs
The following table presents the costs incurred relating to natural gas and oil production activities:
1994 1993 1992 (Thousands) At December 31: Capitalized costs. . . . . $909,443 $836,638 $748,325 Accumulated depreciation and depletion . . . . 304,835 256,508 216,005 ------- ------- ------- Net capitalized costs. . . . $604,608 $580,130 $532,320 ======= ======= ======= Costs incurred : Property acquisition . .. $ 8,335 $ 29,345 $ 663 Exploration. . . . . . . . 22,783 13,928 13,166 Development. . . . . . . . 60,690 62,336 46,321
(2) Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas and oil production:
1994 1993 1992 (Thousands)
Revenues: Affiliated . . . . . . . .$ 16,564 $ 15,467 $ 8,964 Nonaffiliated . . . . . . 136,029 140,380 127,369 Production costs . . . . . . 33,891 33,620 30,385 Exploration expenses . . . . 16,634 13,559 16,439 Depreciation and depletion . 52,505 43,841 40,744 Income tax expense . . . . . 3,602 5,039 5,221 ------- ------- ------- Results of operations from producing activities (excluding corporate overhead). . . . . . . . .$ 45,961 $ 59,788 $ 43,544 ======= ======= =======
(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 1994 1993 1992 (Millions of Cubic Feet)
Proved developed and undeveloped reserves: Beginning of year. . . . . . . 822,583 720,032 695,898 Revision of previous estimates. 18,663 9,399 25,736 Purchase of natural gas in place - net (a) . . . . . 6,307 86,113 434 Extensions, discoveries and other additions. . . . . . . 89,918 60,589 46,207 Production . . . . . . . . . . (62,507) (53,550) (48,243) ------- ------- ------- End of year (b). . . . . . . . 874,964 822,583 720,032 ======= ======= ======= Proved developed reserves: Beginning of year. . . . . . . 759,282 665,194 621,846
End of year (c). . . . . . . . 771,635 759,282 665,194
(a) Includes purchases in Canada of 68,000 Mmcf in 1993. (b) Includes proved reserves in Canada of 67,000 MMcf in 1994 and 70,000 MMcf in 1993. (c) Includes proved developed reserves in Canada of 43,000 MMcf in 1994 and 46,000 MMcf in 1993.
Oil 1994 1993 1992 (Thousands of Barrels)
Proved developed and undeveloped reserves: Beginning of year . . . . . 16,468 20,023 19,427 Revision of previous estimates 2,601 (4,876) 951 Purchase (sale) of oil in place - net (a) . . . . (169) 418 (138) Extensions, discoveries and other additions. . . . . . 1,369 3,015 2,189 Production. . . . . . . . . (1,986) (2,112) (2,406) ------ ------ ------ End of year (b) . . . . . . 18,283 16,468 20,023 ====== ====== ====== Proved developed reserves: Beginning of year . . . . . 16,442 18,540 17,072 End of year (c) . . . . . . 18,110 16,442 18,540
(a) Includes purchases in Canada of 68,000 barrels in 1993. (b) Includes proved reserves in Canada of 75,000 barrels in 1994 and 65,000 barrels in 1993. (c) Includes proved developed reserves in Canada of 50,000 barrels in 1994 and 39,000 barrels in 1993.
(4) Standard Measure of Discounted Future Cash Flow (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 percent. 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:
1994 1993 1992 (Thousands)
Future cash inflows . . . . $1,983,757 $2,140,151 $2,058,973 Future production costs . . (562,841) (598,707) (551,987) Future development costs. . (46,985) (24,579) (41,612) Future income tax expenses. (361,486) (434,362) (409,970) --------- --------- --------- Future net cash flow. . . . 1,012,445 1,082,503 1,055,404
10 percent annual discount for estimated timing of cash flows. . (471,778) (515,023) (507,082) --------- --------- --------- Standardized measure of discounted future net cash flows (a). . . $ 540,667 $ 567,480 $ 548,322 ========= ========= =========
(a) Includes $10,043,000 in 1994 and $31,267,000 in 1993 related to Canada.
Summary of changes in the standardized measure of discounted future net cash flows:
1994 1993 1992 (Thousands)
Sales and transfers of gas and oil produced - net. . $(118,702) $(122,227) $(105,948) Net changes in prices, production and development costs . . (135,742) (80,256) 11,370 Extensions, discoveries, and improved recovery, less related costs . . . . . 74,900 90,035 77,759 Development costs incurred. 16,037 18,482 27,807 Purchase (sale) of minerals in place - net . 9,627 62,843 (142) Revisions of previous quantity estimates. . . . 19,189 (14,910) 1,709 Accretion of discount . . . 72,058 69,284 62,548 Net change in income taxes. 45,012 (8,584) (21,093) Other . . (9,192) 4,491 (7,747) -------- ------- ------- Net increase (decrease) . . (26,813) 19,158 46,263 Beginning of year . . . . . 567,480 548,322 502,059 -------- ------- ------- End of year . . . . . . . . $ 540,667 $ 567,480 $ 548,322
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
PART III
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 26, 1995, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 1994.
Information required by Item 10 with respect to executive officers is included herein after Item 4 at the end of Part I.
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 26, 1995.
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 26, 1995.
Item 13. Certain Relationships and Related Transactions
Information required by Item 13 is incorporated herein by reference to the section describing "Certain Relationships and Related Transactions" in the Company's Definitive Proxy Statement relating to the annual meeting of stockholders to be held on May 26, 1995.
PART IV
Item 14. Exhibits and Reports on Form 8-K
(a) 1. Financial statements
The financial statements listed in the accompanying index to financial statements (page 52) are filed as part of this annual report.
2. Financial Statement Schedule
The financial statement schedule listed in the accompanying index to financial statements and financial schedule (page 53) is filed as part of this annual report.
3. Exhibits
The exhibits listed on the accompanying index to exhibits (pages 54 through 57) are filed as part of this annual report.
(b) Reports on Form 8-K filed during the quarter ended December 31, 1994.
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 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, 1994 25 Consolidated Balance Sheets December 31, 1994 and 1993 26 & 27 Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1994 28 Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1994 29 Long-term Debt, December 31, 1994 and 1993 30 Notes to Consolidated Financial Statements 31 thru 48
2. Schedule for the Years Ended December 31, 1994, 1993 and 1992 included in Part IV:
II - Valuation and Qualifying Accounts and Reserves 53
All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE THREE YEARS ENDED DECEMBER 31, 1994
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 $10,106 $10,010 $9,226(A) $10,890
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
Note:(A) Customer accounts written off, less recoveries.
2.01 (a)
Stock Purchase Agreement dated May 5, 1993 among Arkla, Inc., Arkla Finance Corporation and Equitable Pipeline Company for the purchase of Louisiana Intrastate Gas Company Filed as Exhibit 2.1 (a) to Form 8-K Dated
June 30, 1993
2.01 (b)
Schedule 4.1.11 to the Stock Purchase Agreement pertaining to outstanding litigation claims
Filed as Exhibit 2.1 (b) to Form 8-K Dated June 30, 1993
2.01 (c)
Schedule 4.1.15 to the Stock Purchase Agreement pertaining to environmental matters
Filed as Exhibit 2.1 (c) to Form 8-K Dated June 30, 1993
2.01 (d)
Letter Agreement Dated June 30, 1993 amending the Stock Purchase Agreement
Filed as Exhibit 2.1 (d) to Form 8-K Dated June 30, 1993
3.01
Restated Articles of Incorporation of the Company dated May 21, 1993 (effective May 27, 1993)
Filed as Exhibit 3.01 to Form 10-K for the year ended December 31, 1993.
3.02
By-Laws of the Company (amended through December 16, 1994)
Filed herewith as Exhibit 3.02
4.01 (a)
Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank relating to Debt Securities
Filed as Exhibit 4.01 (Revised) to Post- Effective Amendment No. 1 to Registration Statement (Registration No. 2-80575)
4.01 (b)
Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank
Filed as Exhibit 4.01 (b) to Form 10-K for the year ended December 31, 1993
4.01 (c)
Resolution adopted June 26, 1986 by the Finance Committee of the Board of Directors of the Company establishing the term of the $75,000,000 of debentures, 8 1/4% Series due July 1, 1996
Filed as Exhibit 4.01 (c) to Form 10-K for the year ended December 31, 1993
4.01 (d)
Resolutions adopted June 22, 1987 by the Finance Committee of the Board of Directors of the Company establishing the terms of the 75,000 units (debentures with warrants) issued July 1, 1987
Filed as Exhibit 4.01 (d) to Form 10-K for the year ended December 31, 1993
4.01 (e)
Resolution adopted April 6, 1988 by the Ad Hoc Finance Committee of the Board of Directors of the Company establishing the terms and provisions of the 9.9% Debentures issued April 14, 1988
Filed as Exhibit 4.01 (e) to Form 10-K for the year ended December 31, 1993
4.01 (f)
Supplemental indenture dated March 15, 1991 with Bankers Trust Company eliminating limitations on liens and additional funded debt
Filed as Exhibit 4.3 to Form S-3 (Registration Statement 33-39505) filed August 21, 1991
4.01 (g)
Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company Addenda Nos. 1 thru 27, establishing the terms and provisions of the Series A Medium-Term Notes
Filed as Exhibit 4.05 to Form 10-K for the year ended December 31, 1991
4.01 (h)
Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance 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
Filed as Exhibit 4.05 to Form 10-K for the year ended December 31, 1992
* 10.01
Equitable Resources, Inc. Key Employee Restricted Stock Option and Stock Appreciation Rights Incentive Compensation Plan (as amended through March 17, 1989)
Refiled herewith as Exhibit 10.01 pursuant to Rule 24 of SEC's Rules of Practice
* 10.02 (a)
Employment Agreement dated as of March 18, 1988 with Frederick H. Abrew
Filed as Exhibit 10.02 (a) to Form 10-K for the year ended December 31, 1993
* 10.02(b)
Amendment effective June 1, 1989 to Employment Agreement with Frederick H. Abrew
Filed as Exhibit 10.02 (b) to Form 10-K for the year ended December 31, 1993
* 10.03 (a)
Employment Agreement dated as of March 18, 1988 with Augustine A. Mazzei, Jr.
Filed as Exhibit 10.03 (a) to Form 10-K for the year ended December 31, 1993
* 10.03 (b)
Amendment effective June 1, 1989 to Employment Agreement with Augustine A. Mazzei, Jr.
Filed as Exhibit 10.03 (b) to Form 10-K for the year ended December 31, 1993
* 10.04 (a)
Agreement dated December 15, 1989 with Barbara B. Sullivan for deferred payment of 1990 director fees
Refiled herewith as Exhibit 10.04 (a) pursuant to Rule 24 of SEC's Rules of Practice
* 10.04 (b)
Agreement dated December 21, 1990 with Barbara B. Sullivan for deferred payment of 1991 director fees
Filed as Exhibit 10.16 to Form 10-K for the year ended December 31, 1990
* 10.04 (c)
Agreement dated December 13, 1991 with Barbara B. Sullivan for deferred payment of 1992 director fees
Filed as Exhibit 10.16 to Form 10-K for the year ended December 31, 1991
* 10.04 (d)
Agreement dated December 28, 1993 with Barbara B. Sullivan for deferred payment of 1994 director fees
Filed as Exhibit 10.04 (d) to Form 10-K for the year ended December 31, 1993
* 10.04 (e)
Agreement dated December 16, 1994 with Barbara B. Sullivan for deferred payment of 1995 director fees
Filed herewith as Exhibit 10.04 (e)
* 10.05
Supplemental Executive Retirement Plan (as amended and restated through December 16, 1994)
Filed herewith as Exhibit 10.05
* 10.06
Retirement Program for the Board of Directors of Equitable Resources, Inc. (as amended through August 1, 1989)
Refiled herewith as Exhibit 10.06 pursuant to Rule 24 of SEC's Rules of Practice
* 10.07
Supplemental Pension Plan (as amended and restated through December 16, 1994)
Filed herewith as Exhibit 10.07
* 10.08
Policy to Grant Supplemental Deferred Compensation Benefits in Selected Instances to a Select Group of Management or Highly Compensated Employees (as amended and restated through August 1, 1989)
Refiled herewith as Exhibit 10.08 pursuant to Rule 24 of SEC's Rules of Practice
* 10.09 (a)
Equitable Resources, Inc. and Subsidiaries Short-Term Incentive Compensation Plan dated January 18, 1988
Refiled herewith as Exhibit 10.09 pursuant to Rule 24 of SEC's Rules of Practice
* 10.09 (b)
Amendment dated February 17, 1993 to Equitable Resources, Inc. and Subsidiaries Short-Term Incentive Compensation Plan
Filed as Exhibit 10.22 to Form 10-K for the year ended December 31, 1992
* 10.10 (a)
Agreement dated December 31, 1987 with Malcolm M. Prine for deferred payment of 1988 director fees
Filed as Exhibit 10.10 (a) to Form 10-K for the year ended December 31, 1993
* 10.10 (b)
Agreement dated December 30, 1988 with Malcolm M. Prine for deferred payment of 1989 director fees
Filed as Exhibit 10.10 (b) to Form 10-K for the year ended December 31, 1993
* 10.11 (a)
Agreement dated September 30, 1986 with Daniel M. Rooney for deferred payment of 1986 and 1987 director fees
Filed as Exhibit 10.11 (a) to Form 10-K for the year ended December 31, 1993
* 10.11 (b)
Agreement dated December 21, 1987 with Daniel M. Rooney for deferred payment of 1988 director fees
Filed as Exhibit 10.11 (b) to Form 10-K for the year ended December 31, 1993
* 10.11 (c)
Agreement dated December 30, 1988 with Daniel M. Rooney for deferred payment of 1989 director fees
Filed as Exhibit 10.11 (c) to Form 10-K for the year ended December 31, 1993
* 10.11 (d)
Agreement dated December 15, 1989 with Daniel M. Rooney for deferred payment of 1990 director fees
Refiled herewith as Exhibit 10.11 (d) pursuant to Rule 24 of SEC's Rules of Practice
* 10.11 (e)
Agreement dated December 21, 1990 with Daniel M. Rooney for deferred payment of 1991 director fees
Filed as Exhibit 10.27 to Form 10-K for the year ended December 31, 1990
* 10.11 (f)
Agreement dated December 13, 1991 with Daniel M. Rooney for deferred payment of 1992 director fees
Filed as Exhibit 10.27 to Form 10-K for the year ended December 31, 1991
* 10.11 (g)
Agreement dated December 18, 1992 with Daniel M. Rooney for deferred payment of 1993 director fees
Filed as Exhibit 10.27 to Form 10-K for the year ended December 31, 1992
* 10.11 (h)
Agreement dated December 14, 1993 with Daniel M. Rooney for deferred payment of 1994 director fees
Filed as Exhibit 10.11 (h) to Form 10-K for the year ended December 31, 1993
* 10.11 (i)
Agreement dated December 15, 1994 with Daniel M. Rooney for deferred payment of 1995 director fees
Filed herewith as Exhibit 10.11 (i)
10.12
Trust Agreement with Pittsburgh National Bank to act as Trustee for Supplemental Pension Plan, Supplemental Deferred Compensation Benefits, Retirement Program for Board of Directors, and Supplemental Executive Retirement Plan
Refiled herewith as Exhibit 10.12 pursuant to Rule 24 of SEC's Rules of Practice
* 10.13
Equitable Resources, Inc. Non-Employee Directors' Stock Incentive Plan
Filed herewith as Exhibit 10.13
* 10.14
Equitable Resources, Inc. Long-Term Incentive Plan
Filed herewith as Exhibit 10.14
* 10.15
Agreement dated December 31, 1994 with Donald I. Moritz for consulting services
Filed herewith as Exhibit 10.15
11.01 Statement re Computation of Earnings Per Share Filed herewith as Exhibit 11.01
Schedule of Subsidiaries Filed herewith as Exhibit 21
23.01 Consent of Independent Auditors Filed herewith as Exhibit 23.01
99.01 Equitable Resources, Inc. Employees Savings Plan Form 11-K Annual Report Filed herewith as Exhibit 99.01
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: (Frederick H. Abrew) President and Chief Executive Officer
Date: March 17, 1995
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.
President and Chief Executive Officer and Director s/ Frederick H. Abrew (Principal Executive Officer) March 17, 1995 Frederick H. Abrew
Vice President and s/ A. Mark Abramovic Chief Financial Officer March 17, 1995 A. Mark Abramovic
Vice President - Accounting and Administration s/ Joseph L. Giebel (Chief Accounting Officer) March 17, 1995 Joseph L. Giebel
s/ Clifford L. Alexander, Jr. Director March 17, 1995 Clifford L. Alexander, Jr.
s/ Merle E. Gilliand Director March 17, 1995 Merle E. Gilliand
s/ E. Lawrence Keyes, Jr. Director March 17, 1995 E. Lawrence Keyes, Jr.
s/ Thomas A. McConomy Director March 17, 1995 Thomas A. McConomy
s/ Donald I. Moritz Director March 17, 1995 Donald I. Moritz
s/ Malcolm M. Prine Director March 17, 1995 Malcolm M. Prine
Director Daniel M. Rooney
s/ David S. Shapira Director March 17, 1995 David S. Shapira
s/ Barbara Boyle Sullivan Director March 17, 1995 Barbara Boyle Sullivan
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
Equitable's consolidated net income for 1994 was $60.7 million or $1.76 per share, compared with $73.5 million or $2.27 per share for 1993, and $60.0 million or $1.92 per share for 1992.
While natural gas production reached a record high for 1994, an increase of 17 percent over 1993, income was adversely impacted by a 13 percent decline in average wellhead prices for natural gas, increased operating and interest expense, and lower margins from the Company's Louisiana Intrastate Gas subsidiary. 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 natural gas distribution and transmission 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.
RESULTS OF OPERATIONS
Beginning in 1994, the Company expanded the reporting of operations to comprise four segments--Exploration and Production, Natural Gas Marketing, Natural Gas Distribution and Natural Gas Transmission. This discussion supplements the detailed financial information by business segment presented in Note L to the consolidated financial statements.
EXPLORATION AND PRODUCTION
Operating revenues, which are derived primarily from the sale of produced natural gas, oil and natural gas liquids and from contract drilling, were $195.8 million in 1994 compared with $202.4 million in 1993 and $191.5 million in 1992. The decrease in revenues for 1994 compared to 1993 is due primarily to lower wellhead prices for natural gas and oil, and lower selling prices and production of natural gas liquids which were partially offset by increased gas production. The increase in revenues for 1993 compared to 1992 is due primarily to increases in average wellhead prices and production of natural gas.
Exploration and Production 1994 1993 1992
Operating Revenues (thousands): Natural Gas . . . . . . . . . $121,810 $119,746 $ 90,886 Oil . . . . . . . . . . . 29,239 34,176 43,469 Natural Gas Liquids . . . . . 15,244 19,545 21,256 Contract Drilling . . . . . . 15,427 14,611 19,924 Direct Billing Settlements. . 7,815 7,815 7,815 Other . 6,260 6,529 8,128 ------- ------- ------- Total Revenues . . . . $195,795 $202,422 $191,478 ======= ======= ======= Sales Quantities: Natural Gas (MMcf). . . . . . 62,507 53,550 48,243 Oil (MBls). . . . . . . . . . 1,986 2,112 2,406 Natural Gas Liquids (thousands of gallons) . . . . . . . . 51,032 60,973 64,938
Gas purchased amounted to $10.6 million in 1994 compared with $17.0 million in 1993 and $15.3 million in 1992. The decrease in gas purchased for 1994 compared to 1993 is due to the lower requirements attributed to decreased production of natural gas liquids. The increase in gas purchased for 1993 compared to 1992 is due to higher costs for purchased gas.
Other operating expenses were $154.4 million in 1994, $142.9 million in 1993, and $139.8 million in 1992. Increases for the respective years are attributed to increased production expenses and depreciation and depletion related to the higher level of natural gas production.
Operating income was $30.8 million in 1994, $42.5 million in 1993, and $36.4 million in 1992. The decrease in operating income for 1994 compared to 1993 reflects lower wellhead prices for natural gas and oil, and lower selling prices and production of natural gas liquids which were partially offset by increased gas production. The increase in operating income for 1993 compared to 1992 reflects primarily the increase in average wellhead prices and production of natural gas.
Average wellhead natural gas prices for 1994 decreased 13 percent from the 1993 level, which was the highest level that had been experienced since 1988. Thus far in 1995, the wellhead prices have shown little sign of improving. Prices for oil and natural gas liquids continued the decline that began as far back as 1991. Natural gas production continued to increase in 1994 reflecting the on-going development of Appalachian properties, which are the foundation of the segment's activities, as well as expansion in the off-shore Gulf Coast area.
The 1995 capital expenditure program of $71.0 million for exploration and production includes $15.4 million for development of Appalachian holdings, $18.3 million for the Rocky Mountain area, $32.3 million for off-shore drilling in the Gulf of Mexico, and $2.7 million for exploration in South America. Market and price trends will continue to be the principal factors for the economic justification of drilling investments under the 1995 program.
NATURAL GAS MARKETING
Operating revenues, which are derived primarily from the marketing of natural gas, sale of produced natural gas liquids, and intrastate transportation of natural gas in Louisiana, were $890.8 million in 1994 compared with $599.6 million in 1993 and $314.6 million in 1992. The increase in revenues between the years is attributed primarily to the acquisition of Louisiana Intrastate Gas Company (LIG) on June 30, 1993, as more fully described in Note M to the consolidated financial statements.
Natural Gas Marketing 1994 1993 1992
Operating Revenues (thousands): Natural Gas Marketing . . . . $830,082 $565,605 $ 314,276 Natural Gas Liquids . . . . . 51,113 27,576 -- Transportation. . . . . . . . 9,266 6,247 -- Other . 317 196 350 ------- ------- ------- Total Revenues . . . . $890,778 $599,624 $314,626 ======= ======= ======= Sales Quantities: Marketed Natural Gas (MMcf) . 429,651 253,516 162,135 Natural Gas Liquids (thousands of gallons) . . . . . . . . 194,493 101,218 --
Gas purchased amounted to $857.4 million in 1994 compared with $575.7 million in 1993 and $305.9 million in 1992. The increased cost between the years reflects the increase in volume of marketed natural gas and requirements for the higher production levels of natural gas liquids.
Other operating expenses were $29.3 million in 1994, $12.2 million in 1993, and $3.8 million in 1992. Increases for the respective years reflect the acquisition of LIG.
Operating income was $4.1 million in 1994, $11.7 million in 1993, and $4.9 million in 1992. The decrease in operating income for 1994 compared to 1993 reflects lower prices for natural gas liquids. The increase in operating income for 1993 compared to 1992 reflects primarily the acquisition of LIG.
Gas marketing activities continued to expand during 1994. However, the impact of lower energy prices overshadowed the nearly seventy percent increase in marketed volumes. LIG, which contributed to the increase in marketed services, fell below profit expectations because of the substantial decline in liquids processing margins. This is attributed to the competitive pressure of lower oil prices during most of the year. Nevertheless, the acquisition of LIG has positioned the Company's marketing activities in the Gulf Coast area where it also has expanding exploration and production activities. The Company is developing gas storage and interchange facilities which will connect with the Henry Hub as well as LIG's system of pipelines, gas processing facilities, and multiple interconnections with major pipelines. This integration and expansion of services is the foundation for developing a Gulf Coast market center.
The 1995 capital expenditure program of $25.2 million for marketing operations includes $19.0 million for development of the gas storage system, $5.0 million for improvement of LIG's pipeline and gathering system, and $1.2 million for development of information systems to support the expanded services expected to be offered.
NATURAL GAS DISTRIBUTION
Operating revenues, which are derived from the sale and transportation of natural gas primarily to retail customers at state regulated rates, were $390.5 million in 1994 compared with $335.1 million in 1993 and $328.0 million in 1992. The increase in revenues for 1994 compared to 1993 is due primarily to higher retail rates to pass through increased purchased gas costs to customers, increased sales to utilities, and increased commercial and industrial sales reflecting some transportation customers switching service. The increase in revenues for 1993 compared to 1992 is due to the full-year impact of a retail rate increase for Pennsylvania customers, which went into , effect in July of 1992 offset by lower retail rates to pass through decreased purchased gas costs to customers.
Natural Gas Distribution 1994 1993 1992
Operating Revenues (thousands): Residential Gas Sales . . . . $265,356 $247,238 $241,331 Commercial Gas Sales. . . . . 66,956 59,057 59,386 Industrial and Utility Gas Sales . 31,853 8,017 4,593 Transportation Service. . . . 21,750 16,526 17,967 Other . 4,560 4,311 4,745 ------- ------- ------- Total Revenues. . . . . . . $390,475 $335,149 $328,022 ======= ======= ======= Sales Quantities (MMcf): Residential Gas Sales . . . . 29,570 29,980 30,089 Commercial Gas Sales. . . . 9,681 8,235 8,097 Industrial and Utility Gas Sales 12,855 1,767 721 Transportation Deliveries . . 8,611 10,986 13,080 Heating Degree Days (Normal - 5,968). . . . . . 5,607 5,628 5,629
Gas purchased amounted to $232.9 million in 1994, $182.8 million in 1993, and $179.4 million in 1992. The increase in gas costs for 1994 compared to 1993 reflects the pass-through of higher costs in rates to retail customers and the increase in sales to commercial, industrial, and utility customers. The increase in gas costs for 1993 compared to 1992 reflects increased sales to commercial, industrial, and utility customers partially offset by the pass-through of lower costs in rates to retail customers.
Other operating expenses amounted to $114.4 million in 1994, $106.6 million in 1993, and $97.2 million in 1992. The increase between the years is due principally to increased labor, sales and marketing, distribution, and uncollectible account expenses.
Operating income was $43.2 million in 1994 compared with $45.7 million in 1993 and $51.4 million in 1992. The decrease in operating income between the years is due primarily to increased operating expenses, which more than offset the higher margins being realized.
The operating results of the distribution operations continue to be impacted by the effects of weather on gas sales, primarily to residential customers. However, increased sales to utility customers and the continuing expansion of new gas-using technologies such as co-generation, natural gas vehicles, and natural gas-fired cooling have served to retain system throughput. In addition, new services for customers, such as energy management, have helped to offset the effects of weather that continues to be warmer than normal.
The 1995 capital expenditure program of $25.1 million for distribution operations includes $17.1 million for the distribution system, $5.7 million for development of information systems and $2.3 million for other items.
NATURAL GAS TRANSMISSION
Operating revenues, which are derived from the interstate transportation, storage and sale of natural gas subject to federal regulation, and the marketing of natural gas, were $116.8 million in 1994 compared with $188.9 million in 1993 and $203.4 million in 1992. The decrease in revenues between the years reflects the effects of FERC Order 636 restructuring which took effect in the middle of 1993.
Natural Gas Transmission 1994 1993 1992
Operating Revenues (thousands): Industrial and Utility Gas Sales . . . $ 2,309 $114,867 $155,271 Marketed Gas Sales. . . . . . 21,244 10,200 -- Transportation Service. . . . 69,958 47,534 34,779 Storage Service . . . . . . . 16,993 10,014 6,693 Other . 6,265 6,267 6,658 ------- ------- ------- Total Revenues. . . . . . . $116,769 $188,882 $203,401 ======= ======= ======= Sales Quantities (MMcf): Industrial and Utility Gas Sales . . . 388 26,345 36,697 Marketed Gas Sales. . . . . . 9,131 4,052 -- Transportation Deliveries . . 123,472 88,550 79,015
Gas purchased amounted to $18.2 million in 1994, $95.9 million in 1993, and $127.4 million in 1992. The decrease in gas costs between the years reflects the elimination of pipeline gas sales pursuant to FERC Order 636 restructuring.
Other operating expenses amounted to $66.4 million in 1994, $62.3 million in 1993, and $54.0 million in 1992. The increase in expenses between the years is due primarily to provisions for possible refunds to customers.
Operating income was $32.2 million in 1994 compared with $30.7 million in 1993 and $22.0 million in 1992. The increase in operating income between the years is due primarily to the restructuring of tariff rates pursuant to FERC Order 636 whereby all fixed costs are now recovered in the demand portion of pipeline rates.
The 1995 capital expenditure program of $19.6 million for transmission operations includes $12.3 million for maintaining and expanding the transmission system, $4.0 million for expansion of gas storage facilities, and $3.3 million for other items.
CAPITAL RESOURCES AND LIQUIDITY
Operating Activities
Cash required for operations is impacted primarily by the seasonal nature of the Company's distribution 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. In addition, short- term loans are 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 its distribution and transmission plant and continuing development and expansion of its resource production activities. Such expenditures during 1994 were $146.2 million. A total of $140.9 million has been authorized for the 1995 capital expenditure program.
Short-term loans are also used as interim financing for a portion of capital expenditures. The Company expects to finance its 1995 capital expenditures with cash generated from operations and temporarily with short-term loans.
Capital expenditures, including acquisitions, totaled about $922 million during the five-year period ended December 31, 1994, of which 45 percent was financed from operations.
Financing Activities
The Company 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 2.99 percent to 6.80 percent during 1994. At December 31, 1994, $256.0 million of commercial paper and $13.3 million of bank loans were outstanding at an average interest rate of 5.94 percent. In January 1995, the Company established a five-year revolving Credit Agreement with a group of banks providing $500 million of available credit. The agreement requires a facility fee of one-tenth of one percent. Adequate credit is 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.
During the first quarter of 1994, the Company issued the remaining $43.5 million of Medium-Term Notes--Series B which were available under a shelf registration filed in March 1992 covering $100 million of medium-term notes. The Company filed a new shelf registration effective June 9, 1994, for the issuance of $100 million of Medium-Term Notes--Series C to be used to retire short-term loans. No Series C Notes have been issued.
Federal Income Tax Provisions
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 1994. 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, 1994, the Company has available $82.9 million of AMT credit carryforwards. The impact of AMT on future cash flow will depend on the level of taxable income. 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 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 as the related reserves are depleted. The credits recorded in 1994, 1993, and 1992 reduced the Company's federal income tax provisions by $16.4 million, $20.6 million, and $14.1 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 $6.5 million is accrued at December 31, 1994. The portion of amounts expensed through 1994 that have been deferred, pending recovery in future rates, and included in regulatory assets amounts to $3.5 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 costs generally do not affect results of operations due to regulatory procedures for purchased gas cost recovery in rates. The increase in refunds due customers reflects provisions for refund of a portion of Equitrans' current rates that are in effect subject to approval by the FERC.
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 24
Statements of Consolidated Income for each of the three years in the period ended December 31, 1994 25
Consolidated Balance Sheets December 31, 1994 and 1993 26 & 27
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1994 28
Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1994 29
Long-term Debt, December 31, 1994 and 1993 30
Notes to Consolidated Financial Statements 31 - 48
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, 1994 and 1993, 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, 1994. Our audits also included the financial statement schedule listed in the Index at Item 14(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Equitable Resources, Inc., and Subsidiaries at December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As described in Note E to the consolidated financial statements, the Company changed its method of accounting for postretirement benefits in 1993.
s/ Ernst & Young LLP Ernst & Young LLP
Pittsburgh, Pennsylvania February 13, 1995
EQUITABLE RESOURCES, INC. Notes to Consolidated Financial Statements December 31, 1994
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 percent 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 $.9 million in 1994, $1.0 million in 1993 and $1.3 million in 1992. 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 $2.1 million in 1994, $1.8 million in 1993 and $1.3 million in 1992.
(4) INVENTORIES: Inventories are stated at cost which is below market. Gas stored underground--current inventory is stated at cost under the average cost method. 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 Companies establish 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.
(6) DEFERRED PURCHASED GAS COST: Where permitted by regulatory authority under purchased gas adjustment clauses or similar tariff provisions, the Company defers the difference between purchased gas cost, less refunds, and the billing of such cost and amortizes 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) DERIVATIVE FINANCIAL INSTRUMENTS: The Company uses exchange- traded natural gas and crude oil futures contracts to hedge exposures to energy price changes. To qualify for hedge accounting, the Company must be exposed to energy price risk and the futures contracts must be designated and effective as hedges. Realized gains and losses on futures contracts which qualify as hedges of firm commitments or anticipated transactions are deferred and recognized in income when the hedged transactions occur. The Company also trades natural gas futures. Realized and unrealized gains and losses on such transactions are recorded in other income in the period in which the changes occur. Margin requirements on futures contracts are recorded in other current assets on the balance sheet.
(9) CASH FLOWS: The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
(10) RECLASSIFICATION: Certain amounts contained in prior year comparative information have been reclassified to conform with the 1994 presentation.
B. Direct Billing Settlements
Kentucky West Virginia Gas Company received FERC approval of settlement agreements with all customers for the direct billing to recover the higher Natural Gas Policy Act (NGPA) prices, which the FERC had denied on natural gas produced from exploration and production properties between 1978 and 1983. The portion of the settlement with the Equitable Gas Division has been subject to Pennsylvania Public Utility Commission (PUC) review. The PUC approved the recovery of $7.8 million relating to the settlement in each of the years 1992 to 1994, which increased net income reported for the third quarter of each year by $4.7 million. Approximately $42 million from the settlement remains to be recovered in future gas cost filings with the PUC over the next six years.
The settlement with Columbia Gas Transmission Company for the recovery of $19 million 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 following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities:
December 31, 1994 1993 (Thousands) Deferred tax liabilities (assets): Exploration and development costs expensed for income tax reporting . . . . $141,479 $138,089 Tax depreciation in excess of book depreciation . . . . . . . 255,683 250,032 Regulatory temporary differences . . 37,319 36,841 Deferred purchased gas cost. . . . . 6,397 8,413 Alternative minimum tax. . . . . . . (82,925) (69,333) Investment tax credit. . . . . . . . (9,306) (10,340) Other. . . . . . . . . . . . . . . . (17,606) (21,829) ------- ------- Total (including amounts classified as current liabilities of $4,444 for 1994 and $733 for 1993) . . $331,041 $331,873 ======= =======
As of December 31, 1994 and 1993, $76.2 million and $76.4 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, 1994 1993 1992 (Thousands)
Current: Federal. . . . . . . . . . $11,196 $15,577 $13,540 State. . . . . . . . . . . 2,640 3,687 7,245 Deferred: Federal. . . . . . . . . . (6,848) (2,758) (4,547) State. . . . . . . . . . . 1,789 3,514 2,532 ----- ------ ------ Total . . . . . . . . $ 8,777 $20,020 $18,770 ====== ====== ======
Provisions for income taxes are less than amounts computed at the federal statutory rate of 35 percent for 1994 and 1993, and 34 percent for 1992 on pretax income. The reasons for the difference are summarized as follows:
Years Ended December 31, 1994 1993 1992 (Thousands)
Tax at statutory rate . $ 24,327 $ 32,716 $ 26,791 State income taxes . . . 3,069 4,332 6,453 Increase in federal income tax rate. . . . - 5,070 - Nonconventional fuels tax credit . . . . . . (16,442) (20,600) (14,051) Other . (2,177) (1,498) (423) ------- ------- ------- Income tax expense . . $ 8,777 $ 20,020 $ 18,770 ======= ======= ======= Effective tax rate . . . 12.6 percent 21.4 percent 23.8 percent
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 percent. 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 $82.9 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 $14.9 million which begin to expire in 2006. The net operating loss carryforwards apply to Louisiana Intrastate Gas.
Amortization of deferred investment tax credits amounted to $1.1 million for 1994, $1.4 million for 1993 and $1.1 million for 1992.
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.
The following table sets forth the plans' funded status and amounts recognized in the Company's consolidated balance sheets:
December 31, 1994 1993 (Thousands)
Actuarial present value of benefit obligations: Vested benefit obligation $120,763 $132,402 ======= ======= Accumulated benefit obligation $123,877 $135,809 ======= ======= Market value of plan assets $143,121 $159,433 Projected benefit obligation 134,111 148,265 ------- ------- Excess of plan assets over projected benefit obligation 9,010 11,168 Unrecognized net asset (2,905) (3,237) Unrecognized net gain (15,606) (16,732) Unrecognized prior service cost 9,512 10,403 ------- ------- Prepaid pension cost recognized in the consolidated balance sheets $ 11 $ 1,602 ======= =======
At year-end the discount rate used in determining the actuarial present value of benefit obligations was 8 1/4 percent for 1994, 7 1/4 percent for 1993 and 8 1/4 percent for 1992. The assumed rate of increase in compensation levels was 4 1/2 percent for 1994 and 1993 and 5 percent for 1992.
The Companies' pension cost, using a 9 percent average rate of return on plan assets, comprised the following:
Years Ended December 31, 1994 1993 1992 (Thousands)
Service cost benefits earned during the period. $ 3,916 $ 2,806 $ 2,345 Interest cost on projected benefit obligation 10,752 10,472 9,917 Actual loss (return) on assets. . . . . 2,757 (17,224) (18,214) Net amortization and deferral. (14,680) 5,486 7,069 ------ ------ ------ Net periodic pension cost . . $ 2,745 $ 1,540 $ 1,117 ====== ====== ======
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. The Company's transition obligation is being amortized over 20 years. In determining the accumulated postretirement benefit obligation at December 31, 1994, the Company used a beginning inflation factor of 10 1/2 percent decreasing gradually to 4 3/4 percent after 15 years and a discount rate of 8 1/4 percent. At December 31, 1993, the beginning inflation factor was 11 percent decreasing gradually to 4 3/4 percent after 16 years and the discount rate was 7 1/4 percent. The following summarizes the status of the Company's accrued postretirement benefit costs (OPEBS):
December 31, 1994 1993 (Thousands) Accumulated postretirement benefit obligation: Retired employees. . . . . . . . . $ 21,269 $ 23,078 Active employees: Fully eligible . . . . . . . . . 9,158 8,942 Other. . . . . . . . . . . . . . 13,459 16,741 ------- ------- Total obligation . . . . . . . 43,886 48,761 Unrecognized net gain . . . . . . . 5,160 40 Unrecognized transition obligation. (41,501) (43,806) ------- ------- Accrued postretirement benefit cost . $ 7,545 $ 4,995 ======= =======
The net periodic cost for postretirement health care and life insurance benefits includes the following: Years Ended December 31, 1994 1993 (Thousands)
Service cost. . . . . . . . . . . . $1,049 $1,065 Interest cost . . . . . . . . . . . 3,423 3,936 Amortization of transition obligation. . . 2,305 2,306 ----- ----- Periodic cost. . . . . . . . . . . $6,777 $7,307 ===== =====
As of December 31, 1994 and 1993, $3.5 million and $2.9 million, respectively, of the accrued OPEBS related to rate regulated operations have been deferred as regulatory assets. Rate filings have been undertaken to seek recovery of accrued costs 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 7 percent and would increase the periodic cost by 8 percent.
The cost of OPEBS for 1992 was recognized as paid and amounted to $2.9 million.
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 M.
(2) Key Employee Restricted Stock Option Plan
The Equitable Resources, Inc., Key Employee Restricted Stock Option and Stock Appreciation Rights Incentive Compensation Plan is nonqualified and provided for the granting of restricted stock awards or options to purchase common stock of the Company at prices ranging from 75 percent to 100 percent of market value on the date of grant. 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.
The following schedule summarizes the stock option activity:
Years Ended December 31, 1994 1993 1992
Options outstanding January 1 . . 253,068 139,725 228,787 Granted . . . . . . . . . . . . . - 148,543 - Exercised . . . . . . . . . . . . (7,650) (33,325) (89,062) Canceled, forfeited, surrendered or expired . . . . . . . . . . . (3,600) (1,875) - ------- ------- ------- Options outstanding December 31 . 241,818 253,068 139,725 ======= ======= ======= Average price of options exercised during the year . . . $22.48 $18.97 $17.07 At December 31: Prices of options outstanding . $18.81 $17.50 $15.20 to to to $36.50 $36.50 $20.13
Average option price . . . . . . $29.82 $29.69 $19.76
Shares reserved for issuance . . 663,699 671,349 705,209
No future grants may be made under the Plan which was replaced by the Long-Term Incentive Plan effective May 27, 1994 as described below.
(3) Long-Term Incentive Plan
On May 27, 1994, shareholders approved the Equitable Resources, Inc. Long-Term Incentive Plan which provides for the granting of shares of common stock to officers and key employees of the Company. These grants may be made in the form of stock options, restricted stock, stock appreciation rights and other types of stock-based or performance-based awards as determined by the Compensation Committee of the Board of Directors at the time of each grant. Stock awarded under the Plan, or purchased through the exercise of options, and the value of stock appreciation units, are restricted and subject to forfeiture should an optionee terminate employment prior to specified vesting dates. The maximum number of shares which could have been granted under the Plan during 1994 was 763,500 shares. In each subsequent year, an additional number of shares equal to 1 percent of the total outstanding shares as of the preceding December 31 will be available for grant. In no case may the number of shares granted under the Plan exceed 1,725,500 shares. No awards may be made under the Plan after May 27, 1999. In May 1994, 363,400 stock options were granted to purchase common stock at $33.81 per share, which was the mean of the high and the low trading prices of the common stock on the date of grant. These options expire five years from the date of grant. At December 31, 1994, 1,725,500 shares of common stock were reserved for issuance under the Plan.
(4) Non-Employee Directors' Stock Incentive Plan
On May 27, 1994, shareholders approved the Equitable Resources, Inc. Non-Employee Directors' Stock Incentive Plan which provides for the granting of up to 80,000 shares of common stock in the form of stock option grants and restricted stock awards to non-employee directors of the Company. Each Director received 450 shares of restricted stock on February 3, 1994. On June 1, 1994, each director was granted an option for 500 shares of common stock at $34.625 per share. On the first business day of June, in each year from 1995 through 1998, each Director will be granted an option for 500 additional shares of common stock. The exercise price for each share is 100 percent of the mean of the high and the low trading prices of the common stock on the date of grant. Each option is exercisable upon the earlier of three years from the date of grant or a Director's retirement, disability or death. No option may be exercised more than five years after date of grant. At December 31, 1994, 76,400 shares of common stock were reserved for issuance under the Plan.
(5) Dividend Reinvestment and Stock Purchase Plan
Pursuant to this plan, stockholders may reinvest dividends and make limited additional cash investments to purchase shares of common stock. Shares issued through the Plan may be acquired on the open market or by issuance of previously unissued shares. At December 31, 1994, 194,183 shares of common stock were reserved for issuance under the Plan.
G. Short-Term Loans
Maximum lines of credit available to the Company were $325 million during 1994, $360 million during 1993 and $140 million during 1992. The Company is not required to maintain compensating bank balances. Commitment fees averaging one-tenth of one percent were paid to maintain credit availability. In January 1995, the Company established a five-year revolving Credit Agreement with a group of banks providing $500 million of available credit. The agreement requires a facility fee of one-tenth of one percent.
At December 31, 1994, short-term loans consisted of $256.0 million of commercial paper and $13.3 million of bank loans at a weighted average annual interest rate of 5.94 percent; and at December 31, 1993, $189.9 million and $64.0 million, respectively, at a weighted average annual interest rate of 3.30 percent. The maximum amount of outstanding short-term loans was $269.3 million in 1994, $339.0 million in 1993 and $130.5 million in 1992. The average daily total of short-term loans outstanding was approximately $204.6 million during 1994, $174.9 million during 1993 and $107.4 million during 1992; weighted average annual interest rates applicable thereto were 4.4 percent in 1994, 3.3 percent in 1993 and 3.8 percent in 1992.
H. Long-Term Debt
The Company filed a shelf registration with the Securities and Exchange Commission effective June 9, 1994 to issue $100 million of Medium-Term Notes--Series C to be used to retire short-term loans. No Series C Notes have been issued.
During the first quarter of 1994, the Company issued the remaining $43.5 million of Medium Term Notes--Series B under a shelf registration filed with the Securities and Exchange Commission in March 1992. The Series B Notes have maturity dates ranging from three to thirty years from date of issuance and a weighted average interest rate of 6.60 percent.
The 9 1/2 percent Convertible Subordinated Debentures are convertible at any time into common stock at a conversion price of $11.06 per share. During 1994, 1993 and 1992, $345,000, $564,000 and $259,000 of these debentures were converted into 31,187 shares, 50,983 shares and 23,399 shares of common stock, respectively. At December 31, 1994, 209,731 shares of common stock were reserved for conversions.
Interest expense on long-term debt amounted to $35.5 million in 1994, $33.2 million in 1993 and $31.9 million in 1992. Aggregate maturities of long-term debt will be $24.5 million in 1995, $75.0 million in 1996, none in 1997, $5.0 million in 1998 and $78.8 million in 1999.
I. Derivative Financial Instruments
The Company is exposed to risk from fluctuations in energy prices in the normal course of business. The Company uses exchange-traded energy futures contracts to hedge exposures to changes in energy prices, primarily relating to its gas marketing operations. The Company also trades in energy futures. Energy futures contracts are commitments to either purchase or sell a designated commodity, generally natural gas or crude oil, at a future date for a specified price and may be settled in cash or through delivery. The contracts used by the Company cover one-month periods from one to eighteen months in the future. Initial margin requirements are met in cash or other instruments, and changes in contract values are settled daily. Energy futures contracts have minimal credit risk because futures exchanges are the counterparties.
At December 31, 1994, natural gas futures contracts for the purchase of 10.8 Bcf and the sale of 3.7 Bcf were outstanding as hedges on future transactions. At December 31, 1994, deferrals related to hedging activities include realized losses of $.2 million and unrealized losses of $1.5 million.
At December 31, 1994, there were no outstanding energy futures contracts held for trading purposes. During 1994, the average fair value of traded contracts was $30,000 and a net gain of $1.5 million was realized. The value of these financial instruments is subject to fluctuations in market prices for natural gas and crude oil. Exposure to this risk is managed by maintaining open positions within defined trading limits.
J. 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.
The estimated fair value of long-term debt, including the portion due within one year, at December 31, 1994 and 1993 would be $430.2 million and $433.0 million, 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 percent Debentures and 7 1/2 percent Debentures may not be redeemed prior to maturity. The 9.9 percent Debentures require payment of premiums for early redemption, exclusive of annual sinking fund requirements.
The futures described in Note I are reflected in other current assets at fair value of $(1.5) million.
K. Concentrations of Credit Risk
Revenues and related accounts receivable from exploration and production operations are generated primarily from the sale of produced natural gas to utility and industrial customers located mainly in the Appalachian area; the sale of produced oil to refinery customers in the Rocky Mountain and Appalachian areas; and the sale of produced natural gas liquids to a refinery customer in Kentucky.
Natural gas marketing operating revenues and related accounts receivable are generated from the nationwide marketing of natural gas to brokers and large volume utility and industrial customers; and the sale of produced natural gas liquids and intrastate transportation of natural gas in Louisiana.
Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation 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.
Natural gas transmission operating revenues and related accounts receivable are generated from FERC-regulated interstate pipeline transportation and storage service for the affiliated utility, Equitable Gas, as well as other utility and end-user customers located in nine mid- Atlantic and northeastern states.
The Company is not aware of any significant credit risks which have not been recognized in provisions for doubtful accounts.
L. Financial Information by Business Segment
Beginning in 1994, the Company expanded the reporting of operations to comprise four segments. Exploration and production acitivities comprise the exploration, development, production and sale of natural gas and oil, extraction and sale of natural gas liquids and contract drilling. Natural gas marketing activities comprise marketing of natural gas, extraction and sale of natural gas liquids and intrastate transportation. Natural gas distribution activities comprise the operations of the Company's state- regulated natural gas utility. Natural gas transmission activities comprise gas transportation, gathering, storage and marketing activities involving the Company's three FERC-regulated gas pipelines.
The following table sets forth financial information for each of the business segments:
Years Ended December 31, 1994 1993 1992 (Thousands)
Operating Revenues: Exploration and production $ 195,795 $ 202,422 $ 191,478 Natural gas marketing 890,778 599,624 314,626 Natural gas distribution 390,475 335,149 328,022 Natural gas transmission 116,769 188,882 203,401 Sales between segments (196,537) (231,283) (225,153) --------- --------- ---------- Total $1,397,280 $1,094,794 $ 812,374 ========= ========= ========== Operating Income: Exploration and production $ 30,843 $ 42,453 $ 36,348 Natural gas marketing 4,089 11,700 4,850 Natural gas distribution 43,180 45,714 51,372 Natural gas transmission 32,136 30,630 21,856 --------- --------- --------- Total $ 110,248 $ 130,497 $ 114,426 ========= ========= ========= Identifiable Assets: Exploration and production $ 724,144 $ 699,322 $ 666,924 Natural gas marketing 396,166 386,040 33,092 Natural gas distribution 690,068 660,889 610,830 Natural gas transmission 297,140 302,102 278,109 Eliminations (88,396) (101,446) (120,531) --------- --------- --------- Total $2,019,122 $1,946,907 $1,468,424 ========= ========= =========
Depreciation and Depletion: Exploration and production $ 57,196 $ 47,645 $ 45,569 Natural gas marketing 11,702 5,778 69 Natural gas distribution 15,196 14,624 12,425 Natural gas transmission 9,253 8,847 7,877 --------- --------- --------- Total $ 93,347 $ 76,894 $ 65,940 ========= ========= ========= Capital Expenditures: Exploration and production $ 84,460 $ 101,203 $ 52,719 Natural gas marketing 15,765 195,042 204 Natural gas distribution 32,712 26,077 22,593 Natural gas transmission 13,237 17,089 24,073 --------- --------- --------- Total $ 146,174 $ 339,411 $ 99,589 ========= ========= =========
M. 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 any losses resulting from claims of liability under the 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 natural gas marketing segment and exploration and production segment, respectively. 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 million 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.
N. Commitments and Contingencies
Rent expense was $9.7 million in 1994, $9.8 million in 1993 and $9.3 million in 1992. Long-term leases are principally for division operating headquarters and warehouse buildings and computer hardware and have renewal options ranging to 19 years from December 31, 1994. Future minimum rentals for all noncancelable long-term leases at December 31, 1994 are as follows: 1995, $5.9 million; 1996, $5.3 million; 1997, $4.6 million; 1998, $3.2 million; 1999, $2.6 million, and $15.7 million thereafter for a total of $37.3 million.
The Company has annual commitments of approximately $31 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to 8 years at December 31, 1994, which relate to gas distribution operations. 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. The estimated costs associated with identified situations that require remedial action are accrued.
However, certain of these costs are deferred as regulatory assets when recoverable through regulated rates. 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 and 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 M.
March June September December 31 30 30 31 (Thousands except per share amounts)
Operating revenues $439,538 $316,122 $297,712 $343,908 Operating income 60,979 10,054 12,847 26,368 Net income 36,359 6,057 2,381 15,932 Earnings per share $1.05 $.18 $.07 $.46
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
P. Natural Gas and Oil Producing Activities
The supplementary information summarized below presents the results of natural gas and oil activities for the exploration and production segment in accordance with Statement of Financial Accounting Standards 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 percent of total Company proved reserves for the years presented.
(1) Production Costs
The following table presents the costs incurred relating to natural gas and oil production activities:
1994 1993 1992 (Thousands) At December 31: Capitalized costs. . . . . $909,443 $836,638 $748,325 Accumulated depreciation and depletion . . . . 304,835 256,508 216,005 ------- ------- ------- Net capitalized costs. . . . $604,608 $580,130 $532,320 ======= ======= ======= Costs incurred : Property acquisition . .. $ 8,335 $ 29,345 $ 663 Exploration. . . . . . . . 22,783 13,928 13,166 Development. . . . . . . . 60,690 62,336 46,321
(2) Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas and oil production:
1994 1993 1992 (Thousands)
Revenues: Affiliated . . . . . . . .$ 16,564 $ 15,467 $ 8,964 Nonaffiliated . . . . . . 136,029 140,380 127,369 Production costs . . . . . . 33,891 33,620 30,385 Exploration expenses . . . . 16,634 13,559 16,439 Depreciation and depletion . 52,505 43,841 40,744 Income tax expense . . . . . 3,602 5,039 5,221 ------- ------- ------- Results of operations from producing activities (excluding corporate overhead). . . . . . . . .$ 45,961 $ 59,788 $ 43,544 ======= ======= =======
(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 1994 1993 1992 (Millions of Cubic Feet)
Proved developed and undeveloped reserves: Beginning of year. . . . . . . 822,583 720,032 695,898 Revision of previous estimates. 18,663 9,399 25,736 Purchase of natural gas in place - net (a) . . . . . 6,307 86,113 434 Extensions, discoveries and other additions. . . . . . . 89,918 60,589 46,207 Production . . . . . . . . . . (62,507) (53,550) (48,243) ------- ------- ------- End of year (b). . . . . . . . 874,964 822,583 720,032 ======= ======= ======= Proved developed reserves: Beginning of year. . . . . . . 759,282 665,194 621,846
End of year (c). . . . . . . . 771,635 759,282 665,194
(a) Includes purchases in Canada of 68,000 Mmcf in 1993. (b) Includes proved reserves in Canada of 67,000 MMcf in 1994 and 70,000 MMcf in 1993. (c) Includes proved developed reserves in Canada of 43,000 MMcf in 1994 and 46,000 MMcf in 1993.
Oil 1994 1993 1992 (Thousands of Barrels)
Proved developed and undeveloped reserves: Beginning of year . . . . . 16,468 20,023 19,427 Revision of previous estimates 2,601 (4,876) 951 Purchase (sale) of oil in place - net (a) . . . . (169) 418 (138) Extensions, discoveries and other additions. . . . . . 1,369 3,015 2,189 Production. . . . . . . . . (1,986) (2,112) (2,406) ------ ------ ------ End of year (b) . . . . . . 18,283 16,468 20,023 ====== ====== ====== Proved developed reserves: Beginning of year . . . . . 16,442 18,540 17,072 End of year (c) . . . . . . 18,110 16,442 18,540
(a) Includes purchases in Canada of 68,000 barrels in 1993. (b) Includes proved reserves in Canada of 75,000 barrels in 1994 and 65,000 barrels in 1993. (c) Includes proved developed reserves in Canada of 50,000 barrels in 1994 and 39,000 barrels in 1993.
(4) Standard Measure of Discounted Future Cash Flow (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 percent. 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:
1994 1993 1992 (Thousands)
Future cash inflows . . . . $1,983,757 $2,140,151 $2,058,973 Future production costs . . (562,841) (598,707) (551,987) Future development costs. . (46,985) (24,579) (41,612) Future income tax expenses. (361,486) (434,362) (409,970) --------- --------- --------- Future net cash flow. . . . 1,012,445 1,082,503 1,055,404
10 percent annual discount for estimated timing of cash flows. . (471,778) (515,023) (507,082) --------- --------- --------- Standardized measure of discounted future net cash flows (a). . . $ 540,667 $ 567,480 $ 548,322 ========= ========= =========
(a) Includes $10,043,000 in 1994 and $31,267,000 in 1993 related to Canada.
Summary of changes in the standardized measure of discounted future net cash flows:
1994 1993 1992 (Thousands)
Sales and transfers of gas and oil produced - net. . $(118,702) $(122,227) $(105,948) Net changes in prices, production and development costs . . (135,742) (80,256) 11,370 Extensions, discoveries, and improved recovery, less related costs . . . . . 74,900 90,035 77,759 Development costs incurred. 16,037 18,482 27,807 Purchase (sale) of minerals in place - net . 9,627 62,843 (142) Revisions of previous quantity estimates. . . . 19,189 (14,910) 1,709 Accretion of discount . . . 72,058 69,284 62,548 Net change in income taxes. 45,012 (8,584) (21,093) Other . . (9,192) 4,491 (7,747) -------- ------- ------- Net increase (decrease) . . (26,813) 19,158 46,263 Beginning of year . . . . . 567,480 548,322 502,059 -------- ------- ------- End of year . . . . . . . . $ 540,667 $ 567,480 $ 548,322
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 26, 1995, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 1994.
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 26, 1995.
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 26, 1995.
Item 13.
Item 13. Certain Relationships and Related Transactions
Information required by Item 13 is incorporated herein by reference to the section describing "Certain Relationships and Related Transactions" in the Company's Definitive Proxy Statement relating to the annual meeting of stockholders to be held on May 26, 1995.
PART IV
Item 14.
Item 14. Exhibits and Reports on Form 8-K
(a) 1. Financial statements
The financial statements listed in the accompanying index to financial statements (page 52) are filed as part of this annual report.
2. Financial Statement Schedule
The financial statement schedule listed in the accompanying index to financial statements and financial schedule (page 53) is filed as part of this annual report.
3. Exhibits
The exhibits listed on the accompanying index to exhibits (pages 54 through 57) are filed as part of this annual report.
(b) Reports on Form 8-K filed during the quarter ended December 31, 1994.
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 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, 1994 25 Consolidated Balance Sheets December 31, 1994 and 1993 26 & 27 Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1994 28 Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1994 29 Long-term Debt, December 31, 1994 and 1993 30 Notes to Consolidated Financial Statements 31 thru 48
2. Schedule for the Years Ended December 31, 1994, 1993 and 1992 included in Part IV:
II - Valuation and Qualifying Accounts and Reserves 53
All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE THREE YEARS ENDED DECEMBER 31, 1994
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 $10,106 $10,010 $9,226(A) $10,890
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
Note:(A) Customer accounts written off, less recoveries.
2.01 (a)
Stock Purchase Agreement dated May 5, 1993 among Arkla, Inc., Arkla Finance Corporation and Equitable Pipeline Company for the purchase of Louisiana Intrastate Gas Company Filed as Exhibit 2.1 (a) to Form 8-K Dated
June 30, 1993
2.01 (b)
Schedule 4.1.11 to the Stock Purchase Agreement pertaining to outstanding litigation claims
Filed as Exhibit 2.1 (b) to Form 8-K Dated June 30, 1993
2.01 (c)
Schedule 4.1.15 to the Stock Purchase Agreement pertaining to environmental matters
Filed as Exhibit 2.1 (c) to Form 8-K Dated June 30, 1993
2.01 (d)
Letter Agreement Dated June 30, 1993 amending the Stock Purchase Agreement
Filed as Exhibit 2.1 (d) to Form 8-K Dated June 30, 1993
3.01
Restated Articles of Incorporation of the Company dated May 21, 1993 (effective May 27, 1993)
Filed as Exhibit 3.01 to Form 10-K for the year ended December 31, 1993.
3.02
By-Laws of the Company (amended through December 16, 1994)
Filed herewith as Exhibit 3.02
4.01 (a)
Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank relating to Debt Securities
Filed as Exhibit 4.01 (Revised) to Post- Effective Amendment No. 1 to Registration Statement (Registration No. 2-80575)
4.01 (b)
Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank
Filed as Exhibit 4.01 (b) to Form 10-K for the year ended December 31, 1993
4.01 (c)
Resolution adopted June 26, 1986 by the Finance Committee of the Board of Directors of the Company establishing the term of the $75,000,000 of debentures, 8 1/4% Series due July 1, 1996
Filed as Exhibit 4.01 (c) to Form 10-K for the year ended December 31, 1993
4.01 (d)
Resolutions adopted June 22, 1987 by the Finance Committee of the Board of Directors of the Company establishing the terms of the 75,000 units (debentures with warrants) issued July 1, 1987
Filed as Exhibit 4.01 (d) to Form 10-K for the year ended December 31, 1993
4.01 (e)
Resolution adopted April 6, 1988 by the Ad Hoc Finance Committee of the Board of Directors of the Company establishing the terms and provisions of the 9.9% Debentures issued April 14, 1988
Filed as Exhibit 4.01 (e) to Form 10-K for the year ended December 31, 1993
4.01 (f)
Supplemental indenture dated March 15, 1991 with Bankers Trust Company eliminating limitations on liens and additional funded debt
Filed as Exhibit 4.3 to Form S-3 (Registration Statement 33-39505) filed August 21, 1991
4.01 (g)
Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company Addenda Nos. 1 thru 27, establishing the terms and provisions of the Series A Medium-Term Notes
Filed as Exhibit 4.05 to Form 10-K for the year ended December 31, 1991
4.01 (h)
Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance 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
Filed as Exhibit 4.05 to Form 10-K for the year ended December 31, 1992
* 10.01
Equitable Resources, Inc. Key Employee Restricted Stock Option and Stock Appreciation Rights Incentive Compensation Plan (as amended through March 17, 1989)
Refiled herewith as Exhibit 10.01 pursuant to Rule 24 of SEC's Rules of Practice
* 10.02 (a)
Employment Agreement dated as of March 18, 1988 with Frederick H. Abrew
Filed as Exhibit 10.02 (a) to Form 10-K for the year ended December 31, 1993
* 10.02(b)
Amendment effective June 1, 1989 to Employment Agreement with Frederick H. Abrew
Filed as Exhibit 10.02 (b) to Form 10-K for the year ended December 31, 1993
* 10.03 (a)
Employment Agreement dated as of March 18, 1988 with Augustine A. Mazzei, Jr.
Filed as Exhibit 10.03 (a) to Form 10-K for the year ended December 31, 1993
* 10.03 (b)
Amendment effective June 1, 1989 to Employment Agreement with Augustine A. Mazzei, Jr.
Filed as Exhibit 10.03 (b) to Form 10-K for the year ended December 31, 1993
* 10.04 (a)
Agreement dated December 15, 1989 with Barbara B. Sullivan for deferred payment of 1990 director fees
Refiled herewith as Exhibit 10.04 (a) pursuant to Rule 24 of SEC's Rules of Practice
* 10.04 (b)
Agreement dated December 21, 1990 with Barbara B. Sullivan for deferred payment of 1991 director fees
Filed as Exhibit 10.16 to Form 10-K for the year ended December 31, 1990
* 10.04 (c)
Agreement dated December 13, 1991 with Barbara B. Sullivan for deferred payment of 1992 director fees
Filed as Exhibit 10.16 to Form 10-K for the year ended December 31, 1991
* 10.04 (d)
Agreement dated December 28, 1993 with Barbara B. Sullivan for deferred payment of 1994 director fees
Filed as Exhibit 10.04 (d) to Form 10-K for the year ended December 31, 1993
* 10.04 (e)
Agreement dated December 16, 1994 with Barbara B. Sullivan for deferred payment of 1995 director fees
Filed herewith as Exhibit 10.04 (e)
* 10.05
Supplemental Executive Retirement Plan (as amended and restated through December 16, 1994)
Filed herewith as Exhibit 10.05
* 10.06
Retirement Program for the Board of Directors of Equitable Resources, Inc. (as amended through August 1, 1989)
Refiled herewith as Exhibit 10.06 pursuant to Rule 24 of SEC's Rules of Practice
* 10.07
Supplemental Pension Plan (as amended and restated through December 16, 1994)
Filed herewith as Exhibit 10.07
* 10.08
Policy to Grant Supplemental Deferred Compensation Benefits in Selected Instances to a Select Group of Management or Highly Compensated Employees (as amended and restated through August 1, 1989)
Refiled herewith as Exhibit 10.08 pursuant to Rule 24 of SEC's Rules of Practice
* 10.09 (a)
Equitable Resources, Inc. and Subsidiaries Short-Term Incentive Compensation Plan dated January 18, 1988
Refiled herewith as Exhibit 10.09 pursuant to Rule 24 of SEC's Rules of Practice
* 10.09 (b)
Amendment dated February 17, 1993 to Equitable Resources, Inc. and Subsidiaries Short-Term Incentive Compensation Plan
Filed as Exhibit 10.22 to Form 10-K for the year ended December 31, 1992
* 10.10 (a)
Agreement dated December 31, 1987 with Malcolm M. Prine for deferred payment of 1988 director fees
Filed as Exhibit 10.10 (a) to Form 10-K for the year ended December 31, 1993
* 10.10 (b)
Agreement dated December 30, 1988 with Malcolm M. Prine for deferred payment of 1989 director fees
Filed as Exhibit 10.10 (b) to Form 10-K for the year ended December 31, 1993
* 10.11 (a)
Agreement dated September 30, 1986 with Daniel M. Rooney for deferred payment of 1986 and 1987 director fees
Filed as Exhibit 10.11 (a) to Form 10-K for the year ended December 31, 1993
* 10.11 (b)
Agreement dated December 21, 1987 with Daniel M. Rooney for deferred payment of 1988 director fees
Filed as Exhibit 10.11 (b) to Form 10-K for the year ended December 31, 1993
* 10.11 (c)
Agreement dated December 30, 1988 with Daniel M. Rooney for deferred payment of 1989 director fees
Filed as Exhibit 10.11 (c) to Form 10-K for the year ended December 31, 1993
* 10.11 (d)
Agreement dated December 15, 1989 with Daniel M. Rooney for deferred payment of 1990 director fees
Refiled herewith as Exhibit 10.11 (d) pursuant to Rule 24 of SEC's Rules of Practice
* 10.11 (e)
Agreement dated December 21, 1990 with Daniel M. Rooney for deferred payment of 1991 director fees
Filed as Exhibit 10.27 to Form 10-K for the year ended December 31, 1990
* 10.11 (f)
Agreement dated December 13, 1991 with Daniel M. Rooney for deferred payment of 1992 director fees
Filed as Exhibit 10.27 to Form 10-K for the year ended December 31, 1991
* 10.11 (g)
Agreement dated December 18, 1992 with Daniel M. Rooney for deferred payment of 1993 director fees
Filed as Exhibit 10.27 to Form 10-K for the year ended December 31, 1992
* 10.11 (h)
Agreement dated December 14, 1993 with Daniel M. Rooney for deferred payment of 1994 director fees
Filed as Exhibit 10.11 (h) to Form 10-K for the year ended December 31, 1993
* 10.11 (i)
Agreement dated December 15, 1994 with Daniel M. Rooney for deferred payment of 1995 director fees
Filed herewith as Exhibit 10.11 (i)
10.12
Trust Agreement with Pittsburgh National Bank to act as Trustee for Supplemental Pension Plan, Supplemental Deferred Compensation Benefits, Retirement Program for Board of Directors, and Supplemental Executive Retirement Plan
Refiled herewith as Exhibit 10.12 pursuant to Rule 24 of SEC's Rules of Practice
* 10.13
Equitable Resources, Inc. Non-Employee Directors' Stock Incentive Plan
Filed herewith as Exhibit 10.13
* 10.14
Equitable Resources, Inc. Long-Term Incentive Plan
Filed herewith as Exhibit 10.14
* 10.15
Agreement dated December 31, 1994 with Donald I. Moritz for consulting services
Filed herewith as Exhibit 10.15
11.01 Statement re Computation of Earnings Per Share Filed herewith as Exhibit 11.01
Schedule of Subsidiaries Filed herewith as Exhibit 21
23.01 Consent of Independent Auditors Filed herewith as Exhibit 23.01
99.01 Equitable Resources, Inc. Employees Savings Plan Form 11-K Annual Report Filed herewith as Exhibit 99.01
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: (Frederick H. Abrew) President and Chief Executive Officer
Date: March 17, 1995
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.
President and Chief Executive Officer and Director s/ Frederick H. Abrew (Principal Executive Officer) March 17, 1995 Frederick H. Abrew
Vice President and s/ A. Mark Abramovic Chief Financial Officer March 17, 1995 A. Mark Abramovic
Vice President - Accounting and Administration s/ Joseph L. Giebel (Chief Accounting Officer) March 17, 1995 Joseph L. Giebel
s/ Clifford L. Alexander, Jr. Director March 17, 1995 Clifford L. Alexander, Jr.
s/ Merle E. Gilliand Director March 17, 1995 Merle E. Gilliand
s/ E. Lawrence Keyes, Jr. Director March 17, 1995 E. Lawrence Keyes, Jr.
s/ Thomas A. McConomy Director March 17, 1995 Thomas A. McConomy
s/ Donald I. Moritz Director March 17, 1995 Donald I. Moritz
s/ Malcolm M. Prine Director March 17, 1995 Malcolm M. Prine
Director Daniel M. Rooney
s/ David S. Shapira Director March 17, 1995 David S. Shapira
s/ Barbara Boyle Sullivan Director March 17, 1995 Barbara Boyle Sullivan