10-K 1 FORM 10-K ================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 ------------------------ FORM 10-K (Mark one) [x] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (Fee required) For the fiscal year ended December 31, 1994 ------------------ or [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (No fee required) For the transition period from ______________ to ______________ Commission file number 1-8246 ------------ SOUTHWESTERN ENERGY COMPANY (Exact name of registrant as specified in charter) ARKANSAS 71-0205415 --------------------------------- ---------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1083 Sain Street, Fayetteville, Arkansas 72703 ---------------------------------------- -------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (501) 521-1141 -------------- Securities registered pursuant to Section 12(b) of the Act: Name of each exchange on Title of each class which registered ------------------- ----------------------- Common Stock - Par Value $.10 New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. __________ The aggregate market value of the voting stock held by non-affiliates of the Registrant was $351,357,014 based on the New York Stock Exchange - Composite Transactions closing price on March 24, 1995 of $13.875. The number of shares outstanding as of March 24, 1995, of the Registrant's common stock, par value $.10, was 25,607,365. DOCUMENTS INCORPORATED BY REFERENCE Documents incorporated by reference and the Part of the Form 10-K into which the document is incorporated: (1) Annual Report to holders of the Registrant's common stock for fiscal year ended December 31, 1994 - PARTS I, II, and IV; and (2) definitive proxy statement to holders of the Registrant's common stock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Shareholders on May 31, 1995 - PART III. ================================================================================ SOUTHWESTERN ENERGY COMPANY FORM 10-K ANNUAL REPORT FOR THE YEAR ENDED DECEMBER 31, 1994 TABLE OF CONTENTS
PART I Page ---- Item 1. Business ............................................................................... 1 Natural gas and oil exploration and production ......................................... 1 Natural gas gathering, transmission and distribution ................................... 4 Real estate development ................................................................ 9 Employees .............................................................................. 9 Industry segment and statistical information ........................................... 9 Item 2. Properties ............................................................................. 9 Item 3. Legal Proceedings ...................................................................... 10 Item 4. Submission of Matters to a Vote of Security Holders .................................... 11 Executive Officers of the Registrant ................................................... 11 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters .................. 12 Item 6. Selected Financial Data ................................................................ 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations .. 12 Item 8. Financial Statements and Supplementary Data ............................................ 12 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ... 12 PART III Item 10. Directors and Executive Officers of the Registrant ..................................... 12 Item 11. Executive Compensation ................................................................. 12 Item 12. Security Ownership of Certain Beneficial Owners and Management ......................... 12 Item 13. Certain Relationships and Related Transactions ......................................... 13 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ........................ 13
PART I ITEM 1. BUSINESS Southwestern Energy Company (the Company) is a diversified natural gas company which conducts its primary activities through four wholly owned subsidiaries. The Company operates principally in the exploration and production segment, the gas distribution segment and the gas transmission segment of the natural gas industry. The Company was incorporated on July 2, 1929, under the laws of the state of Arkansas. The Company operates an integrated natural gas gathering, transmission and distribution system in northwest Arkansas, and natural gas distribution systems in northeast Arkansas and parts of Missouri. The nature of the Company's natural gas transmission and distribution operations changed in 1992 when a new 258 mile long intrastate pipeline in which the Company owns an interest commenced operations. The intrastate pipeline crosses three interstate pipelines and ties the Company's distribution and gathering pipeline systems in northwest Arkansas to its distribution systems in northeast Arkansas and southeast Missouri. The Company also serves as operator of the pipeline. In 1943, the Company commenced a program of exploration for and development of natural gas reserves in Arkansas for supply to its utility customers. In 1971, the Company initiated an exploration and development program outside Arkansas, unrelated to the utility requirements. Since that time, the Company's exploration and development activities outside Arkansas have expanded. The exploration, development and production activities are a separate, primary business of the Company. The Company is an exempt holding company under the Public Utility Holding Company Act of 1935. Exploration and production activities consist of ownership of mineral interests in productive and undeveloped leases located entirely within the United States. The Company engages in gas and oil exploration and production through its subsidiaries, SEECO, Inc. (SEECO) and Southwestern Energy Production Company (SEPCO). SEECO operates exclusively in the state of Arkansas and holds a large base of both developed and undeveloped gas reserves and conducts an ongoing drilling program in the historically productive Arkansas section of the Arkoma Basin. SEPCO conducts an exploration program in areas outside Arkansas, primarily the Gulf Coast areas of Texas and Louisiana. SEPCO also holds a block of leasehold acreage located on the Fort Chaffee military reservation in western Arkansas and in other parts of Arkansas away from the operating areas of the Company's other subsidiaries. The Company's subsidiary Arkansas Western Gas Company (Arkansas Western) operates integrated natural gas distribution systems in Arkansas and Missouri. Arkansas Western is the largest single purchaser of SEECO's gas production. Southwestern Energy Pipeline Company (SWPL) owns an interest in the NOARK Pipeline System (NOARK), an intrastate natural gas transmission system which extends across northern Arkansas. A discussion of the primary businesses conducted by the Company through its wholly owned subsidiaries follows. NATURAL GAS AND OIL EXPLORATION AND PRODUCTION Substantially all of the Company's exploration and production activities and reserves are concentrated in the Arkoma Basin of Arkansas and the Gulf Coast areas of Texas and Louisiana. At December 31, 1994, the Company had proved natural gas reserves of 316.1 billion cubic feet (Bcf) and proved oil reserves of 1,231 thousand barrels (MBbls). Revenues of the exploration and production subsidiaries are predominately generated from production of natural gas. The Company's gas production increased for the seventh consecutive year in 1994, totaling 37.7 Bcf, up 6% from 35.7 Bcf in 1993. Sales of gas production accounted for 96% of total operating revenues for this segment in 1994, 98% in 1993, and 96% in 1992. SEECO's largest customer for sales of its gas production was the Company's utility subsidiary. Sales to unaffiliated purchasers by both SEECO and SEPCO have increased significantly, however, during the last few years primarily as a result of higher production from Arkansas properties and from properties in the Gulf Coast areas. Sales to unaffiliated purchasers accounted for 63% of total gas volumes sold by the exploration and production segment in 1994, 64% in 1993, and 55% in 1992. 1 Gas volumes sold by SEECO to Arkansas Western for its northwest Arkansas division (AWG) were approximately 8.8 Bcf in 1994, 7.1 Bcf in 1993 and 7.2 Bcf in 1992. Through these sales, SEECO furnished approximately 64% of the northwest Arkansas system's requirements in 1994 and 50% in both 1993 and 1992. The increase in 1994 was due largely to increased storage injections and higher volumes resulting from a settlement reached to resolve certain gas cost issues before the Arkansas Public Service Commission (APSC). The settlement, which involved the price of gas sold under a long-term contract between SEECO and AWG, is hereafter referred to as "the gas cost settlement", and is discussed more fully below. SEECO also delivered approximately 1.5 Bcf in 1994, 2.2 Bcf in 1993 and 2.8 Bcf in 1992 directly to certain large business customers of AWG through a transportation service of the utility subsidiary that became effective in October, 1991. Most of the sales to AWG are pursuant to a twenty-year contract between SEECO and AWG entered into in July, 1978, under which the price had been frozen since 1984. This contract was amended in 1994 as a result of the gas cost settlement. The settlement became effective July 1, 1994, and calls for sales under the contract to take place at a price which is equal to a spot market index plus an additional premium. The settlement results in a lower contract price based on current market conditions. That effect is offset in part by provisions which allow additional volumes to be sold under the contract. The amended contract provides for volumes equal to the historical level of sales under the contract to be sold at the spot market index plus a premium of $.95 per Mcf, while any incremental sales volumes will receive a premium of $.50 per Mcf. In 1994, approximately 8.1 Bcf (net to the Company's interest) was sold under the contract compared to approximately 6.0 Bcf in 1993. Other significant terms of the settlement prevent any of the parties thereto from asking for refunds, transfer certain of AWG's storage facilities to SEECO, and prohibits AWG from filing a rate case before January, 1996. In addition to this contract, SEECO also sells gas to AWG under newer long-term contracts with flexible pricing provisions and under short-term spot market arrangements. SEECO's sales to AWG accounted for approximately 32%, 31% and 45% of total exploration and production revenues in 1994, 1993 and 1992, respectively. SEECO's sales to Associated Natural Gas Company (Associated), a division of Arkansas Western which operates natural gas distribution systems in northeast Arkansas and parts of Missouri, were 5.1 Bcf in 1994, 5.7 Bcf in 1993 and 4.3 Bcf in 1992. These deliveries accounted for approximately 58% of Associated's total requirements in 1994, 67% in 1993 and 56% in 1992. These sales represented 14% of total exploration and production revenues in 1994, 15% in 1993 and 14% in 1992. Deliveries to Associated decreased in 1994 due to warmer weather in the heating season and increased in 1993 primarily due to colder heating weather and storage requirements during the summer months. Effective October, 1990, SEECO entered into a ten-year contract with Associated to supply its base load system requirements at a price to be redetermined annually. Deliveries under this contract were made at a price of $1.90 per thousand cubic feet (Mcf) from inception of the contract through the first nine months of 1993, increased to $2.385 per Mcf for the contract period ended September 30, 1994, and are currently being made at a price of $2.20 per Mcf. In 1990, SEECO completed the initial mapping and engineering phases of a multi-year geological field study of the Arkoma Basin of Arkansas. The product developed was an extensive database and geologic interpretations of the distribution of gas-bearing sands in the region and resulted in the identification of 69.7 Bcf of proved undeveloped reserves that were added to the Company's base of proved reserves. At December 31, 1994, after transfers and revisions, the remaining proved undeveloped reserves identified by the study were 46.4 Bcf. The data base developed is continually updated by drilling activity and serves as the guide for a development drilling program that the Company plans to continue over the next several years. The development drilling program added 22.2 Bcf in 1994, 27.0 Bcf in 1993, and 22.5 Bcf in 1992 of new natural gas reserve additions and resulted in the transfer of 3.0 Bcf in 1994, 2.6 Bcf in 1993, and 8.7 Bcf in 1992 from the proved undeveloped category to the proved developed category. SEECO participated in a total of 97 development wells during 1994 with a completion rate of 72%. SEECO expects the number of wells it participates in to increase during 1995, but due to anticipated lower working interests, expects the number 2 of wells net to the Company's interest to remain approximately the same as 1994. SEECO's sales to unaffiliated purchasers increased to 10.7 Bcf in 1994, from 10.0 Bcf in 1993 and 4.7 Bcf in 1992. The increase in both years resulted from the Company's development drilling program. At present, SEECO's contracts for sales of gas to unaffiliated customers consist of short-term sales made to customers of AWG's transportation program and spot sales into markets away from AWG's distribution system. These sales are subject to seasonal price swings. In the past, the Company's ability to enter into sales arrangements with unaffiliated customers has generally been constrained by a lack of pipeline transportation to markets away from the Arkoma Basin. Initiatives of the FERC to restructure the natural gas interstate pipeline service rules through its Order No. 636 series have improved and should continue to improve the Company's ability to market its existing and potential reserves. Also contributing to the increase in the ability of SEECO to market its gas to unaffiliated customers was the completion in September, 1992 of NOARK, as explained more fully below under "Natural gas gathering, transmission and distribution." SEECO's sales to unaffiliated purchases accounted for approximately 23%, 22% and 13% of total exploration and production revenues in 1994, 1993 and 1992, respectively. At December 31, 1994, the gas reserves of SEPCO were located primarily in the states of Arkansas, Oklahoma and the Gulf Coast areas of Texas and Louisiana, while its oil reserves were located primarily in Oklahoma and the Gulf Coast areas of Louisiana and Texas. SEPCO holds about 26% of the Company's natural gas reserves and all of its oil reserves. SEPCO's gas sales increased to 13.1 Bcf in 1994, from 12.9 Bcf in 1993 and 9.6 Bcf in 1992. The increased production since 1992 was primarily from properties located in the Gulf Coast areas of Texas and Louisiana. The increase in 1994 was the result of the completion of a production platform at the Galveston Block 283 gas field late in 1993 and first production from the Earl Chauvin No. 1 well, a 1993 discovery in southeast Louisiana. The increase in 1993 was primarily the result of the completion of a production platform at Brazos Block 397 and the start of production in November 1993 from Galveston Block 283. The Company's production from the Gulf Coast areas is sold under contracts which reflect current short- term prices and which are subject to seasonal price swings. The Company curtailed part of its gas production during 1992 when sales prices were deemed below acceptable levels. Oil production was 200 MBbls in 1994, compared to 97 MBbls in 1993, and 120 MBbls in 1992. The increase in oil production in 1994 primarily resulted from the acquisition of certain Oklahoma producing properties during the year. The Company's exploration program has been directed almost exclusively toward natural gas in recent years. The Company plans to continue to concentrate on developing gas reserves, but will also selectively seek opportunities to participate in projects oriented toward oil production. Over the long-term, however, oil sales are not expected to account for a significant part of the Company's future revenues. SEPCO's gas and oil sales accounted for approximately 33% of total exploration and production operating revenues in 1994 and 1993, and 31% in 1992. In 1989, SEPCO purchased at oral auction 11,000 undrilled acres containing 17 separate drilling units on the Fort Chaffee military reservation of western Arkansas. The total cost of this acreage was approximately $11.0 million. To date, the Company has drilled or participated in eight wells at Fort Chaffee that have discovered an estimated 47.0 Bcf of new gas reserves, net to the Company's interest. The Company is currently in the process of testing a well recently drilled at Fort Chaffee. Sales of gas production from Fort Chaffee totaled 4.3 Bcf in 1994, 5.1 Bcf in 1993 and 5.8 Bcf in 1992. The decrease is a result of the natural decline in the productive capability of these properties. Conflicts with military training activities have limited SEPCO's drilling operations at Fort Chaffee. The Company has attempted to work with the military to improve work schedules and operating restrictions, but those efforts have been to little avail even though the base was scheduled for closing. As a result, Fort Chaffee will probably play a lesser role in the Company's plans. From late 1992 through 1993 sales from Fort Chaffee took place under a firm sales contract for 25 million cubic feet per day (MMcfd) to an independent marketer. The gas was transported by the marketer 3 under a firm transportation contract on NOARK. The Company met its obligation under the firm sales contract in part by providing gas supplied from SEECO's development drilling program. In late 1993, the marketer filed suit against NOARK, the Company and certain of its affiliates, seeking rescission of the firm sales and transportation contracts. Since that time, the Company has entered into its own sales arrangements covering the affected gas production. This gas production continues to be transported through NOARK at a price based on current spot market prices, net of transportation. See discussion at "Natural gas gathering, transmission and distribution" for additional information concerning the independent marketer's decision to cease honoring its contractual obligations. Outside Arkansas, the Company added 8.7 Bcf of new reserves in 1994 and 19.0 Bcf in 1993 from drilling. Of that total, 8.5 Bcf in 1994 and 15.2 Bcf in 1993 was from discoveries in the coastal areas of Texas and Louisiana. The Gulf Coast region continues to be the focus of most of the Company's exploration activity outside Arkansas. The Company expects in the future to continue to direct its exploration activities toward the onshore Gulf Coast. During 1994, the Company increased its emphasis on acquisitions of producing properties and expects that effort to continue as a supplement to its exploration and development drilling programs. The Company acquired approximately 20.6 Bcf of gas and 1,038 MBbls of oil during 1994, mostly in the Anadarko Basin of Oklahoma. In the natural gas and oil exploration segment, competition is encountered primarily in obtaining leaseholds for future exploration. Competition in the state of Arkansas has increased in recent years, due largely to the development of improved access to interstate pipelines. Due to the Company's significant leasehold acreage position in Arkansas and its long-time presence and reputation in this area, the Company believes it will continue to be successful in acquiring new leases in Arkansas. While improved intrastate and interstate pipeline transportation in Arkansas should increase the Company's access to markets for its gas production, these markets will generally be served by a number of other suppliers. Thus, the Company will encounter competition which may affect both the price it receives and contract terms it must offer. Outside Arkansas, the Company is less well-established and faces competition from a larger number of other producers. The Company has in recent years been successful in building its inventory of undeveloped leases and obtaining participating interests in drilling prospects outside Arkansas. The Company expects its 1995 capital expenditures for gas and oil exploration and development to total $55.2 million, approximately equal to the $55.4 million incurred in 1994. Most of the capital spending will be directed to the continued development of the Company's proved acreage in the Arkoma Basin and the Company's exploration program in the Gulf Coast areas of Texas and Louisiana. The Company will review this budget periodically during the year for possible adjustment depending upon cash flow projections related to fluctuating prices for oil and natural gas. NATURAL GAS GATHERING, TRANSMISSION AND DISTRIBUTION The Company's natural gas distribution operations are concentrated primarily in north Arkansas and southeast Missouri. The Company serves approximately 164,000 retail customers and obtains a substantial portion of the gas they consume through its Arkoma Basin gathering facilities. The Company is also a participant in a partnership that owns the NOARK Pipeline System. The complexity of AWG's distribution operations, particularly its gathering system in the Arkoma Basin gas fields, increased significantly with the start up of NOARK. AWG provides field management services to NOARK under a contract with the partnership and AWG's gathering system delivers to NOARK a substantial part of the gas NOARK transports. The Company completed a pipeline in 1993 that connects NOARK to Associated's distribution system, tying together the Company's two primary gas distribution systems. 4 Arkansas Western consists of two operating divisions. The AWG division gathers natural gas in the Arkansas River Valley of western Arkansas and transports the gas through its own transmission and distribution systems, ultimately delivering it at retail to approximately 97,000 customers in northwest Arkansas. The Associated division currently receives its gas from transportation pipelines and delivers the gas through its own transmission and distribution systems, ultimately delivering it at retail to approximately 67,000 customers primarily in northeast Arkansas and southeast Missouri. Associated, formerly a wholly owned subsidiary of Arkansas Power and Light Company, was acquired and merged into Arkansas Western, effective June 1, 1988. The Arkansas Public Service Commission (APSC) and the Missouri Public Service Commission (Missouri Commission) regulate the Company's utility rates and operations. In Arkansas, the Company operates through municipal franchises which are perpetual by state law. These franchises, however, are not exclusive within a geographic area. In Missouri, the Company operates through municipal franchises with various terms of existence. AWG and Associated deliver natural gas to residential, commercial and industrial customers. The industrial customers are generally smaller concerns using gas for plant heating or product processing. AWG has no restriction on adding new residential or commercial customers and will supply new industrial customers which are compatible with the scale of its facilities. AWG has never denied service to new customers within its service area or experienced curtailments because of supply constraints. Associated has not denied service to new customers within its service area or experienced curtailments because of supply constraints since the acquisition date, although service restrictions and supply related curtailments did occur prior to that time. Curtailment of large industrial customers of AWG and Associated occurs only infrequently when extremely cold weather requires their systems to be dedicated exclusively to human needs customers. AWG and Associated have experienced a general trend in recent years toward lower rates of usage among their customers, largely as a result of conservation efforts which the Company encourages. Competition is increasingly being experienced from alternative fuels, primarily electricity, fuel oil and propane. A significant amount of fuel switching has not been experienced, though, as natural gas is generally the least expensive, most readily available fuel in the service territories of AWG and Associated. The competition from alternative fuels and, in a limited number of cases, alternative sources of natural gas has intensified in recent years as a result of the significant declines in prices of petroleum products and the deliverability surplus of natural gas experienced in the recent past. Industrial customers are most likely to consider utilization of these alternatives, as they are less readily available to commercial and residential customers. In an effort to provide some pricing alternatives to its large industrial customers with relatively stable loads, AWG offers an optional tariff to its larger business customers and to any other large business customer which shows that it has an alternate source of fuel at a lower price or that one of its direct competitors in another area has access to cheaper sources of energy. This optional tariff enables those customers willing to accept the risk of price and supply volatility to direct AWG to obtain a certain percentage of their gas requirements in the spot market. Participating customers continue to pay the nongas costs of service included in AWG's present tariff for large business customers and agree to reimburse AWG for any take-or-pay liability caused by spot market purchases on the customer's behalf. In an effort to more fully meet the service needs of larger business customers, both AWG and Associated instituted a transportation service in October, 1991, that allows such customers in Arkansas to obtain their own gas supplies directly from other suppliers. Associated has offered transportation service to its larger customers in Missouri for several years and AWG's spot market purchasing program has provided customers in northwest Arkansas with many of the benefits of transportation service. Under the programs, transportation service is available in Arkansas to any large business customer which consumes a minimum of 150,000 Mcf per year and no less than 3,000 Mcf per month. Transportation service is available in Missouri to any customer whose average monthly usage exceeds 2,000 Mcf. The minimums can be met by aggregating facilities under common ownership. A total of eleven customers are currently using the Arkansas 5 transportation service, including three of AWG's four largest customers in northwest Arkansas and Associated's two largest customers in northeast Arkansas. In its 1991 order approving the transportation program, the APSC indicated that the program's approval would be on a one year trial basis to allow for time to gain operating experience in an effort to make improvements, if needed, in the program. Since the expiration of the first trial year, the APSC has continued to extend the program on an annual basis. The APSC has established a procedural schedule for considering during 1995 finalization of the transportation program. In addition, the public hearing will also address whether there is a need to continue AWG's spot market purchasing program. Other issues may also be raised by the parties to the proceeding. AWG purchases its system gas supply directly at the wellhead under long-term contracts. Purchases are made from approximately 300 working interest owners in 491 producing wells. As previously indicated, SEECO furnished approximately 64% of AWG's requirements in 1994 and 50% in both 1993 and 1992. A significant portion of the unaffiliated volumes purchased by AWG are covered by contracts which contain provisions for periodic or automatic escalation in the price to be paid. In the mid-1980's, however, AWG took steps to freeze the prices paid under those contracts containing indefinite price escalators tied to Section 102 or prices escalating under Section 103 of the NGPA. Producers under these contracts were offered an amendment freezing the price at the December, 1984 level, with a right to renegotiate in one year. AWG received acceptances from producers holding the majority of the reserves under such contracts, either accepting the amendment or agreeing to freeze the price. Since that time, the price freeze has remained in effect and AWG has continued to make payments at the frozen 1984 price levels. This price freeze also applied to purchases from SEECO under its long-term contract with AWG until the gas cost settlement became effective July 1, 1994. A significant portion of AWG's supply comes from newer, market responsive, long-term contracts which take advantage of the lower prices presently available from gas suppliers. At December 31, 1994, AWG had a gas supply available to its northwest Arkansas system of approximately 239 Bcf of proved developed reserves, equal to 17 times current annual usage. Of this total, approximately 113 Bcf were net reserves available from SEECO. Under the terms of the gas cost settlement, SEECO's reserves are no longer dedicated to AWG. However, a portion of these reserves are utilized to meet the annual sales volume commitment of 9.0 Bcf (gross) under the amended long-term contract with AWG. For purposes of determining AWG's available gas supply, deliveries to AWG's spot market purchasing program or transportation customers and the reserves related to those deliveries are not considered. During 1993, Associated renegotiated its purchase contracts with interstate pipelines in accordance with the pipeline restructuring as mandated by the Federal Energy Regulatory Commission's (FERC) Order No. 636. Prior to Order 636, Associated purchased its system supply from six interstate pipelines, SEECO and various spot market suppliers. Associated now purchases gas for its system supply from unaffiliated suppliers in the producing fields accessed by interstate pipelines and from SEECO. Purchases from SEECO are under a ten-year contract with annual price redeterminations. Purchases from unaffiliated suppliers are under firm contracts with terms between one and three years. The rates charged by these suppliers include demand components to ensure availability of gas supply, administrative fees and a commodity component which is based on spot market gas prices. Associated's gas purchases are transported through nine pipelines. The pipeline transportation rates include demand charges to reserve pipeline capacity and commodity charges based on volumes transported. Associated has also contracted with five of the interstate pipelines for storage capacity to meet its peak seasonal demands. These contracts involve demand charges based on the maximum deliverability, capacity charges based on the maximum storage quantity, and charges for the quantities injected and withdrawn. Over the past several years changes at the federal level have brought significant changes to the regulatory structure governing interstate sales and transportation of natural gas. The FERC's Order No. 636 series 6 changed a major portion of the gas acquisition merchant function provided to gas distributors by interstate pipelines. AWG already obtains its supply at the wellhead directly from producers and has not been directly impacted by Order No. 636. Associated has acquired the bulk of its gas supply at the wellhead since its acquisition by AWG, but continued until Order No. 636 to purchase a portion of both its peak and base requirements from interstate suppliers. The changes mandated by Order No. 636 have placed the responsibility for arranging firm supplies of natural gas directly on local distribution companies and have, as a result, lessened the ability of Associated to purchase gas on the short-term spot market. As a result of pipeline deregulation, Associated has paid approximately $3.2 million in contract reformation costs and take-or-pay costs and $1.9 million in transition costs which its interstate pipeline suppliers incurred and were allowed to recover. The Company anticipates full recovery of the $1.9 million in transition costs incurred. To date, the Company has recovered, subject to refund, approximately $1.6 million of the contract reformation costs and take- or-pay costs from its utility sales customers in the state of Missouri. Of the unrecovered $1.6 million related to contract reformation costs and take-or-pay costs, $.7 million is applicable to Associated's transportation customers in the state of Missouri and $.9 million is applicable to all customers in the state of Arkansas. The Staff of the Missouri Commission (Staff) has reviewed these payments and made a recommendation that the unrecovered $.7 million related to Associated's transportation customers should be disallowed on the grounds that such recovery would constitute retroactive ratemaking. The Company disagreed with this recommendation and a hearing was held on January 31, 1995. The Company is awaiting the Missouri Commission's order. AWG also purchases gas from unaffiliated producers under take-or-pay contracts. Currently, the Company believes that it does not have a significant exposure to liabilities resulting from these contracts, although the Company's exposure to take-or-pay liabilities to its gas suppliers has increased in recent years as a result of a decline in its gas purchase requirements. This decline occurred because some of its large business customers converted to the transportation service offered by AWG and Associated and began to obtain their own gas supplies directly from other sources. The Company expects to be able to continue to satisfactorily manage its exposure to take-or-pay liabilities. As discussed earlier, Associated purchases a portion of its gas supply at the wellhead from one of the Company's gas producing subsidiaries under a long- term firm contract entered into in October, 1990. As a result of recent gas cost audits in Missouri for the two-year period ended August 31, 1992, the Staff recommended disallowance of approximately $3.1 million in gas costs incurred under this contract. This amount represents the difference between the price paid by Associated and a spot market index price for gas delivered into an interstate pipeline operating in the Arkoma Basin. The price paid by Associated under the contract was $1.90 per Mcf during the period in question. In making its recommendation, the Staff acknowledged that Associated had lowered its gas cost and saved its ratepayers money by purchasing gas from its affiliate. The Staff also acknowledged that the appropriate price for purchases made under this long-term firm contract should include a premium over the spot market price. However, a Staff consultant testified that there was insufficient data upon which to determine an appropriate premium over a spot market index for pricing purchases under this contract and that he was unable to determine what the appropriate premium should be. A hearing was held on January 31, 1995. The Company presented testimony to demonstrate that the price paid under the contract was at or below the market price for contracts with similar terms during the period in which the purchases were made. The APSC previously reviewed the costs charged to Arkansas ratepayers under this contract and found them to be proper and allowable for recovery. The Missouri Commission has not yet issued an order in this proceeding. The Staff has also audited Associated's gas purchases for the period from September, 1992 through August, 1993 and recommended no changes to the gas costs for that period. The gas heating load is one of the most significant uses of natural gas and is sensitive to outside temperatures. Sales, therefore, vary throughout the year. Profits, however, have become less sensitive to 7 fluctuations in temperature in recent years as the structure of the Company's utility rates has become somewhat flatter; i.e., most recovery of return on rate base is built into a customer charge and the first step of its rates. Gas distribution revenues in future years will be impacted by both customer growth and rate increases allowed by regulatory commissions. In recent years, AWG has experienced customer growth of approximately 3.5% to 4.0% annually, while Associated has experienced customer growth of 1% to 2% annually. Based on current economic conditions in the Company's service territories, the Company expects this trend in customer growth to continue. AWG and Associated pass along to customers through an automatic cost of gas adjustment clause any increase or decrease experienced in purchased gas costs. As previously mentioned, the APSC and the Missouri Commission regulate the Company's utility rates and operations. Late in 1990, the APSC and the Missouri Commission approved rate increases for the Company totaling $7.4 million annually. AWG received an increase of $5.7 million annually and Associated was awarded an increase of $.9 million annually for its Missouri properties and $.8 million annually for its system in Arkansas. Rate increase requests which may be filed in the future will depend upon customer growth, increases in operating expenses, and additional investments in property, plant and equipment. AWG is precluded from filing an application for a rate increase with the APSC prior to January 1, 1996, as a result of the gas cost settlement. The Company anticipates filing a rate increase request for AWG in early 1996 and will continue to monitor the status of returns on the systems operated by Associated and file rate cases as the need arises. AWG's rates for gas delivered to its customers are not regulated by the FERC, but its transmission and gathering pipeline systems are subject to the FERC's regulations concerning open access transportation since AWG accepted a blanket transportation certificate in connection with its merger with Associated. NOARK is an intrastate pipeline constructed by a limited partnership in which SWPL holds a 47.93% general partnership interest and is the pipeline's operator. NOARK's main line was completed and placed in service in September, 1992. A lateral line of NOARK that allows the Company's gas distribution segment to augment its supply to an existing market as well as supply gas to new markets was completed and placed in service in November, 1992. The 258 mile long pipeline originates near the Fort Chaffee military reservation in western Arkansas and terminates in northeast Arkansas. NOARK interconnects with three major interstate pipelines and provides additional access to markets for gas production of both the Company and other producers. Construction of an eight- mile interstate pipeline connecting NOARK to the distribution system of Associated was completed during 1993. NOARK is a public utility regulated by the APSC. The APSC established NOARK's maximum transportation rate based on its original construction cost estimate of approximately $73.0 million. Due to construction problems and the addition of a compressor station, the ultimate costs of the pipeline exceeded the original estimate by approximately $30 million. NOARK has a capacity of 141 MMcfd. In 1994, NOARK had an average daily throughput of 82 MMcfd, compared to 79 MMcfd in 1993, its first full year of operation. Arkansas Western has contracted for 41 MMcfd of firm capacity on NOARK under a ten-year transportation contract. NOARK also has a five-year transportation contract with an independent marketer to transport 50 MMcfd through NOARK on a firm basis. The Company's exploration and production segment was supplying 25 MMcfd of the volumes transported by the marketer under that agreement. In late 1993, the gas marketing company filed suit against NOARK, the Company and certain of its affiliates, and, effective January 1, 1994, ceased transporting gas under its agreement with NOARK. The complaint and subsequent filings seek rescission of the transportation contract and a contract to purchase gas from the Company's affiliates, and actual and punitive damages. The Company and NOARK both believe the suit is without merit and have filed counterclaims seeking enforcement of the contracts and damages. The Company is currently making its own sales arrangements and transporting production through NOARK which was previously purchased by the marketer. 8 As a result of the developments described above, NOARK is currently incurring losses and the Company expects further losses from its equity investment in NOARK until the pipeline is able to increase its level of throughput and until improvement occurs in the competitive conditions which determine the transportation rates NOARK can charge. NOARK provides additional pipeline capacity to a portion of the Arkoma Basin in Arkansas which was not previously adequately served by pipelines offering firm transportation. NOARK competes primarily with two interstate pipelines in its gathering area. One of those elected to become an open access transporter subsequent to NOARK's start of construction. That pipeline, which was recently sold, has not offered firm transportation, but the increased availability of interruptible transportation service has intensified the competitive environment within which NOARK operates. The Company and the other partners of NOARK are currently investigating options which could improve NOARK's future financial prospects. The Company is subject to laws and regulations relating to the protection of the environment. The Company's policy is to accrue environmental and cleanup related costs of a non-capital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. The Company has no material amounts accrued at December 31, 1994. Additionally, management believes any future remediation or other compliance related costs will not have any material effect upon capital expenditures, earnings or the competitive position of the Company's subsidiaries in the segments in which they operate. REAL ESTATE DEVELOPMENT A. W. Realty Company (AWR) owns an interest in approximately 170 acres of real estate, most of which is undeveloped. AWR's real estate development activities are concentrated on a 130-acre tract of land located near the Company's headquarters in a growing part of Fayetteville, Arkansas. The Company has owned an interest in this land for many years. The property is zoned for commercial, office and multi-family residential development. AWR continues to review with a joint venture partner various options for developing this property which would minimize the Company's initial capital expenditures but still enable it to retain an interest in any appreciation in value. This activity, however, does not represent a significant portion of the Company's business. EMPLOYEES At December 31, 1994, the Company had 661 employees, 89 of whom are represented under a collective bargaining agreement. INDUSTRY SEGMENT AND STATISTICAL INFORMATION The following portions of the 1994 Annual Report to Shareholders (filed as Exhibit 13 to this filing) are hereby incorporated by reference for the purpose of providing additional information about its business. Refer to Note 9 to the financial statements for information about industry segments and "Financial and Operating Statistics" for additional statistical information, including the average sales price per unit of gas produced and of oil produced and the average production cost per unit. ITEM 2. PROPERTIES The portions of the 1994 Annual Report to Shareholders (filed as Exhibit 13 to this filing) listed below are hereby incorporated by reference for the purpose of describing its properties. Refer to the Appendix for information concerning areas of operation of the Company's gas distribution systems. For information concerning the Company's exploration and production areas of operation, also refer to the Appendix. See the table entitled "Operating Properties" at the Appendix for information concerning miles of pipe of the Company's gas distribution systems and for information regarding leasehold acreage and producing wells by geographic region of the Company's exploration and production segment. Also, see Notes 5 and 6 to the financial statements for additional information about the Company's gas and oil operations. 9 For information concerning capital expenditures, refer to the "Capital Expenditures" section of "Management's Discussion and Analysis of Financial Condition and Results of Operations". Also refer to "Financial and Operating Statistics" for information concerning gas and oil wells drilled and gas and oil produced. The following information is provided to supplement that presented in the 1994 Annual Report to Shareholders: NET WELLS DRILLED DURING THE YEAR EXPLORATORY
PRODUCTIVE YEAR WELLS DRY HOLES TOTAL ---- ---------- --------- ----- 1994........ 4.7 1.8 6.5 1993........ 2.8 4.0 6.8 1992........ 1.2 6.1 7.3
DEVELOPMENT PRODUCTIVE YEAR WELLS DRY HOLES TOTAL ---- ---------- --------- ----- 1994........ 45.5 14.7 60.2 1993........ 37.9 10.5 48.4 1992........ 53.4 13.4 66.8 WELLS IN PROGRESS AS OF DECEMBER 31, 1994 TYPE OF WELL GROSS NET ------------ ----- --- Exploratory.................... 2.0 .5 Development.................... 6.0 1.6 ----- ----- Total.......................... 8.0 2.1 ===== =====
Due to the insignificance of the Company's oil reserves and producing oil wells to its total reserves and producing wells, separate disclosure of gas and oil producing wells has not been made. No individually significant discovery or other major favorable or adverse event has occurred since December 31, 1994. During 1994, SEECO and SEPCO were required to file Form 23, "Annual Survey of Domestic Oil and Gas Reserves" with the Department of Energy. The basis for reporting reserves on Form 23 is not comparable to the reserve data included in Note 6 to the financial statements in the 1994 Annual Report to Shareholders. The primary differences are that Form 23 reports gross reserves, including the royalty owners' share and includes reserves for only those properties where either SEECO or SEPCO is the operator. ITEM 3. LEGAL PROCEEDINGS The Company and its subsidiaries are involved in various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings cannot be predicted with certainty, management expects these matters will not have a material adverse effect on the consolidated financial position or results of operations of the Company. 10 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted during the fourth quarter of the fiscal year ended December 31, 1994, to a vote of security holders, through the solicitation of proxies or otherwise. EXECUTIVE OFFICERS OF THE REGISTRANT The following is information with regard to executive officers of the Company:
NAME OFFICER POSITION AGE ---- ---------------- --- Charles E. Scharlau ........ Chairman of the Board (since 1979), Southwestern Energy Company and 68 Subsidiaries,and Chief Executive Officer (since 1968), Southwestern Energy Company. Dan B. Grubb ............... President and Chief Operating 59 Officer(since 1992), Director (1988-1992), Southwestern Energy Company.Chairman and Chief Executive Officer of Grubb Industries, Inc.,and Investor and Business Consultant (since 1988). Previously, President and Chief Operating Officer, Midcon Corporation (since 1987). Stanley D. Green ........... Executive Vice President - Finance 41 and Corporate Development (since 1992), and Chief Financial Officer (since 1987), Vice President - Treasurer and Secretary (since 1987), Controller (since 1981), Southwestern Energy Company and Subsidiaries. B. Brick Robinson .......... Executive Vice President and Chief 64 Operating Officer (since 1988), Southwestern Energy Production Company and SEECO, Inc. (subsidiaries of Southwestern Energy Company). Previously, various positions with Occidental Petroleum Corporation and its subsidiaries, including Vice President, Far East and Domestic Frontier Exploration,Occidental International (since 1985). Gregory D. Kerley .......... Vice President - Treasurer and 39 Secretary (since 1992), and Chief Accounting Officer (since 1990), Controller (since 1990), Southwestern Energy Company and Subsidiaries. Previously, Treasurer and Controller, Agate Petroleum, Inc. (since 1984).
All officers are elected at the Annual Meeting of the Board of Directors for one-year terms or until their successors are duly elected. There are no arrangements between any officer and any other person pursuant to which he was selected as an officer. There is no family relationship between any of the named executive officers or between any of them and the Company's directors. Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is presented in the definitive Proxy Statement dated April 21, 1995, under the section entitled "Security Ownership of Directors, Nominees and Executive Officers" and is incorporated herein by reference. 11 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The "Shareholder Information" and "Financial and Operating Statistics" sections of the 1994 Annual Report to Shareholders (filed as Exhibit 13 to this filing) are hereby incorporated by reference for information concerning the market for and prices of the Company's common stock, the number of shareholders and cash dividends paid. The terms of the Company's long-term debt instruments and agreements impose restrictions on the payment of cash dividends. At December 31, 1994, $121,754,000 of retained earnings was available for payment as cash dividends. These covenants generally limit the payment of dividends in a fiscal year to the total of net income earned since January 1, 1990, plus $20,000,000 less dividends paid and purchases, redemptions or retirements of capital stock during the period since December 4, 1991. The Board of Directors increased the quarterly dividend by 20% in the third quarter of 1993, to $.06 per share, equal to an annual rate of $.24 per share (after the effect of a three-for-one stock split distributed August 5, 1993). While the Board of Directors intends to continue the practice of paying dividends quarterly, amounts and dates of such dividends as may be declared will necessarily be dependent upon the Company's future earnings and capital requirements. ITEM 6. SELECTED FINANCIAL DATA, AND ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The following portions of the 1994 Annual Report to Shareholders (filed as Exhibit 13 to this filing) are hereby incorporated by reference. "Financial and Operating Statistics" for selected financial data of the Company. "Management's Discussion and Analysis of Financial Condition and Results of Operations." The consolidated financial statements as detailed in Item 14 (a)(1) below. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There have been no changes in or disagreements with accountants on accounting and financial disclosure. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The definitive Proxy Statement to holders of the Company's Common Stock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Shareholders on May 31, 1995 (the 1995 Proxy Statement), is hereby incorporated by reference for the purpose of providing information about the identification of directors. Refer to the sections "Election of Directors" and "Security Ownership of Directors, Nominees and Executive Officers" for information concerning the directors. Information concerning executive officers is presented in Part I, Item 4 of this Form 10-K. ITEM 11. EXECUTIVE COMPENSATION The 1995 Proxy Statement is hereby incorporated by reference for the purpose of providing information about executive compensation. Refer to the section "Executive Compensation." ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The 1995 Proxy Statement is hereby incorporated by reference for the purpose of providing information about security ownership of certain beneficial owners and management. Refer to the section "Security Ownership 12 of Directors, Nominees and Executive Officers" for information about security ownership of certain beneficial owners and management. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The 1995 Proxy Statement is hereby incorporated by reference for the purpose of providing information about related transactions. Refer to the section "Security Ownership of Directors, Nominees and Executive Officers" and "Compensation Committee Interlocks and Insider Participation" for information about transactions with members of the Company's Board of Directors. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) The following consolidated financial statements of the Company and its subsidiaries, included with its 1994 Annual Report to Shareholders (filed as Exhibit 13 to this filing) and the report of independent auditors on such report are hereby incorporated by reference: Report of Independent Auditors. Consolidated Balance Sheets as of December 31, 1994 and 1993. Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992. Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992. Consolidated Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992. Notes to Consolidated Financial Statements, December 31, 1994, 1993 and 1992. (2) The consolidated financial statement schedules have been omitted because they are not required under the related instructions, or are inapplicable and therefore have been omitted. (3) The exhibits listed on the accompanying Exhibit Index (pages 15-17) are filed as part of, or incorporated by reference into, this Report. (b) Reports on Form 8-K: A Current Report on Form 8-K was filed on November 8, 1994, regarding a news release dated October 31, 1994, announcing that two of the Company's wholly owned subsidiaries entered into a settlement with the Staff of the Arkansas Public Service Commission (APSC) and the Attorney General of the State of Arkansas regarding certain gas cost issues which had been outstanding before the APSC for almost four years. The issues in question involved the price of gas sold by one of the Company's gas producing subsidiaries under a long-term contract with the Company's utility subsidiary. Under the settlement, the price paid by the Company's utility subsidiary will be referenced to an index plus a premium. At current market prices, the new provision will result in a reduced sales price under the contract. The terms of the settlement became effective as of July 1, 1994, and were approved by the APSC on January 5, 1995. The settlement is discussed in more detail on page 2 in the "Natural gas and oil exploration and production" section of Item 1. A Current Report on Form 8-K was filed on March 10, 1995, regarding a news release dated February 23, 1995, announcing that the Company's Board of Directors authorized the Company to repurchase up to $30.0 million of the Company's common shares. The Company plans to buy the shares from time to time, depending on market conditions, in the open market or in private negotiated transactions. Shares repurchased will be held in treasury and may be used for general corporate purposes, including issuance under option plans. The repurchase program will continue until terminated by the Company's Board of Directors. 13 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THE REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. SOUTHWESTERN ENERGY COMPANY --------------------------- (Registrant) Dated: March 24, 1995 BY: /s/STANLEY D.GREEN ---------------------------- Stanley D. Green, Executive Vice President - Finance and Corporate Development, and Chief Financial Officer PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES INDICATED ON MARCH 24, 1995. /s/ CHARLES E. SCHARLAU Director, Chairman, and ------------------------------- Charles E. Scharlau Chief Executive Officer Executive Vice President - /s/ STANLEY D. GREEN Finance and Corporate Development, ------------------------------- Stanley D. Green and Chief Financial Officer Vice President - Treasurer /s/ GREGORY D. KERLEY and Secretary, and ------------------------------- Gregory D. Kerley Chief Accounting Officer /s/ E. J. BALL Director ------------------------------- E. J. Ball /s/ JAMES B. COFFMAN Director ------------------------------- James B. Coffman /s/ JOHN PAUL HAMMERSCHMIDT Director ------------------------------- John Paul Hammerschmidt /s/ CHARLES E. SANDERS Director ------------------------------- Charles E. Sanders SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT. Not Applicable 14 EXHIBIT INDEX EXHIBIT NO. DESCRIPTION ------- ----------- 3. Articles of Incorporation and Bylaws of the Company (amended and restated Articles of Incorporation incorporated by reference to Exhibit 3 to Annual Report on Form 10-K for the year ended December 31, 1993); Bylaws of the Company, as amended (filed herewith). 4. Shareholder Rights Agreement, dated May 5, 1989 (incorporated by reference to Exhibit 1 filed with the Company's Form 8-K on May 10, 1989). Material Contracts: 10.1 Gas Purchase Contract between SEECO, Inc., and Arkansas Western Gas Company, dated July 24, 1978, as amended May 21, 1979, and Amended and Restated as of July 1, 1994 (filed herewith). 10.2 Agreement between Southwestern Energy Company, Arkansas Western Gas Company, Arkansas Power & Light Company and Associated Natural Gas Company, dated September 1, 1987, as amended February 22, 1988, and May 16, 1988 (original agreement and first amendment to the Agreement incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for the year ended December 31, 1987; second amendment to the Agreement thereto incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for the year ended December 31, 1988). 10.3 Gas Purchase Contract between SEECO, Inc. and Associated Natural Gas Company, dated October 1, 1990 (incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for the year ended December 31, 1990). 10.4 Compensation Plans: (a) Summary of Southwestern Energy Company Annual and Long-Term Incentive Compensation Plan, effective January 1, 1985, as amended July 10, 1989 (Replaced by Southwestern Energy Company Incentive Compensation Plan, effective January 1, 1993) (original plan incorporated by reference to Exhibit 10 to Annual Report on Form 10- K for the year ended December 31, 1984; first amendment thereto incorporated by reference to Exhibit 10 to Annual Report on Form 10- K for the year ended December 31, 1989). (b) Summary of Southwestern Energy Company Incentive Compensation Plan, effective January 1, 1993 (incorporated by reference to Exhibit 10.4(b) to Annual Report on Form 10-K for the year ended December 31, 1993). (c) Nonqualified Stock Option Plan, effective February 22, 1985, as amended July 10, 1989 (Replaced by Southwestern Energy Company 1993 Stock Incentive Plan, dated April 7, 1993) (original plan incorporated by reference to Exhibit 10 to Annual Report on Form 10- K for the year ended December 31, 1985; amended plan incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for the year ended December 31, 1989). (d) Southwestern Energy Company 1993 Stock Incentive Plan, dated April 7, 1993 (incorporated by reference to the appendix filed with the Company's definitive Proxy Statement to holders of the Registrant's Common Stock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Shareholders on May 26, 1993). 15 EXHIBIT NO. DESCRIPTION ------- ----------- (e) Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors, dated April 7, 1993 (incorporated by reference to the appendix filed with the Company's definitive Proxy Statement to holders of the Registrant's Common Stock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Shareholders on May 26, 1993). 10.5 Southwestern Energy Company Supplemental Retirement Plan, adopted May 31, 1989, and Amended and Restated as of December 15, 1993 (amended and restated plan incorporated by reference to Exhibit 10.5 to Annual Report on Form 10-K for the year ended December 31, 1993). 10.6 Southwestern Energy Company Supplemental Retirement Plan Trust, dated December 30, 1993 (incorporated by reference to Exhibit 10.6 to Annual Report on Form 10-K for the year ended December 31, 1993). 10.7 Executive Severance Agreement for Charles E. Scharlau, effective August 4, 1989 (incorporated by reference to Exhibit 10 to Annual Report on Form 10- K for the year ended December 31, 1989). 10.8 Executive Severance Agreement for Stanley D. Green, effective August 4, 1989 (incorporated by reference to Exhibit 10 to Annual Report on Form 10- K for the year ended December 31, 1989). 10.9 Executive Severance Agreement for B. Brick Robinson, effective August 4, 1989 (incorporated by reference to Exhibit 10 to Annual Report on Form 10- K for the year ended December 31, 1989). 10.10 Executive Severance Agreement for Dan B. Grubb, effective July 8, 1992 (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K for the year ended December 31, 1992). 10.11 Executive Severance Agreement for Gregory D. Kerley, effective December 14, 1994 (filed herewith). 10.12 Employment Agreement for Charles E. Scharlau, dated December 18, 1990, effective January 1, 1991, as amended December 7, 1994 (original agreement incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for the year ended December 31, 1990; amendment filed herewith). 10.13 Employment Agreement for Dan B. Grubb, effective July 8, 1992 (incorporated by reference to Exhibit 10.16 to Annual Report on Form 10-K for the year ended December 31, 1992). 10.14 Form of Indemnity Agreement, between the Company and each officer and director of the Company, dated May 25, 1988 or October 9, 1991 (incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for the year ended December 31, 1988; and incorporated by reference to Exhibit 10.20 to Annual Report on Form 10-K for the year ended December 31, 1991). 10.15 Gas Transportation Agreement between NOARK Pipeline System, Limited Partnership and Arkansas Western Gas Company, dated February 4, 1991, and amended February 14, 1992 (original agreement incorporated by reference to Exhibit 10.22 to Annual Report on Form 10-K for the year ended December 31, 1991; amended agreement incorporated by reference to Exhibit 10.19 to Annual Report on Form 10-K for the year ended December 31, 1992). 10.16 Limited Partnership Agreement of NOARK Pipeline System, Limited Partnership, dated October 10, 1991, and amended February 24, 1993 (original agreement incorporated by reference to Exhibit 10.23 to Annual Report on Form 10-K for the year ended December 31, 1991; amended agreement incorporated by reference to Exhibit 10.21 to Annual Report on Form 10-K for the year ended December 31, 1992). 10.17 Operating Agreement of NOARK Pipeline System, dated March 19, 1991 (incorporated by reference to Exhibit 10.25 to Annual Report on Form 10-K for the year ended December 31, 1991). 16 EXHIBIT NO. DESCRIPTION ------- ----------- 10.18 Agreement for Sale of Partnership Interest between Southwestern Energy Pipeline Company and GRUBB NOARK Pipeline, Inc., dated July 24, 1992 (incorporated by reference to Exhibit 10.25 to Annual Report on Form 10-K for the year ended December 31, 1992). 13. 1994 Annual Report to Shareholders, except for those portions not expressly incorporated by reference into this Report. Those portions not expressly incorporated by reference are not deemed to be filed with the Securities and Exchange Commission as part of this Report (filed herewith). 22. Subsidiaries of the Registrant (incorporated by reference to Exhibit 22 to Annual Report on Form 10-K for the year ended December 31, 1992). 17 EX-3.1 2 BY-LAWS EXHIBIT 3 SOUTHWESTERN ENERGY COMPANY --------------------------- BY-LAWS * * * * * * ARTICLE I --------- STOCKHOLDERS SECTION 1. The place for holding all meetings of stockholders shall be the --------- office of the Corporation in the City of Fayetteville, State of Arkansas, or at such other place or places as shall be decided upon from time to time by the Board of Directors of the Corporation. The presiding officer, who shall conduct all stockholder meetings, shall be the Chairman of the Board or in the absence of a Chairman of the Board shall be the President, or in the absence of the President a member of the Board of Directors selected by the other members of the Board of Directors. At any meeting requiring a vote of the stockholders for the election of directors or for any other purpose requiring a ballot and vote by the stockholders there shall be two judges of election, appointed by the Chairman of the meeting, who shall take an oath of office to faithfully perform their duties. The judges of election shall canvass the meeting, determine the number of stockholders present in person and by proxy and determine if a quorum is present. It shall be the duty of the judges of election to examine, validate and tabulate the proxies voted and the votes cast in person. Upon completion of the tabulation, their report shall be read to the meeting and the results of such elections then formally declared by the Chairman of the meeting. SECTION 2. VOTING: Stockholders having the right to vote shall be entitled --------- ------ to vote at meetings either in person or by proxy appointed by instrument in writing subscribed by the stockholder or by his duly authorized attorney. Such stockholder shall be entitled to one vote for each share of stock having voting power registered in his name on the books of the Company. A complete list of the stockholders entitled to vote at any election of directors, arranged in alphabetical order with the address of each and the number of voting shares held by each, shall be prepared by the Secretary and filed in the office where the election is to be held, at least ten days before every election, and shall at all times during the usual hours for business, and during the whole time of said election, be open to examination of any stockholder. SECTION 3. QUORUM: Except as provided in the next section hereof, any --------- ------ number of stockholders together holding at least a majority of the stock issued and outstanding and entitled to vote thereat, who shall be present in person or represented by proxy at any meeting duly called, shall constitute a quorum for the transaction of business. SECTION 4. ADJOURNMENT OF MEETING: If less than a quorum shall be in --------- ---------------------- attendance at any time for which the meeting shall have been called, the meeting may, after the lapse of at least half an hour, be adjourned from time to time by a majority vote of the stockholders present or represented and entitled to vote thereat. If notice of such adjourned meeting is sent to the stockholders entitled to receive the same, such notice also containing a statement of the purpose of the meeting and that the previous meeting failed for lack of a quorum, and that under the provisions of this Section it is proposed to hold the adjourned meeting with a quorum of those present, then any number of stockholders, in person or by proxy, shall constitute a quorum at such meeting unless otherwise provided by statute. SECTION 5. ANNUAL ELECTION OF DIRECTORS: The annual meeting of --------- ---------------------------- stockholders for the election of directors and the transaction of other business shall be held on such date and at such time as may be determined by the Board of Directors from time to time. At each annual meeting, the stockholders entitled to vote thereat shall by plurality vote by ballot elect a Board of Directors, and they may also transact such other corporate business as shall be stated in the notice of meeting. Only persons who are nominated in accordance with the following procedures shall be eligible for election as directors. Nominations of persons for election to the Board of Directors of the Company may be made at a meeting of stockholders by or at the direction of the Board of Directors, by any nominating committee or person appointed by the Board of Directors, or by any stockholder of the Company entitled to vote for the election of directors at the meeting who has complied with the notice procedures set forth in this Section 5 of Article I. Such nominations, other than those made by or at the direction of the Board of Directors, shall be made pursuant to timely notice in writing to the secretary of the Company. To be timely, a stockholder's notice shall be delivered to or mailed and received at the principal executive offices of the Company not less than 50 nor more than 75 days prior to the meeting date; provided, however, that in the event that less than 65 days' notice of the meeting date is given to stockholders, notice by the stockholder must be so received no later than the close of business on the 15th day following the day on which notice of the meeting date was mailed. Such stockholder's notice shall set forth (a) as to each nominee whom the stockholder proposes to nominate for election or reelection as a director, (i) the name, age, business address and residence address of the nominee, (ii) the principal occupation or employment of the nominee, (iii) the class and number of shares of capital stock of the Company which are beneficially owned by the nominee and (iv) any other information relating to the nominee that is required to be disclosed in solicitations for proxies for election of directors pursuant to Schedule 14A under the Securities Exchange Act of 1934, as amended; and (b) as to the stockholder giving the notice, (i) the name and record address of the stockholder and (ii) the class and number of shares of capital stock of the Company that are beneficially owned by the stockholder. The Company may require any proposed nominee to furnish such other information as may reasonably be required by the Company to determine the eligibility of such proposed nominee to serve as a director of the Company. The presiding officer of the meeting shall, if the facts warrant, determine that a nomination was not made in accordance with the foregoing procedure, and if he should so determine, he may so declare to the meeting and the defective nomination shall be disregarded. 2 At any meeting of stockholders, only such business shall be conducted as shall have been properly brought before the meeting. For business to be properly brought before a meeting by a stockholder, the stockholder must have given timely notice thereof to the secretary of the Company. To be timely, such notice must be delivered to or mailed and received at the principal executive offices of the Company not less than 50 nor more than 75 days prior to the meeting date; provided, however, that in the event that less than 65 days' notice of the meeting date is given to stockholders, notice by the stockholder must be so received no later than the close of business on the 15th day following the day on which notice of the meeting date was mailed. Such stockholder's notice shall set forth as to each matter the stockholder proposes to bring before the meeting: (i) a brief description of the business desired to be brought before the meeting and the reasons for conducting such business at the meeting, (ii) the name and address of the stockholder proposing such business, (iii) the class and number of shares of capital stock of the Company that are beneficially owned by such stockholder and (iv) any material interest of such stockholder in such business. The presiding officer of the meeting shall, if the facts warrant, determine that business was not properly brought before the meeting in accordance with the foregoing procedure and, if he should so determine, he may so declare to the meeting and any such business not properly brought shall not be transacted. Notwithstanding the provisions of this paragraph, so long as the Company is subject to Rule 14a-8 under the Securities Exchange Act of 1934, as amended, business consisting of a proposal properly included in the Company's proxy statement with respect to a meeting pursuant to such Rule may be transacted at a meeting. SECTION 6. SPECIAL MEETING - HOW CALLED: Special meetings of the --------- ---------------------------- stockholders for any purpose or purposes may be called by the President or Secretary, and shall be called upon a resolution in writing therefor, stating the purpose or purposes thereof, delivered to the President or Secretary, signed by two directors or by a majority in interest of the stockholders entitled to vote, or by resolution of the directors. The record date for determining stockholders entitled to request a special meeting shall be fixed by the Board of Directors of the Company. Any stockholder seeking to request a special meeting shall, by written notice, request the Board of Directors to fix a record date. The Board of Directors shall, upon receipt of such a request, fix the record date in accordance with Section 4-27-707 of the Arkansas Business Corporation Act of 1987 (the "ABCA"). If the record date falls on a Saturday, Sunday or legal holiday, the record date shall be the day next following which is not a Saturday, Sunday or legal holiday. SECTION 7. MANNER OF VOTING AT STOCKHOLDERS MEETINGS: At all meetings of --------- ----------------------------------------- stockholders all questions, except as otherwise expressly provided by statute or by these By-Laws, shall be determined by a majority vote of the stockholders present in person or represented by proxy and entitled to vote; provided, however, that any qualified voter may demand a vote by ballot, and in that case, such vote shall immediately be taken. 3 SECTION 8. NOTICE OF STOCKHOLDERS MEETING: Written or printed notice, --------- ------------------------------ stating the place and time of the meeting, shall be given by the Secretary to each stockholder entitled to vote thereat at his last known post office address, at least ten (10) days before the meeting in the case of an annual meeting and five (5) days before the meeting in the case of a special meeting. SECTION 9. SPECIFIC POWERS OF STOCKHOLDERS: The directors in their --------- ------------------------------- discretion may submit any contract or act for approval or ratification at any annual meeting of the stockholders or at any meeting of the stockholders called for the purpose of considering any such act or contract, and any contract or act that shall be approved or be ratified by the vote of the holders of a majority of the capital stock of the Corporation which is represented in person or by proxy at such meeting (provided that a lawful quorum of stockholders be there represented in person or by proxy) shall be as valid and as binding upon the Corporation and upon all the stockholders, as though it had been approved or ratified by every stockholder of the Corporation, whether or not the contract or act would otherwise be open to legal attack because of directors' interest, or for any other reason. SECTION 10. ACTION WITHOUT MEETING: ----------------------------------- (a) Notice of Action by Written Consent. Prompt notice of the taking of ----------------------------------- any action without a meeting pursuant to Section 4-27-704 of the Arkansas Business Corporation Act of 1987 (the "ABCA"), by less than unanimous written consent, shall be given to those stockholders who have not consented in writing. (b) Record Date. The record date for determining stockholders entitled to ----------- express consent to an action in writing without a meeting shall be fixed by the Board of Directors of the Company. Any stockholder seeking to have the stockholders authorize or take action by written consent without a meeting shall, by written notice, request the Board of Directors to fix a record date. The Board shall, upon receipt of such a request, fix the record date in accordance with Section 4-27-707 of the ABCA. If the record date falls on a Saturday, Sunday or legal holiday, the record date shall be the day next following which is not a Saturday, Sunday or legal holiday. (c) Date of Consent. The date for determining if an action has been --------------- consented to by the holder or holders of shares having requisite voting power to authorize or take the action specified therein (the "Consent Date") shall be the close of business on the 31st day after the later of (x) the record date fixed pursuant to paragraph (b) of this Section 10 and (y) the date on which materials soliciting consents are mailed to stockholders if such materials are required to be mailed under applicable law. If the Consent Date falls on a Saturday, Sunday or legal holiday, the Consent Date shall be the day next following which is not a Saturday, Sunday or legal holiday. On or prior to the Consent Date, consents may be revoked by written notice (i) to the Company, (ii) to the stockholder or stockholders soliciting consents or soliciting revocations in opposition to 4 action by consent proposed by the Company (the "Soliciting Stockholders"), or (iii) to a proxy solicitor or other agent designated by the Company or the Soliciting Stockholder. (d) Procedures. In the event of the delivery to the Company of a written ---------- consent or consents purporting to authorize or take action and/or related revocations (each such written consent and related revocation being referred to in this Section 10 as a "Consent"), the Secretary of the Company shall provide for the safekeeping of such Consent and, as soon as practicable after the Consent Date, shall conduct such reasonable investigation as he deems necessary or appropriate for the purpose of ascertaining the validity of such Consent and all matters incident thereto, including, without limitation, whether the holders of shares having the requisite voting power to authorize or take the action specified in the Consent have given consent; provided, however, that if the -------- ------- action to which the Consent relates is the removal or replacement of one or more members of the Board, the Secretary of the Company shall designate two persons, who may not be members of the Board or otherwise affiliated with the Company, or a firm of nationally recognized independent inspectors of election, to serve as Inspectors with respect to such Consent and such Inspectors shall discharge the functions of the Secretary of the Company under this paragraph (d). If after such investigation the Secretary or the Inspectors (as the case may be) shall determine that the Consent is valid, that fact shall be certified on the records of the Company kept for the purpose of recording the proceedings of meetings of stockholders, and the Consent shall be filed in such records, at which time the Consent shall become effective as stockholder action as of the fifth business day following such certification. ARTICLE II ---------- DIRECTORS SECTION 1. FIRST MEETING: The newly elected directors may hold their first --------- ------------- meeting for the purpose of organization and the transaction of business, if a quorum be present, immediately after the annual meeting of the stockholders; or the time and place of such meeting may be fixed by consent in writing of all the directors. SECTION 2. ELECTION OF OFFICERS: At such meeting the directors may elect a --------- -------------------- Chairman of the Board and shall elect a President from their number, one or more Vice Presidents, a Secretary and a Treasurer, who need not be directors. Such officers shall hold office until the next annual election of officers and until their successors are elected and qualify. In case such officer shall not be elected at such first meeting, they may be chosen at any subsequent meeting of directors called for the purpose. SECTION 3. REGULAR MEETINGS: Regular meetings of the directors may be held --------- ---------------- without notice at such place, either within or without the State of Arkansas, and at such time as shall be determined from time to time by resolution of the directors. 5 SECTION 4. SPECIAL MEETINGS - HOW CALLED - NOTICE: Special meetings of the --------- -------------------------------------- Board may be called by the President or by the Secretary on the written request of any two directors upon notice given to each director by letter delivered at least two days before the meeting or by telegram delivered at least one day before the meeting or by such shorter telephone or other notice as the person or persons calling the meeting may deem appropriate in the circumstances. SECTION 5. NUMBER, QUORUM, QUALIFICATIONS AND RETIREMENT: --------- --------------------------------------------- (a) The number of directors shall be five (5). A majority of the directors shall constitute a quorum for the transaction of business. Directors need not be stockholders. Directors shall retire after reaching the age of 78 in 1995, 77 in 1996, 76 in 1997, and 75 in any year thereafter. (b) Any director retiring in the year 1994 or after and meeting all of the requirements of this Section 5 shall be appointed to the position of director emeritus. Directors emeriti shall be invited, but not required, to attend each board of directors meeting and any board committee meetings they may be assigned to as ad hoc members. At such meetings directors emeriti shall participate in all discussions but shall not be entitled to vote on any matter. (c) Only existing non-employee members of the board of directors are eligible to become directors emeriti. Employee members of the board of directors will become eligible for the position of director emeritus after their employee status has ended. Any director becoming a director emeritus is no longer eligible for election as a director. (d) A director shall become a director emeritus and not eligible for renomination as director after 20 years of service and having attained the age of 78 in 1995, 77 in 1996, 76 in 1997, and 75 in any year thereafter. (e) A director emeritus may resign at any time. A director emeritus shall be discharged if that director emeritus shall fail to attend, except for good cause, three consecutive regularly scheduled meetings or one half of the regular scheduled meetings in a calendar year. A director emeritus shall receive a fee of $1,000 for each meeting attended or such other fee as may be set by the board of directors and shall be reimbursed for his reasonable expenses incurred in attending a meeting. SECTION 6. PLACE OF MEETING: The directors may hold their meetings and --------- ---------------- have one or more offices, and keep the books of the Company outside the State of Arkansas, at any office or offices of the Company, or at any other place as they may from time to time by resolution determine; provided, however, that a duplicate stock ledger shall always be kept at the principal office in Arkansas. 6 SECTION 7. GENERAL POWERS OF DIRECTORS: The Board of Directors shall have --------- --------------------------- the management of the business of the Company, and subject to the restrictions imposed by law, by the Certificate of Incorporation, or by these By-Laws, may exercise all the powers of the Corporation. SECTION 8. SPECIFIC POWERS OF DIRECTORS: Without prejudice to such general --------- ---------------------------- powers it is hereby expressly declared that the directors shall have the following powers, to wit: (1) To adopt and alter a common seal of the Corporation. (2) To make and change regulations, not inconsistent with these By-Laws, for the management of the Company's business and affairs. (3) To purchase or otherwise acquire for the Company any property, rights or privileges which the Company is authorized to acquire. (4) To pay for any property purchased for the Company either wholly or partly in money, stock, bonds, debentures or other securities of the Company. (5) To borrow money and to make and issue notes, bonds and other negotiable and transferable instruments, mortgages, deeds of trust and trust agreements, and to do every act and thing necessary to effectuate the same. (6) To remove any officer for cause, or any officer other than the President summarily without cause, and in their discretion, from time to time, to devolve the powers and duties of any officer upon any other person for the time being. (7) To appoint and remove or suspend such subordinate officers, agents or factors, as they may deem necessary, and to determine their duties, and fix and, from time to time, change their salaries or remuneration, and to require security as and when they think fit. (8) To confer upon any officer of the Company the power to appoint, remove and suspend subordinate officers, agents and factors. (9) To determine who shall be authorized on the Company's behalf to make and sign bills, notes, acceptances, endorsements, checks, releases, receipts, contracts and other instruments. (10) To determine who shall be entitled to vote in the name and behalf of the Company, or to assign and transfer, any shares of stock, bonds, or other securities of other corporations held by the Company. (11) To delegate any of the powers of the Board in relation to the ordinary business of the Company to any standing or special committee, or to any officer, or agent (with power of subdelegate), upon such terms as they think fit. 7 (12) To call special meetings of the stockholders for any purpose or purposes. (13) To submit any contract or act for authorization or ratification by the stockholders in the manner and with the effect provided in Section 9 of Article I. SECTION 9. COMPENSATION OF DIRECTORS: By resolution of the Board, the --------- ------------------------- directors may be paid their expenses of attendance and may be paid a fixed fee for attendance at each meeting of the Board of Directors or a stated fee as director. No such payment or anything herein contained shall preclude any director from serving the Company in any other capacity as an officer, attorney, agent or otherwise and receiving compensation therefor. ARTICLE III ----------- EXECUTIVE COMMITTEE SECTION 1. HOW APPOINTED: The directors may appoint from their number an --------- ------------- executive committee which may make its own rules of procedure and shall meet where and as provided by such rules, or by a resolution of the directors. A majority shall constitute a quorum, and in every case the affirmative vote of a majority of all the members of the committee shall be necessary to the adoption of any resolution. SECTION 2. POWERS: During the intervals between the meetings of the --------- ------ directors the executive committee shall have and may exercise all the powers of the directors in the management of the business and affairs of the Company, including power to authorize the seal of the Company to be affixed to all papers which may require it, in such manner as such committee shall deem best for the interests of the Company, in all cases in which specific directions shall not have been given by the directors. ARTICLE IV ---------- OFFICERS SECTION 1. The officers of the Company may be a Chairman of the Board, --------- which office may be filled by resolution of the Board of Directors, and shall be a President, one or more Vice Presidents, one of whom to be designated as Executive Vice President and shall have senior authority, a Secretary, a Treasurer, and such assistants and other officers as may from time to time be elected or appointed by the Board of Directors. Any two offices (but not more than two) may be held by the same person. SECTION 2. CHAIRMAN OF THE BOARD OF DIRECTORS: The Chairman of the Board --------- ---------------------------------- of Directors shall preside at all meetings of the stockholders and of the Board of Directors; and by virtue of his office shall be a member of the executive committee. He shall have supervision of such matters as may be designated to him by the Board of Directors or the executive committee. 8 SECTION 2-A. VICE CHAIRMAN OF THE BOARD OF DIRECTORS: The Vice Chairman of ----------- --------------------------------------- the Board of Directors shall be vested with all the powers and shall perform all the duties of the Chairman in the absence or disability of the latter unless or until the Board of Directors shall otherwise determine. He shall have such other powers and perform such other duties as shall be prescribed by the Board of Directors. SECTION 3. PRESIDENT: The President shall, in the absence of a Chairman of --------- --------- the Board, preside at all meetings of the directors, and act as Chairman at, and call to order all meetings of the stockholders; and he shall have power to call special meetings of the stockholders and directors for any purpose or purposes, appoint and discharge, subject to the approval of the directors, employees and agents of the Corporation and fix their compensation, make and sign contracts and agreements in the name and behalf of the Corporation, except that he be not authorized to dispose or encumber material assets of the Corporation without the authority of the Board of Directors, and while the directors and/or committees are not in session he shall have general management and control of the business and affairs of the Corporation; he shall see that the books, reports, statements and certificates required by the statute under which this Corporation is organized or any other laws applicable thereto are properly kept, made and filed according to law; and he shall generally do and perform all acts incident to the office of President, or which are authorized or required by law. SECTION 4. VICE PRESIDENTS: The Vice Presidents in the order of their --------- --------------- seniority shall be vested with all the powers and shall perform all the duties of the President in the absence or disability of the latter, unless or until the directors shall otherwise determine. They shall have such other powers and perform such other duties as shall be prescribed by the directors. SECTION 5. SECRETARY: The Secretary shall give, or cause to be given, --------- --------- notice of all meetings of the stockholders and directors, and all other notices required by law or by these By-Laws, and in case of his absence or refusal or neglect so to do, any such notice may be given by any person thereunto directed by the President, or by the directors or stockholders upon whose requisition the meeting is called as provided in these By-Laws. He shall record all proceedings of the meetings of the Corporation and of the directors in a book to be kept for that purpose, and shall perform such other duties as may be assigned to him by the directors or the President. He shall have custody of the seal of the Company and shall affix the same to all instruments requiring it, when authorized by the directors or the President, and attest the same. He shall be sworn to the faithful discharge of his duties. SECTION 6. ASSISTANT SECRETARY: The Assistant Secretary shall be vested --------- ------------------- with the powers and shall perform all the duties of Secretary in the absence or disability of the latter, unless or until the directors shall otherwise determine. He shall have such other powers and perform such other duties as shall be prescribed by the directors. SECTION 7. TREASURER: The Treasurer shall have the custody of all funds, --------- --------- securities, evidences of indebtedness and other valuable documents 9 of the Company; he shall receive and give or cause to be given receipts and acquittances for moneys paid in on account of the Company and shall pay out of the funds on hand all just debts of the Company of whatever nature upon maturity of the same; he shall enter or cause to be entered in books of the Company to be kept for that purpose full and accurate accounts of all monies received and paid out on account of the Company, and, whenever required by the President or the Board of Directors, he shall render a statement of his cash accounts. He shall, unless otherwise determined by the Board of Directors, have charge of the original stock books, transfer books and stock ledgers and act as transfer agent in respect of the stock and securities of the Company; he shall prepare and submit from time to time to the Board of Directors financial, cash and operating budgets or estimates; he shall prepare and submit such other financial data and information as he shall be directed to by the Board of Directors; and he shall perform all of the other duties incident to the office of Treasurer. He shall give the Company a bond for the faithful discharge of his duties in such amount and with such surety as the Board of Directors shall prescribe. SECTION 8. ASSISTANT TREASURER: The Assistant Treasurer shall be vested --------- ------------------- with all the powers and shall perform all the duties of Treasurer in the absence or disability of the latter, unless or until the directors shall otherwise determine. He shall have such other powers and perform such other duties as shall be prescribed by the directors. SECTION 9. CONTROLLER: The Corporate Controller shall be responsible for --------- ---------- directing the Corporation's accounting functions. Specific areas include the development and maintenance of planning and budgeting systems, analysis and interpretation of trends requiring management's attention, the preparation of financial and management reports and procedures, and senior management. Ancillary responsibilities include the supervision of external auditors, and participation in the planning and execution of the utility rate cases. ARTICLE V --------- RESIGNATIONS: FILLING OF VACANCIES: INCREASE OF NUMBER OF DIRECTORS SECTION 1. RESIGNATIONS: Any director, member of a committee or other --------- ------------ officer may resign at any time. Such resignation shall be made in writing and shall take effect at the time specified therein, and if no time be specified, at the time of its receipt by the President or Secretary. The acceptance of a resignation shall not be necessary to make it effective. SECTION 2. FILLING OF VACANCIES: If the office of any director, member of --------- -------------------- a committee or other office becomes vacant, the directors in office may appoint any qualified person to fill such vacancy, who shall hold office for the unexpired term and until his successor shall be duly chosen. 10 SECTION 3. INCREASE OF NUMBER OF DIRECTORS: The number of directors may be --------- ------------------------------- increased at any time by the affirmative vote of a majority of the directors, (or, by the affirmative vote of a majority in interest of the stockholders), at a special meeting called for that purpose, and by like vote the additional directors may be chosen at such meeting to hold office until the next annual election and until their successors are elected and qualify. ARTICLE VI ---------- CAPITAL STOCK SECTION 1. ISSUE OF CERTIFICATES OF STOCK: The President shall cause to be --------- ------------------------------ issued to each stockholder one or more certificates, under the seal of the Company, signed by the President or Vice President and the Treasurer or Assistant Treasurer, or Secretary or Assistant Secretary, certifying the number of shares owned by him in the Company; provided, when any such certificate is signed by a transfer agent or registrar, the signature of any officer of the Company or its corporate seal, or both such signatures and seal, may be facsimiles engraved or printed. SECTION 2. LOST CERTIFICATES: A new certificate of stock may be issued in --------- ----------------- the place of any certificate theretofore issued by the Corporation, alleged to have been lost or destroyed, and the directors may, in their discretion, require the owner of the lost or destroyed certificate, or his legal representatives, to give the Corporation a bond, in such sum as they may direct, not exceeding double the value of the stock, to indemnify the Company against any claim that may be made against it on account of the alleged loss of any such certificate or the issuance of any such new certificate. SECTION 3. TRANSFER OF SHARES: The shares of stock of the Company shall be --------- ------------------ transferable only upon its books by the holders thereof in person or by their duly authorized attorneys or legal representatives, and upon such transfer the old certificates shall be surrendered to the Company by the delivery thereof to the person in charge of the stock and transfer books and ledgers, or to such other person as the directors may designate, by whom they shall be cancelled, and new certificates shall thereupon be issued. A record shall be made of each transfer and whenever a transfer shall be made for collateral security, and not absolutely, it shall be so expressed in the entry of the transfer. SECTION 4. CLOSING OF TRANSFER BOOKS: The Board of Directors shall have --------- ------------------------- power to close the stock transfer books of the Corporation for a period not exceeding twenty (20) days preceding the date of any meeting of stockholders or the date for payment of any dividend or the date for the allotment of rights or the date when any change or conversion or exchange of capital stock shall go into effect; provided, however, that in lieu of closing the stock transfer books as aforesaid, the Board of Directors may fix in advance a date, not exceeding sixty-five (65) days preceding the date of any meeting of stockholders or the date for the payment of any dividend, or the date for the allotment of rights, or the date when any change or conversion or exchange of capital stock shall go into effect, as 11 a record date for the determination of the stockholders entitled to notice of, and to vote at, any such meeting, or entitled to receive payment of any such dividend or to any such allotment of rights, or to exercise the rights in respect of any such change, conversion or exchange of capital stock, and in such case such stockholders only as shall be stockholders of record on the date so fixed shall be entitled to such notice of, and to vote at, such meeting, or to receive payment of such dividend, or to receive such allotment rights, or to exercise such rights, as the case may be, not withstanding any transfer of any stock on the books of the Corporation after such record date fixed as aforesaid. SECTION 5. DIVIDENDS: The directors may declare dividends from the surplus --------- --------- or net profits arising from the business of the Corporation as and when they deem expedient. Before declaring any dividend there may be reserved out of the accumulated profits such sum or sums as the directors from time to time in their discretion think proper for working capital or as a reserve fund to meeting contingencies or for equalizing dividends or for such other purposes as the directors shall think conducive to the interests of the Company. The directors may close the transfer books for not exceeding twenty (20) days next preceding the day appointed for the payment of any dividend. ARTICLE VII ----------- MISCELLANEOUS PROVISIONS SECTION 1. CORPORATE SEAL: The corporate seal shall be circular in form --------- -------------- and shall contain the name of the Corporation, and the word "Seal." Said seal may be used by causing it or a facsimile thereof to be impressed or affixed or reproduced or otherwise. SECTION 2. FISCAL YEAR: The fiscal year of the Company shall be the --------- ----------- calendar year. SECTION 3. PRINCIPAL OFFICE: The principal office of this Corporation --------- ---------------- shall be established and maintained at 1083 Sain Street in the City of Fayetteville, Washington County, State of Arkansas, and there shall be kept at such office a book containing the names alphabetically arranged of stockholders of the Corporation and their addresses and the number of shares held by them respectively. SECTION 4. CHECKS, DRAFTS, NOTES: All checks, drafts or other orders for --------- --------------------- the payment of money, notes, or other evidences of indebtedness issued in the name of the Corporation shall be signed by the President or such other officer or officers, agent or agents of the Corporation, and in such manner as shall from time to time be determined by resolution of the Board of Directors. SECTION 5. NOTICE AND WAIVER OF NOTICE: Whenever any notice is required by --------- --------------------------- these By-Laws to be given, personal notice is not meant unless expressly so stated, and any notice so required shall be deemed to be sufficient if given by depositing the same in a post office box in a sealed postpaid wrapper, addressed to the person entitled thereto at his last 12 known post office address, and such notice shall be deemed to have been given on the date of such mailing. Any notice required to be given under these By-Laws may be waived by the person entitled thereto. Stockholders not entitled to vote shall not be entitled to receive notice of any meetings except as otherwise provided by statute. SECTION 6. INDEMNIFICATION OF DIRECTORS AND OFFICERS: Directors and --------- ----------------------------------------- officers of the Company shall be indemnified to the fullest extent now or hereafter permitted by law in connection with any actual or threatened action or proceeding (including civil, criminal, administrative or investigative proceedings) arising out of their service to the Company or to any other organization at the Company's request. Employees and agents of the Company who are not directors or officers thereof may be similarly indemnified in respect of such service to the extent authorized at any time by the Board of Directors. The provisions of this Section shall be applicable to actions or proceedings commenced after the adoption hereof, whether arising from acts or omissions occurring before or after the adoption hereof, and to persons who have ceased to be directors, officers or employees and shall inure to the benefit of their heirs, executors, and administrators. For the purposes of this Section, directors, officers, trustees or employees of an organization shall be deemed to be rendering service thereto at the Company's request if such organization is, directly or indirectly, a wholly owned subsidiary of the Company or is designated by the Board of Directors as an organization service to which shall be deemed to be so rendered. SECTION 7. ADVANCEMENT OF LITIGATION EXPENSES: Expenses incurred by a ---------------------------------------------- director or officer of the Corporation in defending any actual or threatened action, or proceeding (including civil, criminal, administrative or investigative proceedings) arising out of their service to the Company or to any other organization at the Company's request shall be paid by the Company in advance of the final disposition of such action or proceeding upon receipt of an undertaking by, or on behalf of, such person to repay such amount if it shall ultimately be determined that he is not entitled to be indemnified by the Company as authorized by the relevant provisions of the Arkansas Business Corporation Act as it now exists or as it may hereafter be amended. Such expenses of employees and agents of the Company who are not directors or officers may be similarly advanced to the extent authorized at any time by the Board of Directors. The provisions of this section shall be applicable to actions or proceedings commenced after the adoption hereof, whether arising from acts occurring before or after the adoption hereof, and to persons who have ceased to be directors, officers, and employees and shall inure to the benefit of their heirs, executors, and administrators. For the purposes of this section, directors, officers, trustees, or employees of an organization shall be deemed to be rendering service thereto at the Company's request if such organization is, directly or indirectly, a wholly owned subsidiary of the Company or is designated by the Board of Directors as an organization service to which shall be deemed to be so rendered. 13 ARTICLE VIII ------------ AMENDMENTS SECTION 1. AMENDMENT OF BY-LAWS: The stockholders, by the affirmative vote --------- -------------------- of the holders of a majority of the stock issued and outstanding, or the directors, by the affirmative vote of a majority of the directors, may at any meeting, provided the substance of the proposed amendment shall have been stated in the notice of the meeting, amend or alter any of these By-Laws. 1/95 14 EX-10.1 3 GAS PURCHASE AGREEMENT EXHIBIT 10.1 GAS PURCHASE AGREEMENT AMENDED AND RESTATED CONTRACT 59 between SEECO, INC. SELLER and ARKANSAS WESTERN GAS COMPANY BUYER ARKANSAS WESTERN GAS COMPANY GAS PURCHASE CONTRACT SELLER: SEECO, INC. CONTENTS --------
Section Page ------- ---- 1. Definitions................................................... 1 2. Term.......................................................... 3 3. Delivery...................................................... 3 4. Equipment..................................................... 3 5. Price......................................................... 3 6. Taxes......................................................... 4 7. Pressure...................................................... 4 8. Quantities.................................................... 5 9. Royalties..................................................... 7 10. General Terms and Conditions.................................. 8 11. Condensate.................................................... 8 Signature of the Parties........................................... 9
GENERAL TERMS AND CONDITIONS SUPPLEMENT --------------------------------------- (A) Measurement (H) Force Majeure (B) Quality (I) Warranty (C) Addresses and Notices (J) Termination on Default (D) Successors and Assigns (K) Arbitration (E) Multiple Completions (L) Commingled Stream (F) Easements (M) Operation of Wells (G) Government Regulations EXHIBIT A AMENDED AND RESTATED CONTRACT 59 THIS AGREEMENT, executed this 3rd day of February, 1995, by and between ARKANSAS WESTERN GAS COMPANY, an Arkansas corporation, hereby referred to as "Buyer," and SEECO, INC., an Arkansas corporation herein referred to as "Seller." WITNESSETH THAT: 1. Buyer and Seller have previously entered into a gas purchase contract dated July 24, 1978, which is known to the parties as "Contract 59." As a result of a certain stipulation and agreement entered into by the parties in Arkansas Public Service Commission Docket No. 92-028-U, the parties desire to amend and restate Contract 59 to include the terms contained herein. This Amended and Restated Contract 59 constitutes the entire agreement of the parties with respect to the subject matter hereof from the Effective Date forward and supersedes all previous versions of Contract 59 and all previous amendments thereto. THEREFORE, for and in consideration of the premises and mutual covenants herein contained, the parties hereby contract as follows: Section 1: DEFINITIONS. As used in this contract, the following terms and ----------- phrases shall have the following particular meanings. (A) "AWG Division" refers to Buyer's Northwest Arkansas gas utility -------------- operations but shall not include the operations of Buyer's Associated Natural Gas Company Division in Northeast Arkansas and parts of Missouri. (B) "Contract Year" shall be the same as the calendar year, except that the --------------- first Contract Year shall begin on the Effective Date and end on December 31, 1994, while the last Contract Year shall begin on January 1, 1998 and end on July 24, 1998. (C) "Contract Annual Volume" refers to an annual volume equal to 9.0 ------------------------ billion cubic 1 feet ("Bcf"), however, for the period from the Effective Date to December 31, 1994, the Contract Annual Volume shall be 4.906 Bcf, and for the period January 1, 1998 to the Primary Expiration Date, the Contract Annual Volume shall be 5.25 Bcf. (D) "Contract Daily Maximum" refers to 58,000 Mcf/d. ------------------------ (E) "Contract Price Schedule" refers to the price to be paid for gas ------------------------- delivered hereunder during the term hereof. Gas shall be assumed to be delivered on a dry basis, subject to such adjustments as may be authorized by the contract. The price per thousand cubic feet ("Mcf") payable for volumes purchased hereunder shall be equal to the index as published in Inside FERC's ------------- Gas Market Report (Prices of Spot Gas Delivered to Pipelines, per MMBtu dry) for ----------------- the first day of the applicable month for deliveries into NorAm Gas Transmission Company from Arkansas and Oklahoma plus the premiums described below:
Contract Year Volume Premium ------------------------ --------- --------- 1994 (July 1 - 3.816 Bcf $.95/Mcf December 31) 1.09 Bcf $.50/Mcf 1995 7.0 Bcf $.95/Mcf 2.0 Bcf $.50/Mcf 1996 7.0 Bcf $.95/Mcf 2.0 Bcf $.50/Mcf 1997 7.0 Bcf $.95/Mcf 2.0 Bcf $.50/Mcf 1998 (January 1 - 4.083 Bcf $.95/Mcf July 24) 1.167 Bcf $.50/Mcf
During each month of each Contract Year, the different premiums will be applied on a pro rata basis to all purchases made hereunder throughout the Contract Year up to the Contract Annual Volume. In the event that the above described index ceases to be available, Buyer and Seller 2 shall select a mutually agreeable replacement index as promptly as possible. (F) "Effective Date" refers to the date July 1, 1994. ---------------- (G) "Primary Expiration Date" refers to 7:00 a.m. on July 24, 1998. ------------------------- (H) "Point(s) of Delivery" refers to the inlet of Buyer's metering ---------------------- facilities to be located at or near each of the wells from which gas is delivered hereunder or such other point or points as may be designated by Seller from time to time. All Points of Delivery shall be either directly connected to Buyer's system or deliverable to Buyer's system at no additional cost to Buyer. Section 2: TERM. ---- This contract shall continue in effect until the Primary Expiration Date. Section 3: DELIVERY. -------- The gas shall be delivered and title and responsibility shall pass to Buyer at the Point of Delivery. Responsibility for damage caused by, or arising out of possession of, the gas prior to its passage at the Point of Delivery shall be borne by Seller. Section 4: EQUIPMENT. --------- Seller, at Seller's sole cost, risk and expense, shall be responsible for the diligent and workmanlike construction, operation and maintenance of all equipment and roads necessary to enable Seller to effect deliveries of gas in accordance with the contract to Buyer at the Point of Delivery. Buyer shall be responsible for the diligent and workmanlike construction, operation and maintenance of all equipment necessary to receive deliveries of gas under this contract at the Point of Delivery. Section 5: PRICE. ----- 3 (A) Subject to the other provisions hereof, Buyer shall pay to Seller the applicable price under the Contract Price Schedule for each Mcf of gas delivered to Buyer hereunder. (B) Buyer agrees to pay Seller on or before the twenty-fifth (25th) day of each calendar month following Buyer's accounting month for all gas delivered during such prior accounting month. (C) Should the heating value of the gas delivered hereunder be found to be more or less than one thousand (1,000) British thermal units ("Btu") per cubic foot, the price provided for in this Section 5 shall be adjusted by multiplying the price otherwise payable by a fraction whose numerator is the Btu content of gas delivered hereunder, measured on a dry basis, and whose denominator is one thousand (1,000). There shall be no other adjustments to the price payable hereunder. Section 6: TAXES. ----- All taxes now or hereafter imposed in respect of any production from wells from which gas is delivered hereunder shall be accounted for and paid to the taxing authority by the party liable for such tax under the language of the statute imposing same, provided that Buyer shall have the right, at Buyer's option, to account for and pay to the taxing authority for Seller's account any or all such taxes for which Seller may be liable. Buyer further agrees to reimburse Seller for 100% of any new, increased or additional taxes (exclusive of ad valorem or income taxes) imposed after July 24, 1978 on gas prior to delivery to Buyer. Section 7: PRESSURE. -------- Seller shall deliver gas hereunder at the normal operating pressure contained in Buyer's pipeline system from time to time. 4 Section 8: QUANTITIES. ---------- (A) (1) Subject to the further provisions hereof, Buyer agrees to purchase and receive during each Contract Year the Contract Annual volume. (2) Buyer's receipts of gas hereunder will fluctuate from time to time because of Buyer's fluctuating requirements for its system, and Buyer shall take gas hereunder at a rate which matches as closely as reasonably possible the rate of consumption of its AWG Division utility sales customers; provided, however, that Buyer may take gas for injection into its storage facilities in such volumes and at such times as Buyer reasonably deems necessary to meet the requirements of its AWG Division utility customers. Buyer shall balance its receipts hereunder over each Contract Year in order to receive the Contract Annual Volume for that Contract Year, provided that to permit such balancing of receipts Buyer shall have the right to require deliveries hereunder at a daily rate of at least the Contract Daily Maximum. Nothing herein is intended to limit Buyer's right to request deliveries from time to time at daily rates in excess of the Contract Daily Maximum provided Seller is willing and able to sell such excess volumes hereunder. (B) The provisions of this section are subject to all the other terms and conditions of this contract and the rules and regulations of any regulatory authority having jurisdiction. (C) Buyer may request to purchase hereunder, in addition to the Contract Annual Volumes provided to be received hereunder, such additional volumes of gas as Buyer may in the prudent operation of its business require from time to time and which Seller is willing and able to sell hereunder. The price payable by Buyer for such volumes shall be determined in the month of delivery using the same index, assumptions, and adjustments described in the Contract 5 Price Schedule plus a total premium over the index of $.50/Mcf. (D) Seller recognizes that the efficient conduct of Buyer's business requires the operation of Points of Delivery in accordance with the demands of the system taking into consideration Buyer's take requirements under other gas purchase contracts, and Seller agrees that Buyer shall operate any wells designated as Points of Delivery and which are directly connected to Buyer's pipeline system, as well as any other Points of Delivery which are directly connected to Buyer's pipeline system, in accordance with the needs of its utility system and with good field operating practices, and Buyer shall supply at its sole cost and expense and by its own means and methods such labor as may be required to operate said wells or other Points of Delivery and to perform such other duties as are ordinarily required in the regular course of producing and operating said wells or other Points of Delivery except that any remedial work on wells such as a well workover or a recompletion shall be done by and paid by Seller. (E) Seller may designate additional wells to be connected to Buyer's system, and Buyer shall promptly connect such wells; provided however, that Buyer shall not be obligated, but shall have the right at its option, to connect its system to and receive gas from any particular well or wells if Buyer's estimate of the cost of the facilities necessary to connect the well to Buyer's then existing system is more than $20,000 per Bcf of gas reserves. By "cost of facilities" is meant the cost of the right of way, cost of pipe and other equipment necessary, and cost of installing same. If it is not economically feasible for Buyer to connect to a well under the foregoing cost standard, Buyer, at Seller's request, shall make such connection if Seller shall agree to contribute to Buyer the portion of the actual cost of the facilities in excess of $20,000 per Bcf of gas reserves, as set forth above, or Seller may, at Seller's option and at Seller's cost, 6 risk and expense, install, own, operate and maintain the necessary facilities to deliver gas from the particular well to Buyer at a mutually agreeable point which is close enough to Buyer's then existing system so that it will be "economically feasible" under the cost standard hereinabove set forth for Buyer to connect to such mutually agreeable point; and, in such event, Buyer shall be obligated to connect to that point, and the "Point of Delivery" for purposes of this contract as to the gas from that particular well shall be the inlet of Buyer's meter installation at that point. Section 9: ROYALTIES. --------- Seller shall bear all royalties, overriding royalties, production payments, and other payments and settlements of whatsoever kind and nature due with respect to production delivered hereunder or the failure to deliver, and shall hold Buyer harmless against all claims, losses, damages and expenses on account of such settlements. Seller further agrees to indemnify Buyer against any and all royalty owner claims arising prior to July 1, 1994 or subsequently as a result of any actions taken under a certain stipulation and agreement dated October 31, 1994 in Arkansas Public Service Commission Docket No. 92-028-U or this Amended and Restated Contract 59. Seller will from time to time on request furnish to Buyer reasonable evidence of title, including abstracts and division orders covering all interests in gas subject to this agreement, but no examination, reliance, or action of Buyer thereon or pursuant thereto shall impair Seller's warranties and other agreements in this section contained. Buyer agrees to deduct from sums owing by it hereunder the amounts due to the respective holders of royalty and any overriding royalty interests and to holders of undivided leasehold or mineral interests controlled but not 7 owned by Seller and to pay such amounts direct to the persons entitled thereto according to the applicable division orders, accounting to Seller only for the remainder. It is understood that Buyer may from time to time deduct from any monies payable hereunder on account of gas purchased, pro rata, and pay over to governmental authorities, the amount of any and all taxes or other proper charges due to governmental authorities on account of the production or sale of natural gas purchased by Buyer hereunder, if required or permitted by applicable law or regulation to be deducted from the purchase price of gas for purposes of such payment over. In the event that any of Seller's leasehold or mineral interests in any well designated as a Point of Delivery or its right to sell gas hereunder or any royalty, overriding royalty or other interest in subject gas shall be called in question at any time by pending litigation, in law or in equity, or by formal notice from one or more adverse claimants directed to Buyer, Buyer may withhold without interest sums accruing hereunder on account of the interest or interests so called in question until the question shall be finally adjudicated or compromised or until there shall be furnished to Buyer a corporate surety bond in form and amount satisfactory to Buyer protecting it from all loss or expense it may suffer or incur by reason of the controversy; provided that no provision of this section and no action taken pursuant thereto shall be construed to relieve Seller of its warranties and other agreements in this section contained. Section 10. GENERAL TERMS AND CONDITIONS. ---------------------------- Additional terms and conditions are set forth in the "General Terms and Conditions Supplement" which is attached hereto, identified herewith, and hereby made part hereof by this reference, and said terms and conditions constitute part of this contract. Section 11. CONDENSATE. ---------- 8 Seller shall have the right to operate standard type oil field separators or low temperature separation equipment to separate condensate from the gas prior to delivery hereunder, and the condensate thus separated shall be disposed of by Seller free of this contract. No accounting shall be due Seller by Buyer in respect of any liquefied or liquefiable hydrocarbons carried by or recoverable from the gas delivered hereunder. IN WITNESS WHEREOF, this contract has been executed in duplicate original counterparts by the parties on the date first above written. ARKANSAS WESTERN GAS COMPANY SEECO, INC. By:_____________________________ By:________________________________ ATTEST: ATTEST: ________________________________ ___________________________________ 9 GENERAL TERMS AND CONDITIONS SUPPLEMENT --------------------------------------- This supplement is attached to and constitutes part of the Amended and Restated Contract 59 between ARKANSAS WESTERN GAS COMPANY, as Buyer, and SEECO, INC., as Seller, dated February 3, 1995. (A) MEASUREMENT ----------- (1) Except as may be otherwise specifically provided elsewhere herein, the measurement of gas delivered and received hereunder shall be in accordance with the following. (a) The unit of volume hereunder shall be 1,000 cubic feet of gas (sometimes herein referred to as Mcf) as the standard temperature base and standard pressure base specified in the Standard Gas Measurement Law of the State in which the gas is delivered. Whenever the actual conditions of pressure and temperature of the particular gas stream being measured differ from the above standard bases, conversion of the volume from such actual conditions to the above standard conditions shall be made in accordance with the Ideal Gas Laws, corrected for supercompressibility as required under Standard Gas Measurement Law of the State in which the gas is delivered in accordance with the method customarily used by Buyer in that State. Buyer may use any applicable findings and field rules of regulatory authorities with jurisdiction for purposes of computations hereunder. (b) Measurements of gas hereunder shall always be in accordance with the requirements of law, and if the procedures, bases, or standards which this contract contemplates will be used in the determination of gas volumes are changed by law or regulatory action, then the price of gas hereunder and any other provisions of this contract directly or indirectly affected by such change shall be appropriately modified and adjusted to the extent necessary to the end that calculations to determine sums of money due by either party to the other under this contract after any such change or changes will reach the same end result in dollars and cents as would have been reached hereunder in the absence of such change. (c) The volume of gas shall be measured at each Point of Delivery by meters installed and operated and computations made as prescribed in the latest accepted edition of The American Gas Association Gas Measurement Committee Report No. 3, except as the parties may otherwise agree or may otherwise have provided elsewhere herein. The values of the Reynolds number factor, expansion factor, and manometer factor, or any of them, may be assumed by Buyer to be one (1). (d) The temperature of the gas at each Point of Delivery shall be assumed to be 60 degrees Fahrenheit; however, either party may install a recording thermometer to record the actual temperature. (e) The specific gravity of the gas shall be determined for each Point of Delivery in accordance with good engineering practice as often as found necessary in actual 1 operation. (f) Buyer shall install, own, operate and maintain standard type measuring and testing equipment necessary hereunder and shall keep same accurate and in repair. Readings, calibrations, tests, repairs and adjustments of said equipment, and changing of charts, shall be done only by employees or agents of Buyer and in accordance with sound engineering practice as often as found necessary in actual operation. Any other party hereto shall have access to Buyer's measuring and testing equipment at any reasonable time, and shall have the right to have a representative present at tests, calibrations and adjustments thereof. All tests shall be preceded by reasonable notice to the operator of the well or wells affected or to such other party or parties hereto as Buyer may be requested in writing to notify and shall be conducted at least annually. Upon request by another party hereto for a special test of any meter or auxiliary equipment, Buyer shall promptly verify the accuracy of same, provided that the cost of such special test shall be borne by the requesting party unless the percentage of inaccuracy is found to be more than two percent (2%). If upon any test the total inaccuracy resulting from meter errors and auxiliary equipment errors exceeds two percent (2%), then previous readings shall be corrected to zero error for the period of time during which the equipment was inaccurate, but not beyond the close of the preceding accounting month; if said total inaccuracy is not more than two percent (2%), then previous readings shall be considered correct but the equipment shall be adjusted to read correctly. (g) If any meter or auxiliary equipment is out of service or out of repair for a period of time so that the amount of gas delivered cannot be ascertained or computed from the reading thereof, then the gas delivered during such period shall be estimated upon the basis of the best data available, using the first of the following methods which is feasible: (i) by correcting the error if the percentage of error is ascertainable by calibration, test, or mathematical calculations; (ii) by using the registration of any check equipment installed and accurately registering; or (iii) by estimating the volume on the basis of deliveries during preceding periods under similar conditions when the equipment was registering accurately. (h) Upon request, Buyer shall submit its measurement charts and records to any other party to this contract for examination, the same to be returned within 20 days. Buyer's measurement charts and records for a given accounting month shall be conclusively presumed correct if no written objection thereto is served on Buyer within the 36-month period following the given accounting month, and at the end of such 36-month period the same may be destroyed. (i) Any other party or parties hereto may install, operate and maintain, at their own cost, risk, and expense, but in the same manner as is required for Buyer's equipment hereunder, check measuring and testing equipment of standard type, provided that the same does not interfere with the operation of Buyer's equipment, but the measurement and testing of gas for purposes of this contract shall only be by Buyer's equipment. Buyer shall have the same rights with respect to check equipment as are granted the other party or parties hereto with respect to Buyer's equipment. 2 (B) QUALITY ------- Gas delivered hereunder shall be clean, merchantable natural gas containing not more than five grains of sulphur per hundred cubic feet of gas and not more than one-fourth grain of hydrogen sulfide per hundred cubic feet of gas, and shall be free of objectionable liquids and solids, oxygen and other deleterious substances. The gas shall have an average Btu content of at least 975 Btu per cubic foot. Buyer shall not be obligated to accept delivery of gas which either does not conform to the standards of quality and heat content herein set forth or contains corrosive products in quantities sufficient to impair the useful life of Buyer's pipeline facilities or of any gasoline or other processing plant processing the gas delivered, provided that, at Buyer's option, Buyer may from time to time accept deliveries of any or all such gas and bring it up to specification for Seller's account deducting the reasonable expense thereby incurred from remittances otherwise due hereunder. (C) ADDRESSES AND NOTICES --------------------- Except as otherwise herein expressly provided, the parties may be addressed for all purposes of this contract at the addresses set forth after their respective signatures hereto, subject to change from time to time by written notice to the other party. Written notices shall be deemed given to a party when delivered to such party's address; written responses to such notices shall be deemed given to a party when delivered to such party's address, or if sent by United States mail, when deposited in the mail, properly addressed, with sufficient postage affixed. (D) SUCCESSORS AND ASSIGNS ---------------------- This contract shall extend to and be binding upon the successors, heirs, legal representatives, and assigns of the parties. No transfer, assignment, conveyance, or encumbrance, of any kind, of any interest whatsoever in respect of which production is delivered to Buyer hereunder shall be binding upon Buyer until Buyer shall have been given written notice thereof and furnished with a duly certified copy of records evidencing same. (E) MULTIPLE COMPLETIONS -------------------- In the case of multiple completions, each separately completed and producing zone shall be considered a separate well under this contract, and the term "well" as used herein refers to each such separate completion except as may otherwise appear clearly intended in context. (F) EASEMENTS --------- To the full extent that Seller is able to convey such rights, Buyer is hereby granted and assigned an easement and servitude on the premises from which gas is delivered hereunder for installing, operating, and maintaining pipelines and equipment and for any other purposes connected herewith, with the right to remove such lines and equipment before, or within a 3 reasonable time after, the expiration of this contract. For any purpose connected herewith, Buyer shall have free access to any part of Seller's leases from which gas is delivered hereunder. (G) GOVERNMENT REGULATIONS ---------------------- This contract shall be subject to all relevant present and future local, state and federal laws, and all rules, regulations, and orders of any regulatory authority having jurisdiction. Neither party shall be held in default for failure to perform hereunder if such failure is due to good faith compliance with such party's best understanding of the requirements of any such laws, orders, rules or regulations. Seller warrants that production sold and delivered hereunder has been and will be produced and handled in compliance with the requirements of the Fair Labor Standards Act of 1938, and amendments thereto, and any other applicable laws, orders, rules and regulations. (H) FORCE MAJEURE ------------- In the event either party hereto is rendered unable wholly or in part by force majeure to carry out its obligations under this agreement, other than to make payments due hereunder, then on such party's giving notice and full particulars of such force majeure in writing or by facsimile to the other party (notice by Buyer to the operator of a well delivering gas hereunder shall constitute notice to all parties hereunder owning interests in the production from that well for purposes of this paragraph) as soon as possible after the occurrence of the cause relied upon, the obligations of the party giving such notice, so far as they are affected by such force majeure, shall be suspended during the continuance of any inability so caused, and such cause shall, as far as possible, be remedied with all reasonable dispatch. The term "force majeure," as used herein, shall mean acts of God, strikes, lockouts, or industrial disturbances, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrests and restraints of rulers and people, civil disturbances, explosions, breakage of or accident to machinery, equipment, or lines of pipe, the making of repairs, alterations or tests on machinery, equipment or lines of pipe, the freezing of wells or lines of pipe, the partial or entire failure of gas wells, the inability to acquire, or the delays in acquiring, at reasonable cost and after the exercise of reasonable diligence, such servitudes, right of way grants, permits, licenses, approvals and authorizations by regulatory bodies, supplies and materials (or permission from regulatory bodies to use supplies and materials on hand) as may be necessary in order that obligations assumed hereunder may be lawfully performed in the manner herein contemplated, any act or omission on the part of any purchaser or purchasers of gas from Buyer by reason of force majeure affecting such purchaser or purchasers, and any other causes, whether of the kind herein enumerated or otherwise, which are not within the control of the party claiming suspension, and which by the exercise of due diligence such party is unable to overcome, provided that the exercise of due diligence shall never require the settlement of labor disputes against the better judgment of the party having the dispute. 4 (I) WARRANTY -------- Seller warrants, and agrees to defend, title to production delivered hereunder and the right of Seller to sell same. Seller further warrants that all such production is delivered free and clear of all liens, encumbrances, and adverse claims, including liens to secure payment of taxes. Seller shall bear the economic burdens of, and except as may be otherwise herein provided shall pay, all royalties, overriding royalties, production payments and other payments and settlements of whatsoever kind and nature due in respect of production delivered hereunder or the proceeds from the sale thereof under Seller's leases and other contracts of record or otherwise binding on Seller, as well as settlements with all other persons having any interest in production delivered hereunder, and Seller agrees to indemnify Buyer and save it harmless from all claims, suits, actions, debts, accounts, damages, costs, losses, and expenses arising out of adverse claims of any and all persons to or against said production. In the event any adverse claim is asserted, Buyer may retain without interest, as security for the performance of Seller's obligations hereunder with respect to such claim, any amount out of monies then or thereafter payable to Seller hereunder up to the amount of such claim, until such claim has been finally determined or until Seller shall have furnished bond to Buyer in an amount and with sureties satisfactory to Buyer and conditioned for the protection of Buyer with respect to such claim. (J) TERMINATION ON DEFAULT ---------------------- If either party shall fail to perform any of the covenants or obligations imposed upon it under this contract (except where such failure shall be excused under the provisions hereof), the other party may, at its option, terminate this contract by proceeding as follows: the party not in default shall cause a written notice to be served on the party in default, stating specifically the cause for terminating this contract and declaring it to be the intention of the party giving the notice to terminate the same; thereupon the party in default shall have thirty (30) days after the service of the notice in which to remedy or remove the cause or causes stated in the notice for terminating the contract,and, if within said period of thirty (30) days, the party in default does so remedy and remove said cause or causes and fully indemnify the party not in default for any and all consequences of such breach, then such notice shall be withdrawn and this agreement shall continue in full force and effect. In case the party in default does not so remedy and remove the cause or causes and does not indemnify the party giving the notice for any and all consequences of such breach, within said period of thirty (30) days, then this agreement shall become null and void from and after the expiration of said period. Any cancellation of this agreement pursuant to the provisions of this section shall be without prejudice to the right of the party not in default to collect any amounts then due it and without waiver of any other remedy to which the party not in default may be entitled for violation of this contract. (K) ARBITRATION ----------- Where specific provision, if any, is made in this contract for arbitration, the following procedures shall be followed except as may be otherwise expressly provided for the arbitration of a particular matter: Upon written notice from either party to the other party, representatives 5 of both parties shall meet and attempt to settle the matter first by mutual agreement. If they are unable to do so, then the matter shall be submitted to an impartial, qualified arbitrator whose decision shall be final and binding on the parties and whose fee and expenses shall be borne equally by the parties. If the parties have not settled the matter or agreed on an arbitrator within 30 days after the aforesaid written notice, then upon the application of either party the arbitrator shall be designated by the then senior Federal judge for the Western District of Arkansas. (L) COMMINGLED STREAM ----------------- If at any time gas from two or more wells from which gas is delivered hereunder is commingled before delivery to Buyer, or if any gas subject to this contract is commingled with gas not subject to this contract, whether from the same well or other wells, before delivery to Buyer, then Buyer's take obligation in either or both such situations shall be to receive from all sources at the common point of delivery where Buyer receives the commingled stream a total volume which can be allocated as among the wells or interests delivering at the common point in such manner as to result in Buyer's receiving the volume Buyer is obligated to receive from each under the contract or contracts covering same. Under such circumstances, as between the parties Seller assumes responsibility for allocating the volume received by Buyer at the common point as among the various wells and interests delivering to Buyer at the common point and for furnishing Buyer with such information as may be necessary to permit settlements to be properly made hereunder. (M) OPERATION OF WELLS ------------------ (1) Seller, at Seller's expense shall: (a) Complete, control, manage, operate and maintain any wells from which gas is delivered hereunder in a workmanlike manner; and (b) Conduct with Buyer's cooperation, or at Buyer's option, cooperate with Buyer who shall conduct, such well tests as Buyer may require from time to time, but not more often than once each six months, to determine the open flow and rock pressure of the wells subject hereto, provided that in no event shall any liability attach to Buyer in connection with the making of any such tests except through the negligence of Buyer's agents. (2) Buyer, at Buyer's expense shall: (a) Install, operate and maintain such separators, heaters, and other equipment as may be necessary to deliver gas under the terms and conditions of this contract, and such testing connections as may be required; (b) Equip, operate and regulate the pressures on, each of the wells from which gas is delivered hereunder in such manner that the pressure and the volume of gas delivered hereunder can be regulated in a safe and satisfactory manner; 6 (c) Regulate the volume of gas deliveries hereunder in accordance with the needs of Buyer's gas system; and (d) Keep as many attendants stationed in the area of the wells from which gas is delivered hereunder as may be necessary in order that the obligations assumed by Buyer hereunder may be efficiently performed at all times. 7 EX-10.11 4 EXEC. SEVERANCE AGREEMENT EXHIBIT 10.11 EXECUTIVE SEVERANCE AGREEMENT ----------------------------- This agreement (this "Agreement") is made as of the 14th day of December, 1994, between Southwestern Energy Company, an Arkansas corporation with its principal offices at 1083 Sain Street, P.O. Box 1408, Fayetteville, Arkansas 72702-1408 (hereinafter called the "Company"), and Gregory D. Kerley (hereinafter called the "Employee"), residing at 3409 Fredricksburg Circle, Fayetteville, Arkansas 72703. WITNESSETH THAT: WHEREAS, should the Company or shareholders of the Company receive any proposal from a third person concerning a possible business combination with the Company or an acquisition of equity securities of the Company, the Board of Directors of the Company (hereinafter called the "Board") believes it imperative that the Company and the Board be able to rely upon the Employee to continue in his position, and that the Company and the Board be able to receive and rely upon his advice, if they request it, as to the best interests of the Company and its shareholders, without concern that he might be distracted or that his advice might be affected by the personal uncertainties and risks created by such a proposal; WHEREAS, the Company desires to provide the benefits provided for herein in order to enable it to attract and retain qualified executives such as the Employee, without a current expense to the Company; NOW, THEREFORE, to assure the Company that it will have the continued dedication of the Employee and the availability of his advice and counsel notwithstanding the possibility, threat or occurrence of a bid to take over control of the Company and to induce the Employee to remain in the employ of the Company, and for other good and valuable consideration, the Company and the Employee hereby agree as follows: 1. Definitions. ----------- (i) "Cause," when used in connection with the termination of the Employee's employment by the Company, shall mean (a) the willful and continued failure by the Employee substantially to perform his duties and obligations to the Company (other than any such failure resulting from his Disability) which failure continues after the Company has given notice thereof to the Employee or (b) the willful engaging by the Employee in misconduct which is materially injurious to the Company. For purposes of this definition, no act, or failure to act, on the Employee's part shall be considered "willful" unless done, or omitted to be done, by the Employee in bad faith and without reasonable belief that his action or omission was in the best interests of the Company. (ii) "Change in Control" shall mean the occurrence of any of the following: (a) any "person" (as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), an "Acquiring Person") becomes the 2 "beneficial owner" (as such term is defined in Rule 13d-3 promulgated under the Exchange Act), directly or indirectly, of securities of the Company representing 20% or more of the combined voting power of the Company's then outstanding securities, excluding any employee benefit plan sponsored or maintained by the Company (or any trustee of such plan acting as trustee); (b) the Company's stockholders approve an agreement to merge or consolidate the Company with another corporation (other than a corporation 50% or more of which is controlled by, or is under common control with, the Company); (c) any individual who is nominated by the Board for election to the Board on any date fails to be so elected as a direct or indirect result of any proxy fight or contested election for positions on the Board; (d) a "change in control" of the Company of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Exchange Act occurs; or (e) a majority of the Board determines in its sole and absolute discretion that there has been a Change in Control of the Company or that there will be a Change in Control of the Company upon the occurrence of certain specified events and such events occur; Notwithstanding Subparagraphs (a) through (d) of this Paragraph (ii), a Change in Control shall not occur by reason of 3 any event which would otherwise constitute a Change in Control if, immediately after the occurrence of such event, individuals who are Acquiring Persons and who were employees of the Company immediately prior to the occurrence of such event own, on a fully diluted basis, securities of the Company representing (A) 5% or more of the combined voting power of the Company's then outstanding securities or (B) 5% or more of the value of the Company's then outstanding equity securities. (iii) "Committee" shall mean the Compensation Committee of the Board. (iv) "Compensation" shall mean the "base amount" as such term is defined in Section 280G of the Internal Revenue Code of 1986, as amended from time to time (the "Code") and the regulations promulgated thereunder. (v) "Contract Period" shall mean the period defined in Section 2 hereof. (vi) "Disability" shall mean a physical or mental incapacity of the Employee which entitles the Employee to benefits at least equal to two-thirds of his base salary during the period of such incapacity under any long term disability plan applicable to him and maintained by the Company as in effect immediately prior to a Change in Control. (vii) "Good Reason," when used with reference to a termination by the Employee of his employment with the Company, shall mean: 4 (a) the assignment to the Employee of any duties inconsistent with, or the reduction of powers or functions associated with, his positions, duties, responsibilities and status with the Company immediately prior to a Change in Control, or any removal of the Employee from, or any failure to reelect the Employee to, any positions or offices the Employee held immediately prior to a Change in Control, except in connection with the termination of the Employee's employment by the Company for Cause or on account of Disability pursuant to the requirements of this Agreement; (b) a reduction by the Company of the Employee's base salary as in effect immediately prior to a Change in Control, except in connection with the termination of the Employee's employment by the Company for Cause or on account of Disability pursuant to the requirements of this Agreement; (c) a change in the Employee's principal work location to a location more than forty (40) miles from Fayetteville, Arkansas, except for required travel on the Company's business to an extent substantially consistent with the Employee's business travel obligations immediately prior to a Change in Control; (d) (1) the failure by the Company to continue in effect any employee benefit plan, program or arrangement (including, without limitation, "employee benefit plans" within the meaning of Section 3(3) of the Employee 5 Retirement Income Security Act of 1974) in which the Employee was participating immediately prior to a Change in Control (or substitute plans, programs or arrangements providing the Employee with substantially similar benefits), (2) the taking of any action, or the failure to take any action, by the Company which could (A) adversely affect the Employee's participation in, or materially reduce the Employee's benefits under, any of such plans, programs or arrangements, (B) materially adversely affect the basis for computing benefits under any of such plans, programs or arrangements or (C) deprive the Employee of any material fringe benefit enjoyed by the Employee immediately prior to a Change in Control or (3) the failure by the Company to provide the Employee with the number of paid vacation days to which the Employee was entitled immediately prior to a Change in Control in accordance with the Company's vacation policy applicable to the Employee then in effect, except, in each case, in connection with the termination of the Employee's employment by the Company for Cause or on account of Disability pursuant to the requirements of this Agreement; (e) the failure by the Company to pay the Employee any portion of the Employee's current compensation, or any portion of the Employee's compensation deferred under any plan, agreement or arrangement of or with the Company, within seven (7) days of the date such compensation is due; 6 (f) a material increase in the required working hours of the Employee from that required prior to a Change in Control; (g) the failure by the Company to obtain an assumption of the obligations of the Company under this Agreement by any successor to the Company; or (h) any termination of the Employee's employment by the Company during the Contract Period which is not effected pursuant to the requirements of this Agreement. (viii) "Termination Date" shall mean the effective date as provided hereunder of the termination of the Employee's employment. 2. Application of Agreement. This Agreement shall apply only to a ------------------------ termination of employment of the Employee during a period (the "Contract Period") commencing on the date immediately preceding the date of a Change in Control and terminating on the third anniversary of the date of the Change in Control; provided, however, that such Change in Control occurs during the period -------- ------- commencing as of the date hereof and terminating on the first anniversary of the date hereof or as further extended pursuant to the following sentence. On the first anniversary of the date hereof, and on each anniversary of the date hereof thereafter, the period during which this Agreement shall automatically apply shall be extended for one additional year, unless on or before such anniversary the Company notifies the Employee that it elects not to extend such period. 7 Any reference herein to the Employee's employment or termination of employment by or with the Company shall include the Employee's employment or termination of employment by or with any subsidiary or affiliated company of the Company. 3. Termination of Employment of the Employee By the Company During ------------------------------------------------ -------------- the Contract Period. ------------------- (i) During the Contract Period, the Company shall have the right to terminate the Employee's employment hereunder for Cause, for Disability or without Cause by following the procedures hereinafter specified. (ii) Termination of the Employee's employment for Disability shall become effective thirty (30) days after a notice of intent to terminate the Employee's employment, specifying Disability as the basis for such termination, is given to the Employee by the Committee. (iii) The Employee may not be terminated for Cause unless and until a notice of intent to terminate the Employee's employment for Cause, specifying the particulars of the conduct of the Employee forming the basis for such termination, is given to the Employee by the Committee and, subsequently, a majority of the Board finds, after reasonable notice to the Employee (but in no event less than fifteen (15) days' prior notice) and an opportunity for the Employee and his counsel to be heard by the Board, that termination of the Employee's employment for Cause is justified. Termination of the Employee's employment for Cause shall become effective after such finding has been made by the 8 Board and five (5) business days after the Board gives to the Employee notice thereof, specifying in detail the particulars of the conduct of the Employee found by the Board to justify such termination for Cause. (iv) The Company shall have the absolute right to terminate the Employee's employment without Cause at any time during the Contract Period by vote of a majority of the Board. Termination of the Employee's employment without Cause shall be effective five (5) business days after the Board gives to the Employee notice thereof, specifying that such termination is without Cause. (v) Upon a termination of the Employee's employment for Cause during the Contract Period, the Employee shall have no right to receive any compensation or benefits hereunder other than those benefits provided in Paragraph (i)(a) of Section 5 hereof. Upon a termination of the Employee's employment without Cause during the Contract Period, the Employee shall be entitled to receive the benefits provided in Section 5 hereof. This Agreement shall not apply to, and the Employee shall have no right to receive any compensation or benefits hereunder in connection with any termination of the Employee's employment by the Company other than during the Contract Period. 4. Termination of Employment By the Employee During the Contract ------------------------------------------------------------- Period. During the Contract Period, the Employee shall be entitled to terminate ------ his employment with the Company, and shall be entitled to the benefits hereunder as follows. If 9 the Employee terminates his employment with the Company during the twelve-month period beginning immediately preceding the date of a Change in Control, the Employee shall not be entitled to receive the benefits provided for in Section 5 hereof (other than those provided for in Paragraph (i)(a) thereof) unless the termination is for Good Reason. If the Employee shall terminate his employment with the Company after the expiration of such twelve-month period and during the Contract Period (or with respect to the benefits provided for in Section 5(i)(a) hereof, at any time during the contract period), the Employee shall be entitled to receive the benefits provided in Section 5 hereof if such termination is for any reason or without reason. The Employee shall give the Company notice of voluntary termination of employment pursuant to this Section 4, which notice need specify only the Employee's desire to terminate his employment and, if such termination is during the twelve-month period beginning immediately following a Change in Control and is for Good Reason, set-forth in reasonable detail the facts and circumstances claimed by the Employee to constitute Good Reason. Termination of the Employee's employment by the Employee pursuant to this Section 4 shall be effective five (5) business days after the Employee gives notice thereof to the Company. This Agreement shall not apply to, and the Employee shall have no right to receive, any compensation or benefits hereunder in connection with any termination of the Employee's employment by the Employee other than during the Contract Period. This Agreement shall not 10 apply to, and the Employee shall have no right to receive, any compensation or benefits hereunder in connection with a termination of the Employee's employment on account of the Employee's death, whether or not during the Contract Period. 5. Benefits Upon Termination in Certain Circumstances. -------------------------------------------------- (i) Upon the termination of the employment of the Employee by the Company pursuant to Section 3(iv) (or with respect to the benefits in Subparagraph (a) of this Paragraph, Section 3(iv) or 3(v)) hereof or, by the Employee pursuant to Section 4 hereof, the Employee shall be entitled to receive the following payments and benefits: (a) The Company shall pay to the Employee, not later than the Termination Date, a lump sum cash amount equal to the sum of (I) the full base salary earned by the Employee through the Termination Date and unpaid at the Termination Date, calculated at the highest rate of base salary in effect at any time during the twelve months immediately preceding the Termination Date, (II) the amount of any base salary attributable to vacation earned by the Employee but not taken before the Termination Date, (III) any annualized bonus accrued to the Employee through the Termination Date and unpaid at the Termination Date, plus (IV) all other amounts earned by the Employee and unpaid at the Termination Date. 11 (b) The Company shall pay to the Employee, not later than the Termination Date, a lump sum cash amount equal to the product of the Employee's Compensation times 2.99. (ii) If the Employee's employment is terminated by the Company pursuant to Section 3(ii) or 3(iv) hereof, or by the Employee pursuant to Section 4 hereof, the employee shall be entitled to receive the following payments and benefits: (a) The Company shall maintain in full force and effect for the Employee's continued benefit all life, medical, dental, prescription drug and long- and short-term disability plans, programs or arrangements, whether group or individual, in which the Employee was entitled to participate at any time during the twelve month-period prior to the Termination Date, until the earliest to occur of (I) three years after the Termination Date; (II) the Employee's death (provided that benefits payable to his beneficiaries shall not terminate upon his death); or (III) with respect to any particular plan, program or arrangement, the date he is afforded a comparable benefit at a comparable cost to the Employee by a subsequent employer. In the event that the Employee's participation in any such plan, program or arrangement of the Company is prohibited, the Company shall arrange to provide the Employee with benefits substantially similar to those which the Employee is entitled to receive under such plan, program or arrangement for such period. 12 (b) The Company shall pay to the Employee all legal fees and expenses (including legal fees and expenses incurred in connection with an arbitration proceeding engaged in pursuant to Section 10 hereof) incurred by the Employee as a result of such termination of employment (including all such fees and expenses, if any, incurred in contesting or disputing any such termination or in seeking to obtain or enforce any right or benefit provided to the Employee by this Agreement or under any other plan, program or arrangement of the Company or agreement with the Company), as and when such fees and expenses become due. (iii) The Employee shall not be required to mitigate the amount of any payment or benefit provided for in this Section 5 by seeking other employment or otherwise. (iv) The amount of any payment or benefit provided for in this Section 5 shall not be reduced by any compensation, benefits or other amounts paid to or earned by the Employee as the result of employment with another employer after the Termination Date or otherwise. (v) In the event that any payment hereunder, together with any other payment or the value of any benefit received in connection with a Change in Control or the termination or the Employee's employment pursuant to this Agreement or any plan, agreement or other arrangement between the Company and the Employee (or any member of Company's affiliated group as such term is defined in Section 1504 of the Code, without regard to 13 Section 1504(b) thereof) would result in the imposition of an excise tax under Section 4999 of the Code, the payment hereunder may, at the election of the Employee, be reduced by the amount necessary to prevent the imposition of such excise tax. The Company shall engage tax counsel selected by the Employee and reasonably acceptable to the Company to advise the Employee regarding any potential excise tax liability under Section 4999 of the Code and as to any benefit or detriment to the Employee of making the reduction election provided for hereunder. In making the determinations required in order to give the advice contemplated by this Paragraph (v), tax counsel may rely on benefit consultants, accountants and other experts. The Company agrees to pay all fees and expenses of such tax counsel and other experts. 6. Payment Obligations Absolute. The Company's obligation to pay the ---------------------------- Employee the amounts provided for hereunder shall be absolute and unconditional and shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the Company may have against him or anyone else and, including without limitation, any defense or claim based on a breach by the Employee of the covenants contained herein. All amounts payable by the Company hereunder shall be paid without notice or demand. Except as expressly provided herein, the Company waives all rights which it may now have or may hereafter have conferred upon it, by statute or otherwise, to amend, terminate, cancel or 14 rescind this Agreement in whole or in part. Subject to the right of the Company to seek arbitration under Section 10 hereof and recover any payment made hereunder, each and every payment made hereunder by the Company shall be final, and the Company shall not seek to recover all or any part of such payment from the Employee or from whomsoever may be entitled thereto, for any reason whatsoever. 7. Covenant Not to Solicit. ------------------------ (i) In the event the Employee's employment is terminated by the Company pursuant to Section 3(iv) hereof or by the Employee pursuant to Section 4 hereof, the Employee agrees during the three-year period following the Termination Date not to: (a) offer employment to any officer or employee of the Company or any subsidiary or affiliated company of the Company or attempt to induce any such officer or employee to leave the employ of the Company or any subsidiary or affiliated company of the Company; or (b) attempt to persuade or induce, or persuade or induce, any officer, director, agent, customer, client or supplier of the Company or any subsidiary or affiliated company of the Company to discontinue his or her relationship with the Company or any subsidiary or affiliated company of the Company. (ii) In the event of any breach of the foregoing covenant, the Employee acknowledges that the Company's remedy at 15 law is inadequate and that the Company shall be entitled to seek injunctive relief. 8. Successors; Binding Agreement. ----------------------------- (i) This Agreement shall be binding upon any successor (whether direct or indirect, by purchase, merger, consolidation, liquidation or otherwise) to all or substantially all of the business and/or assets of the Company. Additionally, the Company shall require any such successor expressly to agree to assume and to assume all of the obligations of the Company under this Agreement upon or prior to such succession taking place. A copy of such assumption and agreement shall be delivered to the Employee promptly after its execution by the successor. Failure of the Company to obtain such agreement prior to the effectiveness of any such succession shall be a breach of this Agreement and, as a result of such breach, the Company shall pay to the Employee the benefits as provided in Section 5 hereof as if the Company had terminated the Employee's employment on the date on which such succession becomes effective, without Cause, upon a Change in Control. As used in this Agreement, "Company" shall mean the Company as hereinbefore defined and any successor to its business and or assets as aforesaid, whether or not such successor executes and delivers the agreement provided for in this Section 8(i). (ii) This Agreement is personal to the Employee and the Employee may not assign or transfer any part of his rights or duties hereunder, or any compensation due to him hereunder, to 16 any other person, except that this Agreement shall inure to the benefit of and be enforceable by the Employee's personal or legal representatives, executors, administrators, heirs, distributees, devises, legatees or beneficiaries. No payment pursuant to any will or the laws of descent and distribution shall be made hereunder unless the Company shall have been furnished with a copy of such will and/or such other evidence as the Board may deem necessary to establish the validity of the payment. 9. Modification; Waiver. No provisions of this Agreement may be -------------------- modified, waived or discharged unless such waiver, modification or discharge is agreed to in a writing signed by the Employee and such director or officer as may be specifically designated by the Board. Waiver by any party of any breach of or failure to comply with any provision of this Agreement by the other party shall not be construed as, or constitute, a continuing waiver of such provision, or a waiver of any other breach of, or failure to comply with, any other provision of this Agreement. 10. Arbitration of Disputes. ----------------------- (i) Any disagreement, dispute, controversy or claim arising out of or relating to this Agreement or the interpretation or validity hereof shall be settled exclusively and finally by arbitration except that in the event of the Employee's breach of the covenant contained in Section 7 hereof, the Company shall be entitled to seek injunctive relief pursuant to Section 7(ii) hereof. It is specifically understood and agreed that any 17 disagreement, dispute or controversy which cannot be resolved between the parties, including without limitation any matter relating to the interpretation of this Agreement, may be submitted to arbitration irrespective of the magnitude thereof, the amount in controversy or whether such disagreement, dispute or controversy otherwise would be considered justiciable or ripe for resolution by a court or arbitral tribunal. (ii) The arbitration shall be conducted in accordance with the Commercial Arbitration Rules (the "Arbitration Rules") of the American Arbitration Association (the "AAA"). (iii) The arbitral tribunal shall consist of one arbitrator. The parties to the arbitration jointly shall directly appoint such arbitrator within 30 days of initiation of the arbitration. If the parties shall fail to appoint such arbitrator as provided above, such arbitrator shall be appointed by the AAA as provided in the Arbitration Rules and shall be a person who (a) maintains his principal place of business within 30 miles of the City of Fayetteville, Arkansas, and (b) has had substantial experience (whether practical or academic) in mergers and acquisitions or, if no such person is available, in employee benefits. The Company shall pay all of the fees, if any, and expenses of such arbitrator. (iv) The arbitration shall be conducted within 30 miles of the City of Fayetteville, Arkansas or in such other city in the United States of America as the parties to the dispute may designate by mutual written consent. 18 (v) At any oral hearing of evidence in connection with the arbitration, each party thereto or its legal counsel shall have the right to examine its witnesses and to cross-examine the witnesses of any opposing party. No evidence of any witness shall be presented unless the opposing party or parties shall have the opportunity to cross-examine such witness, except as the parties to the dispute otherwise agree in writing or except under extraordinary circumstances where the interests of justice require a different procedure. (vi) Any decision or award of the arbitral tribunal shall be final and binding upon the parties to the arbitration proceeding. The parties hereto hereby waive, to the extent permitted by law, any rights to appeal or to seek review of such award by any court or tribunal. The parties hereto agree that the arbitral award may be enforced against the parties to the arbitration proceeding or their assets wherever they may be found and that a judgment upon the arbitral award may be entered in any court having jurisdiction. (vii) Nothing herein contained shall be deemed to give the arbitral tribunal any authority, power, or right to alter, change, amend, modify, add to, or subtract from any of the provisions of this Agreement. 11. Notice. All notices, requests, demands and other communications ------ required or permitted to be given by either party to the other party by this Agreement (including, without limitation, any notice of termination of employment and any 19 notice under the Arbitration Rules of an intention to arbitrate) shall be in writing and shall be deemed to have been duly given when delivered personally or received by certified or registered mail, return receipt requested, postage prepaid, at the address of the other party, as follows: If to the Company, to: Southwestern Energy Company 1083 Sain Street P.O. Box 1408 Fayetteville, Arkansas 72702-1408 Attention: Board of Directors and Secretary --------- If to the Employee, to: Mr. Gregory D. Kerley 3409 Fredricksburg Circle Fayetteville, Arkansas 72703 Either party hereto may change its address for purposes of this Section 11 by giving fifteen (15) days' prior notice to the other party hereto. 12. Severability. If any term or provision of this Agreement or the ------------ application thereof to any person or circumstance shall to any extent be invalid or unenforceable, the remainder of this Agreement or the application of such term or provision to persons or circumstances other than those as to which it is held invalid or unenforceable shall not be affected thereby, and each term and provision of this Agreement shall be valid and enforceable to the fullest extent permitted by law. 13. Headings. The headings in this Agreement are inserted for -------- convenience of reference only and shall not be a part of or control or affect the meaning of this Agreement. 20 14. Counterparts. This Agreement may be executed in several ------------ counterparts, each of which shall be deemed an original. 15. Governing Law. This Agreement has been executed and delivered in ------------- the State of Arkansas and shall in all respects be governed by, and construed and enforced in accordance with, the laws of the State of Arkansas. 16. Payroll and Withholding Taxes. The Company may withhold from any ----------------------------- amounts payable to the Employee hereunder all federal, state, city or other taxes that the Company may reasonably determine are required to be withheld pursuant to any applicable law or regulation. 17. Entire Agreement. Except as explicitly provided for herein, this ---------------- Agreement supersedes any and all other oral or written agreements heretofore made relating to the subject matter hereof and constitutes the entire agreement of the parties relating to the subject matter hereof; provided, that, this -------- ---- Agreement shall not supersede or limit or in any way affect the amount of compensation or benefits to which the Employee would be entitled under any other agreement, plan, program or arrangement with the Company including any such agreement, plan, program or arrangement providing for benefits in the nature of severance pay. 21 IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first written above. Southwestern Energy Company By:____________________________ Chairman of the Compensation Committee Southwestern Energy Company By:____________________________ Chairman of the Board of Southwestern Energy Company By:____________________________ Gregory D. Kerley 22 EX-10.12 5 EMPLOYMENT AGREEMENT EXHIBIT 10.12 EMPLOYMENT AGREEMENT -------------------- THIS EMPLOYMENT AGREEMENT (Agreement) is made and entered into on this ------------------------- December 7, 1994, at Fayetteville, Washington County, Arkansas, by and between SOUTHWESTERN ENERGY COMPANY, an Arkansas business corporation, designated herein --------------------------- as SWEN, and CHARLES E. SCHARLAU, designated herein as EMPLOYEE. ------------------- -------- WHEREAS, the parties hereto are subject to an Employment Agreement dated December 18, 1990, and desire to amend such agreement by extending its term, and WHEREAS, at its meeting held on October 5, 1994, the Board of Directors by a motion duly made and passed authorized the extension of the Employment Agreement dated December 18, 1990, for an additional two (2) years, and WHEREAS, Employee has advised SWEN of his desire to extend the term of employment as provided in the Employment Agreement. Agreement: For and in Consideration of the foregoing recitals and of the --------- ------------------------ mutual and interdependent promises SWEN and EMPLOYEE agree that Section C(1)(a) ---- -------- and Section C(2) are hereby amended to read as follows: C(1)(a) The EMPLOYEE'S employment under this Agreement shall commence with January 1, 1991, and shall continue until the expiration of seven (7) years from and after the said date. During such period the EMPLOYEE shall perform the services as a full-time EMPLOYEE of SWEN as designated by the Board of Directors in the area of the Chief Executive Officer of all of the business activities of SWEN. C(2) Termination of Employment of the Employee: If SWEN shall ----------------------------------------- terminate the employment of the EMPLOYEE at any time during the seven (7) year period commencing January 1, 1991, and ending on December 31, 1997, then the termination rights of the EMPLOYEE hereunder shall be determined pursuant to and under that certain Executive Severance Agreement dated August 4, 1989, between SWEN and the EMPLOYEE. The Contract dated August 4, 1989, and identified hereinabove is hereby referred to for a full recital of the terms and provisions thereof and by this reference is made a part hereof. All other terms and conditions of the Employment Agreement dated December 18, 1990 between SWEN and EMPLOYEE remain in effect as written. IN WITNESS WHEREOF, the parties hereto have executed this Agreement in original triplicates on this December 7, 1994, effective as of the date first hereinabove written. SOUTHWESTERN ENERGY COMPANY ATTEST: By__________________________________ John Paul Hammerschmidt _______________________________ Greg D. Kerley, Secretary _____________________________________ Charles E. Sanders COMPENSATION COMMITTEE OF THE BOARD OF DIRECTORS _______________________________________ Charles E. Scharlau EMPLOYEE ACKNOWLEDGEMENT --------------- STATE OF ARKANSAS COUNTY OF WASHINGTON BE IT REMEMBERED, that on this day came before the undersigned, a Notary Public, within and for the County aforesaid, duly commissioned and acting, John Paul Hammerschmidt and Charles Sanders, to me well known as the members of the compensation committee and Greg D. Kerley as the secretary of the committee of the Board of Directors of Southwestern Energy Company, a corporation, and stated that they had executed the same for the consideration and purposes therein mentioned and set forth. WITNESS my hand and seal as such Notary Public this 7th day of December, 1994. ______________________________________ Notary Public My Commission Expires: _________________________ ACKNOWLEDGEMENT --------------- STATE OF ARKANSAS COUNTY OF WASHINGTON BE IT REMEMBERED, that on this day came before the undersigned, a Notary Public, within and for the County aforesaid, duly commissioned and acting, Charles E. Scharlau, to me well known as the party in the foregoing agreement, and stated that he had executed the same for the consideration and purposes therein mentioned and set forth. WITNESS my hand and seal as such Notary Public this 7th day of December, 1994. _______________________________________ Notary Public My Commission Expires: _________________________ EX-13 6 ANNUAL REPORT Management's Discussion and Analysis of Financial Condition and Results of Operations RESULTS OF OPERATIONS Net income in 1994 decreased by 7% to $25.1 million, or $.98 per share, down from $27.1 million, or $1.05 per share, in 1993. Net income in 1992 was $22.3 million, or $.87 per share. The comparison of 1994 to 1993 excludes the cumulative effect of a change in accounting for income taxes which was recorded in the first quarter of 1993. Operating results for 1993 also included an adjustment of $1.7 million, or $.07 per share, to decrease net income and record the effect on accumulated deferred income taxes of a legislated increase in the federal corporate income tax rate. There were no accounting changes or extraordinary items recorded in either 1994 or 1992. The decline in 1994 earnings resulted as lower gas prices and much warmer heating weather offset the favorable effect of the Company's seventh consecutive increase in natural gas production. The low gas prices also magnified the effect on earnings of a settlement reached to resolve certain gas cost issues before the Arkansas Public Service Commission (APSC). The settlement, which involved the price of gas sold under a contract between one of the Company's exploration and production subsidiaries and its utility subsidiary, is hereafter referred to as "the gas cost settlement" and is discussed below under Regulatory Matters. The earnings growth in 1993 was primarily the result of increased sales of the Company's gas production. Revenues and operating income for the Company's major business segments are shown in the following table.
1994 1993 1992 ------------------------------------------------------------------------------- (in thousands) REVENUES Exploration and production $ 80,123 $ 79,374 $ 60,554 Gas distribution 127,060 131,892 117,495 Other 308 262 256 Eliminations (37,305) (36,684) (34,475) ------------------------------------------------------------------------------- $170,186 $174,844 $143,830 =============================================================================== OPERATING INCOME Exploration and production $ 38,883 $ 42,608 $ 33,071 Gas distribution 13,391 15,261 13,094 Corporate expenses (192) (305) (177) ------------------------------------------------------------------------------- $ 52,082 $ 57,564 $ 45,988 ===============================================================================
EXPLORATION AND PRODUCTION REVENUES The Company's exploration and production revenues increased 1% in 1994 and 31% in 1993. The slight increase in 1994 was due to increases in natural gas and oil production, offset by lower average product prices. The increase in 1993 was due to increased natural gas production. Gas production increased by 6% to 37.7 billion cubic feet (Bcf) in 1994 from 35.7 Bcf in 1993. Gas production in 1993 increased by 38% from 25.8 Bcf in 1992. Increased sales to unaffiliated purchasers have accounted for approximately 80% of the increase in gas production since 1992. Gas sales to unaffiliated purchasers increased to 23.8 Bcf in 1994, from 22.9 Bcf in 1993, and 14.4 Bcf in 1992. The increases in sales to unaffiliated purchasers were primarily the result of higher sales from the Company's properties in both Arkansas and the Gulf Coast areas of Texas and Louisiana. The Company sold 15.1 Bcf of its Arkansas production to unaffiliated purchasers during both 1994 and 1993, compared to 10.6 Bcf in 1992. The increase from the 1992 level was the result of the Company's development drilling program in the Arkoma Basin which made additional gas available for sale during the late spring and summer months. Much of this incremental production was sold into interstate markets as a result of improved access to those markets made possible by the NOARK Pipeline System (NOARK). NOARK became operational in late 1992 and extends across northern Arkansas, crossing three major interstate pipelines. The Company, through a subsidiary, holds a general partnership interest in NOARK of approximately 48% and is the pipeline's operator. Sales from the Company's Gulf Coast properties were 6.8 Bcf in 1994, compared to 6.3 Bcf in 1993, and 2.0 Bcf in 1992. The increase in 1994 was primarily the result of the completion of a production platform at the Galveston Block 283 gas field late in 1993 and first production from the Earl Chauvin No. 1 well, a 1993 discovery in southeast Louisiana. The increase in 1993 was primarily the result of the completion of a production platform at Brazos Block 397 and the start of production in November, 1993, from Galveston Block 283.
1994 1993 1992 ------------------------------------------------------------------------------- GAS PRODUCTION Affiliated sales (Bcf) 13.9 12.8 11.4 Unaffiliated sales (Bcf) 23.8 22.9 14.4 ------------------------------------------------------------------------------- 37.7 35.7 25.8 ------------------------------------------------------------------------------- Average price per Mcf $2.04 $2.18 $2.26 =============================================================================== OIL PRODUCTION Unaffiliated sales (MBbls) 200 97 120 ------------------------------------------------------------------------------- Average price per Bbl $15.89 $17.20 $19.75 ===============================================================================
Sales to unaffiliated purchasers are made under contracts which reflect current short-term prices and which are subject to seasonal price swings. The Company curtailed part of its gas production during 1992 when sales prices were deemed below acceptable levels. The Company also uses gas price hedges on a limited basis to reduce the Company's exposure to the risk of changing prices. Deliveries for injection into storage and the gas cost settlement increased the demand of the Company's utility distribution systems for affiliated gas supply in 1994. Gas production sold to Arkansas Western Gas Company (AWG), the utility subsidiary which operates the Company's northwest Arkansas utility system, was 8.8 Bcf in 1994, up from 7.1 Bcf in 1993, and 7.2 Bcf in 1992. The increase in gas sold to AWG in 1994 was due largely to increased storage injections and higher volumes resulting from the gas cost settlement, as discussed below. The decrease in gas sold to AWG in 1993 resulted from the lack of summer injections by AWG into its gas storage facilities, partially offset by an increase in sales due to weather related requirements of the utility 14 system and an increase in sales to a spot market purchasing program available to the larger business customers of AWG. The Company's gas production provided approximately 64% of AWG's requirements in 1994, and approximately 50% in 1993 and 1992. Additionally, in 1994, 1993, and 1992, the Company sold .5 Bcf, .7 Bcf, and .4 Bcf, respectively, of gas to AWG for its spot market purchasing program. The Company's sales to AWG under the spot market purchasing program are based upon competitive bids and generally reflect current spot market prices. Most of the remaining sales to AWG's system are subject to a long-term contract entered into in 1978, under which the price had been frozen since the end of 1984. As mentioned above and discussed more fully under Regulatory Matters, this contract was amended in 1994 as a result of the settlement of certain gas cost issues with the APSC. The settlement became effective July 1, 1994, and calls for sales under the contract to take place at a price which is equal to a spot market index plus an additional premium. The settlement results in a lower contract price based on current market conditions. That effect is offset in part by provisions which allow additional volumes to be sold under the contract. Other sales to AWG are made under long-term contracts with flexible pricing provisions and under short-term spot arrangements. The Company's deliveries to Associated Natural Gas Company (Associated), a division of AWG which operates the Company's natural gas distribution systems in northeast Arkansas and parts of Missouri, were 5.1 Bcf in 1994, 5.7 Bcf in 1993, and 4.3 Bcf in 1992. Deliveries to Associated decreased in 1994 due to warmer weather and increased in 1993 due to colder heating weather and storage requirements during the summer months. Effective October, 1990, one of the Company's exploration and production subsidiaries entered into a ten-year contract with Associated to supply its base load system requirements at a price to be redetermined annually. Deliveries under this contract were made at $1.90 per thousand cubic feet (Mcf) from inception of the contract through the first nine months of 1993, increased to $2.385 per Mcf for the contract period ending September 30, 1994, and are currently being made at $2.20 per Mcf. The average price received at the wellhead for the Company's total gas production was $2.04 per Mcf in 1994, $2.18 per Mcf in 1993, and $2.26 per Mcf in 1992. The decline in the average price received since 1992 reflects the recent decline in spot market prices, an increase in the proportionate share of the Company's production sold at spot market prices and under long-term contracts with market-sensitive pricing, and the effect of the gas cost settlement. Natural gas prices declined during the last half of 1994, and with the abnormally warm winter recently experienced across the country, average prices are generally expected to remain lower in 1995 as compared to 1994. As described above, a significant portion of the Company's gas production is sold under long-term contracts to its gas distribution subsidiary. In the past, the fixed prices received under these sales arrangements helped reduce the effects of fluctuations in the spot market price for natural gas. Going forward, the Company expects increased volatility and seasonality in its operating results as the majority of its gas sales will be tied to a spot market index. In the future, the Company expects the overall average price it receives for its total production to be generally higher than average spot market prices due to the premiums over spot that it receives. Future changes in revenues from sales of the Company's gas production will be dependent upon changes in the market price for gas, access to new markets, maintenance of existing markets, and additions of new gas reserves. The Company expects future increases in its gas production to come primarily from sales to unaffiliated purchasers. While the Company expects over the long term to experience a trend toward increasing volumes of gas production, it is unable to predict changes in the market demand and price for natural gas, including changes which may be induced by the effects of weather on demand of both affiliated and unaffiliated customers for the Company's production. Additionally, the Company holds a large block of undeveloped leasehold acreage and producing acreage which will continue to be developed in the future. The Company's exploration programs have been directed almost exclusively toward natural gas in recent years. The Company will continue to concentrate on developing and acquiring gas reserves, but will also selectively seek opportunities to participate in projects oriented toward oil production. GAS DISTRIBUTION REVENUES Gas distribution revenues fluctuate due to the pass-through of cost of gas increases and decreases, and due to the effects of weather. Because of the corresponding changes in purchased gas costs, the revenue effect of the pass- through of gas cost changes has not materially affected net income.
1994 1993 1992 ------------------------------------------------------------------------------- GAS DISTRIBUTION SYSTEMS Deliveries (Bcf) Sales volumes 26.3 26.8 23.5 Transportation volumes End-use 4.8 5.6 5.2 Off-system 10.7 11.7 2.5 ------------------------------------------------------------------------------- 41.8 44.1 31.2 ------------------------------------------------------------------------------- Average number of sales customers 159,897 155,944 151,592 ------------------------------------------------------------------------------- Heating weather--degree days 4,161 4,929 4,104 ------------------------------------------------------------------------------- Average sales rate per Mcf $4.57 $4.65 $4.75 ===============================================================================
Gas distribution revenues decreased by 4% in 1994 and increased by 12% in 1993. The decrease in 1994 reflected the net effects of strong customer growth, weather which was 16% warmer than the prior year, and lower purchased gas costs caused in part by the gas cost settlement. The increase in 1993 was primarily due to additional deliveries to residential and commercial customers resulting from weather which was 20% colder than in 1992 and from customer growth. Additional revenues related to the transportation of gas behind AWG's system to NOARK also contributed to the increase in 1993. 15 Management's Discussion and Analysis of Financial Condition and Results of Operations continued In 1994, AWG sold 16.3 Bcf to its customers at an average rate of $4.25 per Mcf, compared to 17.1 Bcf at $4.40 per Mcf in 1993, and 15.0 Bcf at $4.62 per Mcf in 1992. Additionally, AWG transported 4.0 Bcf for its end-use customers in 1994, 3.9 Bcf in 1993, and 3.2 Bcf in 1992. Associated sold 10.0 Bcf to its customers in 1994 at an average rate of $5.10 per Mcf, compared to 9.7 Bcf in 1993 at $5.08 per Mcf, and 8.4 Bcf at $4.99 per Mcf in 1992. The increase in 1994 was due to the conversion of an industrial customer from transportation to sales service. While the conversion of this customer to sales service raised the Company's gas distribution revenues, there was no resulting impact on operating income as the rate charged this customer for transportation service was equal to the rate charged for sales service, exclusive of gas costs. Associated transported .8 Bcf for its end-use customers in 1994, compared to 1.7 Bcf in 1993, and 2.0 Bcf in 1992. Total deliveries to industrial customers of AWG and Associated, including transportation volumes, increased to 12.3 Bcf in 1994, from 11.7 Bcf in 1993, and 11.3 Bcf in 1992. The steady increase reflects both the success of the Company's industrial marketing efforts and the continued economic strength of its service territory. AWG also transported 10.7 Bcf of gas through its gathering system in 1994 for off-system deliveries, all through NOARK, compared to 11.7 Bcf in 1993, and 2.5 Bcf in 1992. The average transportation rate was $.13 per Mcf, exclusive of fuel, in all years. Gas distribution revenues in future years will be impacted by both customer growth and rate increases allowed by regulatory commissions. In recent years, AWG has experienced customer growth of approximately 3.5% to 4.0% annually, while Associated has experienced customer growth of 1% to 2% annually. Based on current economic conditions in the Company's service territories, the Company expects this trend in customer growth to continue. Rate increase requests which may be filed in the future will depend upon customer growth, increases in operating expenses, and additional investments in property, plant and equipment. AWG is precluded from filing an application for a rate increase with the APSC prior to January 1, 1996, as a result of the gas cost settlement. The Company anticipates filing a rate increase request for AWG in early 1996 and will continue to monitor the status of returns on the systems operated by Associated and file rate cases as the need arises. REGULATORY MATTERS During 1994, the Company reached a settlement with the Staff of the APSC and the Office of the Attorney General of the State of Arkansas concerning certain gas cost issues which had been outstanding before the APSC for the past four years. The gas cost issues were first raised by the APSC in December, 1990, in connection with its approval of an AWG rate increase. The issues in question involved the price of gas sold under a long-term contract between AWG and one of the Company's gas producing subsidiaries. The terms of the settlement became effective as of July 1, 1994, and were approved by the APSC on January 5, 1995. Under the settlement, the price paid by AWG is tied to a monthly spot market index plus an additional premium. Given current market conditions, the new pricing provision results in a reduced sales price. That effect is offset in part by provisions which allow additional volumes to be sold under the contract. The amended contract provides for volumes equal to the historical level of sales under the contract to be sold at the spot market index plus a premium of $.95 per Mcf, while any incremental sales volumes will receive a premium of $.50 per Mcf. In 1994, approximately 8.1 Bcf (net to the Company's interest) was sold under the contract, compared to approximately 6.0 Bcf in 1993. Other significant terms of the settlement prevent any of the parties thereto from asking for refunds, transfers certain of AWG's natural gas storage facilities to another subsidiary of the Company, and prohibits AWG from filing a rate case for its northwest Arkansas system before January, 1996, as mentioned above. As discussed earlier, Associated also purchases a portion of its gas supply at the wellhead from one of the Company's gas producing subsidiaries under a long-term firm contract entered into in October, 1990. As a result of recent gas cost audits for the two-year period ended August 31, 1992, the Staff of the Missouri Public Service Commission (Staff) recommended the disallowance of approximately $3.1 million in gas costs. This amount represents the difference between the price paid by Associated and a spot market index price for gas delivered into an interstate pipeline operating in the Arkoma Basin. The price paid by Associated under the contract was $1.90 per Mcf during the period in question. In making its recommendation, the Staff acknowledged that Associated had lowered its gas cost and saved its ratepayers money by purchasing gas from its affiliate. The Staff also acknowledged that the appropriate price for purchases made under this long-term firm contract should include a premium over the spot market price. However, a Staff consultant testified that there was insufficient data upon which to determine an appropriate premium over a spot market index for pricing purchases under this contract and that he was unable to determine what the appropriate premium should be. A hearing was held on January 31, 1995. The Company presented testimony to demonstrate that the price paid under the contract was at or below the market price for contracts with similar terms during the period in which the purchases were made. The APSC previously reviewed the costs charged to Arkansas rate-payers under this contract and found them to be proper and allowable for recovery. The Missouri Public Service Commission (Missouri Commission) has not yet issued an order in this proceeding. The Staff has also audited Associated's gas purchases for the period from September, 1992, through August, 1993, and recommended no changes to the gas costs for that period. The Company does not expect any outcome of the proceeding to have a material adverse effect on the results of operations or the financial position of the Company. In April, 1992, the Federal Energy Regulatory Commission issued Order No. 636, a comprehensive set of regulations designed to encourage competition and continue the significant restructuring of the interstate natural gas pipeline industry. Prior to Order No. 636, Associated purchased portions of its gas supply from interstate pipelines under firm long-term supply contracts. The Company has paid approximately $3.2 million in contract reformation costs and 16 take-or-pay costs and $1.9 million in transition costs which these interstate pipelines incurred and were allowed to recover. The Company anticipates full recovery of the $1.9 million in transition costs incurred. Additionally, the Company has recovered, subject to refund, approximately $1.6 million of the contract reformation costs and take-or-pay costs from its utility sales customers in the state of Missouri. Of the unrecovered $1.6 million related to contract reformation costs and take-or-pay costs, $.7 million is applicable to Associated's transportation customers in the state of Missouri and $.9 million is applicable to all customers in the state of Arkansas. The Staff of the Missouri Commission has reviewed these payments and made a recommendation that the unrecovered $.7 million related to Associated's transportation customers should be disallowed on the grounds of retroactive rate-making. The Company disagreed with this recommendation and a hearing was held on January 31, 1995. The Company is awaiting the Missouri Commission's order. AWG also purchases gas from unaffiliated producers under take-or-pay contracts. Currently, the Company believes that it does not have a significant exposure to liabilities resulting from these contracts, although the Company's exposure to take-or-pay liabilities to producers or other suppliers has increased in recent years as a result of a decline in its gas purchase requirements which has occurred as some of its large business customers converted to a transportation service offered by AWG and Associated in Arkansas and began to obtain their own gas supplies directly from other sources. Associated has offered such a service to its customers in Missouri for several years and AWG's spot market purchasing program has provided customers in northwest Arkansas with many of the benefits of transportation service. The Company expects to be able to continue to satisfactorily manage its exposure to take-or-pay liabilities. OPERATING COSTS AND EXPENSES The Company's operating costs and expenses increased by 1% in 1994 and by 20% in 1993. The slight increase in 1994 resulted from increased depreciation, depletion and amortization expense (DD&A) primarily related to the Company's exploration and production segment and increased utility operating expenses, offset by lower purchased gas costs related to lower prices paid for gas supplies. The increase in 1993 was due primarily to increased purchased gas costs related to increased utility deliveries, and increased production costs and DD&A resulting from increased gas sales in the exploration and production segment. Purchased gas costs are one of the largest expense items in each year, typically representing 30% to 40% of the Company's total operating costs and expenses. Purchased gas costs are influenced primarily by changes in requirements for gas sales of the gas distribution segment, the price and mix of gas purchased, and the timing of recoveries of deferred purchased gas costs. As previously mentioned, increases and decreases in purchased gas costs are automatically passed through to the Company's utility customers. The Company follows the full-cost method of accounting for the exploration, development, and acquisition of oil and gas properties. DD&A is calculated using the units-of-production method. The Company's annual gas and oil production, as well as the amount of proved reserves owned by the Company and the costs associated with adding those reserves, are all components of the amortization calculation. DD&A increased 15% in 1994 due both to an increase in gas and oil production and an increase in the amortization rate. The 30% increase in DD&A in 1993 was primarily due to increased levels of natural gas production. The margin between the Company's full cost ceiling and the financial statement carrying value of the Company's gas and oil properties was eroded substantially during 1994 as a result of very low average gas prices in effect at December 31, 1994. Product prices, production rates, levels of reserves, and the evaluation of unamortized costs all influence the calculation of the ceiling. A significant decline in gas prices from year-end 1994, without other mitigating factors, could cause a future write-down and a noncash charge against earnings. Delays inherent in the rate-making process prevent the Company from obtaining immediate recovery of increased operating costs of its gas distribution segment. Inflation impacts the Company by generally increasing its operating costs and the costs of its capital additions. In recent years the impacts of inflation have been mitigated by conditions in the industries in which the Company operates. While some of the gas distribution subsidiary's gas purchase contracts include inflation-based price escalations, these clauses have generally not been operating as gas market conditions have led producers to accept prices below the contract maximum price. Continuing depressed conditions in the gas and oil industry have resulted in lower costs of drilling and leasehold acquisition. OTHER COSTS AND EXPENSES Interest costs were down slightly in 1994, as compared to 1993, due to lower average borrowings on the Company's revolving credit facilities throughout most of the year, partially offset by higher average interest rates. Borrowings under these facilities were higher at year-end 1994, as compared to 1993, primarily as a result of increased capital spending activity during the fourth quarter of 1994. Interest costs decreased in 1993 due to the redemption in late 1992 of the Company's 12.75% Debentures and 9.38% First Mortgage Bonds, and due to both lower average borrowings and lower average interest rates on the Company's revolving credit facilities. The change in other income during 1994 and 1993 relates primarily to the Company's share of operating losses incurred by NOARK. The Company accounts for its 47.93% interest in the NOARK partnership under the equity method of accounting (see Note 7 to the financial statements for additional discussion). NOARK has been operating below capacity and generating losses since it was placed in service. The Company's share of the pretax loss for NOARK included in other income was $2.8 million in 1994, $1.8 million in 1993, and $.6 million in 1992. Deliveries are currently being made by NOARK to portions of AWG's distribution system, to Associated, and to the interstate pipelines with which NOARK interconnects. In 1994, NOARK had 17 Management's Discussion and Analysis of Financial Condition and Results of Operations continued an average daily throughput of 82 million cubic feet of gas per day (MMcfd), compared to 79 MMcfd in 1993, its first full year of operation. NOARK has a total transportation capacity of 141 MMcfd. AWG has contracted for 41 MMcfd of firm capacity on NOARK under a ten-year transportation contract. NOARK also has a five-year transportation contract with Vesta Energy Company (Vesta) covering the marketer's commitment for 50 MMcfd of firm transportation. The Company's exploration and production segment was supplying 25 MMcfd of the volumes transported by Vesta under that agreement. In late 1993, Vesta filed suit against NOARK, the Company, and certain of its affiliates, and, effective January 1, 1994, ceased transporting gas under its contract with NOARK. The complaint and subsequent filings seek rescission of both the transportation contract and a contract to purchase gas from the Company's affiliates, along with actual and punitive damages. The Company and NOARK believe the suit is without merit and have filed counterclaims seeking enforcement of the contracts and damages. The APSC has established a maximum transportation rate of approximately $.285 per dekatherm for NOARK based on its original construction cost estimate of approximately $73 million. Due to construction conditions and the addition of a compressor station, the ultimate cost of the pipeline exceeded the original estimate by approximately $30 million. NOARK competes primarily with two interstate pipelines in its gathering area. One of those elected to become an open access transporter subsequent to NOARK's start of construction. That pipeline, which was recently sold, has not offered firm transportation, but the increased availability of interruptible transportation service has intensified the competitive environment within which NOARK operates. The Company expects further losses from its equity investment in NOARK until the pipeline is able to increase its level of throughput and until improvement occurs in the competitive conditions which determine the transportation rates NOARK can charge. The Company and the other partners of NOARK are currently investigating several options which would improve NOARK's future financial prospects. However, the Company believes that no write-down of its investment in NOARK is appropriate at this time and that it will realize its investment in NOARK over the life of the system. The Company's effective income tax rate was 38.5% in 1994, 42.3% in 1993, and 37.4% in 1992. The rate increased in 1993 because the Company's deferred tax provision included $1.7 million of expense for the legislated increase in the maximum federal corporate income tax rate. LIQUIDITY AND CAPITAL RESOURCES The Company continues to depend principally on internally generated funds as its major source of liquidity. However, the Company has sufficient ability to borrow additional funds to meet its short-term seasonal needs for cash, to finance a portion of its routine spending, if necessary, or to finance other extraordinary investment opportunities which might arise. In 1994, 1993, and 1992, net cash provided from operating activities totaled $66.6 million, $70.2 million, and $49.7 million, respectively. The primary components of cash generated from operations are net income, depreciation, depletion and amortization, and the provision for deferred income taxes. Net cash from operating activities provided 92% of the Company's capital requirements for routine capital expenditures, cash dividends, and scheduled debt retirements in 1994, in excess of 100% in 1993, and 94% in 1992. Dividends paid to common shareholders in 1994 were $6.2 million, compared to $5.7 million in 1993, and $5.1 million in 1992. In July, 1993, the Board of Directors increased the quarterly dividend on the Company's common stock by 20% to $.06 per share from $.05 per share. On an annual basis, the rate is equivalent to $.24 per share, compared to an annual dividend rate of $.20 per share paid in 1992. The dividend rates reflect the effect of a three-for-one stock split distributed in 1993. On February 22, 1995, the Board of Directors authorized the repurchase of up to $30 million of the Company's common shares. The shares will be purchased from time to time, depending on market conditions, in the open market or in private negotiated transactions. The Company plans to utilize available capacity of its revolving credit facilities to fund the share repurchase. Shares repurchased will be held in treasury and may be used for general corporate purposes, including issuance under option plans. The repurchase program will continue until terminated by the Company's Board of Directors. Changes in the Company's liquidity in future years are expected to be related primarily to changes in cash flow generated from its operations. Factors affecting operating results were discussed under Results of Operations. CAPITAL EXPENDITURES Capital expenditures totaled $76.9 million in 1994, $59.2 million in 1993, and $44.9 million in 1992. In 1994, expenditures for the exploration and production segment included $13.9 million for acquisitions of reserves in place. In 1992, the Company also made a $7.6 million equity contribution to the partnership formed to construct NOARK.
1994 1993 1992 ------------------------------------------------------------------------------- (in thousands) CAPITAL EXPENDITURES Exploration and production $55,449 $37,411 $30,823 Gas distribution 17,577 19,892 12,188 Other 3,828 1,916 1,898 ------------------------------------------------------------------------------- $76,854 $59,219 $44,909 ===============================================================================
The Company generally intends to adjust its level of routine capital expenditures depending on the expected level of internally generated cash and the level of debt in its capital structure. The Company expects that its level of capital spending will be adequate to allow the Company to maintain its present markets, finance improvements necessary due to normal customer growth in its gas distribution segment, and explore and develop existing gas and oil properties as well as generate new drilling prospects. Routine capital expenditures expected to be incurred in 1995 are 18 $71.7 million, consisting of $55.2 million for gas and oil exploration, $14.1 million for gas distribution system expenditures, and $2.4 million for general purposes. The Company's capital expenditure plans also include approximately $6.7 million of nonroutine spending, including $3.3 million for the construction and renovation of office and operations facilities in the utility division and $3.4 million for improvements to the utility's gas storage facilities. The gas and oil expenditures include $12.0 million for exploratory drilling and $18.2 million to continue the development of the Company's acreage in the Arkoma Basin. During 1994, the Company increased its emphasis on acquisitions of producing properties and expects that effort to continue as a supplement to its exploration and development drilling programs. Such acquisitions may require capital spending beyond that planned for routine purposes. The Company plans to manage the debt portion of its capital structure over time through its policy of adjusting its routine capital spending, but expects to continue to use additional debt to address extraordinary needs or opportunities, such as attractive acquisitions of gas and oil properties. Additionally, the Company may use its existing revolving credit facilities to meet seasonal or short-term requirements related to its capital expenditures. FINANCING REQUIREMENTS Two floating rate revolving credit facilities provide the Company access to $80.0 million of variable rate long-term capital. Borrowings outstanding under these credit facilities totaled $52.3 million at the end of 1994 and $31.0 million at the end of 1993. The Company also had available short-term lines of credit totaling $3.5 million at the end of 1994 and 1993. The Company plans to evaluate options for converting a significant portion of the amount outstanding on its floating rate revolving credit facilities to another form of long-term debt during 1995. The Company and an affiliate of the other general partner of NOARK are required to severally guarantee the availability of certain minimum cash balances to service NOARK's 9.7375% Senior Secured Notes. These notes are held by a major insurance company which also has a 20% limited partnership interest in NOARK. The notes had a balance of $59.9 million at December 31, 1994, with final maturity in 2009. The Company's share of the several guarantee of available cash balances is 60%. NOARK also has an unsecured long-term revolving credit agreement with a group of banks which provides the partnership access to $30.0 million of additional funds. Amounts outstanding under this credit arrangement were $29.6 million at December 31, 1994, and $25.2 million at December 31, 1993. Amounts borrowed under the long-term revolving credit agreement are severally guaranteed by the Company and an affiliate of the other general partner. The Company's share of this several guarantee is also 60%. In 1994, the Company advanced $2.3 million to NOARK to fund its share of debt service payments and to make the final payment of construction retainage to the pipeline's main line contractor. The Company expects to advance funds to NOARK totaling $4.5 million to $5.0 million during 1995 in connection with its guarantees. In July, 1992, the Company entered into a two-year reverse interest rate swap agreement with a notional amount of $30.0 million. Under the terms of the swap, which expired in 1994, the Company received interest semiannually at a fixed rate of 5.11% and paid interest semiannually at the London Interbank Offered Rate. Over the two-year period the swap was in effect, the Company received $.7 million in excess of its required payments. This amount was recorded as a net reduction of interest expense. Under its existing debt agreements, the Company may not issue long-term debt in excess of 65% of its total capital and may not issue total debt in excess of 70% of its total capital. To issue additional long-term debt, the Company must also have, after giving effect to the debt to be issued, a ratio of earnings to fixed charges of at least 1.50 or higher. At the end of 1994, the capital structure consisted of 40.1% debt (excluding the current portion of long-term debt and the Company's several guarantee of NOARK's obligations) and 59.9% equity, with a ratio of earnings to fixed charges of 3.3. WORKING CAPITAL The Company maintains access to funds which may be needed to meet seasonal requirements through the revolving and short-term lines of credit explained above. The Company had net working capital of $8.9 million at the end of 1994, and $8.1 million at the end of 1993. Current assets increased by 3% to $48.0 million in 1994, while current liabilities increased 1% to $39.1 million. The increase in current assets was due primarily to an increase in the current portion of gas stored underground, reflecting the value of stored gas expected to be utilized on an annual basis, offset by a decrease in accounts receivable due to lower weather related sales at year-end 1994. The increase in current liabilities resulted primarily from an increase in the current portion of long- term debt and an increase in accounts payable, offset by a decrease in taxes payable. The increase in accounts payable resulted primarily from the timing of payments of amounts due. The decrease in taxes payable was due primarily to lower taxable income and increased deductions for intangible drilling costs. Intangible drilling costs are deductible currently for tax purposes, but are capitalized and amortized over future periods for financial reporting purposes. 19 REPORT OF INDEPENDENT AUDITORS To the Board of Directors and Shareholders of Southwestern Energy Company: We have audited the consolidated balance sheets of SOUTHWESTERN ENERGY COMPANY (an Arkansas corporation) AND SUBSIDIARIES as of December 31, 1994 and 1993, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwestern Energy Company and Subsidiaries as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. As discussed in Notes 3 and 4 to the consolidated financial statements, effective January 1, 1993, the Company changed its methods of accounting for income taxes and for postretirement benefits other than pensions. ARTHUR ANDERSEN LLP Tulsa, Oklahoma February 7, 1995 20 Statements of Income Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1994 1993 1992 ----------------------------------------------------------------------------------------------------------------------- ($ in thousands, except per share amounts) OPERATING REVENUES Gas sales $ 160,463 $ 166,164 $ 135,765 Oil sales 3,178 1,662 2,379 Gas transportation 4,721 5,177 3,597 Other 1,824 1,841 2,089 ----------------------------------------------------------------------------------------------------------------------- 170,186 174,844 143,830 ----------------------------------------------------------------------------------------------------------------------- OPERATING COSTS AND EXPENSES Purchased gas costs 36,395 42,962 35,848 Operating and general 42,506 40,093 34,970 Depreciation, depletion and amortization 35,546 30,944 23,880 Taxes, other than income taxes 3,657 3,281 3,144 ----------------------------------------------------------------------------------------------------------------------- 118,104 117,280 97,842 ----------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 52,082 57,564 45,988 ----------------------------------------------------------------------------------------------------------------------- INTEREST EXPENSE Interest on long-term debt 9,962 10,090 10,932 Other interest charges 504 483 547 Interest capitalized (1,599) (1,548) (1,496) ----------------------------------------------------------------------------------------------------------------------- 8,867 9,025 9,983 ----------------------------------------------------------------------------------------------------------------------- OTHER INCOME (EXPENSE) (2,362) (1,657) (421) ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE PROVISION FOR INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 40,853 46,882 35,584 ----------------------------------------------------------------------------------------------------------------------- PROVISION FOR INCOME TAXES Current 9,288 13,704 7,403 Deferred 6,441 6,128 5,916 ----------------------------------------------------------------------------------------------------------------------- 15,729 19,832 13,319 ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 25,124 27,050 22,265 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR INCOME TAXES -- 10,126 -- ----------------------------------------------------------------------------------------------------------------------- NET INCOME $ 25,124 $ 37,176 $ 22,265 ======================================================================================================================= EARNINGS PER SHARE Income Before Cumulative Effect of Accounting Change $.98 $1.05 $.87 Cumulative Effect of Change in Accounting for Income Taxes -- .39 -- ----------------------------------------------------------------------------------------------------------------------- NET INCOME $.98 $1.44 $.87 ======================================================================================================================= WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 25,684,110 25,684,110 25,683,963 =======================================================================================================================
The accompanying notes are an integral part of the financial statements. 21 Balance Sheets Southwestern Energy Company and Subsidiaries
December 31 1994 1993 ------------------------------------------------------------------------------------------------------------------- (in thousands) ASSETS CURRENT ASSETS Cash $ 1,152 $ 834 Accounts receivable 32,325 34,894 Inventories, at average cost 12,199 9,580 Other 2,353 1,489 ------------------------------------------------------------------------------------------------------------------- Total current assets 48,029 46,797 ------------------------------------------------------------------------------------------------------------------- Investments 4,877 5,661 ------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment, at cost Gas and oil properties, using the full cost method, including $20,751,000 in 1994 and $16,769,000 in 1993 excluded from amortization 435,570 375,281 Gas distribution systems 176,728 165,443 Gas in underground storage 36,629 37,171 Other 18,541 14,684 ------------------------------------------------------------------------------------------------------------------- 667,468 592,579 Less: Accumulated depreciation, depletion and amortization 242,008 205,949 ------------------------------------------------------------------------------------------------------------------- 425,460 386,630 ------------------------------------------------------------------------------------------------------------------- Other Assets 6,216 6,366 ------------------------------------------------------------------------------------------------------------------- $484,582 $445,454 =================================================================================================================== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Current portion of long-term debt $ 6,071 $ 3,000 Accounts payable 18,670 16,114 Taxes payable 716 6,449 Customer deposits 4,232 3,927 Current portion of deferred income taxes 1,482 1,426 Over-recovered purchased gas costs, net 3,627 4,187 Other 4,345 3,594 ------------------------------------------------------------------------------------------------------------------- Total current liabilities 39,143 38,697 ------------------------------------------------------------------------------------------------------------------- Long-Term Debt, less current portion above 136,229 124,000 ------------------------------------------------------------------------------------------------------------------- Other Liabilities Deferred income taxes 100,288 93,593 Deferred investment tax credits 2,416 2,617 Other 3,050 2,017 ------------------------------------------------------------------------------------------------------------------- 105,754 98,227 ------------------------------------------------------------------------------------------------------------------- Commitments and Contingencies ------------------------------------------------------------------------------------------------------------------- Shareholders' Equity Common stock, $.10 par value; authorized 75,000,000 shares, issued 27,738,084 shares 2,774 2,774 Additional paid-in capital 21,231 21,231 Retained earnings, per accompanying statements 199,430 180,470 ------------------------------------------------------------------------------------------------------------------- 223,435 204,475 Less: Unamortized cost of restricted shares issued under stock incentive plan, 21,499 shares in 1994 and 17,447 shares in 1993 262 228 Common stock in treasury, at cost, 2,053,974 shares 19,717 19,717 ------------------------------------------------------------------------------------------------------------------- 203,456 184,530 ------------------------------------------------------------------------------------------------------------------- $484,582 $445,454 ===================================================================================================================
The accompanying notes are an integral part of the financial statements. 22 Statements of Cash Flows Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1994 1993 1992 -------------------------------------------------------------------------------------------------------- (in thousands) Cash Flows From Operating Activities Net income $ 25,124 $ 37,176 $ 22,265 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 35,825 31,223 24,160 Deferred income taxes 6,441 6,128 5,916 Equity in loss of partnership 2,818 1,788 531 Cumulative effect of change in accounting for income taxes -- (10,126) -- Change in assets and liabilities: (Increase) decrease in accounts receivable 2,569 (589) (5,002) (Increase) decrease in inventories (2,619) (1,544) 440 Increase in accounts payable 2,556 2,298 876 Increase (decrease) in taxes payable (5,733) 3,111 1,848 Increase in customer deposits 305 417 347 Decrease in over-recovered purchased gas costs (560) (286) (1,335) Net change in other current assets and liabilities (113) 603 (316) -------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 66,613 70,199 49,730 -------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Capital expenditures (76,854) (59,219) (44,909) Investment in partnership (2,319) -- (7,573) (Increase) decrease in gas stored underground 542 9,119 (4,432) Other items 3,200 1,599 1,997 -------------------------------------------------------------------------------------------------------- Net cash used in investing activities (75,431) (48,501) (54,917) -------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Net increase (decrease) in revolving long-term debt 21,300 (15,500) 22,000 Payments on other long-term debt (6,000) (835) (12,769) Dividends paid (6,164) (5,651) (5,137) -------------------------------------------------------------------------------------------------------- Net cash provided (used) by financing activities 9,136 (21,986) 4,094 -------------------------------------------------------------------------------------------------------- Increase (decrease) in cash 318 (288) (1,093) Cash at beginning of year 834 1,122 2,215 -------------------------------------------------------------------------------------------------------- Cash at end of year $ 1,152 $ 834 $ 1,122 ========================================================================================================
Statements of Retained Earnings Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1994 1993 1992 -------------------------------------------------------------------------------------------------------- (in thousands) Retained Earnings, beginning of year $180,470 $148,945 $131,817 Net income 25,124 37,176 22,265 Cash dividends declared ($.24 per share in 1994, $.22 per share in 1993 and $.20 per share in 1992) (6,164) (5,651) (5,137) -------------------------------------------------------------------------------------------------------- Retained Earnings, end of year $199,430 $180,470 $148,945 ========================================================================================================
The accompanying notes are an integral part of the financial statements. 23 Notes to Financial Statements December 31, 1994, 1993 and 1992 (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CONSOLIDATION The consolidated financial statements include the accounts of Southwestern Energy Company and its wholly owned subsidiaries, Southwestern Energy Production Company, SEECO, Inc., Arkansas Western Gas Company, Southwestern Energy Pipeline Company, Arkansas Western Pipeline Company, and A.W. Realty Company. All significant intercompany accounts and transactions have been eliminated. The Company accounts for a general partnership interest of approximately 48% in the NOARK Pipeline System, Limited Partnership (NOARK) using the equity method of accounting. In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," the Company recognizes profit on intercompany sales of gas delivered to storage by its utility subsidiary. Certain reclassifications have been made to the prior years' financial statements to conform with the 1994 presentation. PROPERTY, DEPRECIATION, DEPLETION AND AMORTIZATION Gas and Oil Properties-The Company follows the full cost method of accounting for the exploration, development, and acquisition of gas and oil reserves. Under this method, all such costs (productive and nonproductive) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. The Company excludes all costs of unevaluated properties from immediate amortization. Gas Distribution Systems-Costs applicable to construction activities, including overhead items, are capitalized. Depreciation and amortization of the gas distribution system is provided using the straight-line method with average annual rates for plant functions ranging from 2.2% to 6.9%. Gas in underground storage is stated at average cost. Other property, plant and equipment is depreciated using the straight-line method over estimated useful lives ranging from 5 to 40 years. The Company charges to maintenance or operations the cost of labor, materials, and other expenses incurred in maintaining the operating efficiency of its properties. Betterments are added to property accounts at cost. Retirements are credited to property, plant and equipment at cost and charged to accumulated depreciation, depletion and amortization with no gain or loss recognized, except for abnormal retirements. Capitalized Interest-Interest is capitalized on the costs of unevaluated gas and oil properties excluded from amortization. In accordance with established utility regulatory practice, an allowance for funds used during construction of major projects is capitalized and amortized over the estimated lives of the related facilities. GAS DISTRIBUTION REVENUES AND RECEIVABLES Customer receivables arise from the sale or transportation of gas by the Company's gas distribution subsidiary. The Company's gas distribution customers represent a diversified base of residential, commercial, and industrial users. Approximately 97,000 of these customers are served in northwest Arkansas and approximately 67,000 are served in northeast Arkansas and Missouri. The Company records gas distribution revenues on an accrual basis, as gas volumes are used, in order to provide a proper matching of revenues with expenses. The gas distribution subsidiary's rate schedules include purchased gas adjustment clauses whereby the actual costs of purchased gas above or below the levels included in the base rates are permitted to be billed or are required to be credited to customers. Each month, the difference between actual costs of purchased gas and gas costs recovered from customers is deferred. The deferred differences are billed or credited, as appropriate, to customers in subsequent months. GAS PRODUCTION IMBALANCES The exploration and production subsidiaries record gas sales using the entitlement method. The entitlement method requires revenue recognition of the Company's share of gas production from properties in which gas sales are disproportionately allocated to owners because of marketing or other contractual arrangements. The Company's net imbalance position at December 31, 1994 and 1993 was not significant. INCOME TAXES Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. INVESTMENT TAX CREDITS Investment tax credits have been deferred for financial reporting purposes and are being amortized over the estimated useful lives of the related properties. 24 DERIVATIVES The Company has only limited involvement with derivative financial instruments and does not use them for trading purposes. They are used to manage defined interest rate and commodity price risks. Interest rate swap agreements involve the exchange of fixed rate and floating rate interest payments without the exchange of the underlying principal amounts. The differential to be paid or received is recognized as an adjustment to interest expense. See Note 2 for a discussion of the Company's interest rate swap agreement which expired in 1994. The Company had no outstanding interest rate swap agreements at December 31, 1994. The Company uses natural gas swap agreements on a limited basis to hedge sales of natural gas. Under the natural gas swap agreements, the Company makes payments or receives the differential between a specified price and the actual selling price of natural gas. Gains and losses resulting from hedging activities have not had a material impact on the Company's results of operations. The Company had no outstanding natural gas swap agreements at December 31, 1994. EARNINGS PER SHARE AND SHAREHOLDERS' EQUITY Earnings per common share are based on the weighted average number of common shares outstanding during each year. All share and per share information for 1992 has been restated to reflect the effects of a three-for-one stock split distributed on August 5, 1993. (2) LONG-TERM DEBT Long-term debt as of December 31, 1994 and 1993 consisted of the following:
1994 1993 --------------------------------------------------------------------------------------------------------------------------------- (in thousands) SENIOR NOTES 8.69% Series due December 4, 1997 $ 22,500 $ 22,500 8.86% Series due in annual installments of $3.1 million beginning December 4, 1995 21,500 21,500 9.36% Series due in annual installments of $2.0 million beginning December 4, 2001 22,000 22,000 10.63% Series due in annual installments of $3.0 million through September 30, 2002 24,000 30,000 --------------------------------------------------------------------------------------------------------------------------------- 90,000 96,000 OTHER Variable rate (6.62% at December 31, 1994) unsecured revolving credit arrangements with two banks 52,300 31,000 --------------------------------------------------------------------------------------------------------------------------------- Total long-term debt 142,300 127,000 Less: Current portion of long-term debt 6,071 3,000 --------------------------------------------------------------------------------------------------------------------------------- $136,229 $124,000 =================================================================================================================================
The Company has several prepayment options under the terms of its Senior Notes. Prepayments made without premium are subject to certain limitations. Other prepayment options involve the payment of premiums based in some instances on market interest rates at the time of prepayment. At December 31, 1994, the Company had two variable rate facilities which make available $80.0 million of long-term revolving credit, of which $52.3 million was outstanding. Each facility allows the Company four interest rate options--the floating prime rate, a fixed rate tied to either short-term certificate of deposit or Eurodollar rates, or a fixed rate based on the lenders' cost of funds. The revolving credit facilities expire in 1998. The Company intends to renew or replace the facilities prior to expiration. At December 31, 1994, the Company had available other lines of credit totaling $3.5 million. These lines either expire within one year or are cancellable by the banks involved at any time. All bear interest at or below the banks' prime rates. There were no outstanding borrowings under these lines at December 31, 1994. The terms of the long-term debt instruments and agreements contain covenants which impose certain restrictions on the Company, including limitation of additional indebtedness and restrictions on the payment of cash dividends. At December 31, 1994, approximately $121.8 million of retained earnings was available for payment as dividends. In 1992, the Company entered into a two-year interest rate swap agreement with a notional amount of $30.0 million to take advantage of low variable rates in relation to existing fixed rates on the Company's long-term debt. This interest rate swap agreement expired in 1994. Aggregate maturities of long-term debt for each of the years ending December 31, 1995 through 1999, are $6.1 million, $6.1 million, $28.6 million, $58.4 million, and $6.1 million. Total interest payments of $10.2 million, $10.3 million, and $11.7 million were made in 1994, 1993, and 1992, respectively. 25 Notes to Financial Statements continued Southwestern Energy Company and Subsidiaries (3) INCOME TAXES Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes." The liability method specified by SFAS No. 109 requires the calculation of accumulated deferred income taxes by application of the tax rate expected to be in effect when the taxes will actually be paid or refunds will be received. Under the liability method, the effect on deferred taxes of a change in tax rates is recognized in income in the period of enactment of the rate change. Under generally accepted accounting principles previously in effect, deferred income taxes were not adjusted to reflect changes in tax rates. The recognition of the cumulative effect, through December 31, 1992, of this change in accounting increased net income in the first quarter of 1993 by $10.1 million, or $.39 per share. SFAS No. 109 also required an adjustment in the third quarter of 1993 to record the effects of a legislated increase in tax rates. This adjustment decreased income before the cumulative effect of the accounting change by $1.7 million, or $.07 per share. The provision for income taxes included the following components:
1994 1993 1992 ---------------------------------------------------------------------------------------------------------------------------------- (in thousands) Federal: Current $ 7,758 $11,514 $ 6,190 Deferred 5,588 3,827 5,096 Deferred tax adjustment for tax rate increase -- 1,743 -- State: Current 1,530 2,190 1,213 Deferred 1,054 752 1,004 Investment tax credit amortization (201) (194) (184) ---------------------------------------------------------------------------------------------------------------------------------- Provision for income taxes $15,729 $19,832 $13,319 ==================================================================================================================================
The provision for income taxes was an effective rate of 38.5% in 1994, 42.3% in 1993, and 37.4% in 1992. The following reconciles the provision for income taxes included in the consolidated statements of income with the provision which would result from application of the statutory federal tax rate to pretax financial income:
1994 1993 1992 --------------------------------------------------------------------------------------------------------------------------------- (in thousands) Expected provision at federal statutory rate of 35% in 1994 and 1993 and 34% in 1992 $14,299 $16,409 $12,098 Increase (decrease) resulting from: State income taxes, net of federal income tax benefit 1,682 1,914 1,463 Percentage depletion on gas and oil production (96) (117) (106) Adjustment to deferred taxes for tax rate increase -- 1,743 -- Investment tax credit amortization (201) (194) (184) Other 45 77 48 --------------------------------------------------------------------------------------------------------------------------------- Provision for income taxes $15,729 $19,832 $13,319 =================================================================================================================================
The components of the Company's net deferred tax liability as of December 31, 1994 and 1993 were as follows:
1994 1993 --------------------------------------------------------------------------------------------------------------------------------- (in thousands) Deferred tax liabilities: Differences between book and tax basis of property $ 89,289 $83,875 Stored gas differences 5,736 5,132 Deferred purchased gas costs 1,557 1,232 Prepaid pension costs 1,628 1,731 Book over tax basis in partnerships 3,535 2,675 Gas imbalances 410 644 Other 685 876 --------------------------------------------------------------------------------------------------------------------------------- 102,840 96,165 --------------------------------------------------------------------------------------------------------------------------------- Deferred tax assets: Accrued compensation 700 770 Other 370 376 --------------------------------------------------------------------------------------------------------------------------------- 1,070 1,146 --------------------------------------------------------------------------------------------------------------------------------- Net deferred tax liability $101,770 $95,019 =================================================================================================================================
26 Prior to the change in accounting for income taxes, the sources of deferred tax items, and the corresponding tax effects during 1992 were as follows (in thousands): ------------------------------------------------------------------------------ Intangible and other exploration and development costs $1,581 Investment tax credits amortized (184) Stored gas differences 972 Excess of tax over book depreciation 1,987 Deferred purchased gas costs 355 Excess of tax over book partnership loss 953 Other 252 ------------------------------------------------------------------------------ Deferred provision for income taxes $5,916 ==============================================================================
Total income tax payments of $14.6 million, $10.2 million, and $6.4 million were made in 1994, 1993, and 1992, respectively. (4) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS Substantially all employees are covered by the Company's defined benefit pension plan. Benefits are based on years of benefit service and the employee's "average compensation," as defined. The Company's funding policy is to contribute amounts which are actuarially determined to provide the plan with sufficient assets to meet future benefit payment requirements and which are tax deductible. Plan assumptions for 1994 and 1993 included an expected long-term rate of return on plan assets of 9%, a weighted average discount rate of 7.5% in 1994 and 8.5% in 1993 for the net pension cost computation, and a salary progression rate of 5%. The reconciliation of prepaid pension cost at December 31, 1994 utilizes a discount rate of 8.5% for future settlements. The following table sets forth the plan's funded status and amounts recognized in the Company's balance sheets at December 31, 1994 and 1993:
1994 1993 ----------------------------------------------------------------------------------------------- (in thousands) Actuarial present value of benefit obligations: Vested benefits $(20,643) $(20,746) Nonvested benefits (1,635) (1,685) ----------------------------------------------------------------------------------------------- Accumulated benefit obligation (22,278) (22,431) Effect of projected future compensation levels (6,368) (7,463) ----------------------------------------------------------------------------------------------- Projected benefit obligation (28,646) (29,894) Plan assets at fair value, primarily common stocks and bonds 36,675 36,601 ----------------------------------------------------------------------------------------------- Plan assets in excess of projected benefit obligation 8,029 6,707 Unrecognized net gain (3,617) (1,869) Unrecognized net asset (1,135) (1,318) Unrecognized prior service cost 454 274 ----------------------------------------------------------------------------------------------- Prepaid pension cost $ 3,731 $ 3,794 ===============================================================================================
Net pension cost for 1994, 1993 and 1992 included the following components:
1994 1993 1992 ----------------------------------------------------------------------------------------------- (in thousands) Service costs (benefits earned during the period) $ 1,217 $ 897 $ 805 Interest cost on projected benefit obligation 2,280 1,999 1,768 Actual return on plan assets (791) (2,819) (4,914) Net amortization and deferral (2,643) (673) 1,860 ----------------------------------------------------------------------------------------------- Net pension cost (credit) $ 63 $ (596) $ (481) ===============================================================================================
The Company also has a supplemental retirement plan which provides for certain pension benefits. Net pension cost recorded for this plan was $201,000, $628,000, and $241,000 in 1994, 1993, and 1992, respectively. In 1993, this plan was funded with $1.2 million. At December 31, 1994, the supplemental retirement plan had a prepaid pension cost of $130,000. Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Under SFAS No. 106, the cost of those benefits is accrued over the period the employee provides services to the Company. Prior to 1993, postretirement benefit expenses were recognized on a pay-as-you-go basis and were not material. The Company currently funds postretirement benefits as claims are incurred. 27 Notes to Financial Statements continued Southwestern Energy Company and Subsidiaries The Company provides postretirement health care and life insurance benefits to eligible employees. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages. A significant portion of the postretirement benefit cost relates to the Company's utility operations and has been deferred as a regulatory asset. Net postretirement benefit cost for 1994 and 1993 included the following components:
1994 1993 ------------------------------------------------------------------------------------------------------- (in thousands) Service cost of benefits earned during the year $ 79 $ 61 Amortization of transition amount 178 103 Amortization of unrecognized gain 17 -- Interest cost on accumulated postretirement benefit obligation (APBO) 164 158 ------------------------------------------------------------------------------------------------------- Net postretirement benefit cost $438 $322 =======================================================================================================
The APBO as of December 31, 1994 and 1993 was comprised of the following:
1994 1993 ------------------------------------------------------------------------------------------------------- (in thousands) Retirees $ 766 $ 655 Active participants, fully eligible 442 543 Other participants 804 835 ------------------------------------------------------------------------------------------------------- Total APBO $2,012 $2,033 =======================================================================================================
In determining the APBO, assumed weighted average discount rates of 8.5% and 7.5% were used for 1994 and 1993, respectively. An increase of 8.0% in the cost of covered health care benefits was assumed for 1995. This rate is assumed to decrease ratably to 6.0% over 7 years and remain at that level thereafter. The effect of a one percentage point increase in the assumed health care cost trend rate for each future year would increase the total APBO at year-end 1994 by $254,000 and the 1994 net postretirement benefit cost by $31,000. (5) NATURAL GAS AND OIL PRODUCING ACTIVITIES All of the Company's gas and oil properties are located in the United States. The table below sets forth the results of operations from gas and oil producing activities:
1994 1993 1992 ------------------------------------------------------------------------------------------------------- (in thousands) Sales $ 80,123 $ 79,374 $ 60,554 Production (lifting) costs (6,771) (6,341) (4,271) Depreciation, depletion and amortization (29,743) (25,686) (19,128) ------------------------------------------------------------------------------------------------------- 43,609 47,347 37,155 Income tax expense (16,684) (18,081) (13,787) ------------------------------------------------------------------------------------------------------- Results of operations $ 26,925 $ 29,266 $ 23,368 =======================================================================================================
The results of operations shown above exclude overhead and interest costs. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits. The table below sets forth capitalized costs incurred in gas and oil property acquisition, exploration and development activities during 1994, 1993 and 1992:
1994 1993 1992 ------------------------------------------------------------------------------------------------------- (in thousands) Property acquisition costs $21,972 $ 5,920 $ 4,768 Exploration costs 12,419 11,695 6,441 Development costs 20,943 19,722 19,563 ------------------------------------------------------------------------------------------------------- Capitalized costs incurred $55,334 $37,337 $30,772 ======================================================================================================= Amortization per Mcf equivalent $.759 $.710 $.723 =======================================================================================================
28 The following table shows the capitalized costs of gas and oil properties and the related accumulated depreciation, depletion and amortization at December 31, 1994 and 1993:
1994 1993 --------------------------------------------------------------------------------------------- (in thousands) Proved properties $405,081 $350,854 Unproved properties 30,489 24,427 --------------------------------------------------------------------------------------------- Total capitalized costs 435,570 375,281 Less: Accumulated depreciation, depletion and amortization 176,764 146,471 --------------------------------------------------------------------------------------------- Net capitalized costs $258,806 $228,810 =============================================================================================
The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 1994. Included in property acquisition costs is $7.3 million representing leasehold and seismic costs related to the remaining unevaluated portion of acreage located on the Fort Chaffee military reservation. These costs are expected to be evaluated and subjected to amortization within the next five years as this acreage is further explored and developed. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.
1994 1993 1992 Prior Total ------------------------------------------------------------------------------------------------------------------ (in thousands) Property acquisition costs $3,655 $1,441 $286 $7,199 $12,581 Exploration costs 3,230 1,200 128 579 5,137 Capitalized interest 1,178 452 71 1,332 3,033 ------------------------------------------------------------------------------------------------------------------ $8,063 $3,093 $485 $9,110 $20,751 ==================================================================================================================
(6) NATURAL GAS AND OIL RESERVES (UNAUDITED) The following table summarizes the changes in the Company's proved natural gas and oil reserves for 1994, 1993 and 1992:
1994 1993 1992 ---------------------------------------------------------------------------------------------------------------------------- Gas Oil Gas Oil Gas Oil (MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls) ---------------------------------------------------------------------------------------------------------------------------- Proved reserves, beginning of year 318,776 479 312,291 359 307,484 505 Revisions of previous estimates (16,551) (258) (4,110) (25) 704 (30) Extensions, discoveries and other additions 30,932 189 46,069 250 29,627 4 Production (37,706) (200) (35,693) (97) (25,755) (120) Acquisition of reserves in place 20,647 1,038 222 -- 231 -- Disposition of reserves in place -- (17) (3) (8) -- -- ---------------------------------------------------------------------------------------------------------------------------- Proved reserves, end of year 316,098 1,231 318,776 479 312,291 359 ============================================================================================================================ Proved, developed reserves: Beginning of year 260,240 469 246,904 337 226,767 467 End of year 261,690 1,116 260,240 469 246,904 337 ============================================================================================================================
The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves" (standardized measure) is a disclosure required by SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." The standardized measure does not purport to present the fair market value of a company's proved gas and oil reserves. In addition, there are uncertainties inherent in estimating quantities of proved reserves. Substantially all quantities of gas and oil reserves owned by the Company were estimated by the independent petroleum engineering firm of K & A Energy Consultants, Inc. Following is the standardized measure relating to proved gas and oil reserves at December 31, 1994, 1993 and 1992:
1994 1993 1992 --------------------------------------------------------------------------------------------------------- (in thousands) Future cash inflows $ 683,438 $ 745,967 $ 681,033 Future production and development costs (96,813) (85,609) (84,483) Future income tax expense (207,359) (236,170) (207,249) --------------------------------------------------------------------------------------------------------- Future net cash flows 379,266 424,188 389,301 10% annual discount for estimated timing of cash flows (189,774) (196,913) (179,331) --------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $ 189,492 $ 227,275 $ 209,970 =========================================================================================================
29 Notes to Financial Statements continued Southwestern Energy Company and Subsidiaries Under the standardized measure, future cash inflows were estimated by applying year-end prices, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pretax cash inflows. Future income taxes were computed by applying the year-end statutory rate, after consideration of permanent differences and enacted tax legislation, to the excess of pretax cash inflows over the Company's tax basis in the associated proved gas and oil properties. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the standardized measure. Following is an analysis of changes in the standardized measure during 1994, 1993 and 1992:
1994 1993 1992 --------------------------------------------------------------------------------------------------------------------------------- (in thousands) Standardized measure, beginning of year $227,275 $209,970 $198,274 Sales and transfers of gas and oil produced, net of production costs (73,352) (73,017) (56,283) Net changes in prices and production costs (29,344) 22,392 9,446 Extensions, discoveries, and other additions, net of future production and development costs 43,458 74,511 52,917 Revisions of previous quantity estimates (19,225) (5,217) 318 Accretion of discount 34,968 31,885 30,253 Net change in income taxes 24,564 (13,524) (4,623) Changes in production rates (timing) and other (18,852) (19,725) (20,332) --------------------------------------------------------------------------------------------------------------------------------- Standardized measure, end of year $189,492 $227,275 $209,970 =================================================================================================================================
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP The Company held a general partnership interest in NOARK of 47.93% at December 31, 1994 and 47.33% at December 31, 1993, and is the pipeline's operator. NOARK is a 258 mile long intrastate gas transmission system which extends across northern Arkansas and was placed in service in September, 1992. NOARK's total construction cost was approximately $103.0 million, with $16.0 million provided by equity contributions of the partners and the remainder provided by long-term debt. NOARK's transportation capacity is 141 million cubic feet of gas per day (MMcfd). The Company's investment in NOARK totaled $4.8 million at December 31, 1994 and $5.3 million at December 31, 1993. The Company's investment in NOARK includes advances of $2.3 million made during 1994 to make the final payment of construction retainage and to provide certain minimum cash balances to service NOARK's long-term debt. Subsequent to December 31, 1994, the Company advanced an additional $1.1 million to NOARK. See Note 12 for further discussion of NOARK's funding requirements and the Company's investment in NOARK. NOARK's financial position at December 31, 1994 and 1993 is summarized below:
1994 1993 ----------------------------------------------------------------------------------------- (in thousands) Current assets $ 1,078 $ 1,551 Noncurrent assets 100,662 102,322 ----------------------------------------------------------------------------------------- $101,740 $103,873 ========================================================================================= Current liabilities $ 6,009 $ 7,290 Long-term debt 86,250 85,050 Loans from general partners 3,225 -- Partners' capital 6,256 11,533 ----------------------------------------------------------------------------------------- $101,740 $103,873 =========================================================================================
The Company's share of NOARK's 1994, 1993 and 1992 pretax loss included in other income (expense) on the statements of income was $2.8 million, $1.8 million, and $.6 million, respectively. NOARK's results of operations for 1994, 1993 and 1992 are summarized below:
1994 1993 1992 --------------------------------------------------------------------------- (in thousands) Operating revenues $10,111 $ 8,301 $ 1,466 Pretax loss $(5,917) $(3,778) $(1,348) ===========================================================================
(8) DISCLOSURES ABOUT THE FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate the value: Cash and Customer Deposits - The carrying amount is a reasonable estimate of fair value. 30 Long-Term Debt - The fair value of the Company's long-term debt is estimated based on the expected current rates which would be offered to the Company for debt of the same maturities. The estimated fair values of the Company's financial instruments as of December 31, 1994 and 1993 were as follows:
1994 1993 -------------------- -------------------- Carrying Fair Carrying Fair Amount Value Amount Value ---------------------------------------------------------------------------------------- (in thousands) Cash $1,152 $1,152 $834 $834 Customer deposits $4,232 $4,232 $3,927 $3,927 Long-term debt $142,300 $144,245 $127,000 $134,661 ========================================================================================
Anticipated regulatory treatment of the excess of fair value over carrying value of the portion of the Company's long-term debt attributable to its regulatory activities, if in fact such debt were settled at amounts approximating those above, would dictate that these amounts be used to increase the Company's rates over a prescribed amortization period. Accordingly, any settlement would not result in a material impact on the Company's financial position or results of operations. At December 31, 1993, the Company also had an interest rate swap with a notional amount of $30.0 million, as discussed in Note 2, with terms that approximate fair market value. (9) SEGMENT INFORMATION The Company operates principally in the exploration and production segment and the gas distribution segment of the natural gas industry. Exploration and production activities consist of ownership of mineral interests in productive and undeveloped leases located entirely in the United States. The gas distribution activities consist of the operation of integrated natural gas transmission and distribution utility systems in the states of Arkansas and Missouri. Intersegment sales by the exploration and production segment to the gas distribution segment are priced in accordance with terms of existing gas contracts and current market conditions. Following is industry segment data for the years ended December 31, 1994, 1993 and 1992:
1994 1993 1992 ------------------------------------------------------------------------------ (in thousands) REVENUES Exploration and production $ 80,123 $ 79,374 $ 60,554 Gas distribution 127,060 131,892 117,495 Other 308 262 256 Eliminations (37,305) (36,684) (34,475) ------------------------------------------------------------------------------ $170,186 $174,844 $143,830 ------------------------------------------------------------------------------ INTERSEGMENT REVENUES Exploration and production $ 36,465 $ 36,091 $ 33,994 Gas distribution 584 337 225 Other 256 256 256 ------------------------------------------------------------------------------ $ 37,305 $ 36,684 $ 34,475 ------------------------------------------------------------------------------ OPERATING INCOME Exploration and production $ 38,883 $ 42,608 $ 33,071 Gas distribution 13,391 15,261 13,094 Corporate expenses (192) (305) (177) ------------------------------------------------------------------------------ $ 52,082 $ 57,564 $ 45,988 ------------------------------------------------------------------------------ IDENTIFIABLE ASSETS Exploration and production $286,887 $236,968 $224,302 Gas distribution 171,470 186,704 179,998 Other 26,225 21,782 22,875 ------------------------------------------------------------------------------ $484,582 $445,454 $427,175 ------------------------------------------------------------------------------ DEPRECIATION, DEPLETION AND AMORTIZATION Exploration and production $ 29,743 $ 25,686 $ 19,128 Gas distribution 4,976 4,564 4,213 Other 827 694 539 ------------------------------------------------------------------------------ $ 35,546 $ 30,944 $ 23,880 ------------------------------------------------------------------------------ CAPITAL ADDITIONS Exploration and production $ 55,449 $ 37,411 $ 30,823 Gas distribution 17,577 19,892 12,188 Other 3,828 1,916 1,898 ------------------------------------------------------------------------------ $ 76,854 $ 59,219 $ 44,909 ==============================================================================
31 Notes to Financial Statements continued Southwestern Energy Company and Subsidiaries (10) STOCK OPTIONS In 1993, the Board of Directors adopted, and the shareholders approved, the Southwestern Energy Company 1993 Stock Incentive Plan (1993 Plan) for the compensation of officers and key employees of the Company and its subsidiaries. The 1993 Plan replaced both the Company's 1985 Non-Qualified Stock Option Plan (1985 Plan) and the long-term component of the Company's then existing cash- based incentive compensation plan. The 1993 Plan provides for grants of options, shares of restricted stock, and stock bonuses that in the aggregate do not exceed 1,275,000 shares, the grant of stand-alone stock appreciation rights (SARs), shares of phantom stock, and cash awards, the shares related to which in the aggregate do not exceed 1,275,000 shares, and the grant of limited and tandem SARs (all terms as defined in the 1993 Plan). The types of incentives which may be awarded are comprehensive and are intended to enable the Board of Directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the ten-year term of the plan. At December 31, 1994, there were options for 886,108 shares outstanding under the 1993 Plan at option prices of $14 5/8 and $17 1/8, representing the fair market values at the dates of grant. Of the total, 783,704 performance accelerated options were granted in 1994 at an option price of $14 5/8. These options vest over a four-year period beginning six years from the date of grant or earlier if certain corporate performance criteria are achieved. The remaining options, granted in 1993, vest to employees over a three-year period from the date of grant. Options for 14,387 shares are currently exercisable. All options expire ten years from the date of grant. Additionally, 5,573 shares in 1994 and 17,447 shares in 1993 of restricted stock have been granted which vest to employees over a five-year period. The related compensation expense is being amortized over the vesting period. Under the 1985 Plan, there were options for 427,050 shares and 84,900 SARs outstanding at December 31, 1994, at prices ranging from $5.58 to $12.81. All options are currently exercisable. All options expire ten years from the date of grant. The number of options, SARs, and option prices have been restated to reflect the effect of a three-for-one stock split distributed in 1993. In 1993, the Company also adopted, and the shareholders approved, the Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors. The directors' plan provides for annual stock option grants of 12,000 shares (with 12,000 limited SARs) to each non-employee director. Options may be awarded under the plan on no more than 240,000 shares. Options are issued at fair market value on the date of grant and become exercisable in installments at a rate of 25% per year for each twelve months' service as a director. At December 31, 1994, there were options for 96,000 shares outstanding at option prices of $14 3/4 and $17 1/2. Options for 12,000 shares are currently exercisable. (11) COMMON STOCK PURCHASE RIGHTS One common share purchase right is attached to each outstanding share of the Company's common stock. Each right entitles the holder to purchase one share of common stock at an exercise price of $25.00, subject to adjustment. The exercise price and the number of rights outstanding have been adjusted to reflect the effects of the stock split distributed in 1993. These rights will become exercisable in the event that a person or group acquires or commences a tender offer for 20% or more of the Company's outstanding shares or the Board determines that a holder of 10% or more of the Company's outstanding shares presents a threat to the best interests of the Company. At no time will these rights have any voting power. If any person or entity actually acquires 20% of the common stock (10% or more if the Board determines such acquiror is adverse), rightholders (other than the 20% or 10% stockholder) will be entitled to buy, at the right's then current exercise price, the Company's common stock with a market value of twice the exercise price. Similarly, if the Company is acquired in a merger or other business combination, each right will entitle its holder to purchase, at the right's then current exercise price, a number of the surviving company's common shares having a market value at that time of twice the right's exercise price. The rights may be redeemed by the Board for $.003 per right prior to the time that they become exercisable. In the event, however, that redemption of the rights is considered in connection with a proposed acquisition of the Company, the Board may redeem the rights only on the recommendation of its independent directors (nonmanagement directors who are not affiliated with the proposed acquiror). These rights expire in 1999. (12) CONTINGENCIES AND COMMITMENTS The Company and the other general partner of NOARK are required to severally guarantee the availability of certain minimum cash balances to service the 9.7375% Senior Secured Notes used to finance a portion of NOARK's total construction cost. At December 31, 1994, the Senior Secured Notes had a remaining balance of $59.9 million. The notes have a remaining term of 15 years and the Company's share of the several guarantee is 60%. At December 31, 1994, NOARK also had an unsecured long-term revolving credit agreement in the amount of $30.0 million with a group of banks, of which $29.6 million was outstanding. Amounts borrowed under the long-term revolving credit facility are severally guaranteed by the Company and an affiliate of the other general partner. The Company's share of the several guarantee of the line of credit is also 60%. Additionally, the Company's gas distribution subsidiary has a ten-year transportation contract with NOARK for firm capacity of 41 MMcfd. 32 In late 1993, a transporter of gas on NOARK's pipeline system filed suit against NOARK, the Company, and certain of its affiliates, and, effective January 1, 1994, ceased transporting gas under its firm transportation agreement with NOARK. The complaint seeks rescission of the transportation contract and rescission of a separate contract to purchase gas from two of the Company's affiliates, as well as actual and punitive damages in excess of $1.0 million. The Company and NOARK believe the suit is without merit and have filed counterclaims seeking enforcement of the contracts and damages. Until enforcement occurs or replacement transportation contracts are arranged, the Company will be required to fund its share of any cash flow deficiencies to the extent they are not funded by the available line of credit. Management of the Company and the NOARK partners are currently investigating several options available to NOARK. However, management believes that no write-down of its investment in NOARK is appropriate at this time and that it will realize its investment in NOARK over the life of the system. Therefore, no provision for any loss has been made in the accompanying financial statements. The Company is subject to laws and regulations relating to the protection of the environment. The Company's policy is to accrue environmental and cleanup related costs of a noncapital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial condition or reported results of operations of the Company. The Company is subject to other litigation that has arisen in the ordinary course of business. In the opinion of management, the results of such litigation will not have a material effect on the results of operations or the financial position of the Company. (13) QUARTERLY RESULTS (UNAUDITED) The following is a summary of the quarterly results of operations for the years ended December 31, 1994 and 1993:
Quarter Ended March 31 June 30 September 30 December 31 --------------------------------------------------------------------------------------------------------------- (in thousands, except per share amounts) 1994 ---- Operating revenues $65,430 $34,605 $27,808 $42,343 Operating income $23,525 $10,471 $6,327 $11,759 Net income $12,994 $4,834 $2,128 $5,168 Earnings per share $.51 $.18 $.09 $.20 1993 ---- Operating revenues $59,208 $33,990 $28,466 $53,180 Operating income $21,259 $8,738 $7,789 $19,778 Income before cumulative effect of accounting change $11,372 $3,696 $1,439 $10,543 Net income $21,498 $3,696 $1,439 $10,543 Earnings per share before cumulative effect of accounting change $.44 $.15 $.05 $.41 Earnings per share $.83 $.15 $.05 $.41 ===============================================================================================================
33 Financial and Operating Statistics
1994 1993 1992 1991 1990 1989 ---------------------------------------------------------------------------------------------------------------------------------- FINANCIAL REVIEW (in thousands) Operating revenues: Exploration and production $ 80,123 $ 79,374 $ 60,554 $ 49,392 $ 41,489 $ 40,499 Gas distribution 127,060 131,892 117,495 121,302 108,911 117,514 Other 308 262 256 256 256 256 Intersegment revenues (37,305) (36,684) (34,475) (34,511) (33,586) (33,670) ---------------------------------------------------------------------------------------------------------------------------------- 170,186 174,844 143,830 136,439 117,070 124,599 ---------------------------------------------------------------------------------------------------------------------------------- Operating costs and expenses: Purchased gas costs 36,395 42,962 35,848 40,423 37,678 46,850 Operating and general 42,506 40,093 34,970 32,609 28,134 26,132 Depreciation, depletion and amortization 35,546 30,944 23,880 18,248 14,756 16,055 Taxes, other than income taxes 3,657 3,281 3,144 3,017 2,885 2,844 ---------------------------------------------------------------------------------------------------------------------------------- 118,104 117,280 97,842 94,297 83,453 91,881 ---------------------------------------------------------------------------------------------------------------------------------- Operating income 52,082 57,564 45,988 42,142 33,617 32,718 Interest expense, net (8,867) (9,025) (9,983) (9,813) (10,530) (10,662) Other income (expense) (2,362) (1,657) (421) (107) (17) 180 ---------------------------------------------------------------------------------------------------------------------------------- Income before provision for income taxes 40,853 46,882 35,584 32,222 23,070 22,236 ---------------------------------------------------------------------------------------------------------------------------------- Provision for income taxes: Current 9,288 13,704 7,403 7,158 4,994 6,671 Deferred 6,441 6,128 5,916 4,999 3,568 1,586 ---------------------------------------------------------------------------------------------------------------------------------- 15,729 19,832 13,319 12,157 8,562 8,257 ---------------------------------------------------------------------------------------------------------------------------------- Income before extraordinary item and cumulative effect of accounting change 25,124 27,050 22,265 20,065 14,508 13,979 Extraordinary loss due to redemption of convertible debentures (net of $257 tax benefit) -- -- -- -- (433) -- Cumulative effect of change in accounting for income taxes -- 10,126 -- -- -- -- ---------------------------------------------------------------------------------------------------------------------------------- Net income $ 25,124 $ 37,176 $ 22,265 $ 20,065 $ 14,075 $ 13,979 ================================================================================================================================== Cash flow from operations (in thousands) $66,613 $70,191 $49,730 $34,986 $36,495 $29,306 Return on equity 12.35% 14.66%/(1)/ 14.53% 14.75% 11.66% 13.51% Gross profit margin 30.60% 32.92% 31.97% 30.89% 28.72% 26.26% Net profit margin 14.76% 15.47%/(1)/ 15.48% 14.71% 12.02% 11.22% ================================================================================================================================== COMMON STOCK STATISTICS/(2)/ Earnings per share before extraordinary item and cumulative effect of accounting change $.98 $1.05 $.87 $.78 $.57 $.56 Earnings per share $.98 $1.44 $.87 $.78 $.56 $.56 Cash dividends declared and paid per share $.24 $.22 $.20 $.19 $.19 $.19 Book value per share $7.92 $7.18 $5.97 $5.30 $4.70 $4.15 Market price at year end $14.88 $18.00 $12.96 $10.50 $10.42 $10.75 Number of shareholders of record at year end 2,875 3,005 2,930 2,989 3,136 3,298 Average shares outstanding 25,684,110 25,684,110 25,683,963 25,678,011 25,270,674 24,940,488 ================================================================================================================================== CAPITALIZATION (in thousands) Long-term debt, including current portion $142,300 $127,000 $143,335 $134,104 $125,535 $128,449 Common shareholders' equity 203,456 184,530 153,233 136,041 120,709 103,455 ---------------------------------------------------------------------------------------------------------------------------------- Total capitalization $345,756 $311,530 $296,568 $270,145 $246,244 $231,904 ---------------------------------------------------------------------------------------------------------------------------------- Total assets $484,582 $445,454 $427,175 $392,208 $366,313 $347,212 ---------------------------------------------------------------------------------------------------------------------------------- Capitalization ratios: Debt (excluding current portion) 40.10% 40.19% 48.31% 49.08% 50.39% 54.82% Equity 59.90% 59.81% 51.69% 50.92% 49.61% 45.18% ================================================================================================================================== CAPITAL EXPENDITURES (in millions) Exploration and production $55.4 $37.4 $30.8 $30.3 $23.4 $26.6 Gas distribution 17.6 19.9 12.2 7.9 9.3 8.9 Other 3.9 1.9 1.9 .7 .7 3.5 ---------------------------------------------------------------------------------------------------------------------------------- $76.9 $59.2 $44.9 $38.9 $33.4 $39.0 ==================================================================================================================================
/(1)/Before the cumulative effect of accounting change. /(2)/All share and per share data have been restated to reflect the effect of a three-for-one stock split distributed in 1993. 34
1994 1993 1992 1991 1990 1989 ----------------------------------------------------------------------------------------------------------------------------------- NATURAL GAS AND OIL WELLS COMPLETED Producers: Gross 78.0 57.0 69.0 25.0 25.0 38.0 Net 50.2 40.7 54.6 11.8 9.1 16.4 Dry holes: Gross 30.0 28.0 29.0 12.0 10.0 22.0 Net 16.5 14.5 19.5 4.1 2.1 7.3 ----------------------------------------------------------------------------------------------------------------------------------- Total: Gross 108.0 85.0 98.0 37.0 35.0 60.0 Net 66.7 55.2 74.1 15.9 11.2 23.7 At the end of 1994, the Company was a participant in 8.0 (2.1 net) wells in process. =================================================================================================================================== NATURAL GAS AND OIL PRODUCED Natural gas: Production, Bcf 37.7 35.7 25.8 20.3 16.7 15.6 Average price per Mcf $2.04 $2.18 $2.26 $2.25 $2.33 $2.43 Oil: Production, MBbls 200 97 120 176 112 149 Average price per barrel $15.89 $17.20 $19.75 $20.67 $22.89 $17.89 Average production (lifting) cost per Mcf equivalent $.17 $.18 $.16 $.19 $.16 $.14 Proved reserves at year end: Natural gas, Bcf 316.1 318.8 312.3 307.5 304.5 252.9 Oil, MBbls 1,231 479 359 505 773 745 =================================================================================================================================== UTILITY OPERATING DATA Sales volumes, Bcf: Residential 11.6 12.9 10.8 10.9 10.1 11.6 Commercial 7.2 7.8 6.6 6.7 6.3 7.1 Industrial 7.5 6.1 6.1 9.5 10.2 9.8 Transportation volumes, Bcf End-use 4.8 5.6 5.2 1.3 .1 .5 Off-system 10.7 11.7 2.5 .2 .3 .1 ----------------------------------------------------------------------------------------------------------------------------------- 41.8 44.1 31.2 28.6 27.0 29.1 ----------------------------------------------------------------------------------------------------------------------------------- Average sales customers: Residential 140,684 137,087 133,103 129,379 127,142 125,581 Commercial 18,872 18,511 18,141 17,880 17,680 17,437 Industrial 341 346 348 370 366 372 ----------------------------------------------------------------------------------------------------------------------------------- 159,897 155,944 151,592 147,629 145,188 143,390 ----------------------------------------------------------------------------------------------------------------------------------- Sales and transportation revenues (in thousands): Residential $ 62,565 $ 67,502 $ 59,747 $ 58,372 $ 48,407 $ 54,181 Commercial 32,252 35,311 31,425 30,718 27,535 30,522 Industrial 25,191 21,757 20,502 29,187 30,463 29,982 Transportation 4,721 5,177 3,597 857 179 368 ----------------------------------------------------------------------------------------------------------------------------------- $124,729 $129,747 $115,271 $119,134 $106,584 $115,053 ----------------------------------------------------------------------------------------------------------------------------------- Miles of pipe: Gathering 405 398 383 375 371 364 Transmission 1,346 1,335 1,328 1,326 1,326 1,309 Distribution 4,246 4,160 4,090 4,002 3,931 3,859 ----------------------------------------------------------------------------------------------------------------------------------- 5,997 5,893 5,801 5,703 5,628 5,532 ----------------------------------------------------------------------------------------------------------------------------------- Degree days 4,161 4,929 4,104 4,095 3,972 4,961 Percent of normal 95% 113% 92% 93% 90% 112% ===================================================================================================================================
35 Shareholder Information ANNUAL MEETING The Annual Meeting of Shareholders of Southwestern Energy Company will be held at the Northwest Arkansas Holiday Inn in Springdale, Arkansas, on Wednesday, May 31, 1995, at 11:00 a.m. Central Daylight Time. STOCK EXCHANGE LISTING Southwestern Energy Company's common stock is traded on the New York Stock Exchange under the symbol SWN and is listed in alphabetical quotation listings in most major newspapers as SowestEngy. INDEPENDENT AUDITORS Arthur Andersen LLP 6450 South Lewis Suite 300 Tulsa, Oklahoma 74136-1068 FINANCIAL INFORMATION Financial analysts and investors who need additional information should contact Stanley D. Green, Executive Vice President--Finance and Corporate Development, at corporate headquarters, 501-521-1141. TRANSFER AGENT AND REGISTRAR First Chicago Trust Company of New York 525 Washington Blvd. Jersey City, NJ 07310 Phone 1-800-446-2617 DIVIDEND REINVESTMENT PLAN Southwestern Energy Company offers holders of record of its common stock the opportunity to purchase additional shares through its Dividend Reinvestment Plan. Dividends and/or optional cash investments of up to $1,000 monthly may be used to purchase additional shares of the Company's stock for nominal service and broker's fees. Information about the Plan is available from the administrator: First Chicago Trust Company of New York P.O. Box 2598 Jersey City, NJ 07303-2598 Phone 1-800-446-2617 ANNUAL REPORT This annual report and the statements contained herein are submitted for the general information of shareholders of the Company and are not intended to induce any sale or purchase of securities or to be used in connection therewith. The 1994 Annual Report filed with the Securities and Exchange Commission on Form 10-K is available to shareholders upon request by writing to the Secretary at corporate headquarters. MARKET PRICES AND QUARTERLY DIVIDENDS PAID
Range of Market Prices Cash Dividends Paid ------------------------------------------------ ------------------- 1994 1993 1994 1993 --------------------------------------------------------------------------------------------- HIGH LOW High Low March 31 $18.88 $15.13 $15.25 $12.13 $.06 $.05 June 30 $17.75 $15.50 $16.83 $14.13 $.06 $.05 September 30 $17.88 $15.50 $21.75 $16.04 $.06 $.06 December 31 $17.75 $14.00 $21.88 $15.13 $.06 $.06 ============================================================================================
Market prices represent transactions on the New York Stock Exchange. 36 Southwestern Energy Company and Subsidiaries APPENDIX TO 1994 ANNUAL REPORT TO SHAREHOLDERS Description of Exploration & Production Operating Areas: Southwestern conducts its exploration and production efforts primarily in three areas; the Arkoma Basin, the Anadarko Basin and the Gulf Coast. The Arkoma Basin is located in the central section of western Arkansas and the central section of eastern Oklahoma. Southwestern's activities are concentrated in the historically productive Arkansas section of the Arkoma Basin. The Anadarko Basin covers most of the western part of Oklahoma and extends to the northwest into the northern panhandle of Texas and the panhandle area of Oklahoma. Southwestern's Gulf Coast operations include both onshore and offshore activity along both the Texas and Louisiana coasts. Description of Gas Distribution Operating Areas: Arkansas Western Gas Company's (AWG) northwest Arkansas gas utility system gathers its gas supply from the Arkoma Basin where they also provide distribution service to communities in that area, including the towns of Ozark and Clarksville. AWG's transmission and distribution lines extend north and supply communities in the northwest part of the state, including the towns of Fayetteville, Springdale and Rogers. AWG's service area also extends east to the Harrison and Mountain Home areas. This eastern section of the AWG system receives a portion of its gas supply from a lateral line off of the NOARK Pipeline System (NOARK) as discussed below. Through its division, Associated Natural Gas Company (Associated), AWG provides distribution of natural gas to communities in northeast Arkansas and parts of Missouri. Major communities served in northeast Arkansas include Blytheville, Piggott and Osceola. The Associated distribution system also serves the "bootheel" area in southeast Missouri, including the communities of Sikeston, New Madrid and Caruthersville and extends north to the Jackson area. In addition, Associated provides service to Butler, Missouri, near the state's western border and Kirksville, Missouri, near the state's northern border through connections off of interstate pipelines in those areas. Description of NOARK Pipeline System Operating Area: Southwestern Energy Pipeline Company owns a 47.93% general partnership interest in NOARK, a 258-mile intrastate pipeline that ties the Claimant's distribution and gathering pipeline systems in northwest Arkansas to its distribution systems in northeast Arkansas and southeast Missouri. NOARK starts near Fort Smith, at the Fort Chaffee military reservation, and extends east through the Arkoma Basin and across northern Arkansas. A lateral from NOARK extends north and connects to AWG's distribution line in the Mountain Home area. NOARK crosses three interstate pipelines in northeast Arkansas and ends at an interconnection with Arkansas Western Pipeline Company's 8-mile interstate pipeline at the Arkansas/Missouri border. This pipeline transports gas from NOARK to Associated's distribution system. Operating Properties: ACREAGE AND PRODUCING WELLS
Undeveloped Developed Wells Gross Net Gross Net Gross Net -------------------------------------------------------------------------------- Arkansas 184,008 95,486 289,387 138,269 736 380.6 Louisiana 15,874 8,938 10,748 3,214 10 5.2 Oklahoma 23,746 15,946 69,835 36,214 465 241.6 Texas 25,121 13,292 51,024 11,247 29 6.7 Other areas 8,361 7,992 5,490 1,313 14 3.8 -------------------------------------------------------------------------------- 257,110 141,654 426,484 190,257 1,254 637.9 ================================================================================
GAS DISTRIBUTION SYSTEMS MILES OF PIPE AWG Associated Total -------------------------------------------------------------------------------- Gathering 405 -- 405 Transmission 744 602 1,346 Distribution 2,691 1,555 4,246 -------------------------------------------------------------------------------- 3,840 2,157 5,997 ================================================================================
EX-27 7 FINANCIAL DATA SCHEDULES
5 1,000 YEAR DEC-31-1994 DEC-31-1994 1,152 0 32,325 0 12,199 48,029 667,468 (242,008) 484,582 39,143 136,229 2,774 0 0 200,682 484,582 163,641 170,186 0 118,104 0 0 8,867 40,853 15,729 25,124 0 0 0 25,124 .98 0