-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, JAdh4pmCeP+LxL+V8T+o/1Qe1MRNt7/BxoBEOMP9el7Ad9b6Abk142xpKanV7GDi plnv/2zBNrA+pi6J2IrDzA== 0000912057-94-001183.txt : 19940331 0000912057-94-001183.hdr.sgml : 19940331 ACCESSION NUMBER: 0000912057-94-001183 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHWESTERN ENERGY CO CENTRAL INDEX KEY: 0000007332 STANDARD INDUSTRIAL CLASSIFICATION: 4923 IRS NUMBER: 710205415 STATE OF INCORPORATION: AR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-08246 FILM NUMBER: 94519250 BUSINESS ADDRESS: STREET 1: 1083 SAIN ST STREET 2: P O BOX 1408 CITY: FAYETTEVILLE STATE: AR ZIP: 72702-1408 BUSINESS PHONE: 5015211141 FORMER COMPANY: FORMER CONFORMED NAME: ARKANSAS WESTERN GAS CO DATE OF NAME CHANGE: 19790917 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, 1993 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. X The aggregate market value of the voting stock held by non-affiliates of the Registrant was $ 438,425,828 based on the New York Stock Exchange - Composite Transactions closing price on March 25, 1994 of $ 17.25. The number of shares outstanding as of March 25, 1994, of the Registrant's common stock, par value $.10, was 25,684,110. 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, 1993 - 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 25, 1994 - PART III. 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 and the gas distribution 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, 1993, the Company had proved natural gas reserves of 318.8 billion cubic feet (Bcf) and proved oil reserves of 479 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 sixth consecutive year in 1993, totaling 35.4 Bcf, up 39% from 25.5 Bcf in 1992. Sales of gas production accounted for 97% of total operating revenues for this segment in 1993, 95% in 1992 and 91% in 1991. 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 2 Arkansas properties and from discoveries made in earlier years offshore in the Gulf of Mexico. Sales to unaffiliated purchasers accounted for 64% of total gas volumes sold by the exploration and production segment in 1993, 55% in 1992 and 35% in 1991. Gas volumes sold by SEECO to Arkansas Western for its northwest Arkansas division (AWG) were approximately 7.1 Bcf in 1993, 7.2 Bcf in 1992 and 7.6 Bcf in 1991. Through these sales, SEECO furnished approximately 50% of the northwest Arkansas system's requirements in each of these years. SEECO also delivered approximately 2.2 Bcf in 1993, 2.8 Bcf in 1992 and .6 Bcf in 1991 directly to certain large business customers of AWG through a transportation service of the utility subsidiary that became effective in October, 1991. These customers previously purchased the majority of their requirements directly from AWG through a spot market purchasing program offered by the utility. Most of the sales to AWG are pursuant to a twenty-year contract between SEECO and AWG which committed to the utility all Company owned reserves in Arkansas as of the contract date of July 24, 1978. Most reserves committed to this contract were classified as Section 105 gas under the Natural Gas Policy Act of 1978 (NGPA). Section 105 covers gas committed to intrastate commerce at the date of enactment of the NGPA and provides that the price received for any such gas will be the contract price, provided that the contract price does not exceed the maximum price as published quarterly by the Federal Energy Regulatory Commission (FERC) for Section 102 gas under the NGPA. The pricing under this contract has been frozen at the December, 1984 level. All gas dedicated to this contract was deregulated as of January 1, 1993. Reserves discovered after the contract date in areas not previously committed to the utility may be sold to the utility at prices determined by present gas market conditions or to unaffiliated companies. The contract also contains provisions for the release of dedicated reserves for sale to unaffiliated companies in certain circumstances. 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 31%, 45% and 49% of total exploration and production revenues in 1993, 1992 and 1991, respectively. In November, 1993, the Arkansas Public Service Commission (APSC or Commission) issued an order which found the purchases of AWG under the 1978 contract to be in violation of an Arkansas statute requiring that gas purchases be made "from the lowest or most advantageous market." The APSC order is discussed more fully below under "Natural gas gathering, transmission and distribution." 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 5.7 Bcf in 1993, 4.3 Bcf in 1992 and 5.3 Bcf in 1991. These deliveries accounted for approximately 67% of Associated's total requirements in 1993, 56% in 1992 and 55% in 1991. These sales represented 15% of total exploration and production revenues in 1993, 14% in 1992 and 20% in 1991. Deliveries to Associated increased in 1993 primarily due to colder winter heating weather and storage requirements during the summer months. The decrease in volumes delivered to Associated in 1992, as compared to 1991, was primarily the result of some of Associated's larger industrial customers switching to transportation service. 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, and are currently being made at a price of $2.385 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, 1993, after 3 transfers and revisions, the remaining proved undeveloped reserves identified by the study were 55.8 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 27.0 Bcf in 1993 and 22.5 Bcf in 1992 of new natural gas reserve additions and resulted in the transfer of 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 74 development wells during 1993 with a completion rate of 73% and expects the number of wells drilled in 1994 to approximate the number drilled in 1993. SEECO's sales to unaffiliated purchasers increased to 9.7 Bcf in 1993, from 4.5 Bcf in 1992 and 1.1 Bcf in 1991. 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, which became effective in October, 1991, and spot sales into markets away from AWG's distribution system. 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." At December 31, 1993, the gas reserves of SEPCO were located primarily in the states of Arkansas, Oklahoma, Louisiana and offshore Texas, while its oil reserves were located primarily in Oklahoma, North Dakota, Louisiana and offshore Texas. SEPCO holds about 22% of the Company's natural gas reserves and all of its oil reserves. SEPCO's gas sales increased to 12.9 Bcf in 1993, from 9.6 Bcf in 1992 and 5.9 Bcf in 1991. The increase in 1993 was primarily the result of increased production from properties located in the Gulf of Mexico. The increase in 1992 was the result of sales from Fort Chaffee, as discussed below. The Company's production from Fort Chaffee and the Gulf of Mexico is sold under contracts which reflect current short-term prices and which are subject to seasonal price swings. The Company curtailed gas production during 1992 and 1991 when sales prices were deemed below acceptable levels. Oil production was 96 MBbls in 1993, compared to 120 MBbls in 1992, and 176 MBbls in 1991. 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 for production 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 gas and oil operating revenues in 1993, 31% in 1992, and 26% in 1991. 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. Conflicts with military training activities have limited SEPCO's drilling operations at Fort Chaffee. The primary training function at Fort Chaffee was transfered to another military installation during 1993 and it appears that scheduling conflicts should be lessened in the future. To date the Company has drilled or participated in eight wells at Fort Chaffee that have discovered an estimated 46.6 Bcf of new gas reserves, net to the Company's interest. SEPCO is currently completing evaluation of a seven line seismic program on its Fort Chaffee acreage. The data provided by the seismic program will be used to develop an exploration plan covering the remainder of SEPCO's acreage at Fort Chaffee. The plan will then be submitted for military approval with a goal of conducting further exploration drilling during 1994. Sales of gas production from Fort Chaffee began 4 in August, 1991 and totaled 5.1 Bcf in 1993, 5.8 Bcf in 1992 and 2.2 Bcf in 1991. Since late 1992, sales from Fort Chaffee have taken 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 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 and does not believe its sales will be adversely affected while the litigation is proceeding. 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 19.0 Bcf of new reserves from drilling, with 15.2 Bcf of that from an onshore discovery in the coastal area of southeast 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 direct its exploration activities toward the onshore Gulf Coast by focusing on the internal generation of prospects in the upper Texas Gulf Coast and in south Louisiana. SEPCO is also participating with an interest of approximately 50% in an exploration program on a 135,000 acre farmout by a major oil company of acreage held by production in the Oklahoma Panhandle. Though the wells drilled are of smaller magnitude than SEPCO's typical Gulf Coast prospect, drilling costs in the Oklahoma Panhandle are low and the wells are economically attractive. Six tests drilled to date have resulted in five completions. Approximately seven new test wells are planned for 1994. 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 holdings of undeveloped acreage 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 1994 capital expenditures for gas and oil exploration and development to total $50.0 million, up from $37.4 million in 1993. Most of the increase in capital spending will be directed to the onshore Gulf Coast along with Fort Chaffee and the Oklahoma Panhandle. 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 160,000 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 5 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. 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 93,000 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 (MPSC) 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 Company is, however, beginning to experience competition from alternative suppliers of natural gas. The competition from alternative fuels and 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 6 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 useage 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 transportation service, including AWG's three largest customers in northwest Arkansas and Associated's largest customer in northeast Arkansas. In its order approving the transportation program, the APSC indicated that it would review the program after one year and consider the desirability of lowering the minimum volume requirement. The APSC also indicated that it would consider in 1992 whether AWG's spot market purchasing program should be continued. The APSC has deferred the review of both programs to a later date. AWG purchases its system gas supply directly at the wellhead under long-term contracts. Purchases are made from approximately 310 working interest owners in 475 producing wells. Most of the 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 applies to gas purchased from SEECO, as well as to purchases from unaffiliated producers. 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, 1993, AWG had a gas supply available to its northwest Arkansas system of approximately 237 Bcf of proved developed reserves, equal to 17 times current annual usage. Of this total, approximately 116 Bcf were net reserves available from SEECO. 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. Prior to 1993, Associated purchased gas for its system supply from six interstate pipelines, SEECO and various spot market suppliers. As a result of the unbundling of gas sales, gathering, transmission and storage services by interstate pipelines mandated by the FERC's Order No. 636, (discussed more fully below), Associated now purchases gas for its system supply from unaffiliated suppliers in the producing fields accessed by interstate pipelines and from SEECO. As previously discussed, Associated purchases its base load system requirements from SEECO under a ten-year contract with annual price redeterminations. Purchases made from unaffiliated suppliers are under purchase contracts with expiration dates ranging from October, 1994 to December, 1995. The rates charged by these suppliers include demand components to ensure availability of gas supply, administration 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. 7 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 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 will not be directly impacted by Order No. 636. Associated has acquired the bulk of its gas supply at the wellhead since its acquisition by AWG, but continues to purchase a portion of both its peak and base requirements from interstate suppliers. During 1993, Associated renegotiated those contracts in accordance with the pipeline restructurings before the FERC. 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. Some of AWG's long-term purchase contracts with unaffiliated companies provide for payments to be made if AWG does not take an annual, minimum quantity of gas (take-or-pay). Any payments made are recovered if the gas is taken before a certain date in the future. As of December 31, 1993, AWG had no unrecovered payments of this type. Associated's previous gas purchase contracts with interstate pipelines also contained take-or-pay provisions. To date, Associated has paid approximately $3.2 million for contract reformation costs incurred by its interstate pipeline suppliers and for contracted quantities of gas not taken. The Company believes these costs are recoverable from its utility customers and expects approval from the proper regulatory agencies after the payments are reviewed in the normal course of business. To date Associated has recovered, subject to refund, approximately $1.6 million of these charges from its customers. The implementation in 1991 of transportation service in Arkansas increases the exposure of AWG and Associated to take-or-pay liabilities, but the Company expects to continue to be able to satisfactorily manage this exposure. AWG has negotiated certain modifications to some of its gas purchase contracts which contain market-out provisions to decrease its exposure to take-or-pay liabilities. 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 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. 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 MPSC regulate the Company's utility rates and operations. Late in 1990, the APSC and the MPSC 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. Arkansas Western has no immediate plans to file for additional rate increases as customer growth and transportation revenues have helped to offset the effects of attrition since the last rate case. 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. In its order approving the 1990 Arkansas rate increase, the APSC established procedures to investigate a number of changes in the regulatory mechanisms under which purchased gas costs are charged to and recovered from the customers of the utility subsidiary. The APSC indicated that its interest was heightened by the fact that Arkansas Western purchases a substantial portion of the gas supply for both AWG and Associated from SEECO. Most of the sales of SEECO's production to AWG take place under a twenty- year, fixed price contract which was approved by the APSC in connection with a corporate rearrangement of the Company in 1978 (the 1978 8 contract). Additionally, the APSC Staff has regularly examined and accepted the gas purchase costs of the utility subsidiary since the Commission approved the corporate reorganization in 1978. These examinations included a review in the 1990 rate case by an outside consultant hired directly by the APSC Staff. That consultant performed an extensive review of the utility's purchasing practices and gas costs, including its purchases from the Company's exploration and production segment, and recommended in filed testimony sponsored by the APSC Staff that all of the utility's gas costs including purchases under the contract in question, be accepted without adjustment. The APSC originally ordered that its proposals related to gas cost recovery and pricing be considered by the parties to the proceeding with the goal of reaching a mutually agreeable resolution of its concerns. After meeting extensively, the parties were unable to reach such a resolution and each party to the proceeding filed its own report with the APSC in July, 1991. In February, 1992, the APSC issued an order establishing a procedural schedule to further address the issues raised by its Staff and Office of the Attorney General of the State of Arkansas (AG). In establishing the schedule, the APSC stated that the record developed does not contain adequately developed evidence on which an informed decision on those issues can be based. The APSC also stated that it will consider only those proposals proffered by the parties which address prospective gas cost reductions. The APSC conducted a hearing in January, 1993, concerning the issues raised in its 1990 order. In November, 1993, the APSC issued an order that found AWG's purchases under the contract in question to be in violation of an Arkansas statute requiring that gas purchases be made "from the lowest or most advantageous market" and that the price paid by AWG was too high. In that same order, the APSC found that purchases by Associated were in compliance with the statute. The order also scheduled a hearing for mid- January, 1994 to accept additional evidence as to the price which should be paid under the AWG contract. At the January, 1994 hearing, both the Staff of the APSC and the AG presented testimony describing recommendations designed to lower the price received by the Company's exploration and production subsidiary under the contract. The Company presented testimony which it believes reinforced its position that the contractual arrangements questioned by the Commission are the most advantageous to its utility customers. Legal briefs were filed in late February, 1994, and the Company expects a Commission order to be forthcoming. If necessary, the Company intends to continue to defend its gas purchasing practices through the courts. The Company does not expect any outcome of this proceeding to have a material adverse impact on the financial position of the Company. Of the Company's 35.4 Bcf of gas production in 1993, approximately 6.0 Bcf was sold under the contract in question. As mentioned above, NOARK is an intrastate pipeline constructed by a limited partnership in which SWPL holds a 47.33% 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 has a capacity of 141 MMcfd and cost approximately $103.0 million to construct. NOARK's original cost estimate was approximately $73.0 million. The cost overrun was the result of the addition of a major central compressor station and increased costs incurred as a result of the rocky, mountainous terrain through which NOARK passes. NOARK completed its first full year of operation in 1993 and had an average daily throughput during the year of 79 MMcfd. 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 9 basis. The Company's exploration and production segment supplies 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 seeks 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 through NOARK the 25 MMcfd of production which was previously purchased by the marketer. 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 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 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 does not offer firm transportation, but the increased availability of interruptible transportation services intensified the competitive environment within which NOARK operates. The Company believes that the FERC's Order No. 636 restructuring rules implemented in the latter part of 1993 will have a positive impact on NOARK. The unbundling of gas sales, gathering, transmission and storage services required by Order No. 636 should provide NOARK with expanded options for accessing gas supply and for transporting gas to downstream customers. 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. 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, 1993. 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 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, 1993, the Company had 651 employees, 85 of whom are represented under a collective bargaining agreement. INDUSTRY SEGMENT AND STATISTICAL INFORMATION The following portions of the 1993 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 10 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 1993 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. 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 1993 Annual Report to Shareholders: NET WELLS DRILLED DURING THE YEAR
EXPLORATORY Productive Year Wells Dry Holes Total ---- ---------- --------- ----- 1993 2.8 4.0 6.8 1992 1.2 6.1 7.3 1991 2.0 1.2 3.2
DEVELOPMENT Productive Year Wells Dry Holes Total ---- ---------- --------- ----- 1993 37.9 10.5 48.4 1992 53.4 13.4 66.8 1991 9.8 2.9 12.7
WELLS IN PROGRESS AS OF DECEMBER 31, 1993
Type of Well Gross Net ------------ ----- --- Exploratory 2.0 .5 Development 3.0 .6 ----- ---- Total 5.0 1.1 ----- ---- ----- ----
11 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, 1993. During 1993, 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 1993 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 not involved and were not involved at December 31, 1993, in any material pending legal proceedings. The outcome of litigation in which the Company is involved would not have a material effect on the consolidated financial statements. 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, 1993, 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), 67 Southwestern Energy Company and Subsidiaries, and Chief Executive Officer (since 1968), Southwestern Energy Company. Dan B. Grubb President and Chief Operating Officer 58 (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 and 40 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 Operating 63 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).
12 Gregory D. Kerley Vice President - Treasurer and Secretary 38 (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). J. Thomas Devins Vice President and Chief Operating Officer 53 (since 1992), Southwestern Energy Pipeline Company (subsidiary of Southwestern Energy Company). Previously, President, NOARK Gas Marketing Company (since 1990), President, Diamond Shamrock Natural Gas Marketing Company (since 1988) and Vice President, Gulf Energy Development Corporation (since 1985).
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 executive officers. 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 1993 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, 1993, $102,793,000 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 1993 Annual Report to Shareholders (filed as Exhibit 13 to this filing) are hereby incorporated by reference. 13 "Financial and Operating Statistics" for selected financial data of the Company. The comparability of data between years is affected by the acquisition of Associated Natural Gas Company in June, 1988. "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 25, 1994 (the 1994 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 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 1994 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 1994 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 of Nominees and Executive Officers" of the proxy statement for information about security ownership of certain beneficial owners and management. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The 1994 Proxy Statement is hereby incorporated by reference for the purpose of providing information about related transactions. Refer to the section "Security Ownership of 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 1993 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, 1993 and 1992. Consolidated Statements of Income for the years ended December 31, 1993, 1992 and 1991. Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991. Consolidated Statements of Retained Earnings for the years ended December 31, 1993, 1992 and 1991. 14 Notes to Consolidated Financial Statements, December 31, 1993, 1992 and 1991. (2) The following financial statement schedules for the years 1993, 1992 and 1991 are submitted herewith:
PAGE REFERENCE --------- Report of Independent Auditors on Supporting Schedules as of December 31, 1993, 1992 and 1991, and for the years then ended 18 V. Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991. 19 VI. Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991 20 IX. Short-Term Borrowings for the years ended December 31, 1993, 1992 and 1991. 21 X. Supplementary Income Statement Information for the years ended December 31, 1993, 1992 and 1991 22
All other schedules are omitted because they are not required, inapplicable, or the information is otherwise shown in the financial statements or notes thereto. (3) The exhibits listed on the accompanying Exhibit Index (pages 23 - 25) immediately following the financial statement schedules are filed as part of, or incorporated by reference into, this Report. (b) Reports on Form 8-K: No reports on Form 8-K were filed during the quarter ended December 31, 1993. The Company filed on January 17, 1994, a Current Report on Form 8-K reporting that the Arkansas Public Service Commission issued an order on November 29, 1993, in a three-year-old gas cost case involving purchases by Arkansas Western under a long-term gas purchase contract with SEECO. The order found Arkansas Western's purchases under the contract in question to be in violation of an Arkansas statute requiring that gas purchases be made "from the lowest or most advantageous market." The order found that the price paid by Arkansas Western to its affiliate was too high, determined that purchases under the contract should be indexed to an "appropriate market price", but stated that "additional evidence is necessary in order to determine the most equitable pricing methodology" and "the parties should provide testimony on any premium that should be attached to the published price to reflect Arkansas Western's gas requirements." The Commission scheduled a public hearing on these issues to begin on January 18, 1994. Additionally, as reported on the Form 8-K, a class action refund complaint was filed against Arkansas Western in December, 1993, asking the APSC to order Arkansas Western to refund amounts related to gas costs collected from its customers since 1978. The claim purports to be a class action, although no Arkansas law specifically authorizes the pursuit of class action complaints before the APSC. The complaint is based on the APSC's order discussed above. The complaint requests that the Commission order Arkansas Western to refund its ratepayers and customers at least $14 million per year since 1978 or $210 million or the amount by which the rates charged have exceeded the amount reasonably justified by the rules of the APSC and the statutes of Arkansas. The complaint does not explain how the refund amount was calculated, and no refund amount can be calculated from the order because the order made no finding as to the appropriate price. In the order issued by the APSC, it was reiterated that refunds were not at issue in this docket and that Arkansas Western's gas purchasing practices, affiliate transactions, gas costs and 15 gas cost allocation practices were being addressed on a prospective basis only. The Registrant believes the complaint is frivolous. The Company filed on January 19, 1994, a current report on Form 8-K reporting that Vesta Energy Company ("Vesta") filed on December 21, 1993, and amended on January 6, 1994, a complaint in the Federal District Court for the Northern District of Oklahoma against the Registrant, four of its subsidiaries, and the NOARK Pipeline System. The complaint makes several allegations and generally claims that the defendants induced Vesta to enter into a contract to transport 50,000 Million British Thermal Units (MMBtu) of gas per day on NOARK and a separate contract to purchase 25,000 MMBtu per day of the total from two of the Registrant's subsidiaries through a series of false representations. On February 17, 1994, Vesta requested permission to amend its complaint a second time to allege anti-trust violations under the Sherman Act. Vesta is seeking rescission of the contracts, actual damages in excess of $1.0 million and punitive damages in excess of $1.0 million. The Registrant believes that Vesta's claim is wholly without merit and in February, 1994, NOARK and the Registrant filed separate lawsuits against Vesta in state and federal courts in Arkansas seeking enforcement of the contracts and damages. 16 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) BY: /s/ STANLEY D. GREEN ------------------------ Stanley D. Green, Dated: March 25, 1994 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 25, 1994. /s/ CHARLES E. SCHARLAU - ------------------------------- Director, Chairman, and Charles E. Scharlau Chief Executive Officer /s/ STANLEY D. GREEN Executive Vice President - - ------------------------------- Finance and Corporate Development, Stanley D. Green and Chief Financial Officer /s/ GREGORY D. KERLEY Vice President - Treasurer - -------------------------------- 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 17 REPORT OF INDEPENDENT AUDITORS ON SUPPORTING SCHEDULES AS OF DECEMBER 31, 1993, 1992, AND 1991 AND FOR THE YEARS THEN ENDED To the Board of Directors and Shareholders of Southwestern Energy Company: We have audited in accordance with generally accepted auditing standards the financial statements included in Southwestern Energy Company's 1993 Annual Report to Shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated February 7, 1994. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index above are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN & CO. Tulsa, Oklahoma February 7, 1994 18 SCHEDULE V
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES -------------------------------------------- PROPERTY, PLANT AND EQUIPMENT ----------------------------- FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 ---------------------------------------------------- (in thousands) Balance at Balance Beginning Additions Retirements at End Classification of Period at Cost or Sales Transfers of Period -------------- -------- ------- ----------- --------- --------- For the year ended December 31, 1993: Gas and oil properties $338,062 $37,337 $ 118 $ - $375,281 Gas distribution systems 146,837 19,892 1,286 - 165,443 Gas in underground storage 46,290 - 9,119 - 37,171 Other 13,040 1,990 346 - 14,684 -------- ------- ------- ------ -------- $544,229 $59,219 $10,869 $ - $592,579 -------- ------- ------- ------ -------- -------- ------- ------- ------ -------- For the year ended December 31, 1992: Gas and oil properties $307,261 $30,772 $ (29) $ - $338,062 Gas distribution systems 136,267 12,188 1,634 16 146,837 Gas in underground storage 41,858 4,432 - - 46,290 Other 11,131 1,949 24 (16) 13,040 -------- ------- ------- ------ -------- $496,517 $49,341 $1,629 $ - $544,229 -------- ------- ------- ------ -------- -------- ------- ------- ------ -------- For the year ended December 31, 1991: Gas and oil properties $276,979 $30,309 $ 27 $ - $307,261 Gas distribution systems 129,541 7,856 1,236 106 136,267 Gas in underground storage 42,293 - 435 - 41,858 Other 10,702 723 188 (106) 11,131 -------- ------- ------- ------ -------- $459,515 $38,888 $1,886 $ - $496,517 -------- ------- ------- ------ -------- -------- ------- ------- ------ --------
19 SCHEDULE VI
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES -------------------------------------------- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION ---------------------------------------------------- OF PROPERTY, PLANT AND EQUIPMENT -------------------------------- FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 ---------------------------------------------------- (in thousands) Additions Charged To Retirements -------------------- ----------- Salvage Balance at Costs Net of Balance Beginning and Other Original Removal at End Classification of Period Expenses Accounts (1) Cost Costs Transfers of Period -------------- ----------- -------- ------------ -------- ------- --------- --------- For the year ended December 31, 1993: Gas and oil properties $120,841 $25,630 $ - $ - $ - $ - $146,471 Gas distribution systems 49,748 4,564 763 939 138 - 54,274 Other 4,360 750 295 201 - - 5,204 -------- ------- ----- ------ ----- ---- --------- $174,949 $30,944 $1,058 $1,140 $138 $ - $205,949 -------- ------- ----- ------ ----- ---- --------- -------- ------- ----- ------ ----- ---- --------- For the year ended December 31, 1992: Gas and oil properties $101,784 $19,057 $ - $ - $ - $ - $120,841 Gas distribution systems 46,240 4,213 698 1,488 85 - 49,748 Other 3,466 610 297 13 - - 4,360 -------- ------- ----- ------ ----- ---- -------- $151,490 $23,880 $ 995 $1,501 $ 85 $ - $174,949 -------- ------- ----- ------ ----- ---- -------- -------- ------- ----- ------ ----- ---- -------- For the year ended December 31, 1991: Gas and oil properties $ 88,014 $13,770 $ - $ - $ - $ - $101,784 Gas distribution systems 42,597 3,978 631 1,054 79 9 46,240 Other 2,715 500 262 2 - (9) 3,466 -------- ------- ----- ------ ----- ---- -------- $133,326 $18,248 $ 893 $1,056 $ 79 $ - $151,490 -------- ------- ----- ------ ----- ---- -------- -------- ------- ----- ------ ----- ---- -------- (1) Represents primarily amounts for depreciation on transportation equipment which is charged to operating and general expense and other accounts on the basis of transportation equipment usage, and amortization of an acquisition adjustment which is charged to other income and expense.
20 SCHEDULE IX
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES -------------------------------------------- SHORT-TERM BORROWINGS --------------------- FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 ---------------------------------------------------- (in thousands except percentages) Maximum Average Weighted Category of Weighted Amount Amount Average Aggregate Balance Average Outstanding Outstanding Interest Rate Short-Term at End Interest During the During the During the Borrowings(1) of Period Rate Period Period Period (2) -------------- --------- ------- -------------- ----------- -------------- For the year ended December 31, 1993: Payable to banks $ - N/A $ - $ - N/A --------- ------ -------- ------- -------- --------- ------ -------- ------- -------- For the year ended December 31, 1992: Payable to banks $ - N/A $ - $ - N/A --------- ------ -------- ------- -------- --------- ------ -------- ------- -------- For the year ended December 31, 1991: Payable to banks $ - N/A $11,500 $ 6,679 5.92% --------- ------ -------- ------- -------- --------- ------ -------- ------- -------- (1) These are borrowings under short-term agreements which bear interest at various rates at or below the prime rate. The revolving lines are either cancellable by the banks involved at any time or renewable, at the bank's option, annually. (2) Based on the number of days and rates at which borrowings were outstanding.
21 SCHEDULE X
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES -------------------------------------------- SUPPLEMENTARY INCOME STATEMENT INFORMATION ------------------------------------------ FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 ---------------------------------------------------- 1993 1992 1991 ------- ------- ------- (in thousands) Taxes, other than income taxes: Ad valorem taxes $1,120 $1,071 $ 997 Privilege taxes 110 122 113 Severance taxes 436 499 490 Other, primarily payroll taxes 1,641 1,478 1,441 Less amounts charged to other accounts (26) (26) (24) ------- ------- ------- Taxes, other than income taxes $3,281 $3,144 $3,017 ------- ------- ------- ------- ------- ------- Maintenance and repairs $4,844 $3,950 $3,764 ------- ------- ------- ------- ------- -------
22 EXHIBIT INDEX EXHIBIT NO. DESCRIPTION REFERENCE - ------- ----------- --------- 3. Articles of Incorporation and Bylaws of the Company * 4. Shareholder Rights Agreement, dated May 5, 1989 (v) Material Contracts: 10.1 Gas Purchase Contract between SEECO, Inc., and Arkansas Western Gas Company, dated July 24, 1978, and amended May 21, 1979 (i) 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 (iii), (iv) 10.3 Gas Purchase Contract between SEECO, Inc., and Associated Natural Gas Company, dated October 1, 1990 (vii) 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 1993 Incentive Compensation Plan, effective January 1, 1993. (i), (vi) (b) Summary of Southwestern Energy Company 1993 Incentive Compensation Plan, effective January 1, 1993. * (c) Nonqualified Stock Option Plan, as amended July 10, 1989 (Replaced by Southwestern Energy Company 1993 Stock Incentive Plan, dated April 7, 1993). (ii) (d) Exploration Incentive Plan A, effective January 1, 1988, as amended July 10, 1989. (vi) (e) Southwestern Energy Company 1993 Stock Incentive Plan, dated April 7, 1993. (x) (f) Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors, dated April 7, 1993. (x) 10.5 Southwestern Energy Company Supplemental Retirement Plan, adopted May 31, 1989, and Amended and Restated as of December 15, 1993. * 10.6 Southwestern Energy Company Supplemental Retirement Plan Trust, dated December 30, 1993. * 10.7 Executive Severance Agreement for Charles E. Scharlau, effective August 4, 1989. (vi) 10.8 Executive Severance Agreement for Stanley D. Green, effective August 4, 1989. (vi) 10.9 Executive Severance Agreement for B. Brick Robinson, effective August 4, 1989. (vi) 10.10 Executive Severance Agreement for Dan B. Grubb, effective July 8, 1992. (ix) 23 10.11 Consulting Agreement between the Company and J. B. Coffman & Associates, Inc., effective November 8, 1989. (vi) 10.12 Employment Agreement for Charles E. Scharlau, dated December 18, 1990, effective January 1, 1991. (vii) 10.13 Employment Agreement for Dan B. Grubb, effective July 8, 1992. (ix) 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. (iv), (viii) 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. (ix) 10.16 Limited Partnership Agreement of NOARK Pipeline System, Limited Partnership, dated October 10, 1991, and amended February 24, 1993. (viii), (ix) 10.17 Operating Agreement of NOARK Pipeline System, dated March 19, 1991. (viii) 10.18 Agreement for Sale of Partnership Interest between Southwestern Energy Pipeline Company and GRUBB NOARK Pipeline, Inc., dated July 24, 1992. (ix) 13. 1993 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. * 22. Subsidiaries of the Registrant. (ix) _______________ (i) Incorporated by reference to the exhibit filed with the Company's filing on Form 10-K for the year ended December 31, 1984. (ii) Incorporated by reference to the exhibit filed with the Company's filing on Form 10-K for the year ended December 31, 1985. (iii) Incorporated by reference to the exhibit filed with the Company's filing on Form 10-K for the year ended December 31, 1987. (iv) Incorporated by reference to the exhibit filed with the Company's filing on Form 10-K for the year ended December 31, 1988. (v) Incorporated by reference to the exhibit filed with the Company's Form 8-K on May 10, 1989. (vi) Incorporated by reference to the exhibit filed with the Company's filing on Form 10-K for the year ended December 31, 1989. (vii) Incorporated by reference to the exhibit filed with the Company's filing on Form 10-K for the year ended December 31, 1990. 24 (viii) Incorporated by reference to the exhibit filed with the Company's filing on Form 10-K for the year ended December 31, 1991. (ix) Incorporated by reference to the exhibit filed with the Company's filing on form 10-K for the year ended December 31, 1992. (x) 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. * Exhibit filed with the Company's filing on Form 10-K for the year ended December 31, 1993. 25 EX-3 2 ARTICLES OF INCORPORATION ARTICLES OF AMENDMENT OF SOUTHWESTERN ENERGY COMPANY Southwestern Energy Company, a corporation organized and existing under the laws of the State of Arkansas, acting herein by and through its duly authorized officers, hereby certifies as follows: 1. The name of the corporation is Southwestern Energy Company. 2. On February 26, 1993, the board of directors adopted a resolution setting forth and declaring advisable a proposal to amend the Company's Articles of Incorporation to increase the Company's number of authorized shares of capital stock to 75,000,000 shares and to decrease the par value of the Company's common stock to $.10 per share. 3. On May 26, 1993, at the annual shareholders meeting held upon 60 days notice with 8,561,370 shares of common stock outstanding and entitled to vote, 4,901,622 shares were voted in favor of and 1,611,668 shares were voted against the proposal to amend the Company's Articles of Incorporation to increase the Company's number of shares of capital stock to 75,000,000 shares and to decrease the par value of the Company's common stock to $.10 per share. 4. The Sixth Article was amended to read as follows: SIXTH: Section A: The total amount of the authorized capital stock of this corporation is seventy-five million (75,000,000) shares with a par value of ten cents ($.10) per share, all of which shall be designated as common stock. Each share of said stock shall have one vote. 5. The amended Sixth Article as described in paragraph four (4) above is, accordingly, hereby declared duly adopted pursuant to applicable law. Dated May 26, 1993. SOUTHWESTERN ENERGY COMPANY BY: /s/ GREGORY D. KERLEY -------------------------- Gregory D. Kerley Vice President - Treasurer and Secretary ATTEST /s/ JEFFREY L. DANGEAU - ------------------------ Assistant Secretary ARTICLES OF AMENDMENT AND RESTATED ARTICLES OF INCORPORATION OF SOUTHWESTERN ENERGY COMPANY Southwestern Energy Company, a corporation organized and existing under the laws of the State of Arkansas, acting herein by and through its duly authorized officers, hereby certifies as follows: 1. The name of the corporation is Southwestern Energy Company; 2. On February 24, 1988, the Board of Directors adopted a resolution setting forth and declaring advisable a proposal to restate the Company's Articles of Incorporation, adopting the Arkansas Business Corporation Act of 1987 as the corporate law which shall govern the affairs of the Company and to amend the Company's Articles of Incorporation to limit the liability of directors pursuant to the Arkansas Business Corporation Act of 1987; 3. On May 25, 1988, at the Annual Shareholders Meeting, held upon 60 days' notice with 8,313,496 shares outstanding and entitled to vote, 6,035,945 shares were voted in favor of and 410,879 shares were voted against the proposal to restate and amend the Company's Articles of Incorporation adopting the Arkansas Business Corporation Act; 6,461,830 shares were voted in favor of and 361,576 shares were voted against the proposal to amend the Company's Articles of Incorporation to limit the liability of directors; 4. Article Ninth was amended to read as set forth in the Restated Articles attached hereto and new articles Eleventh and Twelfth were added as set forth in the Restated Articles attached hereto; 5. The Restated Articles of Incorporation attached hereto are, accordingly, hereby declared duly adopted pursuant to applicable law. Dated May 25, 1988 SOUTHWESTERN ENERGY COMPANY By /s/ STANLEY D. GREEN --------------------- Stanley D. Green ATTEST Vice President /s/ THOMAS J. SWEARINGEN - ------------------------ Assistant Secretary AMENDED AND RESTATED ARTICLES OF INCORPORATION OF SOUTHWESTERN ENERGY COMPANY FIRST: The name of this corporation is SOUTHWESTERN ENERGY COMPANY. SECOND: The nature of the business of the corporation and the objects or purposes proposed to be transacted, promoted or carried on by it, are as follows, to-wit: Section A: To acquire, purchase, own, hold, operate, develop, lease, mortgage, pledge, exchange, sell, transfer or otherwise invest, trade or deal in, in any manner securities, stocks, mortgages, bonds, and real and personal property of every kind and description or in any interest therein. Section B: To engage in any capacity in any entertainment, radio, television, mercantile, construction, manufacturing, public utilities, exploratory development or trading business of any kind or character whatsoever, and to do all things incidental to any such business, and to do and perform all other things that are necessary or beneficial to the corporation or to the general public which the Board of Directors may from time to time determine should be done. Section C: To issue bonds, debentures, or other obligations of the corporation, and to secure the same by mortgage, pledge, deed of trust, or otherwise. Section D: To have and to exercise all the powers now or hereafter conferred by the laws of the State of Arkansas upon corporations organized under the laws under which this corporation is organized and any and all Acts Amendatory thereof and supplemental thereto. Section E: To conduct business in the State of Arkansas, other states, the District of Columbia, the territories and colonies of the United States and in foreign countries, and to have one or more offices out of the State of Arkansas, as well as within said state. In any state or country or political division thereof in which the corporation may have qualified to do business, it shall have all the objects and powers herein set forth, but to such extent as may be permitted by the laws of such state or country or political division thereof to any business or commercial corporation. Section F: To do all and everything necessary and proper for the accomplishment of the objects enumerated in these Articles of Incorporation, or any amendment thereof, or necessary or incidental to the protection and benefit of this corporation; and in general to carry on any lawful business necessary or incidental to the attainment of the objects of this corporation whether or not such business is similar in nature to the objects set forth in these Articles of Incorporation or any amendment thereof. The foregoing clauses shall be construed both as objects and powers; and it is hereby expressly provided that the foregoing enumeration of specific objects or powers shall not be held to limit or restrict in any manner either the objects or powers of the corporation, and that the corporation shall possess such incidental powers as are reasonably necessary or convenient for the accomplishment of any of the objects or powers hereinbefore enumerated, either alone or in association with any government, state, municipality, corporation, association, partnership, as a partner or otherwise, person, organization or entity whatsoever, at least to the same extent and as fully as individuals might or could do as principals, agents, contractors, or otherwise. THIRD: The period of existence of this corporation shall be perpetual. FOURTH: The principal office or place of business of this corporation shall be located in the county of Washington in the city of Fayetteville, state of Arkansas, and the address of the principal office shall be 1083 Sain Street, Fayetteville, AR 72703. FIFTH: The name of the resident agent of this corporation is Charles E. Scharlau, whose address is 1083 Sain Street, Fayetteville, Washington County, AR 72703, which shall also be the registered office. SIXTH: Section A: The total amount of the authorized capital stock of this corporation is twenty-five million (25,000,000) shares with a par value of Two and 50/100 ($2.50) per share. Each share of said stock shall have one vote: Section B: No stockholder shall be entitled as a matter of right to subscribe for, or purchase, or receive, or to have offered to him for subscription or purchase, any additional share or shares of stock either of that now authorized in the Articles of Incorporation or hereafter authorized, or any shares whatsoever, however acquired, issued or sold by the corporation, or any bonds, certificates of indebtedness, debentures or other securities convertible into the stock of the corporation, it being the purpose and intent that the Board of Directors shall have full right, power and authority to offer for subscription or sale or to make any disposal of any or all unissued shares of capital stock of the corporation, or any or all shares issued and thereafter acquired by the corporation, upon such consideration in money or property or other things of value as the Board of Directors shall determine. SEVENTH: The amount of capital with which this corporation will begin business is Three Hundred Dollars ($300.00). EIGHTH: The names and post office addresses of each of the incorporators and the number of shares of the capital stock subscribed by each of them are as follows:
Name Address Shares ---- ------- ------ C. O. Moore Stanford, Texas 988 T. E. Patton Rogers, Arkansas 1 E. M. Moore Rogers, Arkansas 1
NINTH: The number of directors of the corporation shall be fixed by the bylaws and may be increased or decreased from time to time in the manner specified therein, provided, however, that the number of directors shall not be less than three. Election of directors need not be by ballot. All shareholders are entitled to cumulate their votes for the election of directors. No director of the corporation need be a stockholder. Any director may be removed at any time, either for or without cause, so long as the stockholders are entitled to vote in respect to the corporate affairs and management of the corporation, by the affirmative vote of stockholders holding of record a majority of the outstanding shares of the stock of the corporation which were entitled to vote at the election of such director, given at a special meeting of such stockholders called for the purpose; provided, however, that no director may be removed if the number of votes sufficient to elect him under cumulative voting is voted against his removal. TENTH: In furtherance, not in limitation, of the powers conferred upon the Board of Directors by statute, the Board of Directors is expressly authorized, without any vote or other action by stockholders other than such as at the time shall be expressly required by statute or by the provisions of these Articles of Incorporation (and amendments thereof, if any) or by the bylaws, to exercise all of the powers, rights and privileges of the corporation (whether expressed or implied in these Articles of Incorporation or conferred by statute) and do all acts and things which may be done by the corporation, including, but without limiting the generality of the foregoing, the right: Section A: By resolution or resolutions passed by the majority vote of all the members of the Board of Directors as from time to time constituted to make, adopt, alter, amend and repeal the bylaws of the corporation, provided, however, that the holders of the majority of the issued and outstanding stock may alter, amend, or repeal the bylaws made by the Board of Directors and may from time to time limit or define the right of the Board of Directors to alter, amend, or repeal any bylaw or bylaws made or adopted; and Section B: By resolution or resolutions passed by the affirmative vote of a majority of the number of directors as from time to time fixed by the bylaws of the corporation, to designate one or more committees, each committee to consist of two or more of the directors of said corporation, and each such committee to the extent provided in said resolution or resolutions or in the bylaws of the corporation, shall have and may exercise the powers of the Board of Directors in the management of the business and affairs of the corporation, such committee or committees to have such name or names as may be stated in the bylaws of the corporation, or as may be determined from time to time by resolution adopted by the Board of Directors; and Section C: By resolution or resolutions passed by the affirmative vote of a majority of the number of directors as from time to time fixed by the bylaws of the corporation, to sell, assign, transfer, convey, or dispose of, or to mortgage or otherwise encumber any real estate or lease of real estate to which or in which the corporation shall at any time have any right or interest, and pursuant to such resolution or resolutions, to acquire any right or interest to or in any real estate or lease of real estate; and Section D: By resolution or resolutions passed by the affirmative vote of a majority of the number of directors as from time to time fixed by the bylaws of the corporation, to authorize or approve the purchase by or on behalf of the corporation, of its capital stock, bonds, debentures, warrants, rights, scrip, other obligations or securities of any nature howsoever evidenced, either pro-rata from all holders thereof or from time to time in the open market or at private sale; and Section E: By resolution or resolutions passed by the affirmative vote of a majority of the number of directors as from time to time fixed by the bylaws of the corporation, to sell, lease, or exchange any or all of the property and assets of this corporation, including its good will and its corporate franchises, upon such terms and conditions as the Board of Directors may deem expedient and for the best interest of the corporation, when and as authorized by the affirmative vote of the holders of record of at least a majority of the issued and outstanding stock, or when authorized by the written consent of the holders of record of at least a majority of stock issued and outstanding. ELEVENTH: To the fullest extent permitted by the Arkansas Business Corporation Act of 1987 as it now exists or may hereafter be amended, a director of this corporation shall not be liable to the corporation or its shareholders for monetary damages for breach of fiduciary duty as a director. TWELFTH: The corporation elects to be governed by the provisions of the Arkansas Business Corporation Act of 1987 as it now exists or may hereafter be amended from time to time. 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 AND QUALIFICATIONS: 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 seventy-two (72) years. This mandatory retirement provision may be waived for directors serving as of May 26, 1981, by motion of the Board of Directors. 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. 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. 6 (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. (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 7 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. 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. 8 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 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 9 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 my 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. 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. 10 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 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. 11 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 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 12 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. 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. 2/94 13 EX-10.4(B) 3 SUMMARY 1993 INCENTIVE COMPENSATION PLAN SOUTHWESTERN ENERGY COMPANY 1993 INCENTIVE COMPENSATION PLAN SUMMARY The Southwestern Energy Company 1993 Incentive Compensation Plan (the "Plan") is effective for fiscal years commencing on and after January 1, 1993 and ending on or prior to December 31, 2003. The purpose of the Plan is to attract, retain and motivate key employees by providing cash and stock incentive compensation to certain employees of the Company and its subsidiaries who have a significant impact on earnings, growth and shareholder value by rewarding both organizational and individual performance. Only active employees of Southwestern Energy Company and its subsidiaries who are employed in a key management capacity are eligible to participate in the Plan. The Plan is administered by the Compensation Committee of Southwestern Energy Company's Board of Directors (the "Committee"). Capitalized terms used herein and not otherwise defined shall have the respective meanings ascribed to them in the Plan. Awards under the Plan are based on pre-determined minimum, target and maximum performance levels using the following performance factors for the various business segments of Southwestern Energy Company and its subsidiaries: (1) Corporate Performance Factors: (i) the Company's Return on Equity for such year, and (ii) the Company's Earnings Per Share Growth. 1 (2) E & P Performance Factors: (i) Increase in Reserve Additions adjusted for revisions to previous estimates; and (ii) Average Finding Costs. (3) Utility Performance Factor: the Expected Return on Rate Base adjusted for inflation. (4) Pipeline Performance Factors: (i) Budgeted Volume of gas to be transported for the Plan Year; and (ii) Gross Revenue Less Direct Expenses. (5) Property Acquisitions: (i) Dollars of Acquisitions, the amount spent during any given Plan Year on the acquisition of producing properties. (ii) Average Acquisition Cost per Mcf. In the initial Plan Year, the property acquisitions segment will not be eligible for a bonus award under the Plan. For the 1994 Plan Year, the bonus award shall be 100 percent discretionary as determined by the Chief Executive Officer of the Company upon approval by the Committee. Achievement of the predetermined minimum, target or maximum Threshold Levels shall determine the bonus percentages ("Bonus Percentages") to be used in calculating bonus amounts. The Bonus Percentages applicable to each Threshold Level may be changed by the Committee from time to time. For each Company Performance Factor, a bonus amount shall be calculated for the year equal to a percentage of each participant's base salary as of the beginning of the Plan Year, adjusted by a percentage ("Weighting Factor") applicable to each Company Performance Standard as established by the Committee. Weighting factors may be changed by the Committee from year to year, and 2 additional Company Performance Factors may be established, so long as the sum of the Weighting Factors are always equal to 100%. The sum of the individual bonus amounts so established for each Company Performance Factor shall be equal to the Organizational Performance Amount. The Plan also allows for discretionary awards to be made to participants upon the recommendation of the Company's Chief Executive Officer with the approval of the Committee. Discretionary awards will be based upon an individual participant's performance against individually established goals or an overall assessment of a participant's contribution in areas that cannot be quantifiably measured ("Discretionary Award Amount"). Furthermore, the Chief Executive Officer is authorized, in his sole discretion, to make awards from a discretionary bonus pool to any employee of the Company or its subsidiaries who is not a participant in the Plan. The amount of the Chief Executive Officer's discretionary pool is determined by the Committee. Each participant's bonus for a given year is equal to the sum of the participant's Organizational Performance Amount and Discretionary Award Amount. At the discretion of the Committee, awards are payable in cash, restricted common stock of the Company, or a combination of cash and restricted common stock. All restrictions on awards of restricted common stock lapse at the rate of 20% per year (or such other rate as the Committee may determine) of the total shares included in an award beginning one year after the date of the award 3 of the shares, unless the restrictions are terminated earlier by the occurrence of any of the following events: 1. The retirement of the participant at the participant's normal retirement date; 2. The death or total and permanent disability of a participant while employed by the Company or a subsidiary; 3. The occurrence of a change in control of Southwestern Energy Company; and 4. The early retirement of the participant or termination of a participant's employment for any other reason if the Committee determines that the lapse of restrictions is in the best interest of the Company and the participant consents. Restricted common stock granted under the Plan is subject to the provisions of the Southwestern Energy Company 1993 Stock Incentive Plan and count toward the aggregate number of shares authorized under that plan. The interest of any participant under the Plan is non-assignable either by voluntary or involuntary assignment or by operation of law. The Plan confers no rights upon any employee concerning the continuation of employment with the Company and does not interfere in any way with the right of the Company to terminate any employee at any time. 4 EX-10.5 4 SUPPLEMENTAL RETIREMENT PLAN SOUTHWESTERN ENERGY COMPANY SUPPLEMENTAL RETIREMENT PLAN Adopted as of May 31, 1989 Amended and Restated as of December 15, 1993 TABLE OF CONTENTS
PAGE ---- ARTICLE I Definitions....................................... 1 A. Actuarial Equivalent...................... 1 B. Beneficiary............................... 1 C. Board of Directors........................ 1 D. Change in Control......................... 2 E. Committee................................. 3 F. Corporation............................... 4 G. ERISA..................................... 4 H. Funded Benefit............................ 4 I. Funded Benefit Account.................... 4 J. IRC....................................... 4 K. Participant............................... 4 L. Pension Plan.............................. 4 M. Plan...................................... 4 N. Qualified Beneficiary Designation......... 4 O. Secular Trust............................. 5 P. Surviving Spouse.......................... 5 Q. Tax Liability............................. 6 R. Unfunded Benefit.......................... 6 ARTICLE II Effective Date.................................... 6 ARTICLE III Unfunded Benefits................................. 7 A. Determination of Unfunded Benefits.................................. 7
(i)
PAGE ---- B. Form and Timing of Unfunded Benefit Payments................. 7 C. Offset for Funded Benefit................. 8 ARTICLE IV Funded Benefits................................... 9 A. Discretionary Contribution................ 9 B. Distributions from the Funded Benefit Account........................... 9 1. Early Distributions.................. 9 (a) Distributions of Distributable Net Income.......................... 9 (b) Tax Compensation Distributions................... 9 2. Determination of Funded Benefit.............................. 10 3. Form and Timing of Funded Benefit.............................. 10 C. Vesting................................... 10 D. Beneficiaries............................. 10 ARTICLE V Plan Administration............................... 11 A. The Committee............................ 11 B. Powers, Duties, Etc. of the Committee................................ 12 ARTICLE VI Miscellaneous.................................... 13 A. Amendment................................ 13 B. Termination.............................. 13 C. Funding.................................. 14 1. Unfunded Benefits.................. 16 2. Funded Benefits.................... 16 D. Benefits Not Assignable.................. 17
(ii)
PAGE ---- E. Plan Not a Contract of Employment................................ 17 F. Benefits Payable to Minors, Incompetents and Others................... 18 G. Payment of Participant's Expenses.................................. 19 H. Construction.............................. 19 (iii)
ARTICLE I DEFINITIONS A. ACTUARIAL EQUIVALENT: The determination of one benefit as actuarially equivalent to another using the actuarial assumptions used for such purpose under the Pension Plan, provided, however, that after a Change in Control such assumptions may not be changed without the written consent of the Participant affected by the change. B. BENEFICIARY: With respect to a Participant's Unfunded Benefit, any person entitled to receive any payment of benefits due under the Pension Plan after a Participant's death, whether pursuant to a Participant's designation or otherwise, whose benefit payments have been reduced under the Pension Plan as a result of (1) the compensation limitation from time to time in effect under IRC Section 401(a)(17) or (2) the limitations imposed pursuant to IRC Section 415. With respect to a Participant's Funded Benefit, any Beneficiary named pursuant to a Qualified Beneficiary Designation in accordance with Section D of Article IV. C. BOARD OF DIRECTORS: The Board of Directors of the Corporation, and any persons empowered by the Corporation's certificate of incorporation, the Corporation's by-laws or resolution of the Board of Directors of the Corporation, to exercise the powers of the Board of Directors of the Corporation with respect to the Plan. D. CHANGE IN CONTROL: Any of the following: (1) 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 "beneficial owner" (as such term is defined in Rule 13d-3 promulgated under the Exchange Act), directly or indirectly, of securities of the Corporation representing 20% or more of the combined voting power of the Corporation's then outstanding securities, excluding any employee benefit plan sponsored or maintained by the Corporation (or any trustee of such plan acting as trustee); (2) the Corporation's stockholders approve an agreement to merge or consolidate the Corporation with another corporation (other than a corporation 50% or more of which is controlled by, or is under common control with, the Corporation); (3) any individual who is nominated by the Board for election to the Board of Directors of the Corporation 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; (4) a Change in Control of the Corporation 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 2 (5) a majority of the Board of Directors of the Corporation determines in its sole and absolute discretion that there has been a Change in Control of the Corporation or that there will be a Change in Control of the Corporation upon the occurrence of certain specified events and such events occur. Notwithstanding Paragraphs (1) through (4) of this Section D, a Change in Control shall not occur by reason of 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 Corporation immediately prior to the occurrence of such event own, on a fully diluted basis, securities of the Corporation representing (a) 5% or more of the combined voting power of the Corporation's then outstanding equity securities or (b) 5% or more of the value of the Corporation's then outstanding equity securities. E. COMMITTEE: Before a Change in Control, the term "Committee" means the Committee appointed to assist the Plan Administrator in administration of the Pension Plan pursuant to Article X thereof. On or after a Change in Control, the term "Committee" shall mean the Committee (as defined in the preceding sentence) as it existed immediately prior to such Change in Control, or such persons as shall be designated by the members of such Committee to be their successors. 3 F. CORPORATION: Southwestern Energy Company or any successor thereto. G. ERISA: The Employee Retirement Income Security Act of 1974, as amended. H. FUNDED BENEFIT: The benefit payable to a Participant pursuant to Article IV hereof. I. FUNDED BENEFIT ACCOUNT: A separate account in the Secular Trust reflecting the Corporation's contributions pursuant to Article IV on behalf of each Participant, adjusted to reflect any income, losses with respect thereto, and any distributions therefrom. J. IRC: The Internal Revenue Code of 1986, as amended. K. PARTICIPANT: Any participant in the Pension Plan whose benefit payments under the Pension Plan have been reduced as a result of (1) the compensation limitation from time to time in effect under IRC Section 401(a)(17) or (2) the limitations imposed pursuant to IRC Section 415. L. PENSION PLAN: The Southwestern Energy Company Pension Plan, as it may be amended. M. PLAN: The Southwestern Energy Company Supplemental Retirement Plan, as it may be amended. N. QUALIFIED BENEFICIARY DESIGNATION: An election by a Participant prior to his death to name a Beneficiary with respect to his Funded Benefit Account: 4 (1) if it is established to the satisfaction of the Committee that the Participant does not have a Surviving Spouse; or (2) that is consented to by the Participant's Sur- viving Spouse, unless the Surviving Spouse is the sole Beneficiary. Such consent is irrevocable and must be witnessed by a Plan representative or acknowledged by a notary public, and must indicate the effect of the election. If the Surviving Spouse is legally incompetent to give consent, the Surviving Spouse's legal guardian may give consent. In the case of a benefit payable after death, the consent may be made after the Participant's death. O. SECULAR TRUST: A trust described in Section C.2 of Article VI, which shall be the funding vehicle for Participants' Funded Benefits. P. SURVIVING SPOUSE: Except to the extent otherwise provided in a qualified domestic relations order, the person married to a Participant on the date of the Participant's death. The spouse of a Participant shall not be considered a Surviving Spouse if, at the time that the spouse's status as a Surviving Spouse would be determined, it is established to the satisfaction of the Committee that (a) the spouse cannot be located; (b) the Participant is legally separated; or (c) the Participant has been abandoned by the Participant's spouse (as determined under applicable 5 local law) and the Participant has an order issued by a court of competent jurisdiction to such effect. Notwithstanding clauses (b) and (c) above, a person shall be considered a Surviving Spouse to the extent required under a qualified domestic relations order. Q. TAX LIABILITY: The amount determined by the Committee to be the estimated federal, state and local income taxes payable by a Participant in respect of Participant's Funded Benefit Account, assuming that the Participant is subject to the marginal federal income tax rate applicable to the highest income level and the maximum applicable marginal state and local income tax rate (based on the Participant's state and city of residence as shown on the records of the Corporation and the state and city in which he works, but without otherwise taking into account the Participant's individual circumstances). R. UNFUNDED BENEFIT: The benefit payable to a Participant or Beneficiary pursuant to Article III of the Plan. ARTICLE II EFFECTIVE DATE The Plan shall be effective with respect to Participants or Beneficiaries whose benefit payments under the Pension Plan commence or will commence on or after July 1, 1989. 6 ARTICLE III UNFUNDED BENEFITS A. DETERMINATION OF UNFUNDED BENEFITS A Participant's or Beneficiary's Unfunded Benefit under the Plan (prior to the offset described in Section C of this Article) shall be determined as the excess, if any, of: (1) the benefits to which such Participant or Beneficiary would have been entitled under the Pension Plan: (a) without regard to (i) the compensation limitation from time to time in effect under IRC Section 401(a)(17); and (ii) the limitations imposed pursuant to IRC Section 415; and (b) assuming that any Participant was employed by the Corporation at the time of a Change in Control, such Participant had credit for all purposes under the Pension Plan for three additional years of service; over (2) the benefits to which such Participant or Beneficiary actually is entitled from time to time under the Pension Plan. B. FORM AND TIMING OF UNFUNDED BENEFIT PAYMENTS 1. A Participant's or Beneficiary's Unfunded Benefit under the Plan shall be paid to the Participant or Beneficiary in a single lump sum at the same time as benefits to such Participant or Beneficiary under the Pension Plan commence, unless the Committee directs that the 7 Actuarial Equivalent of the Participant's or Beneficiary's benefits under the Plan shall be paid at a different time and in a different form. 2. Any payments hereunder shall be subject to any applicable income tax withholding requirements. C. OFFSET FOR FUNDED BENEFIT The Unfunded Benefit, expressed as a lump sum, payable to a Participant or Beneficiary shall be reduced by the sum of (a) the value of the Participant's Funded Benefit Account as of the date the Participant's Unfunded Benefit is required to be paid pursuant to Section B of this Article, (b) the aggregate amount of withholding taxes paid by the Corporation, as a result of the federal, state and local income taxes payable by the Participant in respect of the Company's contributions to the Participant's Funded Benefit Account, (c) the aggregate amount of payments by the Corporation, distributions from the Participant's Funded Benefit Account or amounts withheld by the trustee of the Secular Trust, in each case in respect of federal, state or local income taxes payable in respect of the Participant's Funded Benefit Account and (d) the aggregate amount of any other distributions from the Participant's Funded Benefit Account prior to the date as of which the Participant's Unfunded Benefit becomes payable. 8 ARTICLE IV FUNDED BENEFITS A. DISCRETIONARY CONTRIBUTION The Corporation may, but shall not be required to, make such contributions to the Secular Trust on behalf of such Participants as it shall determine from time to time in its sole discretion. Each contribution to the Secular Trust on behalf of a Participant shall be allocated to and held in the Participant's Funded Benefit Account. B. DISTRIBUTIONS FROM THE FUNDED BENEFIT ACCOUNT 1. EARLY DISTRIBUTIONS (a) DISTRIBUTIONS OF DISTRIBUTABLE NET INCOME Each Participant shall receive a distribution from such Participant's Funded Benefit Account of the the income of such Funded Benefit Account, including net realized capital gains, annually and, in addition, shall receive a distribution of such other amount from the Participant's Funded Benefit Account as may be necessary to reduce the taxable income of such Funded Benefit Account for each taxable year, to the extent possible, to zero. (b) TAX COMPENSATION DISTRIBUTIONS Within 30 days after the end of each calendar year, each Participant or Beneficiary shall receive a distribution from the Participant's Funded Benefit Account equal to the lesser of (i) the value of the Participant's Funded Benefit Account or (ii) the excess, if any, of (A) 9 the Tax Liability in respect of the Participant's Funded Benefit Account for such calendar year (taking into account any withholding taxes paid in respect of such Tax Liability), over (B) the amount distributed pursuant to Paragraph 1(a) of this Section B after reduction for any applicable federal, state or local income taxes payable with respect thereto. 2. DETERMINATION OF FUNDED BENEFIT A Participant's Funded Benefit under the Plan shall be determined as the value of the Participant's Funded Benefit Account on the date benefits to such Participant under the Pension Plan commence. 3. FORM AND TIMING OF FUNDED BENEFIT A Participant's Funded Benefit under the Plan shall be paid to the Participant in a single lump sum within 30 days after benefits to such Participant under the Pension Plan commence. C. VESTING A Participant shall at all times be fully vested in the value of his Funded Benefit Account. D. BENEFICIARIES Pursuant to a Qualified Beneficiary Designation, a Participant may designate one or more Beneficiaries to re- ceive any part or all of the Funded Benefit payable to him under the Plan that has not been paid to him prior to his death. Any consent by a Surviving Spouse or waiver of 10 spousal consent shall be effective only with respect to such Surviving Spouse. To the extent a Participant fails to make such a designation or a designated Beneficiary does not survive the Participant and there is no successor or alternate Beneficiary or the designation is otherwise ineffective, any amounts due after the Participant's death shall be paid to his Surviving Spouse, or if there is no Surviving Spouse, to the legal representative of his estate. No Surviving Spouse or other Beneficiary shall have any right to a Participant's Funded Benefits under the Plan unless he shall survive the Participant. Any designation of a Beneficiary must be filed with the Committee in order to be effective. Any designation of a Beneficiary may be revoked at any time prior to the date of the Participant's death by filing a later designation pursuant to a Qualified Beneficiary Designation or an instrument of revocation with the Committee. ARTICLE V PLAN ADMINISTRATION A. THE COMMITTEE 1. The Plan shall be administered by the Committee. 2. The members of the Committee shall not receive compensation with respect to their services for the Committee. 11 3. The Committee shall act by a majority of its members at the time in office and such action may be taken either by a vote at a meeting or in writing without a meeting. The Committee may authorize any person to execute any document or documents on its behalf, and any interested person, upon receipt of notice of such authorization directed to it, may thereafter accept and rely upon any document executed by such authorized person until the Committee shall deliver to such interested person a revocation of such authorization. 4. A member of the Committee who also is a Participant shall be disqualified from voting or acting upon any matter relating specifically to the Participant. B. POWER, DUTIES, ETC. OF THE COMMITTEE 1. The Committee shall have the power to construe the Plan and to determine all questions of fact that may arise thereunder, and any such construction or determination shall be conclusively binding upon all persons interested in the Plan. 2. Subject to the terms of the Plan, the Committee may establish rules and procedures satisfactory to it for the administration of the Plan and the transaction of its business. 3. All payments of benefits or expenses of the Plan shall be made by the Corporation at the direction of the Committee. 12 4. The Committee shall be the "named fiduciary" of the Funded Benefit portion of the Plan, with full power to manage and control Plan assets. 5. The Committee shall have all the rights, powers, duties and obligations granted or imposed upon it elsewhere in the Plan. 6. The Committee may designate other persons to carry out the responsibilities of the Committee provided for hereunder. 7. To the extent permitted under applicable law, the Committee shall not be subject to and shall be indemnified by the Corporation for any liabilities arising from any action or omission respecting the Plan. ARTICLE VI MISCELLANEOUS A. AMENDMENT The Board of Directors shall have the right at any time to amend the Plan in whole or in part, effective retroactively, or otherwise, provided, however, that no amendment shall decrease the amount that would be payable to a Participant or Beneficiary hereunder determined as if the Participant terminated employment with the Corporation immediately prior to such amendment. B. TERMINATION The Board of Directors reserves the right to terminate the Plan, provided, however, that such termination 13 shall not decrease the amount payable to a Participant or Beneficiary hereunder determined as if the Participant had terminated employment with the Corporation immediately prior to such amendment. All other provisions of the Plan shall remain in effect unless otherwise amended. C. FUNDING 1. UNFUNDED BENEFITS The Unfunded Benefits payable under the Plan shall be unfunded. Unfunded Benefits under the Plan shall be paid from the general assets of the Corporation. The Corporation may establish a trust pursuant to a trust agreement and make contributions thereto for the purpose of assisting the Corporation in meeting its obligations in respect of Unfunded Benefits payable under the Plan. Any such trust agreement shall contain procedures to the following effect: (a) In the event of the insolvency of the Corporation, the trust fund will be available to pay the claims of any creditor of the Corporation to whom a distribution may be made in accordance with state and federal bankruptcy laws. The Corporation shall be deemed to be "insolvent" if the Corporation is subject to a pending proceeding as a debtor under the federal Bankruptcy Code (or any successor federal statute) or any state bankruptcy code. In the event the Corporation becomes insolvent, the Board of Directors and chief executive officer of the Corporation shall notify the trustee of that event as soon as 14 practicable. Upon receipt of such notice, or if the trustee receives other written allegation of the Corporation's insolvency, the trustee shall cease making payments of benefits from the trust fund, shall hold the trust fund for the benefit of the Corporation's creditors, and shall take such steps that are necessary to determine within 30 days whether the Corporation is insolvent. In the case of the trustee's actual knowledge of or other determination of the Corporation's insolvency, the trustee will deliver assets of the trust fund to satisfy claims of the Corporation's creditors as directed by a court of competent jurisdiction; (b) The trustee shall resume payment of benefits under the trust agreement only after the trustee has determined that the Corporation is not insolvent (or is no longer insolvent, if the trustee had previously determined the Corporation to be insolvent) or upon receipt of an order of a court of competent jurisdiction requiring such payment. If the trustee discontinues payment of benefits pursuant to Paragraph 1 of this Section and subsequently resumes such payment, the first payment on account of a Participant following such discontinuance shall include an aggregate amount equal to the difference between the payments which would have been made on account of such Participant under the trust agreement and the aggregate payments actually made on account of such Participant by the Corporation during any such period of discontinuance, plus interest on such amount 15 at a rate equivalent to the net rate of return earned by the trust fund during the period of such discontinuance. 2. FUNDED BENEFITS (a) The Corporation shall establish the Secular Trust pursuant to a trust agreement and make such contributions thereto from time to time for the purpose of providing Funded Benefits as it shall determine in its sole discretion. The Secular Trust shall be irrevocable. The Secular Trust shall provide for the distributions to Participants described in Article IV hereof. Such distributions shall be allocated first to the income of the Secular Trust and then to principal. (b) Notwithstanding anything in the Plan to the contrary, at no time shall any part of the assets of the Secular Trust be used for, or diverted to, purposes other than for the exclusive benefit of Participants or their Beneficiaries, and for defraying the reasonable costs of administering the Plan, except that, if and to the extent permitted by applicable law, a contribution which was made by a mistake in fact or was conditioned upon the deductibility of the contribution under IRC 404 shall be returned to the Corporation within one year after the payment of the contribution or the disallowance of the deduction, to the extent disallowed, as the case may be. (c) The trustee of the Secular Trust shall be subject to the direction of the Committee or an investment manager 16 selected by the Committee, and shall have no discretion with respect to the management and control of the assets of the Secular Trust, except to the extent that the trust agreement provides that the trustee shall have the power to manage and control the assets of the Secular Trust. D. BENEFITS NOT ASSIGNABLE Benefits provided under the Plan may not be anticipated, assigned (either at law or in equity), alienated or subject to attachment, garnishment, levy, execution or other legal or equitable process other than pursuant to the laws of descent and distribution; provided, however, that amounts in respect of a Participant's Funded Benefit shall be paid pursuant to a qualified domestic relations order within the meaning of Section 206(d) of ERISA, under procedures established by the Committee. In the event any amount of a Participant's Funded Benefit is payable pursuant to a qualified domestic relations order, payments to a Participant in respect of his Funded Benefit shall be adjusted accordingly. A Participant's or Beneficiary's Unfunded Benefit shall not increase as a result of the payment of part or all of a Participant's Funded Benefit pursuant to a qualified domestic relations order. E. PLAN NOT A CONTRACT OF EMPLOYMENT The Plan is not a contract of employment, and the terms of employment of any employee shall not be affected in 17 any way by the Plan or related instruments except as specifically provided in the Plan or such related instruments. The establishment of the Plan shall not be construed as conferring any legal rights upon any employee for a continuation of employment, nor shall it interfere with the right of the Corporation or an Affiliate (as defined in the Pension Plan) to discharge any employee and to treat him without regard to the effect which such treatment might have upon him as a Participant. Each Participant and all persons who may have or claim any right by reason of his participation shall be bound by the terms of the Plan and all agreements entered into pursuant thereto. F. BENEFITS PAYABLE TO MINORS, INCOMPETENTS AND OTHERS In the event any benefit is payable to a minor or an incompetent or to a person otherwise under a legal disability, or who, in the sole discretion of the Committee, is by reason of advanced age, illness or other physical or mental incapacity incapable of handling and disposing of his property, or otherwise is in such position or condition that the Committee believes that such person could not utilize the benefit for his support or welfare, the Committee shall have discretion to apply the whole or any part of such benefit directly to the care, comfort, maintenance, support, education or use of such person, or pay the whole or any part of such benefit to the parent of such person, the 18 guardian, committee, conservator or other legal representative, wherever appointed, of such person, the person with whom such person is residing, or to any other person having the care and control of such person. The receipt of any such person to whom any such payment on behalf of any Participant or Beneficiary is made shall be sufficient discharge therefor. G. PAYMENT OF PARTICIPANT'S EXPENSES The Company shall pay to a Participant all legal fees and expenses incurred by the Participant in seeking to enforce any right or benefit provided to the Participant under the Plan, as and when such expenses become due. H. CONSTRUCTION 1. The portion of the Plan respecting Unfunded Benefits is intended to qualify as a plan maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees as referred to in Section 201(2) of ERISA, and its terms shall be interpreted accordingly. The portion of the Plan respecting Funded Benefits is intended to comply with the applicable provisions of ERISA and its terms shall be interpreted accordingly. Otherwise, the laws of the State of Arkansas shall control the interpretation and performance of the terms of the Plan. 2. If any provision of the Plan, or the application of any such provision to any person or 19 circumstances, shall be invalid under any federal or state law, neither the application of such provision to persons or circumstances other than those as to which such provision is invalid nor any other provisions of the Plan shall be affected thereby. 3. The headings and subheadings in the Plan have been inserted for convenience of reference only, and are to be ignored in any construction of the provisions thereof. 20 EX-10.6 5 SUPPLEMENTAL RETIREMENT PLAN TRUST SOUTHWESTERN ENERGY COMPANY SUPPLEMENTAL RETIREMENT PLAN TRUST SERP Trust - Page 1 SOUTHWESTERN ENERGY COMPANY SUPPLEMENTAL RETIREMENT PLAN TRUST Section Recitals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 1 Establishment and Title of the Trust. . . . . . . . . . . . . . . . . . 3 2 Acceptance by the Trustee . . . . . . . . . . . . . . . . . . . . . . . 4 3 Limitation on Use of Funds. . . . . . . . . . . . . . . . . . . . . . . 4 4 Duties and Powers of the Trustee With Respect to Investments. . . . . . 4 5 Additional Powers and Duties of the Trustee . . . . . . . . . . . . . . 4 6 Contributions and Payment . . . . . . . . . . . . . . . . . . . . . . . 5 7 Third Parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 8 Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 9 Administration and Records. . . . . . . . . . . . . . . . . . . . . . . 7 10 Removal or Resignation of the Trustee and Designation of Successor Trustee . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 11 Enforcement of Trust Agreement and Legal Proceedings. . . . . . . . . . 9 12 Amendments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 13 Termination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 14 Non alienation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 15 Communications . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 16 Miscellaneous Provisions . . . . . . . . . . . . . . . . . . . . . . . 10
SERP Trust - Page 2 SOUTHWESTERN ENERGY COMPANY SUPPLEMENTAL RETIREMENT PLAN TRUST THIS TRUST AGREEMENT, made and entered into as of this 30th day of December, 1993, by SOUTHWESTERN ENERGY COMPANY, a corporation organized under the laws of the State of Arkansas, hereinafter referred to as the "Corporation"; and McIlroy Bank Division, Arvest Trust Company, N.A., hereinafter referred to as the "Trustee"; W I T N E S S E T H: WHEREAS, The Corporation maintains the Southwestern Energy Company Supplemental Retirement Plan (the "Plan"), adopted as of May 31, 1989 and amended and restated as of December 15, 1993, under which the Corporation has agreed to provide supplemental retirement income for the benefit of certain highly compensated employees; WHEREAS, The Plan is administered by a committee which has general responsibility and authority to take or direct any action required or advisable with respect to the administration of the Plan (the "Committee"); WHEREAS, The Plan has been amended to permit periodic contributions to irrevocable trust funds established for the benefit of some Participants in the Plan at the Corporation's discretion; and WHEREAS, Under the Plan, as amended and restated, any contributions the Corporation elects to make are to be forwarded to the trustee of the trust established by a trust agreement in accordance with the Plan; NOW, THEREFORE, in consideration of the mutual covenants herein contained, the Corporation and the Trustee declare and agree as follows: SECTION 1. ESTABLISHMENT AND TITLE OF THE TRUST 1.1 The Corporation hereby establishes with the Trustee a trust to be known as the Southwestern Energy Company Supplemental Retirement Trust (hereinafter referred to as the "Trust"), consisting of such sums of money and other property acceptable to the Trustee as from time-to-time shall be paid or delivered to the Trustee. All such money and other property, less all payments and charges as authorized herein, are hereinafter referred to as the "Trust Fund." 1.2 The Trust Fund shall be held by the Trustee in trust and shall be dealt with in accordance with the provisions of this Trust Agreement. 1.3 The Trust Fund shall be held for the exclusive purpose of providing payments to Participants and defraying reasonable expenses of administration in accordance with the provisions of the Trust Agreement until all such payments as are required by the Trust Agreement have been made. SERP Trust - Page 3 SECTION 2. ACCEPTANCE BY THE TRUSTEE 2.1 The Trustee accepts the Trust established under the Trust Agreement on the terms and subject to the provisions set forth herein, and it agrees to discharge and perform fully and faithfully all of the duties and obligations imposed upon it under the Trust Agreement. SECTION 3. LIMITATION ON USE OF FUNDS 3.1 No part of the principal or income of the Trust Fund shall be recoverable by the Corporation or used for any purpose other than for the exclusive purpose of providing payments to Participants and their beneficiaries in accordance with the provisions of the Trust Agreement and paying withholding taxes or other taxes or charges as provided herein. SECTION 4. DUTIES AND POWERS OF THE TRUSTEE WITH RESPECT TO INVESTMENTS 4.1 The Trustee shall hold the Trust assets, and any cash received by the Trustee on behalf of the Participant pending distribution, in accordance with Section 6. The Trustee shall invest and reinvest the principal and income of the trust pursuant to the directions of the Committee, or an investment manager or investment managers selected by the Committee in accordance with Section 2(c) of the Plan, which directions may specify that the Trustee invest in tax-free investments or in liquid accounts which need not provide for the payment of interest. The Trustee shall comply to the extent permitted by law with any such directions so made. Except as otherwise provided in Section 6.2(a), with respect to a failure of the Corporation or the Committee, as applicable, to forward certain amounts or, in the event of a termination of the Trust, to the extent permitted by applicable law, the Trustee shall not dispose of any Trust asset except upon the written direction of the Committee pursuant to Section 6. The Committee may direct the Trustee to substitute for any Trust assets allocated to a Participant fully-paid annuity contracts issued by an insurance company authorized to do insurance business in the State of Arkansas and having equivalent terms and conditions to such allocated Trust assets. The Committee shall specify in writing in the directions to the Trustee, the name and address of the insurance company and the terms and conditions of any such annuity contracts. 4.2 (a) The Trustee shall act with the care, skill, prudence and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims and in the best interests of the Participant. (b) The assets of the Trust may not be commingled with the assets of any other trust established pursuant to the Plan for investment or any other purposes. SECTION 5. ADDITIONAL POWERS AND DUTIES OF THE TRUSTEE 5.1 In accordance with Section 4, the Trustee shall have the following powers and authority with respect to all property constituting a part of the Trust Fund (a) To participate in any plan of reorganization, consolidation, merger, combination, liquidation or other similar plan relating to any such property, and to consent to or oppose any such SERP Trust - Page 4 plan or any action thereunder, or any contract, lease, mortgage, purchase, sale or other action by any corporation or other entity. (b) To deposit any such property with any protective, reorganization or similar committee; to delegate discretionary power to any such committee; and to pay part of the expenses and compensation of any such committee and any assessments levied with respect to any property so deposited. (c) To exercise any conversion privilege or subscription right available in connection with any such property; to oppose or to consent to the reorganization, consolidation, merger or readjustment of the finances of any corporation, company or association, or to the sale, mortgage, pledge or lease of the property of any corporation, company or association any of the securities of which may at any time be held in the Trust Fund, and to do any act with reference thereto, including the exercise of options, the making of agreements or subscriptions and the payment of expenses, assessments or subscriptions which may be deemed necessary or advisable in connection therewith, and to hold and retain any securities or other property which it may so acquire. (d) To commence or defend suits or legal proceedings and to represent the Trust in all suits or legal proceedings; to settle, compromise or submit to arbitration any claims, debts or damages due or owing to or from the Trust. (e) To exercise, personally or by general or limited power of attorney, any right, including the right to vote, appurtenant to any such property. (f) To register any securities held by it in its own name or in the name of any custodian of such property or of its nominee, including the nominee of any system for the central handling of securities, with or without the addition of words indicating that such securities are held in a fiduciary capacity and to deposit or arrange for the deposit of any such securities with such a system. (g) To engage any legal counsel, including counsel to the Corporation, or any other suitable agents, to consult with such counsel or agents with respect to the construction of this Trust Agreement, the duties of the Trustee hereunder, the transactions contemplated by this Trust Agreement or any act which the Trustee proposes to take or omit, to rely upon the advice of such counsel or agents, and to pay their reasonable fees, expenses and compensation. (h) To make, execute and deliver, as Trustee, any and all deeds, guarantees, conveyances, contracts, waivers, releases or other instruments in writing necessary or proper for the accomplishment of any of the foregoing powers. SECTION 6. CONTRIBUTIONS AND PAYMENT 6.1 (a) At such time as the Corporation forwards the initial contribution to the Trust, the Corporation or, if it does not act, the Committee shall provide the Trustee with (i) the name, address of record and social security number of the Participant , (ii) the beneficiary or beneficiaries designated to receive any payments due after the death of the Participant in accordance with the Plan and (iii) such other information as may be required to facilitate payments to the Participant and the Participant's designated beneficiaries by the Trustee. SERP Trust - Page 5 (b) The amount of each contribution to the Trust Fund on behalf of a Participant shall be held in a separate trust (the "Trust Account") established and maintained by the Trustee for such Participant. (c) The value of each Trust Account shall be adjusted as of each date on which a contribution to the Trust allocable to a Participant is forwarded by the Corporation, the Trustee receives any payment under a Contract or the Trustee is required to make a payment to the Participant or the Participant's designated beneficiary or beneficiaries, but no less frequently than annually, to reflect the effect of contributions received, payments made, and all other transactions of the preceding period. Such adjustments shall be made by (i) deducting the total of all payments made from the Trust Account during such period, (ii) adding the total amount of all contributions allocated to the Trust Account, and (iii) adding or deducting, as the case may be, all income received and accrued and realized and unrealized profits and losses attributable to the Trust Account. The Trustee shall deliver a written copy of such valuation to the Participant and the Committee within 30 business days after each valuation date. The Participant and the Committee shall have 90 days in which to file written objections to such valuation with the Trustee. If no written objections have been filed within such 90-day period, such valuation shall be conclusive and binding to the maximum extent permitted under applicable law, upon all persons having an interest in the Trust. 6.2 The Trustee shall make payments pursuant to the following provisions of this Section 6.2. (a) The Trustee shall distribute to each Participant from such participant's Trust Account the income of such Trust Account, including net realized capital gains, annually and, in addition, shall distribute from the principal of the trust an amount necessary to reduce the taxable income of such Participant's Trust Account for each taxable year, to the extent possible, to zero. (b) For each calendar year during which this Trust Agreement is in effect, the Committee shall calculate the estimated federal, state and local income taxes payable by the Participant in respect of the Participant's Trust Account. In making this calculation, the Committee shall assume that the participant is subject to the marginal federal income tax rate applicable to the highest income level and the maximum applicable marginal state and local income tax rate (based on the Participant's state and city of residence as shown on the records of the Corporation and the state and city in which he works, but without otherwise considering the Participant's individual circumstances). Such amount shall be referred to herein as the Participant's "Tax Liability." The committee shall notify the Trustee of the Participant's Tax Liability promptly after it has been calculated by the Corporation. Within 30 days after the end of each calendar year, the Trustee shall distribute to each Participant the participant's Trust Account an amount equal to the lesser of (i) the value of the Participant's funded Benefit Account or (ii) the excess, if any, of (A) the Participant's Tax Liability in respect of the Participant's Trust Account for such calendar year (taking into account any withholding taxes paid in respect of such Tax Liability), over (B) the amount distributed pursuant to Paragraph (a) of this section, after reduction for any applicable federal, state or local income taxes payable with respect thereto. (c) The Trustee shall, subject to paragraph (d) below, distribute such other amounts to the Participant at such time and in such manner as the Corporation or Committee shall direct the Trustee as is required under the Plan. Provided, however, that, unless otherwise provided under the Plan, no payment shall be made to the Participant under this Section until the Participant is eligible to elect to commence receiving benefits under the Southwestern Energy Company Employee Pension Plan. The Trustee shall remit such payments (i) with reasonable promptness to the SERP Trust - Page 6 Participant (or to the Participant's designated beneficiary or beneficiaries, if the Participant shall not then be living), provided that each payment made shall be remitted within 10 days after the end of the calendar month for which such payment is due or (ii) within such longer time periods as directed by the Committee in accordance with applicable law. (d) In the event of the termination of the Trust, a distribution of the assets held in the Trust Account shall be made by the Trustee to the Participant (or the Participant's designated beneficiary or beneficiaries in the event the Participant is not then living) to the extent permitted by law. (e) The Trustee shall withhold and transmit to the appropriate taxing authorities all required amounts from all payments made under this Section 6.2, and shall furnish to the Participant, to the extent required by applicable law, an IRS Form 1099 or other appropriate form, in respect of the amount of taxable income credited to his Trust fund during each applicable year and the amount of taxes withheld in respect thereof. The Corporation shall withhold and transmit to the appropriate taxing authorities all such required amounts from contributions to the Trust. SECTION 7. THIRD PARTIES 7.1 A third party dealing with the Trustee shall not be required to make inquiry as to the authority of the Trustee to take any action nor be under any obligation to follow the proper application by the Trustee of the proceeds of sale of any property sold by the Trustee or to inquire into the validity or propriety of any act of the Trustee. SECTION 8. COMPENSATION 8.1 As of the date this Trust is adopted, and as of, or before, the first day of each calendar quarter thereafter (or such other period as the Trustee and the Corporation shall mutually agree), the Corporation shall pay the Trustee such reasonable compensation for its services as may be agreed upon in writing from time to time by the Committee and the Trustee. 8.2 Expenses and Trustee's compensation payable pursuant to Section 8.1 shall in no event be chargeable or payable from the Trust Fund. 8.3 Brokerage charges, transfer taxes, and other expenses incident to any investment transaction by the Trustee with respect to the trust fund shall be deemed to be part of the securities or other property acquisitions or deducted in computing the proceeds from securities or other property disposed, as the case may be. SECTION 9. ADMINISTRATION AND RECORDS 9.1 The Trustee shall keep or cause to be kept accurate and detailed accounts of any investments, receipts, disbursements and other transactions hereunder, and all accounts, books and records relating thereto shall be open to inspection and audit at all reasonable times by any person designated by the Committee or the Participant. All such accounts, books and records shall be preserved (in original form, or on microfilm, magnetic tape or any other similar process) for such period as the Trustee may determine, but the Trustee may only destroy such accounts, books and records after first notifying the Committee and the Participant with an interest in the Trust Fund in SERP Trust - Page 7 writing of its intention to do so and transferring to the Committee any of such accounts, books and records requested. 9.2 Within 30 days after the close of each calendar year, and within 30 days after the removal or resignation of the Trustee or the termination of the Trust, the Trustee shall file with the Committee a written account setting forth all receipts, disbursements and other transactions effected by it during the preceding calendar year or during the period from the close of the preceding calendar year to the date of such removal, resignation or termination, including a statement of all cash and other property held at the end of such calendar year or other period. Unless such written account is fraudulent, to the extent permitted by applicable law, the Trustee shall be released from liability with respect to the propriety of its acts and transactions shown in such account, except with respect to any such acts or transactions as to which the Corporation or the Committee shall, within 90 days from the date of filing such annual or other account, file with the Trustee written objections. 9.3 The Trustee shall from time to time permit any independent public accountants selected by the Corporation or the Committee to have access during ordinary business hours to such records as may be necessary to audit the Trustee's accounts. 9.4 Nothing contained in the Trust Agreement shall be construed as depriving the Corporation or the Participant of the right to have a judicial settlement of the Trustee's accounts, and, upon any proceeding for a judicial settlement of the Trustee's accounts or for instructions, the only necessary parties thereto in addition to the Trustee shall be the Committee and the Participant. 9.5 In the event of the removal or resignation of the Trustee, the Trustee shall deliver to the successor Trustee all records which shall be required by the successor Trustee to enable it to carry out the provisions of this Trust Agreement. 9.6 In addition to any returns required of the Trustee by law, the Trustee shall prepare and file such tax reports and other returns as the Committee and the Trustee may from time to time agree. SECTION 10. REMOVAL OR RESIGNATION OF THE TRUSTEE AND DESIGNATION OF SUCCESSOR TRUSTEE 10.1 At any time, the Committee may remove the Trustee, with or without cause, upon at least 30 days' notice to the Trustee. 10.2 The Trustee may resign at any time upon at least 60 days' notice in writing to the Committee. 10.3 In the event of such removal or resignation, the Trustee shall duly file with the Committee a written account as provided in Section 9.2 above for the period since the last previous annual accounting, listing the cash and other property held in the Trust and setting forth all receipts, disbursements, distributions and other transactions respecting the Trust not included in any previous account. 10.4 Within 30 or 60 days, as applicable, after any such notice of removal or resignation of the Trustee, the Committee or the Corporation shall designate a successor Trustee qualified to act hereunder. Each such successor Trustee, during such period as it shall act as such, shall have the powers and duties herein conferred upon an individual Trustee, and the word "Trustee," wherever SERP Trust - Page 8 used herein, except where the context otherwise requires, shall be deemed to include any successor Trustee. Upon designation of a successor Trustee and delivery to the resigned or removed Trustee of written acceptance by the successor Trustee of such designation, such resigned or removed Trustee shall promptly assign, transfer, deliver and pay over to such Trustee, in conformity with the requirements of applicable law, the funds and properties in its control or possession then constituting the Trust Fund. SECTION 11. ENFORCEMENT OF TRUST AGREEMENT AND LEGAL PROCEEDINGS 11.1 The Corporation and the Committee shall have the right to enforce any provision of this Trust Agreement, and the Participant shall have the right as a beneficiary of the Trust to enforce any provision of this Trust Agreement that affects the right, title and interest of the Participant. In any action or proceedings affecting the Trust, the only necessary parties shall be the Committee, the Trustee and the Participant, and, except as otherwise required by applicable law, no other person shall be entitled to any notice or service of process. Any judgment entered in such an action or proceeding shall, to the maximum extent permitted by applicable law, be binding and conclusive on all persons having or claiming to have any interest in the Trust. SECTION 12. AMENDMENTS 12.1 The Board of Directors of the Corporation (or, to the extent authorized by the Board of Directors of the Corporation, the Committee) may from time to time amend or modify any of the provisions of this Trust Agreement, except Sections reducing 1.3 and increasing the 3.1; provided, however, that no amendment to the Trust Agreement materially reducing the rights or increasing the obligations of the Trustee shall be effective without the Trustee's consent. 12.2 The Corporation (or, in the case of amendments which do not materially affect the costs of maintaining the Plan and Trust, the Committee) and the Trustee (if applicable) shall execute such supplements to, or amendments of, the Trust Agreement as shall be necessary to give effect to any such amendment or modification. SECTION 13. TERMINATION 13.1 The Trust shall continue for such time as may be necessary to accomplish the purpose for which it was created, but, subject to the terms of the Plan, the Committee may terminate the Trust at any time upon 30 days' notice in writing to the Trustee. 13.2 Upon receipt by the Trustee of valid notice of termination of the Trust pursuant to Section 13.1, the Trustee shall, with reasonable promptness, arrange for the orderly distribution of all Trust property in accordance with Section 6.2 and applicable law. The Trust shall continue until no property is held thereunder. SECTION 14. NON ALIENATION 14.1 Insofar as applicable law or the Plan may otherwise require, (i) no amount payable to or in respect of the Participant at any time under the Trust shall be subject in any manner to SERP Trust - Page 9 alienation by anticipation, sale, transfer, assignment, bankruptcy, pledge, attachment, charge or encumbrance of any kind, and any attempt to so alienate, sell, transfer, assign, pledge, attach, charge or otherwise encumber any such amount, whether presently or thereafter payable, shall be void, and (ii) the Trust Fund shall in no manner be liable for or subject to the debts or liabilities of the Participant or the Corporation or any of its affiliates. SECTION 15. COMMUNICATIONS 15.1 Communications to the Corporation or the Committee shall be addressed to the Corporation, or to the Committee in care of the Corporation, in either case at 1083 Sain Street, Fayetteville, Arkansas 72703, to the attention: Treasurer, provided, however, that upon the Corporation's written request, such communications shall be sent to such other address as the Corporation may specify. 15.2 Communications to the Trustee shall be addressed to it at One McIlroy Plaza, Fayetteville, Arkansas 72701, provided, however, that, upon the Trustee's written request, such communications shall be sent to such other address as the Trustee may specify. 15.3 Communications to the Participant shall be addressed to the Participant as specified in Section 6.1; provided, however, that, upon the Participant's written request, such communications shall be sent to such other addresses as the Participant may specify. 15.4 Communication shall be deemed given when mailed or hand delivered. 15.5 Any action of the Committee pursuant to this Trust Agreement, including all orders, requests, directions, instructions, approvals and objections of the Committee to the Trustee, shall be in writing signed on behalf of the Committee by any member thereof, unless the Committee shall otherwise direct by resolution certified to the Trustee by the Secretary of the Committee. Any such action of the Corporation pursuant to the Trust Agreement shall be in writing and signed on behalf of the Corporation by any duly authorized officer of the Corporation. The Trustee may rely on, and will be fully protected with respect to any action taken or omitted in reliance on, any information, order, request, direction, instruction, approval, objection, and list delivered to the Trustee by the Committee or any such action of the Corporation or, to the extent applicable under this Trust Agreement, by the Participant, the Participant's surviving spouse or other designated beneficiary or the legal representatives of the Participant's estate. 15.6 The Board of Directors of the Corporation shall from time to time certify to the Trustee the membership of the Committee and the Committee shall from time to time certify to the Trustee the person or persons authorized to act for the Committee; provided, however, that certification shall not be required where the membership of the Committee or such authorized person or persons has not changed subsequent to the immediately preceding pertinent certification. The Trustee may continue to rely on any such certification until notified to the contrary. SECTION 16. MISCELLANEOUS PROVISIONS 16.1 The Trust Agreement shall be binding upon and inure to the benefit of the Corporation, the Participant and the Trustee and their respective permitted successors and assigns. SERP Trust - Page 10 16.2. The Corporation agrees, to the extent permitted by law, to indemnify the Trustee and hold it harmless from and against any liability that it may incur in the administration of the Trust Fund, except to the extent that any such cost is the result of the negligence or misconduct of the Trustee, its officers, its employees or its agents. The Trustee shall not be reimbursed out of the assets of the Trust Fund in the event that the Corporation has not fulfilled its obligations under the foregoing provisions of this Section. To the maximum extent permitted by applicable law, no personal liability whatsoever shall attach to or be incurred by any employee, officer or director of the Corporation, as such, or as a member of the Committee, under or by reason of the terms or conditions contained in or implied from this Trust Agreement. 16.3 The Trustee may employ such ministerial agents as it shall choose to assist it in the performance of the Trustee's administrative duties if the Trustee reasonably believes in the exercise of its discretion that such an arrangement is in the best interests of all interested persons and will improve the efficiency of the administration of the Trust Fund. 16.4 To the extent permitted by law, the Trustee shall be entitled to rely, and shall be fully protected in so relying, upon any written instructions reasonably believed to have been received from the Committee provided in accordance with the terms of the Trust Agreement. The Corporation shall designate the persons who comprise the Committee and the Committee shall designate up to three persons to provide instructions to the Trustee. Any changes in the authorized persons must be communicated to the Trustee by a person then designated to the Trustee as an authorized person. 16.5 The Trustee assumes no obligation, responsibility or duty to determine whether the amount of any contribution is in accordance with the Plan or to collect or enforce payments of any such contribution. 16.6 Any corporation into which the Trustee may be merged or with which it may be consolidated, or any corporation resulting from any merger, reorganization or consolidation to which the Trustee may be a party, or any corporation to which all or substantially all the trust business of the Trustee may be transferred, shall be the successor of the Trustee hereunder without the execution or filing of any instrument or the performance of any act. 16.7 Title to the Sections of the Trust Agreement are included for convenience only and shall not control the meaning or interpretation of any provision of the Trust Agreement. 16.8 To the extent not preempted by any laws of the United States now or hereinafter enacted, the Trust Agreement and the Trust established hereunder shall be governed by and construed, and all provisions hereof shall be enforced and administered, according to the laws of the State of Arkansas. 16.9 This Trust Agreement may be executed in any number of counterparts, each of which shall be deemed to be the original although the others shall not be produced. SERP Trust - Page 11 IN WITNESS WHEREOF, this Trust Agreement has been duly executed by the parties hereto on the 30th day of December, 1993. SOUTHWESTERN ENERGY COMPANY By: /s/ STANLEY D. GREEN ------------------------- Executive Vice President Attest /s/ GREG D. KERLEY - ------------------- Secretary TRUSTEE By: /s/ ROBERT P. PLUMMER -------------------------- Its: Senior Vice President & Trust Division Manager -------------------------- SERP Trust - Page 12 EX-13 6 PORTIONS OF 1993 SOUTHWESTERN ANNUAL REPORT Southwestern Energy Company and Subsidiaries MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Southwestern Energy Company is an exempt holding company under the Public Utility Holding Company Act of 1935 which conducts its primary activities through four wholly owned subsidiaries. The Company's operating results and financial condition thus reflect the activities of its subsidiaries. These subsidiaries are active in the exploration and production, local distribution and transmission segments of the natural gas industry. The Company strengthened its financial position in 1993 and continues to have access to adequate sources of capital to finance its operations and capital spending. The consolidated financial statements and the "Financial and Operating Statistics" should be referred to in conjunction with the following review. "Selected Financial Data" can be found in the "Financial and Operating Statistics". Results of Operations Net income in 1993 before the cumulative effect of a change in accounting for income taxes increased by 21% to $27.1 million, or $1.05 per share, up from $22.3 million, or $.87 per share, in 1992. Net income in 1991 was $20.1 million, or $.78 per share. Operating results for 1993 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 the increase in the maximum corporate income tax rate enacted by the Omnibus Budget Reconciliation Act of 1993 (OBRA). Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes," required that the entire amount of this adjustment be recorded as a charge to operating results during the period in which the increased rates were enacted. When Southwestern adopted the provisions of SFAS No. 109 in the first quarter of 1993, the Company recorded a $10.1 million, or $.39 per share, increase in net income as the cumulative effect on prior years of adopting the accounting change. Even though the adjustment resulting from enactment of OBRA was required to be recorded in the same year as the adoption of the new standard, SFAS No. 109 does not allow the effects of the two events to be netted against each other. There were no accounting changes or extraordinary items recorded in either 1992 or 1991. The Company's reported earnings per share have been restated to reflect the effect of a three-for-one stock split distributed in the third quarter of 1993. The earnings growth in 1993 and 1992 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.
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Revenues Exploration and production $ 79,374 $ 60,554 $ 49,392 Gas distribution 131,892 117,495 121,302 Other 262 256 256 Eliminations (36,684) (34,475) (34,511) - ----------------------------------------------------------------------------- $174,844 $143,830 $136,439 ============================================================================= Operating Income Exploration and production $ 42,608 $ 33,071 $ 28,310 Gas distribution 15,261 13,094 14,027 Corporate expenses (305) (177) (195) - ----------------------------------------------------------------------------- $ 57,564 $ 45,988 $ 42,142 =============================================================================
Exploration and Production Revenues The Company's exploration and production revenues increased 31% in 1993 and 23% in 1992, due in both years to increased natural gas production. Production increased by 39% to 35.4 billion cubic feet (Bcf) in 1993 from 25.5 Bcf in 1992. Production in 1992 increased by 28% from 19.9 Bcf in 1991. The increase in gas production since 1991 is attributable to increased sales to unaffiliated purchasers. Gas sales to unaffiliated purchasers increased to 22.6 Bcf in 1993 from 14.1 Bcf in 1992 and 7.0 Bcf in 1991. The increase in sales to unaffiliated purchasers was the result of higher sales from the Company's properties in both Arkansas and the Gulf of Mexico. The Company sold 14.8 Bcf of its Arkansas production to unaffiliated purchasers during 1993, compared to 10.3 Bcf in 1992 and 3.3 Bcf in 1991. The increase in 1993 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. The increase in 1992 was the result of the development drilling program and of production at the Fort Chaffee military reservation which began in August, 1991. Production outside Arkansas, all of which is sold to unaffiliated purchasers, was 7.8 Bcf in 1993, compared to 3.8 Bcf in 1992 and 3.7 Bcf in 1991. 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. Both of those fields are in the Gulf of Mexico. Based on current rates of production, these additions should leave the Company's production from the Gulf of Mexico stable during 1994.
1993 1992 1991 - ----------------------------------------------------------------------------- Gas Production Affiliated sales (Bcf) 12.8 11.4 12.9 Unaffiliated sales (Bcf) 22.6 14.1 7.0 - ----------------------------------------------------------------------------- 35.4 25.5 19.9 - ----------------------------------------------------------------------------- Average price per Mcf $2.18 $2.26 $2.26 ============================================================================= Oil Production Unaffiliated sales (MBbls) 96 120 176 - ----------------------------------------------------------------------------- Average price per Bbl $17.20 $19.75 $20.67 ============================================================================
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 and 1991 when sales prices were deemed below acceptable levels. Colder weather during the heating season and storage requirements during the summer months affected the demand of the Company's utility distribution systems for gas supply in 1993. Gas production sold to Arkansas Western Gas Company (AWG), which operates the Company's northwest Arkansas utility system, was 7.1 Bcf in 1993, 7.2 Bcf in 1992 and 7.6 Bcf in 1991. 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 system and an increase in sales to a spot market purchasing program available to the larger business customers of AWG. Injections into AWG's gas storage facilities were not necessary as physical improvements made by the utility during 1993 decreased the level of cushion gas necessary to efficiently operate these facilities. The decrease in sales to AWG in 1992, as compared to 1991, occurred because a number of AWG's large business customers switched to a new transportation service offered by the utility. This decrease in sales to AWG was offset by direct sales of one of the exploration and production subsidiaries to AWG's large business customers. In 1993, 1992 and 1991, the Company's gas production provided approximately 50% of AWG's requirements. Additionally, in 1993, 1992 and 1991, the Company sold .7 Bcf, .4 Bcf and 1.1 Bcf, respectively, of gas to AWG for the spot market purchasing program described above. 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 this system are subject to a long-term contract entered into in 1978, under which the price has been frozen since the end of 1984. Other sales to the utility are made under newer long-term contracts which contain provisions for annual price redetermination. In November, 1993, the Arkansas Public Service Commission (APSC or Commission) issued an order which found the purchases of AWG under the 1978 contract to be in violation of an Arkansas statute requiring that gas purchases be made "from the lowest or most advantageous market." The APSC order is discussed more fully below under Regulatory Matters. 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 5.7 Bcf in 1993, 4.3 Bcf in 1992 and 5.3 Bcf in 1991. Deliveries to Associated increased in 1993 primarily due to colder winter heating weather and storage requirements during the summer months. The decrease in volumes sold to Associated in 1992, as compared to 1991, was primarily the result of certain industrial customers switching to transportation service. 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, and are currently being made at $2.385 per Mcf. The average price received at the wellhead for the Company's total gas production was $2.18 per Mcf in 1993 and $2.26 per Mcf in both 1992 and 1991. While spot market prices were generally higher in 1993, the Company's production mix reflected a lower proportion of sales under older, higher priced contracts. The Company believes that the overall trend of natural gas pricing in the near future will be favorable, due primarily to rising demand and the decline of industry drilling activity in recent years. However, for the next few years the Company expects the average price it receives for its total production to continue to be either flat or decreasing as any incremental gas production will likely be sold at current spot market prices which are generally lower than the average price presently received by the Company for sales under older long-term contracts. As described above, a substantial portion of the Company's gas production is sold under long-term contracts to Southwestern's gas distribution subsidiary. These sales arrangements help reduce the effects of fluctuations in the spot market price for natural gas. 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. New sales contracts entered into under present market conditions may be either short-term or long-term in nature, but will likely contain some type of variable pricing mechanism which will be responsive to changes in the market price for gas. The Company expects access to markets for sales of its production to continue to improve as a result of the NOARK Pipeline System (NOARK). NOARK provides additional transportation capacity out of the Arkoma Basin where most of the Company's present reserves are located. The pipeline 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 of 47.33% in NOARK and is the pipeline's operator. The Company completed a pipeline in 1993 to connect NOARK to Associated's system, tying together the Company's primary gas distribution systems. 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 because of 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.
1993 1992 1991 - ----------------------------------------------------------------------------- Gas Distribution Systems Deliveries (Bcf) Sales volumes 26.8 23.5 27.1 Transportation volumes End users 5.6 5.2 1.3 Off-system 11.7 2.5 .2 - ----------------------------------------------------------------------------- 44.1 31.2 28.6 - ----------------------------------------------------------------------------- Average number of customers 155,944 151,592 147,629 - ----------------------------------------------------------------------------- Heating weather-degree days 4,929 4,104 4,095 - ----------------------------------------------------------------------------- Average sales rate per Mcf $4.65 $4.75 $4.36 =============================================================================
Gas distribution revenues increased by 12% in 1993 and decreased by 3% in 1992. 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. The decrease in 1992 was due to the conversion of certain industrial customers from sales to transportation service. While the conversion of these customers to transportation service lowered the Company's gas distribution revenues, there was no resulting impact on operating income as the rate charged these customers for transportation service was equal to the rate charged for sales service, exclusive of gas costs. In 1993, AWG sold 17.1 Bcf to its customers at an average rate of $4.40 per Mcf, compared to 15.0 Bcf at $4.62 per Mcf in 1992 and 17.2 Bcf at $4.22 per Mcf in 1991. Additionally, AWG transported 3.9 Bcf for its customers in 1993, 3.2 Bcf in 1992 and .7 Bcf in 1991 under a transportation program implemented in October, 1991. Associated sold 9.7 Bcf to its customers in 1993 at an average rate of $5.08 per Mcf, compared to 8.4 Bcf in 1992 at $4.99 per Mcf and 9.9 Bcf at $4.62 per Mcf in 1991. Associated transported 1.7 Bcf for its customers in 1993, compared to 2.0 Bcf in 1992 and .6 Bcf in 1991. Total deliveries to industrial customers of AWG and Associated, including transportation volumes, increased to 11.7 Bcf in 1993, from 11.3 Bcf in 1992 and 10.8 Bcf in 1991. 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 11.7 Bcf of gas through its gathering system in 1993 for off-system deliveries, primarily to NOARK, compared to 2.5 Bcf in 1992. The average transportation rate was $.13 per Mcf, exclusive of fuel, in both 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 3% to 3.5% 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. A rate increase request is not imminent as the strong customer growth and additional transportation revenues have helped offset the effects of attrition since the Company's last rate case. Regulatory Matters In November, 1993, the APSC issued an order in a three-year-old gas cost case involving purchases by AWG under a long-term contract with one of the Company's gas producing subsidiaries. The order found AWG's purchases under the contract to be in violation of an Arkansas statute requiring that gas purchases be made "from the lowest or most advantageous market." The order found that the price paid by AWG was too high, but said that additional evidence was necessary to enable the Commission to determine a proper price. A hearing was held in mid-January, 1994, to receive additional evidence. The long-term contract in question was approved by the APSC in 1979. The gas cost issues addressed in the order were first raised by the Commission in December, 1990, in connection with the APSC's approval of an AWG rate increase. During the rate case, the Commission Staff hired a consultant who performed an extensive review of the utility's purchasing practices and gas costs and recommended in filed testimony that all of the Company's gas costs, including purchases under the contract in question, be accepted without adjustment. In spite of the testimony filed by its Staff, the Commission established a proceeding to investigate its concerns. At the January, 1994 hearing, both the Staff of the Commission and the Office of the Attorney General of the State of Arkansas presented testimony describing recommendations designed to lower the price received by the Company's production subsidiary under the contract. The Company presented testimony which it believes reinforced its position that the contractual arrangements questioned by the Commission are the most advantageous available to its utility customers. Legal briefs related to the hearing were filed in late February, 1994, and the Company expects a Commission order to be forthcoming. If necessary, the Company intends to continue to defend its gas purchasing practices through the courts. The Commission has previously stated that AWG's gas purchasing practices, affiliate transactions, gas costs and gas cost allocation issues would be considered in the proceeding on a prospective basis only. The Company does not expect any outcome of the proceeding to have a material adverse effect on the financial position of the Company. Of the Company's 35.4 Bcf of gas production during 1993, approximately 6.0 Bcf was sold under the contract in question. Another regulatory development which should not have a significant impact on the Company is the issuance by the Federal Energy Regulatory Commission (FERC) of its Order No. 636 series, the restructuring rules covering natural gas service by interstate pipelines. Order No. 636 makes significant changes to the merchant function historically provided to gas distributors by interstate pipelines. Since AWG and Associated already obtain the bulk of their supply at the wellhead directly from producers, the changes mandated should be insignificant to the Company. Prior to Order No. 636, Associated purchased gas from interstate pipelines under contracts with take-or-pay provisions. To date, the Company has paid approximately $3.2 million for contract reformation costs incurred by its interstate pipeline suppliers and for contracted quantities of gas not taken. The Company believes these costs are recoverable from its utility customers and expects approval from the proper regulatory agencies after the payments are reviewed in the normal course of business. To date, the Company has recovered, subject to refund, approximately $1.6 million of these charges from its customers. 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. The Company's exposure to take-or-pay liabilities to producers or other suppliers could increase as a result of the decline in its gas purchase requirements which has occurred as some of its large business customers participate in a transportation service offered by AWG and Associated in Arkansas and 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 20% in 1993 and by 4% in 1992. The increase in 1993 was due primarily to increased purchased gas costs related to increased utility deliveries, and increased production costs and depreciation, depletion and amortization resulting from increased gas sales in the exploration and production segment. The increase in 1992 resulted from increased operating and general expenses and increased depreciation, depletion and amortization related to increased gas sales in the exploration and production segment, partially offset by lower purchased gas costs caused by the conversion of certain industrial customers of the gas distribution segment from sales to transportation service. Purchased gas costs are the largest expense item in each year, typically representing 35% to 45% 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 passed through automatically to the Company's utility customers. Depreciation, depletion and amortization is calculated using the units-of-production method for the Company's gas and oil properties. 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. The record level of natural gas production in each year was the primary reason for the 30% increase in depreciation, depletion and amortization in 1993 and the 31% increase in 1992. 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 many 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. There are some recent indications, however, that these depressed conditions are abating, which could cause an increase in such costs in the future. Other Costs and Expenses 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, as discussed below in Financing Requirements, and due to both lower average borrowings and lower average interest rates on the Company's revolving debt facilities. Interest costs increased slightly in 1992, as compared to 1991, due primarily to the Company's issuance of $66.0 million of fixed rate debt in December, 1991, which was issued to refinance lower cost variable rate bank debt. The change in other income during 1993 and 1992 relates primarily to the Company's share of operating losses incurred by NOARK. The Company accounts for its 47.33% interest in the NOARK partnership under the equity method of accounting (see Note 7 to the financial statements for additional discussion). The Company's share of the pre-tax loss for NOARK included in other income was $1.8 million in 1993 and $.6 million in 1992. Deliveries are currently being made by NOARK to portions of AWG's distribution systems, to Associated and to the interstate pipelines with which NOARK interconnects. NOARK completed its first full year of operation in 1993 and had an average daily throughput during the year of 79 million cubic feet of gas per day (MMcfd). 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 supplies 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 seeks rescission of the transportation contract and a contract to purchase gas from the Company's affiliates, along with 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 the 25 MMcfd of production through NOARK which was previously purchased by Vesta. The APSC has established a maximum transportation rate of approximately $.285 per dekatherm for NOARK based on its original construction cost estimate of approximately $73.0 million. NOARK's actual cost of construction was approximately $103.0 million, due primarily to unanticipated construction conditions which were encountered along certain segments of the pipeline's route. 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 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 does not offer firm transportation, but the increased availability of interruptible transportation services intensified the competitive environment within which NOARK operates. The Company believes that the FERC's Order No. 636 restructuring rules implemented in the latter part of 1993 will have a positive impact on NOARK. The unbundling of gas sales, gathering, transmission and storage services required by Order No. 636 should provide NOARK with expanded options for accessing gas supply and for transporting gas to downstream customers. The Company believes it will realize its investment in NOARK over the life of the system. The Company's effective income tax rate was 42.3% in 1993, 37.4% in 1992 and 37.7% in 1991. The rate increased in 1993 because the Company's deferred tax provision included $1.7 million of expense for the increase in the maximum corporate tax rate legislated by OBRA. 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 1993, 1992 and 1991, net cash provided from operating activities totaled $70.2 million, $49.7 million and $35.0 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 in excess of 100% of the Company's capital requirements for routine capital expenditures, cash dividends and scheduled debt retirements in 1993, 94% in 1992 and 75% in 1991. 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 new rate is equivalent to $.24 per share, compared to a dividend rate of $.20 per share paid in 1992 and a dividend rate of $.19 per share paid in 1991. The dividend rates reflect the effect of a three-for-one stock split distributed in 1993. Total dividends paid to common shareholders in 1993 were $5.7 million compared to $5.1 million in 1992 and $4.8 million in 1991. 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 Routine capital expenditures were $59.2 million in 1993, $44.9 million in 1992 and $38.9 million in 1991. In 1992, the Company also made a $7.6 million equity contribution to the partnership formed to construct NOARK.
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Capital Expenditures Exploration and production $37,411 $30,823 $30,339 Gas distribution 19,892 12,188 7,856 Other 1,916 1,898 693 - ----------------------------------------------------------------------------- $59,219 $44,909 $38,888 =============================================================================
The Company generally intends to limit its routine capital expenditures to internally generated cash or less. This level of spending should 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 to explore and develop existing gas and oil properties as well as generate new drilling prospects. Routine capital expenditures expected to be incurred in 1994 are $67.3 million, consisting of $50.0 million for gas and oil exploration, $13.3 million for gas distribution system expenditures and $4.0 million for general purposes. The Company's capital expenditure plans also include approximately $6.7 million of non-routine spending, including $5.5 million to extend gas service to new communities along NOARK's route and $1.2 million to construct a transmission loop in Associated's system. The majority of the 1994 budgeted expenditure to extend gas service to new communities along NOARK is a carryover from the 1993 capital expenditures budget. The gas and oil expenditures include $12.5 million for exploratory drilling, $4.3 million for additional drilling and development of properties on the Fort Chaffee military reservation and $14.0 million to continue the development of the Company's proved acreage in the Arkoma Basin. The Company may use its existing revolving credit facilities to meet seasonal or short-term requirements related to these expenditures. Additionally, the Company recently formed a group to focus solely on the acquisition of producing properties and expects that effort to supplement its exploration and development drilling programs. The Company plans to manage the debt portion of its capital structure over time through its policy of generally limiting its routine capital spending to internally generated cash or less, but expects to continue to use additional debt to address extraordinary needs or opportunities, such as attractive acquisitions of gas and oil properties. Financing Requirements Two floating rate revolving credit facilities provided the Company access to $60.0 million of variable rate long-term capital at December 31, 1993. Borrowings outstanding under these credit facilities totaled $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 1993. The Company is currently in the process of renegotiating the terms and increasing the capacity of its variable rate facilities. In the fourth quarter of 1992, the Company redeemed its 12.75% Debentures and its 9.38% First Mortgage Bonds which were due in 1993. The redemptions were funded by the Company's variable rate credit facilities. The Company and an affiliate of the other major general partner of NOARK are required to severally guarantee the availability of certain minimum cash balances to service a $63.0 million issue of 9.7375% Senior Secured Notes. The notes, which have a remaining term of approximately 16 years, are held by a major insurance company which also has a 20% limited partnership interest in NOARK. The Company's share of the several guarantee of available cash balances is 60%. Also in 1993, NOARK entered into an unsecured long-term revolving credit agreement with a group of banks which provides the partnership access to $30.0 million of additional funds. At December 31, 1993, $25.2 million was outstanding under this credit arrangement. This facility replaced a $20.0 million short-term line of credit, all of which was outstanding at December 31, 1992. Amounts borrowed under the long-term revolving credit agreement are severally guaranteed by the Company and an affiliate of the other major general partner. The Company's share of the several guarantee is also 60%. NOARK has borrowed approximately 84% of its total construction costs under these financing arrangements. The remainder of NOARK's capital was provided by equity contributions of the partners during 1992. The Company expects to fund approximately $1.7 million during 1994, in the form of equity contributions or loans to the partnership, in connection with its guarantees. In July, 1992, in view of interest rates obtainable at the time, 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, the Company receives interest semiannually at a fixed rate of 5.11% and pays interest semiannually at the London Interbank Offered Rate (LIBOR). The LIBOR rate is determined at the end of each six-month period. 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 1993, the capital structure consisted of 40.19% debt (excluding the current portion of long-term debt) and 59.81% equity, with a ratio of earnings to fixed charges of 3.98. 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 $8.1 million at the end of 1993 and $14.2 million at the end of 1992. Current assets increased by 4% to $46.8 million in 1993, while current liabilities increased 25% to $38.7 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. The increase in current liabilities resulted primarily from an increase in the current portion of long-term debt and an increase in accounts payable and taxes payable. The increases in accounts payable and taxes payable resulted primarily from the timing of payments of amounts due. Additionally, a portion of the increase in taxes payable in 1993 was due to the increase in taxable income. 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, 1993 and 1992, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. 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, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, 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 & CO. Tulsa, Oklahoma February 7, 1994 Southwestern Energy Company and Subsidiaries STATEMENTS OF INCOME
For the Years Ended December 31 1993 1992 1991 - ----------------------------------------------------------------------------- ($ in thousands, except per share amounts) Operating Revenues Gas sales $165,597 $135,274 $129,196 Oil sales 1,659 2,377 3,639 Gas transportation 5,177 3,597 857 Other 2,411 2,582 2,747 - ----------------------------------------------------------------------------- 174,844 143,830 136,439 - ----------------------------------------------------------------------------- Operating Costs and Expenses Purchased gas costs 42,962 35,848 40,423 Operating and general 40,093 34,970 32,609 Depreciation, depletion and amortization 30,944 23,880 18,248 Taxes, other than income taxes 3,281 3,144 3,017 - ----------------------------------------------------------------------------- 117,280 97,842 94,297 - ----------------------------------------------------------------------------- Operating Income 57,564 45,988 42,142 - ----------------------------------------------------------------------------- Interest Expense Interest on long-term debt 10,090 10,932 10,464 Other interest charges 483 547 776 Interest capitalized (1,548) (1,496) (1,427) - ----------------------------------------------------------------------------- 9,025 9,983 9,813 - ----------------------------------------------------------------------------- Other Income (Expense) (1,657) (421) (107) - ----------------------------------------------------------------------------- Income Before Provision for Income Taxes and Cumulative Effect of Accounting Change 46,882 35,584 32,222 - ----------------------------------------------------------------------------- Provision for Income Taxes Current 13,704 7,403 7,158 Deferred (includes $1.7 million in 1993 related to legislated increase in tax rates) 6,128 5,916 4,999 - ----------------------------------------------------------------------------- 19,832 13,319 12,157 - ----------------------------------------------------------------------------- Income Before Cumulative Effect of Accounting Change 27,050 22,265 20,065 Cumulative Effect of Change in Accounting for Income Taxes 10,126 - - - ----------------------------------------------------------------------------- Net Income $ 37,176 $ 22,265 $ 20,065 ============================================================================= Earnings Per Share Income Before Cumulative Effect of Accounting Change $1.05 $.87 $.78 Cumulative Effect of Change in Accounting for Income Taxes .39 - - - ----------------------------------------------------------------------------- Net Income $1.44 $.87 $.78 ============================================================================= Weighted Average Common Shares Outstanding 25,684,110 25,683,963 25,678,011 =============================================================================
The accompanying notes are an integral part of the financial statements. Southwestern Energy Company and Subsidiaries BALANCE SHEETS
December 31 1993 1992 - ----------------------------------------------------------------------------- (in thousands) ASSETS Current Assets Cash $ 834 $ 1,122 Accounts receivable 34,866 34,30 5 Inventories, at average cost 9,580 8,036 Other 1,525 1,639 - ----------------------------------------------------------------------------- Total current assets 46,805 45,102 - ----------------------------------------------------------------------------- Investments 5,661 7,523 - ----------------------------------------------------------------------------- Property, Plant and Equipment, at cost Gas and oil properties, using the full cost method, including $16,769,000 in 1993 and $20,633,000 in 1992 excluded from amortization 375,281 338,062 Gas distribution systems 165,443 146,837 Gas in underground storage 37,171 46,290 Other 14,684 13,040 - ----------------------------------------------------------------------------- 592,579 544,229 Less: Accumulated depreciation, depletion and amortization 205,949 174,949 - ----------------------------------------------------------------------------- 386,630 369,280 - ----------------------------------------------------------------------------- Other Assets 6,358 5,270 - ----------------------------------------------------------------------------- $445,454 $427,175 ============================================================================= LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Current portion of long-term debt $ 3,000 $ 133 Accounts payable 16,052 13,816 Taxes payable 6,449 3,338 Interest payable 1,445 1,472 Customer deposits 3,927 3,510 Current portion of deferred income taxes 1,426 2,536 Over-recovered purchased gas costs, net 4,187 4,473 Other 2,211 1,669 - ----------------------------------------------------------------------------- Total current liabilities 38,697 30,947 - ----------------------------------------------------------------------------- Long-Term Debt, less current portion above 124,000 143,202 - ----------------------------------------------------------------------------- Other Liabilities Deferred income taxes 93,593 95,203 Deferred investment tax credits 2,617 2,786 Other 2,017 1,804 - ----------------------------------------------------------------------------- 98,227 99,793 - -----------------------------------------------------------------------------
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 180,470 148,945 - ----------------------------------------------------------------------------- 204,475 172,950 Less: Unamortized cost of 17,447 restricted shares issued under stock incentive plan 228 - Common stock in treasury, at cost, 2,053,974 shares 19,717 19,717 - ----------------------------------------------------------------------------- 184,530 153,233 - ----------------------------------------------------------------------------- $445,454 $427,175 =============================================================================
The accompanying notes are an integral part of the financial statements. Southwestern Energy Company and Subsidiaries STATEMENTS OF CASH FLOWS
For the Years Ended December 31 1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Cash Flows From Operating Activities Net income $ 37,176 $ 22,265 $ 20,065 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 31,223 24,160 18,528 Deferred income taxes 6,128 5,916 4,999 Equity in loss of partnership 1,788 531 - Cumulative effect of change in accounting for income taxes (10,126) - - Change in assets and liabilities: Increase in accounts receivable (561) (5,002) (4,163) (Increase) decrease in inventories (1,544) 440 (1,910) Increase (decrease) in accounts payable 2,236 876 (2,162) Increase (decrease) in taxes payable 3,111 1,848 (1,294) Increase (decrease) in interest payable (27) (240) 133 Increase in customer deposits 417 347 150 Increase (decrease) in over-recovered purchased gas costs (286) (1,335) 171 Net change in other current assets and liabilities 656 (76) 469 - ----------------------------------------------------------------------------- Net cash provided by operating activities 70,191 49,730 34,986 - ----------------------------------------------------------------------------- Cash Flows From Investing Activities Capital expenditures (59,219) (44,909) (38,888) Investment in partnership - (7,573) 544 (Increase) decrease in gas stored underground 9,119 (4,432) 435 Other items 1,607 1,997 163 - ----------------------------------------------------------------------------- Net cash used in investing activities (48,493) (54,917) (37,746) - ----------------------------------------------------------------------------- Cash Flows From Financing Activities Net increase (decrease) in revolving long-term debt (15,500) 22,000 (54,500) Proceeds from issuance of other long-term debt - - 66,000 Payments on other long-term debt (835) (12,769) (2,931) Dividends paid (5,651) (5,137) (4,793) - ----------------------------------------------------------------------------- Net cash provided (used) by financing activities (21,986) 4,094 3,776 - ----------------------------------------------------------------------------- Increase (decrease) in cash (288) (1,093) 1,016 Cash at beginning of year 1,122 2,215 1,199 - ----------------------------------------------------------------------------- Cash at end of year $ 834 $ 1,122 $ 2,215 =============================================================================
Southwestern Energy Company and Subsidiaries STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31 1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Retained Earnings, beginning of year $148,945 $131,817 $116,545 Net income 37,176 22,265 20,065 Cash dividends declared ($.22 per share in 1993, $.20 per share in 1992 and $.19 per share in 1991) (5,651) (5,137) (4,793) - ----------------------------------------------------------------------------- Retained Earnings, end of year $180,470 $148,945 $131,817 =============================================================================
The accompanying notes are an integral part of the financial statements. NOTES TO FINANCIAL STATEMENTS December 31, 1993, 1992 and 1991 (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 47.33% 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 1993 presentation. Property, Depreciation, Depletion and Amortization Gas and Oil Properties - The Company follows the full cost method of accounting for the cost of exploration and development 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 6.7%. 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 93,000 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, 1993 and 1992 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. Interest Rate Swap Agreements 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. 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 and 1991 has been restated to reflect the effects of a three-for-one stock split distributed on August 5, 1993. The common stock and additional paid-in capital accounts at December 31, 1992 have been restated to reflect the stock split and the effect of a reduction in the par value of common stock from $2.50 per share to $.10 per share on June 9, 1993. (2) Long-Term Debt Long-term debt as of December 31, 1993 and 1992, consisted of the following:
1993 1992 - ----------------------------------------------------------------------------- (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 beginning September 30, 1994 30,000 30,000 - ----------------------------------------------------------------------------- 96,000 96,000 - ----------------------------------------------------------------------------- Other Variable rate (3.80% at December 31, 1993) unsecured revolving credit arrangements with two banks, each convertible at the Company's option to a term loan repayable in six semi-annual installments beginning no later than June, 1994 31,000 46,500 Other notes payable - 835 - ----------------------------------------------------------------------------- 31,000 47,335 - ----------------------------------------------------------------------------- Total long-term debt 127,000 143,335 Less: Current portion of long-term debt 3,000 133 - ----------------------------------------------------------------------------- $124,000 $143,202 =============================================================================
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, 1993, the Company had two variable rate facilities which make available $60.0 million of long-term revolving credit, of which $31.0 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. As of February 7, 1994, the Company was in the process of renegotiating the terms and increasing the capacity of its variable rate facilities. At December 31, 1993, 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, 1993. 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, 1993, approximately $102.8 million of retained earnings was available for payment as dividends. At December 31, 1993 and 1992, the Company had an interest rate swap agreement outstanding with a notional amount of $30.0 million. The notional amount is used to measure the volume of the agreement and does not represent exposure to credit loss. In the event of default by the counterparty, the risk of this transaction is the cost of replacing the swap agreement at current market rates. Management believes the risk of incurring a loss due to a default by the counterparty is remote, and that if incurred, such loss would be immaterial. Aggregate maturities of long-term debt for each of the years ending December 31, 1994 through 1998, are $3.0 million, $6.1 million, $6.1 million, $59.6 million and $6.1 million. Total interest payments of $10.3 million, $11.7 million and $10.4 million were made in 1993, 1992 and 1991, respectively. (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:
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Federal: Current $11,514 $ 6,190 $ 5,584 Deferred 3,827 5,096 4,598 Deferred tax adjustment for tax rate increase 1,743 - - State: Current 2,190 1,213 1,574 Deferred 752 1,004 577 Investment tax credit amortization (194) (184) (176) - ----------------------------------------------------------------------------- Provision for income taxes $19,832 $13,319 $12,157 =============================================================================
The provision for income taxes was an effective rate of 42.3% in 1993, 37.4% in 1992 and 37.7% in 1991. 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:
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Expected provision at federal statutory rate of 35% in 1993 and 34% in 1992 and 1991 $16,409 $12,098 $10,956 Increase (decrease) resulting from: State income taxes, net of federal income tax benefit 1,914 1,463 1,419 Percentage depletion on gas and oil production (117) (106) (49) Adjustment to deferred taxes for tax rate increase 1,743 - - Investment tax credit amortization (194) (184) (176) Other 77 48 7 - ----------------------------------------------------------------------------- Provision for income taxes $19,832 $13,319 $12,157 =============================================================================
The components of the Company's net deferred tax liability as of December 31, 1993 were as follows (in thousands):
- ----------------------------------------------------------------------------- Deferred tax liabilities: Differences between book and tax basis of property $83,875 Stored gas differences 5,132 Deferred purchased gas costs 1,232 Prepaid pension costs 1,731 Book over tax basis in partnerships 2,675 Gas imbalances 644 Other 876 - ----------------------------------------------------------------------------- 96,165 - ----------------------------------------------------------------------------- Deferred tax assets: Accrued compensation 770 Other 376 - ----------------------------------------------------------------------------- 1,146 - ----------------------------------------------------------------------------- Net deferred tax liability $95,019 =============================================================================
Prior to the change in accounting for income taxes, the sources of deferred tax items and the corresponding tax effects during 1992 and 1991 were as follows:
1992 1991 - ----------------------------------------------------------------------------- (in thousands) Intangible and other exploration and development costs $1,581 $1,952 Investment tax credits amortized (184) (176) Stored gas differences 972 170 Excess of tax over book depreciation 1,987 1,419 Deferred purchased gas costs 355 950 Excess of tax over book partnership loss 953 - Other 252 684 - ----------------------------------------------------------------------------- Deferred provision for income taxes $5,916 $4,999 =============================================================================
Total income tax payments of $10.2 million, $6.4 million and $8.3 million were made in 1993, 1992 and 1991, respectively. (4) Pension Plans and Other Postretirement Benefits Substantially all employees are covered by the Company's defined benefit pension plans. 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 plans with sufficient assets to meet future benefit payment requirements and which are tax deductible. Plan assumptions for 1993 and 1992 included an expected long-term rate of return on plan assets of 9%, a weighted average discount rate of 8.5% for the net pension cost computation and a salary progression rate of 5%. The reconciliation of prepaid pension cost at December 31, 1993 utilizes a discount rate of 7.5% for future settlements. The following table sets forth the plans' funded status and amounts recognized in the Company's balance sheets at December 31, 1993 and 1992:
1993 1992 - ----------------------------------------------------------------------------- (in thousands) Actuarial present value of benefit obligations: Vested benefits $(20,746) $(16,623) Nonvested benefits (1,685) (1,297) - ----------------------------------------------------------------------------- Accumulated benefit obligation (22,431) (17,920) Effect of projected future compensation levels (7,463) (5,098) - ----------------------------------------------------------------------------- Projected benefit obligation (29,894) (23,018) Plan assets at fair value, primarily common stocks and bonds 36,601 34,327 - ----------------------------------------------------------------------------- Plan assets in excess of projected benefit obligation 6,707 11,309 Unrecognized net gain (1,869) (6,904) Unrecognized net asset (1,318) (1,509) Unrecognized prior service cost 274 301 - ----------------------------------------------------------------------------- Prepaid pension cost $ 3,794 $ 3,197 =============================================================================
Net pension cost for 1993, 1992 and 1991 included the following components:
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Service costs (benefits earned during the period) $ 897 $ 805 $ 692 Interest cost on projected benefit obligation 1,999 1,768 1,527 Actual return on plan assets (2,819) (4,914) (6,947) Net amortization and deferral (673) 1,860 4,558 - ----------------------------------------------------------------------------- Net pension cost (credit) $ (596) $ (481) $ (170) =============================================================================
The Company also has a supplemental retirement plan which provides for certain pension benefits. Net pension cost recorded for this plan was $628,000 and $241,000 in 1993 and 1992, respectively. In 1993, this plan was funded with $1.2 million, resulting in an addition to prepaid pension cost of $331,000 at December 31, 1993. 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. The Company provides postretirement health care and life insurance benefits to eligible employees under two different plans. Employees become eligible for these benefits if they meet age and service requirements. Generally, the plans pay 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 1993 included the following components (in thousands): Service cost of benefits earned during the year $ 61 Amortization of transition amount 103 Interest cost on accumulated postretirement benefit obligation (APBO) 158 - ----------------------------------------------------------------------------- Net postretirement benefit cost $322 =============================================================================
The APBO as of December 31, 1993 was comprised of the following (in thousands): Retirees $ 655 Active participants, fully eligible 543 Other participants 835 - ----------------------------------------------------------------------------- Total APBO $2,033 =============================================================================
In determining the APBO, an assumed weighted average discount rate of 7.5% was used. An increase of 9.0% in the cost of covered health care benefits was assumed for 1994. This rate is assumed to decrease ratably to 7.0% over 8 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 1993 by $263,000 and the 1993 net postretirement benefit cost by $29,000. (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:
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Sales $ 79,374 $ 60,554 $ 49,392 Production (lifting) costs (6,341) (4,271) (4,077) Depreciation, depletion and amortization (25,686) (19,128) (13,843) - ----------------------------------------------------------------------------- 47,347 37,155 31,472 Income tax expense (18,081) (13,787) (11,819) - ----------------------------------------------------------------------------- Results of operations $ 29,266 $ 23,368 $ 19,653 =============================================================================
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 1993, 1992 and 1991:
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Property acquisition costs $ 5,920 $ 4,768 $ 5,385 Exploration costs 11,695 6,441 8,790 Development costs 19,722 19,563 16,134 - ----------------------------------------------------------------------------- Capitalized costs incurred $37,337 $30,772 $30,309 ============================================================================= Amortization per Mcf equivalent $.710 $.723 $.653 =============================================================================
The following table shows the capitalized costs of gas and oil properties and the related accumulated depreciation, depletion and amortization at December 31, 1993 and 1992:
1993 1992 - ----------------------------------------------------------------------------- (in thousands) Proved properties $350,854 $314,194 Unproved properties 24,427 23,868 - ----------------------------------------------------------------------------- Total capitalized costs 375,281 338,062 Less: Accumulated depreciation, depletion and amortization 146,471 120,842 - ----------------------------------------------------------------------------- Net capitalized costs $228,810 $217,220 =============================================================================
The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 1993. Included in property acquisition costs is $6.4 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.
1993 1992 1991 Prior Total - ----------------------------------------------------------------------------- (in thousands) Property acquisition costs $2,544 $612 $1,049 $7,424 $11,629 Exploration costs 1,253 153 193 277 1,876 Capitalized interest 918 185 300 1,861 3,264 - ----------------------------------------------------------------------------- $4,715 $950 $1,542 $9,562 $16,769 =============================================================================
(6) Natural Gas and Oil Reserves (Unaudited) The following table summarizes the changes in the Company's proved natural gas and oil reserves for 1993, 1992 and 1991:
1993 1992 1991 - ----------------------------------------------------------------------------- Gas Oil Gas Oil Gas Oil (MMcf) (MBbls)(MMcf) (MBbls) (MMcf)(MBbls) - ----------------------------------------------------------------------------- Proved reserves, beginning of year 312,291 359 307,484 505 304,511 773 Revisions of previous estimates (4,385) (26) 479 (30) (6,707) (123) Extensions, discoveries and other additions 46,069 250 29,627 4 29,563 33 Production (35,418) (96) (25,530)(120) (19,924) (176) Acquisition of reserves in place 222 - 231 - 129 - Disposition of reserves in place (3) (8) - - (88) (2) - ----------------------------------------------------------------------------- Proved reserves, end of year 318,776 479 312,291 359 307,484 505 ============================================================================= Proved, developed reserves: Beginning of year 246,904 337 226,767 467 234,001 763 End of year 260,240 469 246,904 337 226,767 467 =============================================================================
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, 1993, 1992 and 1991:
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Future cash inflows $ 745,967 $ 681,033 $ 643,157 Future production and development costs (85,609) (84,483) (82,811) Future income tax expense (236,170) (207,249) (196,811) - ----------------------------------------------------------------------------- Future net cash flows 424,188 389,301 363,535 10% annual discount for estimated timing of cash flows (196,913) (179,331) (165,261) - ----------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $ 227,275 $ 209,970 $ 198,274 =============================================================================
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 pre-tax 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 pre-tax 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 1993, 1992 and 1991:
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Standardized measure, beginning of year $209,970 $198,274 $196,354 Sales and transfers of gas and oil produced, net of production costs (73,017) (56,283) (45,315) Net changes in prices and production costs 22,392 9,446 (45,655) Extensions, discoveries and other additions, net of future production and development costs 74,511 52,917 29,322 Revisions of previous quantity estimates (5,217) 318 (6,405) Accretion of discount 31,885 30,253 30,033 Net change in income taxes (13,524) (4,623) (279) Changes in production rates (timing) and other (19,725) (20,332) 40,219 - ----------------------------------------------------------------------------- Standardized measure, end of year $227,275 $209,970 $198,274 =============================================================================
(7) Investment in Unconsolidated Partnership The Company holds a 47.33% general partnership interest in NOARK and is the pipeline's operator. NOARK is a 258 mile long intrastate gas transmission system which extends across northern Arkansas. NOARK's transportation capacity is 141 million cubic feet of gas per day (MMcfd). NOARK's main line was completed and placed in service in September, 1992. A lateral line of NOARK that allows the Company to augment its gas supply for existing markets as well as supply new markets was completed and placed in service in November, 1992. The Company's equity investment in NOARK totaled $5.3 million at December 31, 1993 and $7.0 million at December 31, 1992. The Company's share of NOARK's 1993 and 1992 pre-tax loss included in other income (expense) on the statements of income was $1.8 million and $.6 million, respectively. NOARK's financial position at December 31, 1993 and 1992 and its results of operations for the years then ended are summarized below:
1993 1992 - ----------------------------------------------------------------------------- (in thousands) Current assets $ 1,551 $ 1,503 Noncurrent assets 102,322 102,902 - ----------------------------------------------------------------------------- $103,873 $104,405 ============================================================================= Current liabilities $ 7,290 $ 5,406 Long-term debt 85,050 84,200 Partners' capital 11,533 14,799 - ----------------------------------------------------------------------------- $103,873 $104,405 ============================================================================= Operating revenues $ 8,301 $ 1,466 Pre-tax loss $ (3,778) $ (1,348) =============================================================================
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. See Note 12 for an explanation of NOARK's long-term debt and certain obligations related thereto. (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. 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, 1993 and 1992, were as follows:
1993 1992 ------------------ ------------------- Carrying Fair Carrying Fair Amount Value Amount Value - ----------------------------------------------------------------------------- (in thousands) Cash $834 $834 $1,122 $1,122 Customer deposits $3,927 $3,927 $3,510 $3,510 Long-term debt $127,000 $134,661 $143,335 $148,474 =============================================================================
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 and 1992 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, 1993, 1992 and 1991:
1993 1992 1991 - ----------------------------------------------------------------------------- (in thousands) Revenues Exploration and production $ 79,374 $ 60,554 $ 49,392 Gas distribution 131,892 117,495 121,302 Other 262 256 256 Eliminations (36,684) (34,475) (34,511) - ----------------------------------------------------------------------------- $174,844 $143,830 $136,439 - ----------------------------------------------------------------------------- Intersegment Revenues Exploration and production $ 36,091 $ 33,994 $ 34,098 Gas distribution 337 225 157 Other 256 256 256 - ----------------------------------------------------------------------------- $ 36,684 $ 34,475 $ 34,511 - ----------------------------------------------------------------------------- Operating Income Exploration and production $ 42,608 $ 33,071 $ 28,310 Gas distribution 15,261 13,094 14,027 Corporate expenses (305) (177) (195) - ----------------------------------------------------------------------------- $ 57,564 $ 45,988 $ 42,142 - ----------------------------------------------------------------------------- Identifiable Assets Exploration and production $236,968 $224,302 $210,593 Gas distribution 186,704 179,998 168,047 Other 21,782 22,875 13,568 - ----------------------------------------------------------------------------- $445,454 $427,175 $392,208 - ----------------------------------------------------------------------------- Depreciation, Depletion and Amortization Exploration and production $ 25,686 $ 19,128 $ 13,843 Gas distribution 4,564 4,213 3,978 Other 694 539 427 - ----------------------------------------------------------------------------- $ 30,944 $ 23,880 $ 18,248 - ----------------------------------------------------------------------------- Capital Additions Exploration and production $ 37,411 $ 30,823 $ 30,339 Gas distribution 19,892 12,188 7,856 Other 1,916 1,898 693 - ----------------------------------------------------------------------------- $ 59,219 $ 44,909 $ 38,888 =============================================================================
(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 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, 1993, there were options for 102,404 shares outstanding under the 1993 Plan at an option price of $17 1/8, representing the fair market value at the date of grant. The options vest to employees over a three-year period and expire ten years from the date of grant. Additionally, there were 17,447 shares of restricted stock 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, 1993, at prices ranging from $5.58 to $12.81. All options are currently exercisable. Options and SARs totaling 103,350 shares were exercised or canceled during 1993 at prices ranging from $5.58 to $10.60. 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, 1993, there were options for 48,000 shares outstanding at an option price of $17 1/2. (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 major general partner of NOARK are required to severally guarantee the availability of certain minimum cash balances to service $63.0 million of 9.7375% Senior Secured Notes used to finance a portion of NOARK's total construction cost. The notes have a remaining term of 16 years and the Company's share of the several guarantee is 60%. In 1993, NOARK also entered into an unsecured long-term revolving credit agreement in the amount of $30.0 million with a group of banks. At December 31, 1993, $25.2 million was outstanding under this credit arrangement. Amounts borrowed under the long-term revolving credit facility are severally guaranteed by the Company and an affiliate of the other major 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. 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 believes the suit is without merit and filed a counterclaim in February, 1994, 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 believes any funding which may be required for NOARK will not have a material effect on the financial condition or reported results of operations of the Company. 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. (13) Quarterly Results (Unaudited) The following is a summary of the quarterly results of operations for the years ended December 31, 1993 and 1992:
Quarter Ended March 31 June 30 September 30 December 31 - ----------------------------------------------------------------------------- (in thousands, except per share amounts) 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 1992 ----- Operating revenues $48,874 $25,125 $20,992 $48,839 Operating income $16,609 $5,228 $5,354 $18,797 Net income $8,795 $1,820 $1,769 $9,881 Earnings per share $.35 $.07 $.07 $.38 =============================================================================
FINANCIAL AND OPERATING STATISTICS
1993 1992 1991 1990 1989 1988 - --------------------------------------------------------------------------------------------------------- Financial Review (in thousands) Operating revenues: Exploration and production $ 79,374 $ 60,554 $ 49,392 $ 41,489 $ 40,499 $ 34,345 Gas distribution 131,892 117,495 121,302 108,911 117,514 89,277 Other 262 256 256 256 256 256 Intersegment revenues (36,684) (34,475) (34,511) (33,586) (33,670) (27,670) - --------------------------------------------------------------------------------------------------------- 174,844 143,830 136,439 117,070 124,599 96,208 - --------------------------------------------------------------------------------------------------------- Operating costs and expenses: Purchased gas costs 42,962 35,848 40,423 37,678 46,850 34,055 Operating and general 40,093 34,970 32,609 28,134 26,132 21,466 Depreciation, depletion and amortization 30,944 23,880 18,248 14,756 16,055 12,168 Taxes, other than income taxes 3,281 3,144 3,017 2,885 2,844 2,350 - --------------------------------------------------------------------------------------------------------- 117,280 97,842 94,297 83,453 91,881 70,039 - --------------------------------------------------------------------------------------------------------- Operating income 57,564 45,988 42,142 33,617 32,718 26,169 Interest expense, net (9,025) (9,983) (9,813) (10,530) (10,662) (8,049) Other income (expense) (1,657) (421) (107) (17) 180 46 - --------------------------------------------------------------------------------------------------------- Income before provision for income taxes 46,882 35,584 32,222 23,070 22,236 18,166 - --------------------------------------------------------------------------------------------------------- Provision for income taxes: Current 13,704 7,403 7,158 4,994 6,671 4,380 Deferred 6,128 5,916 4,999 3,568 1,586 2,254 - --------------------------------------------------------------------------------------------------------- 19,832 13,319 12,157 8,562 8,257 6,634 - --------------------------------------------------------------------------------------------------------- Income before extraordinary item and cumulative effect of accounting change 27,050 22,265 20,065 14,508 13,979 11,532 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 $ 37,176 $ 22,265 $ 20,065 $ 14,075 $ 13,979 $ 11,532 ========================================================================================================= Cash flow from operations (in thousands) $ 70,191 $ 49,730 $ 34,986 $ 36,495 $ 29,306 $ 20,030 Return on equity(1) 15.51% 14.53% 14.75% 11.66% 13.51% 12.25% Gross profit margin 32.92% 31.97% 30.89% 28.72% 26.26% 27.20% Net profit margin(1) 15.47% 15.48% 14.71% 12.02% 11.22% 11.99% ========================================================================================================= Common Stock Statistics(2) Earnings per share before extraordinary item and cumulative effect of accounting change $1.05 $.87 $.78 $.57 $.56 $.46 Earnings per share $1.44 $.87 $.78 $.56 $.56 $.46 Cash dividends declared and paid per share $.22 $.20 $.19 $.19 $.19 $.19 Book value per share $7.18 $5.97 $5.30 $4.70 $4.15 $3.77 Market price at year end $18.00 $12.96 $10.50 $10.42 $10.75 $6.00 Number of shareholders of record at year end 3,005 2,930 2,989 3,136 3,298 3,426 Average shares outstanding 25,684,110 25,683,963 25,678,011 25,270,674 24,940,488 24,940,488 ========================================================================================================= Capitalization (in thousands) Long-term debt, including current portion $127,000 $143,335 $134,104 $125,535 $128,449 $107,082 Common shareholders' equity 184,530 153,233 136,041 120,709 103,455 94,115 - --------------------------------------------------------------------------------------------------------- Total capitalization $311,530 $296,568 $270,145 $246,244 $231,904 $201,197 - --------------------------------------------------------------------------------------------------------- Total assets $445,454 $427,175 $392,208 $366,313 $347,212 $311,632 - --------------------------------------------------------------------------------------------------------- Capitalization ratios: Debt (excluding current portion) 40.19% 48.31% 49.08% 50.39% 54.82% 52.58% Equity 59.81% 51.69% 50.92% 49.61% 45.18% 47.42% ========================================================================================================= Capital Expenditures (in millions) Exploration and production $37.4 $30.8 $30.3 $23.4 $26.6 $14.0 Gas distribution 19.9 12.2 7.9 9.3 8.9 6.8 Other 1.9 1.9 .7 .7 3.5 .6 - --------------------------------------------------------------------------------------------------------- $59.2 $44.9 $38.9 $33.4 $39.0 $21.4 ========================================================================================================= (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.
1993 1992 1991 1990 1989 1988 - --------------------------------------------------------------------------------------------------------- Natural Gas and Oil Wells Completed Producers: Gross 57.0 69.0 25.0 25.0 38.0 48.0 Net 40.7 54.6 11.8 9.1 16.4 19.1 Dry holes: Gross 28.0 29.0 12.0 10.0 22.0 25.0 Net 14.5 19.5 4.1 2.1 7.3 3.1 - --------------------------------------------------------------------------------------------------------- Total: Gross 85.0 98.0 37.0 35.0 60.0 73.0 Net 55.2 74.1 15.9 11.2 23.7 22.2 At the end of 1993, the Company was a participant in 5.0 (1.1 net) wells in process. ========================================================================================================= Natural Gas and Oil Produced Natural gas: Production, Bcf 35.4 25.5 19.9 16.4 15.3 12.0 Average price per Mcf $2.18 $2.26 $2.26 $2.33 $2.43 $2.61 Oil: Production, MBbls 96 120 176 112 148 160 Average price per barrel $17.20 $19.75 $20.67 $22.89 $17.89 $14.58 Average production (lifting) cost per Mcf equivalent $.18 $.16 $.19 $.16 $.14 $.25 Proved reserves at year end: Natural gas, Bcf 318.8 312.3 307.5 304.5 252.9 216.0 Oil, MBbls 479 359 505 773 745 911 ========================================================================================================= Utility Operating Data(1) Sales volumes, Bcf: Residential 12.9 10.8 10.9 10.1 11.6 8.4 Commercial 7.8 6.6 6.7 6.3 7.1 5.4 Industrial 6.1 6.1 9.5 10.2 9.8 7.9 Transportation volumes, Bcf End users 5.6 5.2 1.3 .1 .5 .5 Off-system 11.7 2.5 .2 .3 .1 1.5 - --------------------------------------------------------------------------------------------------------- 44.1 31.2 28.6 27.0 29.1 23.7 - --------------------------------------------------------------------------------------------------------- Average sales customers: Residential 137,087 133,103 129,379 127,142 125,581 100,846 Commercial 18,511 18,141 17,880 17,680 17,437 14,060 Industrial 346 348 370 366 372 330 - --------------------------------------------------------------------------------------------------------- 155,944 151,592 147,629 145,188 143,390 115,236 - --------------------------------------------------------------------------------------------------------- Sales and transportation revenues (in thousands): Residential $ 67,502 $ 59,747 $ 58,372 $ 48,407 $ 54,181 $38,790 Commercial 35,311 31,425 30,718 27,535 30,522 22,742 Industrial 21,757 20,502 29,187 30,463 29,982 24,646 Transportation 5,177 3,597 857 179 368 349 - --------------------------------------------------------------------------------------------------------- $129,747 $115,271 $119,134 $106,584 $115,053 $86,527 - --------------------------------------------------------------------------------------------------------- Miles of pipe: Gathering 398 383 375 371 364 360 Transmission 1,335 1,321 1,326 1,326 1,309 1,296 Distribution 4,160 4,090 4,002 3,931 3,859 3,794 - --------------------------------------------------------------------------------------------------------- 5,893 5,794 5,703 5,628 5,532 5,450 - --------------------------------------------------------------------------------------------------------- Degree days 4,929 4,104 4,095 3,972 4,961 4,697 Percent of normal 113% 92% 93% 90% 112% 106% ========================================================================================================= (1)Includes operating data of Associated since acquisition in June, 1988.
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 25, 1994, 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 & Co. 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 1993 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 ------------------------------------- -------------------- 1993 1992 1993 1992 - ------------------------------------------------------------------------------ High Low High Low March 31 $15.25 $12.13 $11.17 $9.38 $.05 $.05 June 30 $16.83 $14.13 $11.04 $9.25 $.05 $.05 September 30 $21.75 $16.04 $12.42 $10.04 $.06 $.05 December 31 $21.88 $15.13 $13.96 $11.92 $.06 $.05 ==============================================================================
Market prices represent transactions on the New York Stock Exchange. Southwestern Energy Company and Subsidiaries APPENDIX TO 1993 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 47.33% 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 164,750 88,030 282,336 138,799 632 338.3 Louisiana 15,428 7,783 10,217 2,842 7 3.1 Oklahoma 23,133 17,992 28,726 11,437 122 24.7 Texas 21,539 7,591 50,185 11,192 27 5.7 Other areas 9,316 6,984 5,417 1,385 19 5.2 - --------------------------------------------------------------------------- 234,166 128,380 376,881 165,655 807 377.0 ===========================================================================
GAS DISTRIBUTION SYSTEMS MILES OF PIPE
AWG Associated Total - --------------------------------------------------------------------------- Gathering 398 -- 398 Transmission 739 596 1,335 Distribution 2,625 1,535 4,160 - --------------------------------------------------------------------------- 3,762 2,131 5,893 ===========================================================================
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