-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, V34SzCw5FhmvC1iccTbcNGxoH1ZsaNKy4jYFcYxYKl0cHhiglsJTv+cK5SKzYIx9 46B66/wbrcV0wcOq4I1j7Q== 0000007332-02-000034.txt : 20020415 0000007332-02-000034.hdr.sgml : 20020415 ACCESSION NUMBER: 0000007332-02-000034 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020329 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHWESTERN ENERGY CO CENTRAL INDEX KEY: 0000007332 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 710205415 STATE OF INCORPORATION: AR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-08246 FILM NUMBER: 02592358 BUSINESS ADDRESS: STREET 1: 2350 N. SAM HOUSTON PARKWAY EAST STREET 2: SUITE 300 CITY: HOUSTON STATE: TX ZIP: 77032 BUSINESS PHONE: 2816184700 FORMER COMPANY: FORMER CONFORMED NAME: ARKANSAS WESTERN GAS CO DATE OF NAME CHANGE: 19790917 10-K405 1 swn0329200210k.txt 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 For the fiscal year ended December 31, 2001 ----------------- or ( ) Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ____________ to ____________ Commission file number 1-8246 Southwestern Energy Company (Exact name of Registrant as specified in its charter) Arkansas 71-0205415 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 2350 N. Sam Houston Parkway East, Suite 300, Houston, Texas 77032 (Address of principal executive offices, including zip code) Registrant's telephone number, including area code: (281) 618-4700 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on 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 $278,979,412 based on the New York Stock Exchange -- Composite Transactions closing price on March 7, 2002, of $11.19. The number of shares outstanding as of March 7, 2002, of the Registrant's Common Stock, par value $.10, was 25,502,070. DOCUMENTS INCORPORATED BY REFERENCE Document incorporated by reference and the Part of the Form 10-K into which the document is incorporated: 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 15, 2002 - PART III. ================================================================================
TABLE OF CONTENTS Part I pg Item 1 Business 3 Business strategy 3 Exploration and production 3 Natural gas distribution 9 Marketing and transportation 12 Other items 13 Item 2 Properties 13 Item 3 Legal proceedings 15 Item 4 Submission of matters to a vote of security holders 15 Executive officers of the registrant 15 Part II Item 5 Market for registrant's common equity and related stockholder matters 17 Item 6 Selected financial data 18 Item 7 Management's discussion and analysis of financial condition and results of operations 20 Item 7A Quantitative and qualitative disclosure about market risks 29 Item 8 Financial statements and supplementary data 31 Item 9 Changes in and disagreements with accountants on accounting and financial disclosure 50 Part III Item 10 Directors and executive officers of the registrant 51 Item 11 Executive compensation 51 Item 12 Security ownership of certain beneficial owners and management 51 Item 13 Certain relationships and related transactions 51 Part IV Item 14 Exhibits, financial statement schedules, and reports on Form 8-K 51
2 Part I ITEM 1. BUSINESS Southwestern Energy Company (the "Company" or "Southwestern") is an energy company primarily focused on natural gas. The Company was incorporated in Arkansas in 1929 as a local gas distribution company. Today, Southwestern is an exempt holding company under the Public Utility Holding Company Act of 1935 and derives the vast majority of its operating income and cash flow from its oil and gas exploration and production business. In February 2001, the Company relocated its corporate headquarters from Fayetteville, Arkansas to Houston, Texas. The Company is involved in the following business segments: 1.Exploration and Production - Engaged in natural gas and oil exploration, development and production, with operations principally located in Arkansas, Oklahoma, Texas, New Mexico, and Louisiana. This represents the Company's primary business. 2.Natural Gas Distribution - Engaged in the gathering, distribution and transmission of natural gas to approximately 136,000 customers in Arkansas. 3.Marketing and Transportation - Provides marketing and transportation services in the Company's core areas of operation and owns a 25% interest in the NOARK Pipeline System, Limited Partnership (NOARK). This Report on Form 10-K includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of this Report for a discussion of factors that could cause actual results to differ materially from any such forward-looking statements. Business Strategy The Company's business strategy is to provide long-term growth through focused exploration and production of oil and natural gas. The Company seeks to maximize cash flow and earnings and provide consistent growth in oil and gas production and reserves through the discovery, production and marketing of high margin reserves from a balanced portfolio of drilling opportunities. This balanced portfolio includes low-risk development drilling in the Arkoma Basin and East Texas, moderate-risk exploration and exploitation in the Permian Basin, and high-potential exploration opportunities in the onshore Gulf Coast region. The Company further enhances shareholder value by creating and capturing additional value beyond the wellhead through its natural gas distribution, marketing and transportation activities. EXPLORATION AND PRODUCTION 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's requirements. Since that time, Southwestern's exploration and development activities outside Arkansas have expanded substantially. [map showing the states of Arkansas, Louisiana, Texas, Oklahoma and New Mexico with the following areas identified: Arkoma Basin with the Company's Gas distribution system and Ozark Pipeline, Anadarko Basin, Permian Basin, East Texas Overton Field and Gulf Coast] In 1998, Southwestern brought in new senior management for its exploration and production business and has since replaced over 70% of its professional technical staff to refocus its exploration and production effort. Additionally in 1998, the Company closed its Oklahoma City office and moved these operations to Houston in an effort to increase future profitability. The segment was also reorganized into asset management teams to provide an area-specific focus in exploration and 3 development projects and a new incentive compensation system was put in place to more closely align its employees' efforts with the interests of its shareholders. As a result of these changes, the operating results of this business segment have improved substantially over the last few years and, in 2001, the segment set new records for oil and gas production, reserve additions, operating income and cash flow generated from operations. At December 31, 2001, the Company had proved oil and gas reserves of 402.0 billion cubic feet (Bcf) equivalent, including proved natural gas reserves of 355.8 Bcf and proved oil reserves of 7,704 thousand barrels (MBbls). The Company's reserve life index approximated 10.1 years at year-end 2001, with 80% of total reserves classified as proved, developed. All of the Company's reserves are located entirely within the United States. Revenues of the exploration and production subsidiaries are predominately generated from production of natural gas. Sales of gas production accounted for 89% of total operating revenues for this segment in 2001, 82% in 2000, and 87% in 1999. Areas of Operation Southwestern engages in oil and gas exploration and production through its wholly-owned subsidiaries, SEECO, Inc. (SEECO), Southwestern Energy Production Company (SEPCO) and Diamond "M" Production Company (Diamond M). 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 part of the Arkoma Basin. SEPCO conducts development drilling and exploration programs in the Oklahoma portion of the Arkoma Basin, the Permian Basin of Texas and New Mexico, the Anadarko Basin of Oklahoma, and in Louisiana and Texas. Diamond M operates properties in the Permian Basin of Texas. A wholly-owned subsidiary of SEPCO, Overton Partners, L.L.C., owns an interest in Overton Partners, L.P., a limited partnership formed in 2001 to drill and complete the first 14 development wells in SEPCO's Overton Field in East Texas. Southwestern replaced 224% of its production in 2001 by adding an estimated 89.3 Bcf equivalent (Bcfe) of proved oil and gas reserves at a finding and development cost of $1.11 per thousand cubic feet equivalent (Mcfe), excluding reserve revisions. The Company's finding cost including the effect of downward reserve revisions due to lower year-end commodity prices was $1.60 per Mcfe in 2001. Southwestern's three-year average finding and development cost was $1.22 per Mcfe, including reserve revisions. The following table provides information as of December 31, 2001 related to proved reserves, well count, and gross and net acreage, and 2001 annual information as to production, reserve additions and capital expenditures for each of the Company's core operating areas.
Texas/ Arkoma Mid-Continent New Mexico Louisiana Total ------------------------------------------------------- Proved reserves: Gas (Bcf) 186.0 28.1 106.9 34.8 355.8 Oil (MBbls) - 1,426 5,017 1,261 7,704 Total reserves (Bcfe) 186.0 36.6 137.0 42.4 402.0 Production (Bcfe) 22.3 2.8 9.9 4.8 39.8 Reserve additions (Bcfe) 23.2 8.6 43.2 14.3 89.3 Capital expenditures (in millions) $ 28.6 $ 0.9 $ 44.9 $ 24.6 $ 99.0 Total gross wells 806 551 445 32 1,834 Percent operated 44% 29% 39% 66% 39% Gross acreage 348,143 62,168 377,863 150,992 939,166 Net acreage 237,511 6,629 114,740 87,526 446,406
Arkoma Basin. The Arkoma Basin provides a solid foundation for the Company's exploration and production program and represents the primary source of production and reserves for the Company. At December 31, 2001, the Company had approximately 186.0 Bcf of natural gas reserves in the Arkoma Basin, representing 52% of the Company's natural gas reserves and 46% of total reserves on a Bcf equivalent basis. The Company participated in 52 wells during 2001 with an 81% success ratio. Southwestern's Arkoma program added 23.2 Bcf of gas reserves at a finding and development cost of $1.23 per thousand cubic feet (Mcf) in 2001. The Company's natural gas production in the basin was 22.3 Bcf, a 12% increase over production levels in 2000. Until 2001, Southwestern had experienced declining production in the Arkoma over the past eight years. Average net daily production in 2001 was 61.1 million cubic feet (MMcf/d). Southwestern's Arkoma Basin operations continue to generate a significant amount of the Company's cash flow. With average three-year finding and development costs of $1.05 per Mcf and three-year average production, or lifting, costs of $.26 per Mcf (including production taxes), the Company's cash margins per well in the Arkoma remain very attractive. 4 Lifting costs continued to be low during 2001 at $.32 per Mcf (including production taxes). After direct general and administrative expenses of $.14 per Mcf, Southwestern's netback per Mcf after cash expenses was 89% of the average price it realized for its Arkoma production in 2001, including the impact of commodity hedges. Southwestern's traditional operating area over the years has been in the "fairway" portion of the basin in Arkansas, which is primarily within the boundaries of the Company's utility gathering system. The Company's strategy in this core producing area is to delineate new geologic plays and extend previously identified trends using Southwestern's extensive databank of regional structural and stratigraphic maps. Southwestern completed 14 wells out of 18 drilled in the fairway in 2001 that added 8.3 Bcf of new reserves. Southwestern plans to drill up to 15 wells in the fairway portion of the basin in 2002. In recent years, Southwestern has extended its development program outside of the traditional fairway area to continue its growth. During 2001, the Company continued the development of its Haileyville prospect in Pittsburg County, Oklahoma, with excellent results. Since initial drilling in the area in 1999, Southwestern has successfully completed 13 out of 20 wells drilled. In 2001, Southwestern encountered high-deliverability gas sands in the prospect which resulted in two wells, the Agnes #1-18 and the Cope #3A, separately producing at gross rates of over 20 MMcf/d. Total production at Haileyville was 3.0 Bcf net to Southwestern in 2001 and the prospect added a net of approximately 5.0 Bcf of new gas reserves from six wells. Southwestern's average working interest in the prospect is approximately 35%. In 2001, the Company also continued the development of its Ranger Anticline prospect area, located at the southern edge of the Arkansas portion of the basin. To date, the Company has successfully drilled 10 out of 14 wells in this prospect, adding 12.4 Bcf of reserves net to Southwestern's interest at a finding cost of $.69 per Mcf. In 2001, the Company drilled the Catlett #1-13 well which was placed on production at 2.2 MMcf/d with an 80% working interest, resulting in new reserves of 2.7 Bcf. The Catlett #1-13 well is an example of the continued successful development of this complex overthrust play. The Company also plans to begin testing new exploration prospect areas on the southern edge of the basin similar to its Ranger Anticline play. Additionally, during 2001 the Company initiated an extensive workover program in the Arkoma, which included fracture stimulations, artificial lift, recompletion and wellbore repair projects that provided meaningful production increases. The Company performed 55 of these workover projects in 2001 resulting in production increases totaling 4.4 MMcf/d, at a total cost of $1.4 million. The Company's strategy for the Arkoma is to continue its exploitation drilling and workover programs at a level to maintain its production and reserve base. In 2002, Southwestern plans to invest approximately $18.5 million in the basin to drill approximately 40 wells and perform approximately 50 workovers. Mid-Continent. Southwestern's activities in this region are primarily focused on the Anadarko Basin of Oklahoma. At December 31, 2001, the Company had approximately 28.1 Bcf of natural gas reserves and 1,426 MBbls of oil reserves in the region, representing 8% and 19%, respectively, of the Company's total gas and oil reserves. Average net daily production in 2001 for this region was 7.7 MMcf equivalent (MMcfe). Southwestern does not expect its Mid-Continent operations to be a primary area of future growth due to its efforts to concentrate on those areas where it has a competitive advantage. The Company intends to produce these properties to depletion, sell them or trade them for properties in the Company's core areas of operation. During 2000, the Company sold at auction a portion of its properties in the Mid-Continent area with proved reserves of 13.8 Bcfe for approximately $13.1 million. Texas/New Mexico. Southwestern has key operations in the states of Texas and New Mexico, and is primarily focused on its Overton Field in East Texas, and the Permian Basin in West Texas and Southeast New Mexico. At December 31, 2001, Southwestern had proved reserves of 106.9 Bcf of gas and 5,017 MBbls of oil in the region, representing 30% and 65%, respectively, of the Company's total gas and oil reserves. Overton Field. In April 2000, the Company purchased the Overton Field in Smith County, Texas, from Total Fina Elf for $6.1 million. Estimated initial reserves associated with the purchase were 7.5 Bcfe, for a purchase price of $.81 per Mcfe. The purchase included 16 active gas wells in 13 spacing units, 8,800 contiguous acres in established units and 2,000 additional undeveloped acres outside the units. Overton provides the Company with a low-risk multi-year drilling program and significant production and reserve growth potential. This is due to the level of infill drilling that is possible in the field over the next several years. When purchased by Southwestern in April of 2000, the field was primarily drilled on 640-acre spacing, or one well per square mile. Analogous Cotton Valley fields in the area have been drilled to 80-acre spacing. By downspacing the field to 80-acre spacing, Southwestern could have an additional 90 drilling locations. During 2001, Southwestern's subsidiary, SEPCO, formed a limited partnership, Overton Partners, L.P., with an investor to drill and complete the first 14 development wells at Overton. This partnership was created to accelerate the development of the field. SEPCO is the partnership's General Partner and contributed 50% of the capital required to drill the first 14 wells. 5 In return, SEPCO receives 65% of the partnership's available cash distributions prior to payout of the investor's initial investment and 85% of the partnership's available cash distributions after payout. Production and reserve statistics for Overton include 100% of the partnership's activity, and all operating and financial results are incorporated into the Company's consolidated financial statements. Southwestern drilled a total of 15 wells at its Overton Field during 2001, including 14 development wells in the Overton limited partnership. The wells targeted the Cotton Valley Taylor sand formation at approximately 12,000 feet and all 15 wells were successful. Daily production at Overton increased from 2 MMcfe in March of 2001 to approximately 16 MMcfe at year-end, resulting in production of 2.3 Bcfe net to Southwestern during 2001. The Company's average production cost at Overton was $.53 per Mcfe in 2001. Southwestern's proved reserves at Overton increased to 57.6 Bcfe at year-end 2001, up from 22.0 Bcfe at the end of 2000. The Company invested approximately $30.9 million in its drilling program at Overton during 2001, including $13.5 million funded by the owner of the minority interest in the Overton partnership. The capital investments resulted in reserve additions of 37.8 Bcfe, for a finding and development cost of $.82 per Mcfe. Southwestern's average working interest in the field is 97% and average net revenue interest is 80%. Southwestern expanded its position in the Overton area during 2001 through a farm-in of approximately 5,800 adjacent acres. The acreage contains nine 640-acre units, most of which have only been drilled to 640-acre spacing. The Company has contracted to drill a minimum of two wells on this acreage in 2002. In total, Southwestern plans to invest approximately $12 million to drill 5 to 10 wells in the Overton Field area during 2002. Permian Basin. Since 1997, Southwestern has established a growing presence in the Permian Basin. At December 31, 2001, Southwestern had proved reserves of 33.5 Bcf of gas and 4,251 MBbls of oil in the basin, or 59.0 Bcfe. The Company successfully completed 19 out of 26 wells drilled in the Permian in 2001, resulting in a success rate of 73%. Southwestern's average working interest in these wells was approximately 43%. Average net daily equivalent production in the basin was 17.0 MMcfe and production costs, including production taxes, averaged $.67 per Mcfe during 2001. In 2001, the Company invested $13.6 million in the Permian, resulting in reserve additions of 5.4 Bcfe for a finding and development cost of $2.52 per Mcfe. Southwestern's three-year average finding and development cost in the Permian is $1.33 per Mcfe and three-year average reserve replacement ratio is 197%. Southwestern had a meaningful discovery during 2001 at its Roepke prospect in Crane County, Texas. The discovery well, the Cowden Ranch 48 #7, encountered approximately 87 feet of oil-bearing pay in the Upper and Lower Devonian formations. This well, along with two other successful wells on the prospect, added net reserves of 3.3 Bcfe in 2001, and has set up additional development wells planned for 2002. In late 1999, the Company entered into a joint exploration agreement with Phillips Petroleum to explore for deeper formations under acreage that is held-by-production in Southeast New Mexico. This initial joint venture agreement spawned the development of two more joint exploration agreements that were consummated in late 2000, one with Energen Resources and a second agreement with Phillips. In total, these agreements provide the Company access to an additional 98,700 gross acres to pursue drilling opportunities. Under the agreements, Phillips and Energen have a deferred election at casing point, allowing them to retain a pre-specified working interest share. These agreements have terms ranging from 12 to 21 months, with continuous drilling options thereafter. To date, the Company has successfully drilled 18 out of 21 wells under these joint ventures and four wells are scheduled to be drilled under the agreements in 2002. The Company plans to continue to pursue its strategy of medium-risk exploration and exploitation in the Permian Basin, albeit at a slower pace. Southwestern plans to invest approximately $8.0 million in the Permian in 2002, which includes drilling up to 14 wells. Louisiana. South Louisiana continues to be the main focus area of the Company's exploration activities. At December 31, 2001, Southwestern had proved reserves of 34.8 Bcf of gas and 1,261 MBbls of oil in the state, representing 11% of the Company's total reserves on a gas equivalent basis. Average net daily production in this area was 13.2 MMcfe and production costs (including production taxes) averaged $.58 per Mcfe during 2001. The Company invested $24.6 million in the area in 2001 and added 14.3 Bcfe of proved reserves for a finding and development cost of $1.72 per Mcfe. Southwestern's three-year average finding and development cost in Louisiana is $1.65 per Mcfe and its three-year reserve replacement ratio is 484%. Southwestern's exploration success continued in 2001 with three meaningful discoveries in South Louisiana. Since the first exploration discovery at the Company's Gloria prospect in December 1999, Southwestern has posted an impressive track record in the area with six successful wells out of the last nine drilled in South Louisiana. In January 2001, Southwestern announced a discovery at its Malone prospect, located five miles south of the Company's Gloria discovery in Assumption Parish. The discovery well SL 16626 #1 encountered approximately 260 feet of gas pay in five separate productive sands within the Miocene formation. After drilling the initial discovery well, Southwestern immediately drilled an offset development well on the prospect that reached total depth in February 2001. Both wells are producing at a combined gross rate of 27.0 MMcf/d and 525 barrels of oil per day (Bopd). Southwestern is the operator of the wells and holds a 33% working interest and a 24.3% net revenue interest in the prospect. 6 After drilling dry holes at its Whitehorse and Mahone prospects, the Company made another gas discovery in its Eden 3-D project area. The Mire #1 well on the Company's Horeb prospect in Acadia Parish penetrated 50 feet of pay in the Nonion Struma sand at approximately 12,100 feet. This well was placed on production in November 2001 and is currently producing 12.6 MMcf/d and 160 Bopd. Southwestern operates the Mire well with a 21.5% working interest and a 16.4% net revenue interest. In December 2001, the Company announced a discovery at its Crowne Prospect located in Cameron Parish, Louisiana. The Miami Corporation #27-1 well encountered 75 feet of pay in the targeted Planulina objective. The well was placed on production in February 2002 at 10.0 MMcf/d and 35 Bopd. Southwestern has spud a second well, the Miami Corporation #34-2, to further delineate and develop the reservoir. Southwestern is the operator of these wells with a 40% working interest and a 28.8% net revenue interest. In February 2002, the Company announced that it had reached total depth on the Raymond Egle #1, a development well on its North Grosbec discovery. After overcoming significant mechanical problems during the drilling of this well, it was placed on production at 20.0 MMcf/d and 800 Bopd. The discovery well, the Brownell-Kidd #1, continues to deliver at high rates since being placed on production in May 2000 and is currently producing at 15.0 MMcf/d and 550 Bopd. These wells are operated by Petro-Hunt, L.L.C., and Southwestern holds a 25% working interest and a 17.4% net revenue interest in the prospect. The Company has an extensive inventory of 3-D seismic data covering over 1,470-square miles in Louisiana. From this extensive 3-D database, Southwestern has internally generated an inventory of exploration prospects. The Company also continues to gain exposure to additional 3-D seismic data for future drilling opportunities, including a new 3-D shoot currently underway covering approximately 140-square miles in a highly prospective region in St. Martin and St. Mary Parishes. Southwestern is the operator of the new project with a 40% working interest. The seismic data is expected to be delivered in the third quarter of 2002. In 2002, the Company plans to invest approximately $22.7 million in the Gulf Coast region and drill up to eight exploration wells. Acquisitions In 2001, Southwestern purchased proved reserves of 4.5 Bcfe for $6.5 million, or $1.46 per Mcfe. Included were overriding royalty interests in the Arkoma Basin of 2.2 Bcfe, and 1.9 Bcfe of additional working interest in the Company's Overton Field. In April 2000, the Company purchased the Overton Field in Smith County, Texas, from Total Fina Elf for $6.1 million. Proved developed producing reserves associated with the purchase were 7.5 Bcfe, for a purchase price of $.81 per Mcfe. The purchase included 16 active gas wells in 13 spacing units, 8,800 contiguous acres in established units and 2,000 additional undeveloped acres outside the units. As discussed previously, Southwestern believes the Overton Field contains significant development potential. In 1999, the Company purchased producing properties in the Permian Basin with estimated proved reserves of 9.4 Bcf of gas and 576 MBbls of oil, or 12.9 Bcfe. The properties were purchased from Petro-Quest Exploration, a privately held company headquartered in Midland, Texas, for $9.4 million. The Company did not make any producing property acquisitions in 1998 or 1997. In 1996, the Company acquired approximately 32.7 Bcf of gas and 6,350 MBbls of oil located in Texas and Oklahoma for $45.8 million. The Company's current strategy is to pursue selective acquisitions where it sees further potential and that complement its existing operations. Capital Spending Southwestern invested a total of $99.0 million in its exploration and production program during 2001, including $13.5 million funded by the owner of the minority interest in the Overton partnership. Southwestern participated in drilling 101 wells during 2001, of which 80 were successful, 19 were dry and two were still in progress at year-end. The Company's investments were balanced between its core areas of operations, with approximately $28.6 million invested in the Arkoma Basin, $30.9 million at Overton Field in East Texas, $13.6 million in the Permian Basin, and $24.6 million in South Louisiana. Approximately $20.6 million was invested in exploratory tests, $57.2 million in development drilling and workovers, $4.2 million for the acquisition of leasehold and seismic data, $6.5 million for producing property acquisitions and $10.5 million in capitalized interest and expenses and other technology-related expenditures. In 2002, the Company's planned capital budget for exploration and production is $61.3 million, and a large percentage of this capital, approximately 67%, is allocated to drilling. As in 2001, the Company's investments will again be balanced between its core areas of operations, with approximately 50% of the Company's capital allocated to lower-risk development drilling activities in the Arkoma Basin ($18.5 million) and East Texas ($12.1 million). The remainder of Southwestern's capital will be allocated to medium-risk exploration and exploitation in the Permian Basin ($8.0 million) and to high-potential exploration in the Gulf Coast ($22.7 million). Of the $61.3 million capital budget, approximately $11.4 million is allocated to exploration wells, $29.9 million to development drilling, $4.3 million for land and leasehold acquisition, $3.9 million for 7 seismic expenditures, and $11.8 million in capitalized interest and expenses and technology-related items. Although no capital was budgeted for acquisitions in 2002, the Company will continue to seek producing property transactions in its core producing areas that would complement its overall strategy. The Company expects to maintain its capital investments within the limits of internally generated cash flow, and will adjust its capital program accordingly. Sales and Major Customers Daily natural gas equivalent production averaged 109.0 MMcfe in 2001, compared to 97.7 MMcfe in 2000 and 90.2 MMcfe in 1999. The Company's gas production was 35.5 Bcf in 2001, compared to 31.6 Bcf in 2000 and 29.4 Bcf in 1999. The Company also produced 719,000 barrels of oil in 2001, compared to 676,000 barrels of oil in 2000 and 578,000 barrels in 1999. Southwestern is targeting its production in 2002 to be approximately 42 Bcfe. The Company realized an average wellhead price of $3.85 per Mcf for its natural gas production in 2001, compared to $2.88 per Mcf in 2000 and $2.21 per Mcf in 1999. The Company's average oil price realized was $23.55 per barrel in 2001, compared to $22.99 per barrel in 2000 and $17.11 per barrel in 1999. Southwestern's gas sales to unaffiliated purchasers were 30.4 Bcf in 2001, compared to 23.8 Bcf in 2000 and 21.2 Bcf in 1999. All of the Company's oil production is sold to unaffiliated purchasers. This gas and oil production is sold under contracts which reflect current short-term prices and which are subject to seasonal price swings. These combined gas and oil sales accounted for 83% of total exploration and production revenues in 2001, 76% in 2000 and 69% in 1999. Southwestern's largest single customer for sales of its gas production is the Company's utility subsidiary, Arkansas Western Gas Company (Arkansas Western). These sales are made by SEECO, Inc. (SEECO) primarily under contracts obtained under a competitive bidding process. See "Natural Gas Distribution - Gas Purchases and Supply" below for further discussion of these contracts. Sales to Arkansas Western accounted for approximately 17% of total exploration and production revenues in 2001, 24% in 2000 and 31% in 1999. SEECO's sales to Arkansas Western were 5.1 Bcf in 2001, compared to 7.8 Bcf in 2000 and 8.2 Bcf in 1999. The decrease in sales in 2001 was primarily caused by Arkansas Western's reduced supply requirements due to warmer weather and the sale of the utility's Missouri gas distribution properties in May 2000. Weather in 2001, as measured in degree days, was 9% warmer than both normal and the prior year for Arkansas Western's service territory. Weather was normal in 2000 and 21% colder than 1999; however, sales to Arkansas Western decreased in 2000 due to the sale of the utility's Missouri properties. SEECO's gas production provided approximately 33% of the utility's requirements in 2001, 42% in 2000 and 41% in 1999. SEECO also owns an unregulated natural gas storage facility that has historically been utilized to help meet its peak seasonal sales commitments. The storage facility is connected to Arkansas Western's distribution system. Future sales to Arkansas Western's gas distribution systems will be dependent upon the Company's success in obtaining gas supply contracts with the utility systems. In the future, the Company's subsidiaries will continue to bid to obtain these gas supply contracts, although there is no assurance that it will be successful. If successful, the Company cannot predict the amount of premium that would be associated with the new contracts. Southwestern expects future increases in its gas production to come primarily from sales to unaffiliated purchasers. The Company 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 amount of undeveloped leasehold acreage and producing acreage, and has an inventory of drilling leads, prospects and seismic data that will continue to be evaluated and developed in the future. The Company's exploration programs have been directed primarily toward natural gas in recent years. The Company periodically enters into hedging activities with respect to a portion of its projected crude oil and natural gas production through a variety of financial arrangements intended to support oil and gas prices at targeted levels and to minimize the impact of price fluctuations. The Company's policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. At December 31, 2001, the Company had hedges in place on 32.3 Bcf of future gas production. Subsequent to December 31, 2001 and prior to March 13, 2002, the Company hedged 4.0 Bcf of 2002 gas production under costless collars with floor prices ranging from $2.25 to $2.50 per Mcf and ceiling prices ranging from $3.00 to $3.75 per Mcf, and entered into a collar on 4.0 Bcf of 2003 gas production with a $3.00 per Mcf floor and a $4.75 per Mcf ceiling. Fixed price swaps on 2.5 Bcf of 2002 gas production have a weighted average fixed price receipt of $2.61 per Mcf. The Company also hedged 277,500 barrels of 2002 oil production at a fixed West Texas Intermediate crude price of $20.07 per barrel. The Company currently has hedges in place on approximately 65% of its targeted 2002 gas production and approximately 40% of its 2002 targeted oil production. See Item 7A of this Form 10-K, "Quantitative and Qualitative Disclosures About Market Risk," for further information regarding the Company's hedge position at December 31, 2001. Disregarding the impact of hedges, the Company expects the average price it receives for its gas production to be approximately $.05 to $.10 per Mcf lower than average spot market prices, as market differentials that reduce the average prices received are partially offset by demand charges it receives under the contracts covering its intersegment sales 8 to Arkansas Western. Disregarding the impact of hedges, the Company expects the average price it receives for its oil production to be approximately $1.00 per barrel lower than average spot market prices, as market differentials reduce the average prices received. Competition All phases of the gas and oil industry are highly competitive. Southwestern competes in the acquisition of properties, the search for and development of reserves, the production and sale of gas and oil and the securing of the labor and equipment required to conduct operations. Southwestern's competitors include major gas and oil companies, other independent gas and oil concerns and individual producers and operators. Many of these competitors have financial and other resources that substantially exceed those available to Southwestern. Gas and oil producers also compete with other industries that supply energy and fuel. Competition in the state of Arkansas has increased in recent years, due largely to the development of improved access to interstate pipelines. Due to the Company's significant leasehold acreage position in Arkansas and its long-time presence and reputation in this area, the Company believes it will continue to be successful in acquiring new leases in Arkansas. While improved intrastate and interstate pipeline transportation in Arkansas should increase the Company's access to markets for its gas production, these markets will generally be served by a number of other suppliers. Thus, the Company will encounter competition that may affect both the price it receives and contract terms it must offer. Outside Arkansas, the Company is less 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 in Oklahoma, Texas, New Mexico and Louisiana. NATURAL GAS DISTRIBUTION The Company's subsidiary, Arkansas Western Gas Company, operates integrated natural gas distribution systems concentrated primarily in North Arkansas. The Arkansas Public Service Commission (APSC) regulates the Company's utility rates and operations. Arkansas Western serves approximately 136,000 customers and obtains a substantial portion of the gas they consume through its Arkoma Basin gathering facilities. [map showing the state of Arkansas detailing the utility service areas concentrated in the Northern portion of the state and the location of the Ozark Gas Transmission system] On May 31, 2000, the Company completed the sale of its Missouri gas distribution assets for $32.0 million. The sale resulted in a pretax gain of approximately $3.2 million and proceeds from the sale were used to pay down debt. The gas distribution statistics discussed below include the results from the Company's Missouri utility operations through May 2000. In June 2000, Southwestern announced it would pursue the sale of its utility operations in Arkansas to fund a $109.3 million judgment against the Company (Hales judgment). The Company hired Morgan Stanley Dean Witter as its investment advisor to manage the sale process and the Company received several serious expressions of interest from bona fide parties. However, the Company did not receive an offer that it believed reflected the true value of the utility system. Southwestern plans to operate the Arkansas utility properties as a continuing part of its business. Gas Purchases and Supply Arkansas Western purchases its system gas supply through a competitive bidding process implemented in October 1998, and directly at the wellhead under long-term contracts with flexible pricing provisions. Bid requests under the bidding process included replacement of the gas supply and no-notice service previously provided by a long-term gas supply contract between Arkansas Western and SEECO. In the initial 1998 bid, SEECO, along with the Company's marketing subsidiary, successfully bid on five of seven gas supply packages with prices based on the Reliant East Index plus a demand 9 charge. Based on normal weather patterns, the volumes of gas projected to be supplied under these contracts were approximately equal to the historical annual volumes purchased under the expired long-term contract. However, under the new contracts, SEECO supplied most of Arkansas Western's no-notice service and less of its routine base requirements than it had under the previous contract. As a result, during periods of warmer weather, lower total gas volumes would be purchased by Arkansas Western than compared to periods of normal or colder weather. All of the bid packages originally secured by the Company's subsidiaries in 1998 have now expired. During the third quarter of 2001, SEECO successfully bid on gas supply packages representing approximately half of the requirements for Arkansas Western for 2002. SEECO was unsuccessful in bidding on a no-notice gas supply package that it previously held that generated a significant portion of the demand charges it received on affiliated sales. Arkansas Western also purchases gas for its system supply from unaffiliated suppliers accessed by interstate pipelines. These purchases are under firm contracts with terms between one and two years. The rates charged by most suppliers include demand components to ensure availability of gas supply and a commodity component which is based on monthly indexed market prices. The pipeline transportation rates include demand charges to reserve pipeline capacity and commodity charges based on volumes transported. A portion of the utility's gas purchases are under take-or-pay contracts. Currently, Arkansas Western believes that it does not have a significant exposure to take-or-pay liabilities resulting from these contracts and expects to be able to continue to satisfactorily manage these contracts. Arkansas Western has a regulated natural gas storage facility connected to its distribution system in Northwest Arkansas that it utilizes to help meet its peak seasonal demands. The utility also owns a liquefied natural gas facility and contracts with an interstate pipeline for additional storage capacity to serve its system in the northeastern part of the state. 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. Arkansas Western has no restriction on adding new residential or commercial customers and will supply new industrial customers that are compatible with the scale of its facilities. Arkansas Western has never denied service to new customers within its service area or experienced curtailments because of supply constraints. Curtailment of large industrial customers occurs only infrequently when extremely cold weather requires that system capacity be dedicated exclusively to human needs customers. The utility's rate schedules include purchased gas adjustment clauses whereby the actual cost of purchased gas above or below the level included in the base rates is permitted to be billed or is 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. Markets and Customers Arkansas Western continues to capitalize on the healthy economies and sustained customer growth found in its Northwest Arkansas service territory. In April 2001, the U.S. Census Bureau named Northwest Arkansas as the 6th fastest growing community in the United States. The area population grew 47.5%, or 4.0% annually, over the past ten years. As home to the largest public corporation in the world, Wal-Mart Stores, Inc., the region has enjoyed significant growth due to its presence in the area. Other corporations such as Tyson Foods and J.B. Hunt Transportation have also contributed to the impressive development of this region of the state. Approximately 85% of Arkansas Western's customers are located in this growing region. Arkansas Western provides natural gas to approximately 120,000 residential, 16,000 commercial, and 200 industrial customers, while also providing gas transportation services to approximately 60 end-use and off-system customers. Total gas throughput in 2001 was 27.1 Bcf, compared to 33.5 Bcf in 2000 and 36.4 Bcf in 1999. The decrease in 2001 resulted from the loss of throughput associated with the sale of the utility's Missouri assets in May 2000 and warmer weather. In 2000, the loss of throughput associated with the sale of the Missouri assets was partially offset by colder weather. Off-system transportation volumes were 3.1 Bcf in both 2001 and 2000 and 4.8 Bcf in 1999. Residential and Commercial. Approximately 85% of the utility's revenues are from residential and commercial markets. Residential and commercial customers combined accounted for 54% of total gas throughput for the gas distribution segment in 2001, compared to 55% in 2000 and 51% in 1999. Gas volumes sold to residential customers were 8.4 Bcf in 2001, compared to 10.9 Bcf in 2000 and 10.8 Bcf in 1999. Gas sold to commercial customers totaled 6.1 in 2001 and 7.6 Bcf in 2000 and 1999. The decreases in gas volumes sold in 2001 were due to the sale of the Company's Missouri utility properties and warmer weather. Weather during 2001 was 9% warmer than both normal and the prior year as measured by degree days. 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 recently as tariffs implemented in Arkansas contain a weather normalization clause to lessen the impact of revenue increases and decreases which might result from weather variations during the winter heating season. 10 Industrial and End-use Transportation. Deliveries to Arkansas Western's industrial and transportation customers were 9.5 Bcf in 2001, 11.8 Bcf in 2000 and 13.1 Bcf in 1999. The decrease in deliveries in both 2001 and 2000 were primarily due to the sale of the utility's Missouri properties. No industrial customer accounts for more than 9% of Arkansas Western's total throughput. Arkansas Western offers a transportation service that allows larger business customers to obtain their own gas supplies directly from other suppliers. A total of 54 customers are currently using the transportation service. Competition Arkansas Western has experienced a general trend in recent years toward lower rates of usage among its customers, largely as a result of conservation efforts that the Company encourages. Competition is increasingly being experienced from alternative fuels, primarily electricity, fuel oil, and propane. Arkansas Western has historically maintained a substantial price advantage over these fuels for most applications. This has enabled the utility to achieve excellent market penetration levels. However, the high gas prices experienced in the 2000 - 2001 heating season temporarily eroded the price advantage in some markets. Arkansas Western has now regained its price advantage in substantially all markets as gas prices have declined. Arkansas Western also has the ability through its approved tariffs to lower its rates to large customers to be competitive with available alternative fuels or if the threat of bypass exists. Regulation Arkansas Western's utility rates and operations are regulated by the APSC. The Company operates through municipal franchises that are perpetual by state law. These franchises, however, are not exclusive within a geographic area. As the regulatory focus of the natural gas industry has shifted from the federal level to the state level, some utilities across the nation have unbundled residential sales services from transportation services in an effort to promote greater competition. Although no such legislation or regulatory directives related to natural gas are presently pending in Arkansas, Arkansas Western is aggressively controlling costs and constantly reviewing issues such as system capacity and reliability, obligation to serve, rate design and stranded or transition costs. In Arkansas, the state legislature enacted Act 1556 for the deregulation of the retail sale of electricity by 2002. Act 1556 was modified by Act 324 of 2001 delaying the implementation of electric deregulation to not earlier than October 2003 and no later than October 2005. In December 2001, the APSC submitted its annual report to legislature on the development of electric deregulation and recommended that the legislature consider suspending deregulation to the year 2010 or 2012, or repeal Act 1556 (as modified by Act 324). It is unknown what final legislation will be adopted or, if it is adopted, what its final form will be. If electric deregulation occurs in Arkansas, legislative or regulatory precedents may be set that would also affect natural gas utilities in the future. These issues may include further unbundling of services and the regulatory treatment of stranded costs. Arkansas Western's most recent rate increase was approved in December 1996 for the utility's Northwest region and in December 1997 for its Northeast region. The APSC approved annual rate increases of $5.1 million and $1.2 million, respectively. The December 1996 rate increase order issued by the APSC also provided that Arkansas Western cause to be filed with the APSC an independent study of its procedures for allocating costs between regulated and non-regulated operations, its staffing levels and executive compensation. The independent study was ordered by the APSC to address issues raised by the Office of the Attorney General of the State of Arkansas. The study was conducted in 1999 with a final report issued in December 1999. The report found the Company's costs to be reasonable in all categories. In May 1999, the Staff of the APSC initiated a proceeding in which it sought an annual reduction of approximately $2.3 million in the rates Arkansas Western charges its customers in Northwest Arkansas. Staff's position was based on various adjustments to the utility's rate base, operating expenses, capital structure and rate of return. A large portion of the proposed reduction was based on a downward adjustment to the utility's current return on equity authorized by the APSC in 1996. During the third quarter of 1999, Arkansas Western reached agreement with the Staff and the APSC to resolve this issue and to close several other open dockets. In the settlement agreement, Arkansas Western agreed to reduce its rates collected from customers on a prospective basis in the amount of $1.4 million annually, effective December 1, 1999. The agreement also includes the resolution of a proceeding initiated in December 1998 by the Staff of the APSC where the Staff had recommended the disallowance of approximately $3.1 million of gas supply costs. As a part of the settlement, this docket was closed with no negative adjustment to the Company. In February 2001, the APSC approved a 90-day temporary tariff to collect additional gas costs not yet billed to customers through the normal purchased gas adjustment clause in the utility's approved tariffs. Arkansas Western had under-recovered purchased gas costs of $12.9 million in its current assets at December 31, 2000. The amount of under-recovered purchased gas costs increased significantly during January 2001 as a result of rapidly increasing gas costs. The temporary tariff allowed 11 the utility accelerated recovery of the gas costs it had incurred during the 2000 - 2001 winter heating season. At December 31, 2001, Arkansas Western had over-recovered purchased gas costs of $8.2 million, which will be refunded to its customers during 2002. Gas distribution revenues in future years will be impacted by customer growth and rate increases allowed by the APSC. In recent years, Arkansas Western has experienced customer growth of approximately 2% to 3% annually in its Northwest Arkansas service territory, while it has experienced little or no growth in its service territory in Northeast Arkansas. Based on current economic conditions in its service territories, the Company expects this trend in customer growth to continue. MARKETING AND TRANSPORTATION Gas Marketing Southwestern's gas marketing subsidiary, Southwestern Energy Services Company, was formed in 1996 to better enable the Company to capture downstream opportunities which arise through marketing and transportation activity. Through utilization of Southwestern's existing asset base, its focus is to create and capture value beyond the wellhead. The Company's marketing operations include the marketing of Southwestern's own gas production and third-party natural gas. Operating income for this segment was $2.7 million in 2001, compared to $2.5 million in 2000 and $2.1 million in 1999. The segment marketed 49.6 Bcf of natural gas in 2001, compared to 59.6 Bcf in 2000 and 63.1 Bcf in 1999. In late 2000, this segment began marketing less third-party natural gas in an effort to reduce its potential credit risk and concentrated more of its efforts on Southwestern's affiliated production. Of the total volumes marketed, purchases from the Company's exploration and production subsidiaries accounted for 66% in 2001, 33% in 2000 and 31% in 1999. NOARK Partnership At December 31, 2001, the Company held a 25% general partnership interest in NOARK. The NOARK Pipeline was a 258-mile intrastate natural gas transmission system that extended across northern Arkansas interconnecting with Arkansas Western's gas distribution systems. NOARK Pipeline was completed and placed in service in 1992 and has been operating below capacity and generating losses since it was placed in service. In January 1998, the Company entered into an agreement with Enogex Inc. (Enogex), a subsidiary of OGE Energy Corp., to expand NOARK Pipeline and provide access to Oklahoma gas supplies through an integration of NOARK Pipeline with the Ozark Gas Transmission System (Ozark). Ozark was a 437-mile interstate pipeline system that began in eastern Oklahoma and terminated in eastern Arkansas. Enogex acquired Ozark and contributed the pipeline system to the NOARK partnership. Enogex also acquired the NOARK partnership interests not held by Southwestern. On July 1, 1998, the Federal Energy Regulatory Commission (FERC) authorized the operation and integration of Ozark and NOARK Pipeline as a single, integrated pipeline. Enogex funded the acquisition of Ozark and the expansion and integration with NOARK Pipeline which resulted in Southwestern's interest in the partnership decreasing from 48% to 25% with Enogex owning a 75% interest. There are also provisions in the agreement with Enogex which allow for future revenue allocations to the Company above its 25% partnership interest if certain minimum throughput and revenue assumptions are not met. The new integrated system, known as Ozark Pipeline, became operational November 1, 1998, and includes 749 miles of pipeline with a total throughput capacity of 330 MMcf/d. Deliveries are currently being made by the pipeline to portions of Arkansas Western's distribution systems and to the interstate pipelines with which it interconnects. The average daily throughput for the pipeline was 134.1 MMcf/d in 2001, compared to 188.2 MMcf/d in 2000 and 167.5 MMcf/d in 1999. At December 31, 2001, Arkansas Western had transportation contracts with Ozark Pipeline for 66.9 MMcf/d of firm capacity. These contracts expire in 2002 and 2003 and are renewable annually thereafter until terminated with 180 days' notice. The merged pipeline system now has greater access to major gas producing fields in Oklahoma. With access to greater regional production, Southwestern expects the pipeline's additional throughput to create new marketing and transportation opportunities and reduce the losses as experienced on the project in the past. The merged pipeline also provides the Company's utility systems with additional access to gas supply. The Company's share of the pretax loss from operations related to its NOARK investment was $1.5 million in 2001, $1.8 million in 2000 and $2.0 million in 1999. Competition The Company's gas marketing activities are in competition with numerous other companies offering the same services, many of which possess larger financial and other resources than those of Southwestern. Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users. Other factors affecting competition are cost and availability of alternative fuels, level of consumer demand, and cost of and proximity to pipelines and other transportation facilities. The Company believes that its ability to effectively compete within the marketing segment in the future depends upon establishing and maintaining strong relationships with producers and end-users. 12 NOARK Pipeline previously competed with two interstate pipelines, one of which was the Ozark system, to obtain gas supplies for transportation to other markets. Because of the available transportation capacity in the Arkansas portion of the Arkoma Basin, competition had been strong and had resulted in NOARK Pipeline transporting gas for third parties at rates below the maximum tariffs presently allowed. The integration with Ozark provides increased supplies to transport to both local markets and markets served by the three major interstate pipelines that Ozark Pipeline connects with in eastern Arkansas. The Company believes that Ozark Pipeline will provide the additional supplies necessary to compete more effectively for the transportation of natural gas to end-users and markets served by the interstate pipelines. Regulation Prior to the integration with Ozark, the operations of NOARK Pipeline were regulated by the APSC. The APSC had established a maximum transportation rate of approximately $.285 per dekatherm. The integration of NOARK Pipeline with Ozark resulted in an interstate pipeline system subject to FERC regulations and FERC approved tariffs. The FERC has set the maximum transportation rate of Ozark Pipeline at $.2867 per dekatherm. OTHER ITEMS Environmental Matters The Company's operations are subject to extensive federal, state and local laws and regulations, including the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Water Act, the Clean Air Act and similar state statutes. These laws and regulations require permits for drilling wells and the maintenance of bonding requirements in order to drill or operate wells and also regulate the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the prevention and cleanup of pollutants and other matters. Southwestern maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. Compliance with environmental laws and regulations has had no material effect on Southwestern's capital expenditures, earnings, or competitive position. Although future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause the Company to incur material environmental liabilities or costs. Real Estate Development Southwestern's wholly owned subsidiary, A. W. Realty Company (AWR), owns an interest in approximately 150 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 offices 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 that 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, 2001, Southwestern had 525 total employees, 31 of whom are represented under a collective bargaining agreement. The Company believes that its relations with its employees are good. ITEM 2. PROPERTIES For additional information about the Company's gas and oil operations, refer to Notes 5 and 6 to the financial statements in Item 8 ("Financial Statements and Supplementary Data"). For information concerning capital expenditures, refer to page 41 ("Capital Expenditures" section of Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations"). Also refer to Item 6 ("Selected Financial Data") for information concerning gas and oil produced. 13 The following table provides information concerning miles of pipe of the Company's gas distribution systems. For a further description of Arkansas Western's properties, see the discussion under Item 1 ("Business").
Total ------ Gathering 387 Transmission 984 Distribution 3,756 - -------------------------------------------------------------------------------- 5,127 ================================================================================
The following information is provided to supplement that presented in Item 8. For a further description of Southwestern's oil and gas properties, see the discussion under Item 1 ("Business"). Leasehold acreage
Undeveloped Developed Gross Net Gross Net --------------------------------------------------- Arkoma 126,453 76,051 221,690 161,460 Mid-Continent 6,038 2,884 56,130 3,745 Texas/New Mexico 205,948 78,166 171,915 36,574 Louisiana 107,642 78,161 43,350 9,365 - -------------------------------------------------------------------------------- 446,081 235,262 493,085 211,144 ================================================================================
Producing wells
Gas Oil Total Gross Net Gross Net Gross Net -------------------------------------------------- Arkoma 806 402.0 - - 806 402.0 Mid-Continent 163 111.4 388 78.0 551 189.4 Texas/New Mexico 220 68.8 225 113.4 445 182.2 Louisiana 17 7.8 15 10.6 32 18.4 - -------------------------------------------------------------------------------- 1,206 590.0 628 202.0 1,834 792.0 ================================================================================
Wells drilled during the year
Exploratory Productive Wells Dry Holes Total Year Gross Net Gross Net Gross Net - ---- ----------------------------------------------------- 2001 13.0 6.5 8.0 3.8 21.0 10.3 2000 13.0 4.0 12.0 4.8 25.0 8.8 1999 4.0 1.5 4.0 1.6 8.0 3.1
Development Productive Wells Dry Holes Total Year Gross Net Gross Net Gross Net - ---- ----------------------------------------------------- 2001 67.0 29.5 11.0 2.9 78.0 32.4 2000 65.0 21.9 14.0 6.3 79.0 28.2 1999 47.0 18.3 15.0 6.1 62.0 24.4
Wells in progress as of December 31, 2001
Gross Net --------------- Exploratory - - Development 2.0 0.9 - -------------------------------------------------------------------------------- Total 2.0 0.9 ================================================================================
In December 2001, the Company announced that the Miami Corporation #27-1 well at its Crowne prospect in Cameron Parish, Louisiana, encountered approximately 75 feet of net pay in the targeted Planulina objective. In February, the well was placed on production at a rate of 10.0 MMcf/d and 35 Bopd. Southwestern is currently drilling a second well in the prospect to further delineate and develop the reservoir. Southwestern is the operator of these wells with a 40% working interest. 14 During 2001, Southwestern was 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 2001 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 the Company is the operator. ITEM 3. LEGAL PROCEEDINGS The Company recently settled litigation, subject to court approval, in a case filed against the Company and two of its subsidiaries in a state court in Sebastian County, Arkansas related to the Company's Stockton Gas Storage Facility in Franklin County, Arkansas (the "Stockton Storage Facility"). As previously disclosed, this class action suit was filed on August 25, 2000 on behalf of a class of plaintiffs comprised of all surface owners, mineral owners, royalty owners and overriding royalty owners in the Stockton Storage Facility. The plaintiffs alleged various wrongful, intentional and fraudulent acts relating to the operation of the storage pool beginning in 1968 and continuing to the present and claimed ownership rights in the gas that the Company has stored in the storage pool in an amount in excess of $5 million in actual damages, interest, attorney's fees and punitive damages. Under the terms of the settlement, the Company has agreed to pay the plaintiffs a cash settlement amount and enter into new gas storage agreements at rental rates commensurate with current market rates. The settlement of this litigation did not have a material impact on the Company's results of operations for 2001. 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. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or reported results of operations of the Company. The Company is subject to other litigation and claims that have arisen in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such litigation and claims will not have a material effect on the results of operations or the financial position of the Company. 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, 2001, to a vote of security holders, through the solicitation of proxies or otherwise. Executive Officers of the Registrant
Years Served Name Officer Position Age as Officer - -------------------------------------------------------------------------------- Harold M. Korell President and Chief Executive Officer 57 5 and Director Greg D. Kerley Executive Vice President and 46 12 Chief Financial Officer Richard F. Lane Executive Vice President, 44 3 Southwestern Energy Production Company and SEECO, Inc. Mark K. Boling Senior Vice President, General Counsel 44 - and Secretary Charles V. Stevens Senior Vice President, 52 13 Arkansas Western Gas Company
Mr. Korell has served as President since October 1998 and assumed the position of Chief Executive Officer on January 1, 1999. He joined the Company in 1997 as Executive Vice President and Chief Operating Officer. From 1992 to 1997, he was employed by American Exploration Company where he was most recently Senior Vice President - Operations. From 1990 to 1992, he was Executive Vice President of McCormick Resources and from 1973 to 1989, he held various positions with Tenneco Oil Company, including Vice President, Production. 15 Mr. Kerley was appointed to his present position in December 1999. Previously, he served as Senior Vice President and Chief Financial Officer from 1998 to 1999, Senior Vice President - Treasurer and Secretary from 1997 to 1998, Vice President - Treasurer and Secretary from 1992 to 1997, and Controller from 1990 to 1992. Mr. Kerley also served as the Chief Accounting Officer from 1990 to 1998. Mr. Lane was appointed to his present position in December 2001. Previously, he served as Senior Vice President from February 2001 and Vice President - Exploration from February 1999. Mr. Lane joined the Company in February 1998 as Manager - Exploration. From 1993 to 1998, he was employed by American Exploration Company where he was most recently Offshore Exploration Manager. Previously, he held various managerial and geological positions at FINA, Inc. and Tenneco Oil Company. Mr. Boling joined the Company in his present position in January 2002. Prior to joining the Company, Mr. Boling had a private law practice in Houston specializing in the oil and gas industry since 1993. Previously, Mr. Boling was a partner with Fulbright and Jaworski L.L.P. where he was employed from 1982 to 1993. Mr. Stevens has served the Company in his present position since December 1997. Previously, he served as Vice President of Arkansas Western Gas Company from 1988 to 1997. All officers are elected at the Annual Meeting of the Board of Directors for one-year terms or until their successors are duly elected. There are no arrangements between any officer and any other person pursuant to which he was selected as an officer. There is no family relationship between any of the named executive officers or between any of them and the Company's directors. 16 Part II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's common stock is traded on the New York Stock Exchange under the symbol "SWN." At December 31, 2001, the Company had 2,124 shareholders of record. The following prices represent closing market transactions on the New York Stock Exchange.
Range of Market Prices Cash Dividends Paid Quarter Ended 2001 2000 2001 2000 ------------------------------------------------- March 31 $11.20 $ 8.76 $ 7.44 $5.44 - $.06 June 30 $16.35 $ 8.77 $10.38 $6.06 - $.06 September 30 $13.50 $10.45 $10.00 $6.13 - - December 31 $13.05 $ 9.51 $10.44 $7.25 - -
On June 22, 2000, the Arkansas Supreme Court affirmed a $109.3 million judgment against the Company from a class action lawsuit brought by royalty owners. As a result of the judgment, the Company suspended its quarterly dividend. Dividends totaling $3.0 million were paid during 2000. 17 ITEM 6. SELECTED FINANCIAL DATA
2001 2000 1999 1998 1997 1996 - ------------------------------------------------------------------------------------------------------------------ Financial Review (in thousands) Operating revenues Exploration and production $ 153,937 $ 110,920 $ 75,039 $ 86,232 $ 100,129 $ 86,978 Gas distribution 147,282 151,234 132,420 134,711 154,155 142,730 Gas marketing and other 190,773 208,196 137,942 97,795 83,511 30,636 Intersegment revenues (147,065) (106,467) (65,005) (52,433) (61,606) (57,004) - ------------------------------------------------------------------------------------------------------------------- 344,927 363,883 280,396 266,305 276,189 203,340 - ------------------------------------------------------------------------------------------------------------------- Operating costs and expenses Gas purchases - utility 68,161 58,669 45,370 39,863 46,806 42,851 Gas purchases - marketing 68,010 133,221 92,851 73,235 63,054 14,114 Operating and general 64,108 59,790 57,957 61,915 59,167 50,509 Unusual items - 111,288 - - - - Depreciation, depletion and amortization 52,899 45,869 41,603 46,917 48,208 42,394 Write-down of oil and gas properties - - - 66,383 - - Taxes, other than income taxes 9,080 8,515 6,557 6,943 7,018 5,476 - ------------------------------------------------------------------------------------------------------------------- 262,258 417,352 244,338 295,256 224,253 155,344 - ------------------------------------------------------------------------------------------------------------------- Operating income (loss) 82,669 (53,469) 36,058 (28,951) 51,936 47,996 Interest expense, net (23,699) (23,230) (17,351) (17,186) (16,414) (13,044) Other income (expense) (799) 1,997 (2,331) (3,956) (5,017) (4,015) Minority interest in partnership (930) - - - - - - ------------------------------------------------------------------------------------------------------------------- Income (loss) before income taxes and extraordinary item 57,241 (74,702) 16,376 (50,093) 30,505 30,937 - ------------------------------------------------------------------------------------------------------------------- Income taxes Current - - 537 (6,029) (732) (5,569) Deferred 21,917 (28,905) 5,912 (13,467) 12,522 17,320 - ------------------------------------------------------------------------------------------------------------------- 21,917 (28,905) 6,449 (19,496) 11,790 11,751 - ------------------------------------------------------------------------------------------------------------------- Income (loss) before extraordinary item 35,324 (45,797) 9,927 (30,597) 18,715 19,186 Extraordinary item - (890) - - - - - ------------------------------------------------------------------------------------------------------------------- Net income (loss) $ 35,324 $ (46,687) $ 9,927 $ (30,597) $ 18,715 $ 19,186 - ------------------------------------------------------------------------------------------------------------------- Cash flow from operations, net of working capital changes (in thousands) $ 144,583 $ (53,203)(1)$ 58,131 $ 93,708 $ 79,483 $ 71,830 Return on equity 19.3% n/a 5.21% n/a 8.45% 9.23% - ------------------------------------------------------------------------------------------------------------------- Common Stock Statistics Basic earnings (loss) per share $ 1.40 $ (1.86) $ .40 $ (1.23) $ .76 $ .78 Diluted earnings (loss) per share $ 1.38 $ (1.86) $ .40 $ (1.23) $ .76 $ .78 Cash dividends declared and paid per share - $ .12 $ .24 $ .24 $ .24 $ .24 Book value per share $ 7.19 $ 5.61 $ 7.60 $ 7.45 $ 8.92 $ 8.41 Market price at year-end $ 10.40 $ 10.38 $ 6.56 $ 7.50 -$ 12.88 $ 15.13 Number of shareholders of record at year-end 2,124 2,192 2,268 2,333 - 2,379 2,572 Average diluted shares outstanding 25,601,110 25,043,586 24,947,021 24,882,170 24,777,906 24,788,587 - ------------------------------------------------------------------------------------------------------------------- (1) Cash flow from operations, net of working capital changes, for 2000 would have been $58.1 million excluding the effects of unusual and extraordinary items.
18
2001 2000 1999 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------------------------- Capitalization (in thousands) Total debt, including current portion $ 350,000 $ 396,000 $ 302,200 $ 283,436 $ 299,543 $ 278,285 Common shareholders' equity 183,086 141,291 190,356 185,856 221,565 207,941 - ---------------------------------------------------------------------------------------------------------------------------- Total capitalization $ 533,086 $ 537,291 $ 492,556 $ 469,292 $ 521,108 $ 486,226 - ---------------------------------------------------------------------------------------------------------------------------- Total assets $ 743,123 $ 705,378 $ 671,446 $ 647,620 $ 710,866 $ 660,190 - ---------------------------------------------------------------------------------------------------------------------------- Capitalization ratios: Debt 65.7% 73.70% 61.35% 60.27% 57.23% 56.96% Equity 34.3% 26.30% 38.65% 39.73% 42.77% 43.04% - ---------------------------------------------------------------------------------------------------------------------------- Capital Expenditures (in millions) Exploration and production $ 99.0 $ 69.2 $ 59.0 $ 52.4 $ 73.5 $ 110.3 Gas distribution 5.3 6.0 7.1 10.1 12.6 12.8 Other 1.8 .5 .9 1.9 2.7 1.8 - ---------------------------------------------------------------------------------------------------------------------------- $ 106.1 $ 75.7 $ 67.0 $ 64.4 $ 88.8 $ 124.9 - ---------------------------------------------------------------------------------------------------------------------------- Exploration and Production Natural gas: Production, Bcf 35.5 31.6 29.4 32.7 33.4 34.8 Average price per Mcf $ 3.85 $ 2.88 $ 2.21 $ 2.34 $ 2.57 $ 2.26 Oil: Production, MBbls 719 676 578 703 749 391 Average price per barrel $ 23.55 $ 22.99 $ 17.11 $ 13.60 $ 19.02 $ 21.21 Total gas and oil production, Bcfe 39.8 35.7 32.9 36.9 37.9 37.1 Average production (lifting) cost per Mcf equivalent $ .62 $ .55 $ .44 $ .43 $ .45 $ .29 Proved reserves at year-end: Natural gas, Bcf 355.8 331.8 307.5 303.7 291.4 297.5 Oil, MBbls 7,704 8,130 7,859 6,850 7,852 8,238 Total reserves, Bcfe 402.0 380.6 354.7 344.8 338.5 346.9 - ---------------------------------------------------------------------------------------------------------------------------- Gas Distribution(1) Sales and transportation volumes, Bcf: Residential 8.4 10.9 10.8 11.1 12.6 13.4 Commercial 6.1 7.6 7.6 7.6 8.4 8.8 Industrial 2.5 3.5 3.5 4.2 6.6 7.7 End-use transportation 7.0 8.3 9.6 8.8 6.6 5.5 - ---------------------------------------------------------------------------------------------------------------------------- 24.0 30.3 31.5 31.7 34.2 35.4 Off-system transportation 3.1 3.1 4.8 1.1 2.8 3.6 - ---------------------------------------------------------------------------------------------------------------------------- 27.1 33.4 36.3 32.8 37.0 39.0 - ---------------------------------------------------------------------------------------------------------------------------- Customers at year-end: Residential 119,856 119,024 158,606 156,384 154,864 151,880 Commercial 16,177 16,282 21,929 22,229 21,431 20,845 Industrial 209 228 290 303 311 326 - ---------------------------------------------------------------------------------------------------------------------------- 136,242 135,534 180,825 178,916 176,606 173,051 - ---------------------------------------------------------------------------------------------------------------------------- Degree days 3,654 3,994 3,179 3,472 4,131 4,341 Percent of normal 91% 100% 79% 87% 103% 108% - ---------------------------------------------------------------------------------------------------------------------------- (1) Gas distribution statistics include the operations of the Company's Missouri properties through the sale date of May 31, 2000.
19 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following information should be read in conjunction with the information contained in the financial statements and the notes thereto included in Item 8 of this report and with the discussion below on "Forward-Looking Information." RESULTS OF OPERATIONS Southwestern reported record net income of $35.3 million in 2001, or $1.38 per share on a fully diluted basis, compared to a net loss of $46.7 million in 2000, or $1.86 per share, and net income of $9.9 million in 1999, or $.40 per share. The loss for 2000 includes one-time charges for unusual items, including a $109.3 million judgment in the Hales lawsuit and $2.0 million for other litigation, an extraordinary loss on the early retirement of debt, and a $3.2 million gain from the sale of the Company's Missouri utility properties. Exclusive of these one-time charges and the gain on sale, net income for 2000 would have been $20.5 million, or $.82 per share. Results for both 2001 and 2000 (excluding unusual items) reflect growth in oil and gas production volumes and higher oil and gas prices realized. Results for 1999 were negatively impacted by lower wellhead prices for the Company's oil and gas production and by unseasonably warm weather. Exploration and Production The Company's exploration and production segment's revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas and oil, which are dependent upon numerous factors beyond its control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future.
2001 2000 1999 ----------------------------------- Revenues (in thousands) $ 153,937 $ 110,920 $ 75,039 Operating income (loss) (in thousands) $ 69,340 $ (70,584)(1) $ 16,451 Gas production (Bcf) 35.5 31.6 29.4 Oil production (MBbls) 719 676 578 Total production (Bcfe) 39.8 35.7 32.9 Average gas price per Mcf $ 3.85 $ 2.88 $ 2.21 Average oil price per Bbl $ 23.55 $ 22.99 $ 17.11 Operating expenses per Mcfe Production expenses $ 0.45 $ 0.40 $ 0.35 Production taxes $ 0.17 $ 0.15 $ 0.09 General & administrative expenses $ 0.34 $ 0.32 $ 0.30 Full cost pool amortization $ 1.14 $ 1.06 $ 1.00 (1) Includes a charge of $109.3 million for the Hales judgment and a charge of $2.0 million related to other litigation. Excluding these unusual items, operating income for the exploration and production segment would have been $40.7 million for 2000.
Revenues and Operating Income The Company's exploration and production revenues increased 39% in 2001 and 48% in 2000. The increases were due to increases in production and higher average prices received. Operating income of the exploration and production segment was $69.3 million in 2001 compared to $40.7 million in 2000, excluding the impact of the Hales judgment and the other unusual items, and $16.5 million in 1999. The increase in 2001 was due to an 11% increase in equivalent oil and gas production and higher oil and gas prices realized, partially offset by increased operating costs and expenses. The increase in 2000 was due to an 8% increase in equivalent oil and gas production and higher oil and gas prices realized, partially offset by increased operating costs and expenses. Production and Sales Gas and oil production totaled 39.8 billion cubic feet equivalent (Bcfe) in 2001, 35.7 Bcfe in 2000 and 32.9 Bcfe in 1999. The increase in 2001 production volumes resulted from the Company's continued exploration and development of its South Louisiana properties, the development of its Overton Field in East Texas and increased production in the Arkoma Basin. 20 The increase in 2000 production volumes resulted from new wells added in 2000 and 1999 in the Company's Permian Basin and South Louisiana operating areas, partially offset by the loss of production from certain wells in the Company's Mid-Continent operating area that were sold at auction during 2000. Gas sales to unaffiliated purchasers were 30.4 Bcf in 2001, up from 23.8 Bcf in 2000 and 21.2 Bcf in 1999. Sales to unaffiliated purchasers are primarily made under contracts which reflect current short-term prices and which are subject to seasonal price swings. Intersegment sales to the Company's utility subsidiary, Arkansas Western Gas Company (Arkansas Western) were 5.1 Bcf in 2001, 7.8 Bcf in 2000 and 8.2 Bcf in 1999. See "Gas Distribution - Operating Costs and Expenses" below for further discussion of the utility's gas purchases. The decrease in sales in 2001 was caused by Arkansas Western's reduced supply requirements due to warmer weather and the sale of the utility's Missouri gas distribution properties in May 2000. Weather in 2001, as measured in degree days, was 9% warmer than both normal and the prior year in Arkansas Western's service territory. Weather was normal in 2000 and 21% colder than 1999; however, sales to Arkansas Western decreased in 2000 due to the sale of the utility's Missouri properties. The Company's gas production provided approximately 33% of the utility's requirements in 2001, 42% in 2000 and 41% in 1999. Future sales to Arkansas Western's gas distribution systems will be dependent upon the Company's success in obtaining gas supply contracts with the utility systems. In the future, the Company will continue to bid to obtain these gas supply contracts, although there is no assurance that it will be successful. If successful, the Company cannot predict the amount of premium that would be associated with the new contracts. The Company expects future increases in its gas production to come primarily from sales to unaffiliated purchasers. The Company 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 amount of undeveloped leasehold acreage and producing acreage, and has an inventory of drilling leads, prospects and seismic data that will continue to be evaluated and developed in the future. The Company's exploration programs have been directed primarily toward natural gas in recent years. Commodity Prices The average price realized for the Company's gas production was $3.85 per Mcf in 2001, $2.88 per Mcf in 2000, and $2.21 per Mcf in 1999. The changes in the average price realized primarily reflects changes in average annual spot market prices and the effects of the Company's price hedging activities. The Company's hedging activities lowered the average gas price $.31 per Mcf in 2001, $1.04 per Mcf in 2000, and $.06 per Mcf in 1999. Additionally, the Company has historically received monthly demand charges related to sales made to its utility segment which has increased the Company's average gas price realized. The Company periodically enters into hedging activities with respect to a portion of its projected crude oil and natural gas production through a variety of financial arrangements intended to support oil and gas prices at targeted levels and to minimize the impact of price fluctuations (see Item 7A of this Form 10-K and Note 8 of the financial statements for additional discussion). The Company's policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. At December 31, 2001, the Company had hedges in place on 33.0 Bcf of gas. Subsequent to December 31, 2001 and prior to March 13, 2002, the Company hedged an additional 10.5 Bcf of future gas production. There were no hedges in place at December 31, 2001 on the Company's future oil production. Subsequent to December 31, 2001 and prior to March 13, 2002, the Company hedged 277,500 barrels of its 2002 oil production. The Company currently has hedged approximately 65% of its 2002 anticipated gas production level and 40% of its anticipated oil production level. Disregarding the impact of hedges, the Company expects the average price it receives for its gas production to be approximately $.05 to $.10 per Mcf lower than average spot market prices, as market differentials that reduce the average prices received are partially offset by demand charges it receives under the contracts covering its intersegment sales to the Company's utility systems. Future changes in revenues from sales of the Company's gas production will be dependent upon changes in the market price for gas, access to new markets, maintenance of existing markets, and additions of new gas reserves. The Company realized an average price of $23.55 per barrel for its oil production for the year ended December 31, 2001, up from $22.99 per barrel for 2000 and $17.11 per barrel for 1999. The Company's hedging activities lowered the average oil price $.03 per barrel in 2001 and $6.39 per barrel in 2000. Hedges had no impact on the average realized oil price in 1999. Disregarding the impact of hedges, the Company expects the average price it receives for its oil production to be approximately $1.00 per barrel lower than average spot market prices, as market differentials reduce the average prices received. Operating Costs and Expenses Production expenses per Mcfe for this business segment were $.45 in 2001, compared to $.40 in 2000 and $.35 in 1999. Production taxes per Mcfe were $.17 in 2001, compared to $.15 in 2000 and $.09 in 1999. The increase in unit production 21 expenses in 2001 was due to increased workover expenses and an industry-wide increase in costs related to normal production activities. The increase in unit production expenses in 2000 was due primarily to an increase in workover expenses. The increases in 2001 and 2000 production taxes per Mcfe were due to increased severance and ad valorem taxes that resulted from higher commodity prices. General and administrative expenses per Mcfe were $.34 in 2001, compared to $.32 in 2000 and $.30 in 1999. The increase in general and administrative costs per Mcfe in 2001 was due primarily to increased legal costs related to the resolution of litigation. The increase in general and administrative costs in 2000 as compared to 1999 resulted primarily from increases in incentive compensation pay that is dependent upon the operating results for this segment. The Company's full cost pool amortization rate averaged $1.14 per Mcfe for 2001, compared to $1.06 in 2000 and $1.00 in 1999. The rate increased in 2001 as compared to 2000 due primarily to negative revisions of proved reserves that resulted from a decline in average gas prices and to a $6.6 million decline in the balance of unevaluated costs excluded from amortization in the full cost pool. The average rate increased in 2000 due primarily to a $9.9 million decline in the balance of unevaluated costs excluded from amortization. The Company utilizes the full cost method of accounting for costs related to its oil and natural gas properties. 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. These capitalized costs are subject to a ceiling test, however, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved gas and oil reserves discounted at 10 percent (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of this ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling. Full cost companies must use the prices in effect at the end of each accounting quarter to calculate the ceiling value of its reserves. At December 31, 2001, 2000 and 1999, the Company's unamortized costs of oil and gas properties did not exceed this ceiling amount. At December 31, 2001, the Company's standardized measure was calculated based upon quoted market prices of $2.65 per Mcf for gas and $19.84 per barrel for oil, adjusted for market differentials. A decline in oil and gas prices from year-end 2001 levels or other factors, without other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings. In 2001, the Company's subsidiary, Southwestern Energy Production Company (SEPCO), formed a limited partnership with an investor to drill and complete the first 14 development wells in SEPCO's Overton Field located in Smith County, Texas. This partnership was created to provide capital necessary to accelerate the field's development. The Overton properties were acquired by SEPCO in April 2000 and have multiple development locations through the downspacing of the existing producing units. Because SEPCO is the sole general partner and owns a majority interest in the partnership, operating and financial results for the partnership are consolidated with the other operations of the Company and the investor's share of the partnership activity is reported as a minority interest item in the financial statements. During 2001, the minority interest owner in the partnership contributed $13.5 million in capital to the limited partnership and received distributions of $1.5 million. The investor's share of 2001 revenues, less operating costs and expenses, was $.9 million. Inflation impacts the Company by generally increasing its operating costs and the costs of its capital additions. The effects of inflation on the Company's operations prior to 2000 have been minimal due to low inflation rates. However, during both 2001 and 2000, the impact of inflation intensified in certain areas of the Company's exploration and production segment as shortages in drilling rigs, third-party services and qualified labor developed due to an overall increase in the activity level of the domestic oil and gas industry. The Company anticipates that this impact is now decreasing along with the current level of commodity prices. Gas Distribution The operating results of the Company's gas distribution segment are highly seasonal. The extent and duration of heating weather also impacts the profitability of this segment, although the Company has a weather normalization clause that lessens the impact of revenue increases and decreases which might result from weather variations during the winter heating season. The gas distribution segment's profitability is also dependent upon the timing and amount of regulatory rate increases that are filed with and approved by the Arkansas Public Service Commission (APSC). For periods subsequent to allowed rate increases, the Company's profitability is impacted by its ability to manage and control this segment's operating costs and expenses. On May 31, 2000, the Company completed the sale of its Missouri gas distribution assets for $32.0 million. The sale resulted in a pretax gain of approximately $3.2 million and proceeds from the sale were used to pay down debt. As a result of the adverse Hales judgment, the Company's Board of Directors authorized management to pursue the sale of the Company's remaining gas distribution operations. The sale process did not result in an acceptable bid and the Company currently plans to operate these assets as a continuing part of its business. 22
2001 2000 1999 ----------------------------------------- ($ in thousands except for Mcf amounts) Revenues $ 147,282 $ 151,234 $ 132,420 Gas purchases $ 96,058 $ 93,992 $ 68,876 Operating costs and expenses $ 40,878 $ 42,587 $ 46,357 Operating income $ 10,346 $ 14,655 $ 17,187 Deliveries (Bcf) Sales and end-use transportation 24.0 30.4 31.6 Off-system transportation 3.1 3.1 4.8 Average number of customers 134,041 152,773 177,328 Average sales rate per Mcf $ 8.26 $ 6.55 $ 5.67 Heating weather - degree days 3,654 3,994 3,179 Percent of normal 91% 100% 79% Note: Data for 2000 and 1999 includes the operations of the Company's Missouri properties through the sale date of May 31, 2000. Excluding the Missouri operations, operating income would have been $12.6 million in 2000 and $14.6 million in 1999.
Revenues and Operating Income Gas distribution revenues fluctuate due to the pass-through of gas supply cost changes and 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. Gas distribution revenues decreased 3% in 2001 and increased 14% in 2000. The decrease in 2001 was due to the loss of revenues resulting from the sale of the utility's Missouri assets and the effects of warmer weather, partially offset by a higher unit sales rate caused by high gas prices. The increase in 2000 was due to a higher sales rate and increased sales volumes caused by colder weather, partially offset by the loss of revenues resulting from the sale of the utility's Missouri assets in May 2000. Weather during 2001 in the utility's service territory was 9% warmer than both normal and the prior year. Weather in 2000 was normal and 21% colder than the prior year. Operating income for Southwestern's utility systems decreased 29% in 2001 and 15% in 2000. The decrease in 2001 resulted from the full-year impact of the sale of the utility's Missouri assets, the effects of warmer weather that were not fully offset by the Company's weather normalization clause in its tariffs and increased bad debt expense caused by record high natural gas prices experienced in the first part of 2001. The decrease in 2000 resulted from the sale of the Missouri assets and a $1.4 million annual rate reduction that was implemented in December 1999. Deliveries and Rates In 2001, Arkansas Western sold 17.0 Bcf to its customers at an average rate of $8.26 per Mcf, compared to 22.1 Bcf at $6.55 per Mcf in 2000 and 21.9 Bcf at $5.67 per Mcf in 1999. Additionally, Arkansas Western transported 7.0 Bcf in 2001, 8.3 Bcf in 2000 and 9.6 Bcf in 1999 for its end-use customers. The decrease in volumes sold and transported in 2001 resulted from the sale of the utility's Missouri properties and warmer weather. The decrease in the combined volumes sold and transported in 2000 resulted from the sale of the Missouri properties, partially offset by increased deliveries due to colder weather. The fluctuations in the average sales rates reflect changes in the average cost of gas purchased for delivery to the Company's customers, which are passed through to customers under automatic adjustment clauses. Total deliveries to industrial customers of the utility segment, including transportation volumes, were 9.5 Bcf in 2001, 11.8 Bcf in 2000 and 13.1 Bcf in 1999. The decline in deliveries in 2001 resulted from warmer heating weather and the sale of the utility's Missouri assets. In 2000, the decline resulted from the sale of the Missouri assets. Arkansas Western also transported 3.1 Bcf of gas through its gathering system in both 2001 and 2000 for off-system deliveries, all to the Ozark Gas Transmission System, compared to 4.8 Bcf in 1999. The level of off-system deliveries each year generally reflects the changes of on-system demands of the Company's gas distribution systems for the Company's gas production. The average off-system transportation rate was approximately $.13 per Mcf, exclusive of fuel, in 2001 and $.10 per Mcf in 2000 and 1999. Gas distribution revenues in future years will be impacted by the utility's gas purchase costs, customer growth and rate increases allowed by the APSC. In recent years, Arkansas Western has experienced customer growth of approximately 2% to 3% annually in its Northwest Arkansas service territory, while it has experienced little or no customer growth in its service 23 territory in Northeast Arkansas. Based on current economic conditions in the Company's service territories, the Company expects this trend in customer growth to continue. Tariffs implemented in Arkansas as a result of rate increases in both 1996 and 1997 contain a weather normalization clause to lessen the impact of revenue increases and decreases which might result from weather variations during the winter heating season. Rate increase requests, which may be filed in the future, will depend on customer growth, increases in operating expenses, and additional investment in property, plant and equipment. See "Regulatory Matters" below for additional discussion. Operating Costs and Expenses The changes in purchased gas costs for the gas distribution segment reflect volumes purchased, prices paid for supplies, the mix of purchases from intercompany versus third-party sources and the sale of Missouri assets as discussed above. Other operating costs and expenses of the gas distribution segment decreased in both 2001 and 2000 due primarily to the sale of the utility's Missouri assets. Operating costs in 2001 included increased bad debt expense caused by high natural gas prices. In October 1998, Arkansas Western instituted a competitive bidding process for its gas supply. These bid requests included replacement of the gas supply and no-notice service previously provided by a long-term gas supply contract between Arkansas Western and one of the Company's exploration and production subsidiaries, SEECO, Inc. (SEECO). In the initial 1998 bid, SEECO, along with the Company's marketing subsidiary, successfully bid on five of seven gas supply packages with prices based on the Reliant East Index plus a demand charge. Based on normal weather patterns, the volumes of gas projected to be supplied under these contracts were approximately equal to the historical annual volumes sold under the expired long-term contract. However, under the new contracts, SEECO supplied most of Arkansas Western's no-notice service and less of its routine base requirements than it had under the previous contract. As a result, during periods of warmer weather, lower total gas volumes would be purchased by Arkansas Western than compared to periods of normal or colder weather. All of the bid packages originally secured by the Company's subsidiaries in 1998 have now expired. During the third quarter of 2001, SEECO successfully bid on gas supply packages representing approximately half of the requirements for Arkansas Western for 2002. SEECO was unsuccessful in bidding on a no-notice gas supply package that it previously held that generated a significant portion of the demand charges it received on affiliated sales. Other purchases by Arkansas Western are made under long-term contracts with flexible pricing provisions. Inflation impacts the Company's gas distribution segment by generally increasing its operating costs and the costs of its capital additions. The effects of inflation on the utility's operations in recent years have been minimal due to low inflation rates. Additionally, delays inherent in the rate-making process prevent the Company from obtaining immediate recovery of increased operating costs of its gas distribution segment. Regulatory Matters Arkansas Western's rates and operations are regulated by the APSC. It operates through municipal franchises that are perpetual by state law, but are not exclusive within a geographic area. Although its rates for gas delivered to its retail customers are not regulated by the Federal Energy Regulatory Commission (FERC), its transmission and gathering pipeline systems are subject to the FERC's regulations concerning open access transportation. As the regulatory focus of the natural gas industry has shifted from the federal level to the state level, some utilities across the nation have unbundled residential sales services from transportation services in an effort to promote greater competition. No such legislation or regulatory directives related to natural gas are presently pending in Arkansas. In Arkansas, the state legislature enacted Act 1556 for the deregulation of the retail sale of electricity by 2002. Act 1556 was modified by Act 324 of 2001 delaying the implementation of electric deregulation to not earlier than October 2003 and no later than October 2005. In December 2001, the APSC submitted its annual report to the Arkansas legislature on the development of electric deregulation and recommended that the legislature consider suspending deregulation to the year 2010 or 2012, or repeal Act 1556 (as modified by Act 324). It is unknown what final legislation will be adopted or, if it is adopted, what its final form will be. If electric deregulation occurs in Arkansas, legislative or regulatory precedents may be set that would also affect natural gas utilities in the future. These issues may include further unbundling of services and the regulatory treatment of stranded costs. Arkansas Western has historically maintained a substantial price advantage over electricity for most applications. This has enabled the utility to achieve excellent market penetration levels. However, during 2001 the high gas prices experienced in the 2000 - 2001 heating season temporarily eroded the price advantage. Arkansas Western has now regained its price advantage in substantially all markets as gas prices have declined. Arkansas Western's most recent rate increase was approved in December 1996 for the utility's Northwest region and in December 1997 for the Northeast region. The APSC approved increases of $5.1 million and $1.2 million, respectively. During 1999, the APSC initiated a proceeding in which it sought a $2.3 million reduction in the rates for the Northwest region. 24 In late 1999, the APSC and Arkansas Western reached a settlement in which the Northwest region's rates were reduced by $1.4 million. The reduction was primarily due to a downward adjustment to the return on equity that the APSC had established in the 1996 rate case. While Arkansas Western continues to experience customer growth and has aggressively controlled its costs, its return on investment has declined in recent years. The Company anticipates that it will seek rate relief to improve Arkansas Western's profitability by filing a rate increase application with the APSC during 2002. In February 2001, the APSC approved a 90-day temporary tariff to collect additional gas costs not yet billed to customers through the utility's normal purchased gas adjustment clause in its approved tariffs. The Company had under-recovered purchased gas costs of $12.9 million in current assets at December 31, 2000. The level of under-recovered costs had increased significantly during January 2001 as a result of rapidly increasing gas costs. The temporary tariff allowed the utility accelerated recovery of the gas costs it had incurred during the 2000 - 2001 winter heating season. In June 2001, the APSC established a set of policy principles for gas procurement for utilities. The APSC intends for these policy principles to guide utilities in their gas purchasing decisions. Utilities are required to take all reasonable and prudent steps necessary to develop a diversified gas supply portfolio. The portfolio should consist of an appropriate combination of different types of gas purchase contracts and/or financial hedging instruments that are designed to yield the optimum balance of reliability, reduced volatility and reasonable price. Utilities will be required to submit on an annual basis their gas supply plan, along with their contracting and/or hedging objectives, to the APSC's General Staff for review and determination as to whether it is consistent with these policy principles. If the plan includes a hedging strategy and it is determined to be consistent with the objectives of the policy principles, utilities will be allowed to flow any hedging gain or loss to customers through the purchased gas adjustment clause. During 2001, Arkansas Western submitted to the General Staff its annual gas supply plan for the 2001 - 2002 heating season and a revision to its purchased gas adjustment clause for the recovery of hedging gains and losses. Arkansas Western's gas supply plan and the revision to its purchased gas adjustment clause were both approved by the APSC. Arkansas Western also purchases gas from unaffiliated producers under take-or-pay contracts. The Company believes that it does not have a significant exposure to liabilities resulting from these contracts and expects to be able to continue to satisfactorily manage its exposure to take-or-pay liabilities. In connection with the sale of its Missouri utility operations in 2000, the Company retained responsibility for five unresolved cases pertaining to the Missouri Public Service Commission's (MPSC) annual review of Arkansas Western's gas cost purchasing practices and gas cost recovery. In November 2001, the MPSC approved a stipulation and agreement that settled all five cases. The settlement did not have a material effect on the Company's results of operations. Marketing and Other Marketing
2001 2000 1999 ------------------------------- Revenues (in millions) $ 190.3 $ 207.7 $ 137.5 Operating income (in millions) $2.7 $2.5 $2.1 Gas volumes marketed (Bcf) 49.6 59.6 63.1
Operating income for the marketing segment was $2.7 million on revenues of $190.3 million in 2001, compared to $2.5 million on revenues of $207.7 million in 2000, and $2.1 million on revenues of $137.5 million in 1999. The Company marketed 49.6 Bcf in 2001, compared to 59.6 Bcf in 2000 and 63.1 Bcf in 1999. The decline in total volumes marketed in 2001 reflects the Company's increased focus on marketing its own production and limiting the marketing of third-party volumes in an effort to reduce its credit risk. Of the total volumes marketed, purchases from the Company's exploration and production subsidiaries accounted for 66% in 2001, 33% in 2000 and 31% in 1999. The Company enters into hedging activities with respect to its gas marketing activities to provide margin protection (see Item 7A of this Form 10-K and Note 8 of the financial statements for additional discussion). NOARK Partnership The marketing segment also manages the Company's 25% interest in the NOARK Pipeline System, Limited Partnership (NOARK). The NOARK Pipeline was a 258-mile intrastate gas transmission system that extended across northern Arkansas interconnecting with the Company's distribution systems. The NOARK Pipeline had been operating below capacity and generating losses since it was placed in service in September 1992. In January 1998, the Company entered into an agreement with Enogex Inc. (Enogex), a subsidiary of OGE Energy Corp., to expand the NOARK system and provide access to Oklahoma gas supplies through an integration of NOARK with the Ozark Gas Transmission System (Ozark). Ozark was a 437-mile interstate pipeline system which began in eastern Oklahoma 25 and terminated in eastern Arkansas. Effective August 1, 1998, Enogex acquired Ozark and contributed the pipeline system to the NOARK partnership. Enogex also acquired the NOARK partnership interests not held by Southwestern. Enogex funded the acquisition of Ozark and the expansion and integration with NOARK, which resulted in Southwestern's interest in the partnership decreasing to 25% (from 48%) with Enogex owning a 75% interest. There are also provisions in the agreement with Enogex which allow for future revenue allocations to the Company above its 25% partnership interest if certain minimum throughput and revenue assumptions are not met. Ozark Pipeline, the new integrated system, became operational November 1, 1998, and includes 749 miles of pipeline with a total throughput capacity of 330 million cubic feet of gas per day (MMcf/d). Deliveries are currently being made by the integrated pipeline to portions of Arkansas Western's distribution systems, and to the interstate pipelines with which it interconnects. Ozark Pipeline had an average daily throughput of 134.1 MMcf/d in 2001, 188.2 MMcf/d in 2000 and 167.5 MMcf/d in 1999. In 1998, NOARK had an average daily throughput of 27.3 MMcf/d before the integration with Ozark. As a result of a rate case filed in 2000, Ozark Pipeline's maximum transportation rate increased from $.2455 per dekatherm to $.2867 per dekatherm effective November 1, 2000. At December 31, 2001, the Company's gas distribution subsidiary has transportation contracts with Ozark Pipeline for 66.9 MMcf/d of firm capacity. These contracts expire in 2002 and 2003 and are renewable annually thereafter until terminated with 180 days' notice. The Company's share of the pretax loss from operations included in other income related to its NOARK investment was $1.5 million in 2001, $1.8 million in 2000, and $2.0 million in 1999. The improvements since 1999 result primarily from the ability to collect higher transportation rates on interruptible volumes. The Company believes that it will be able to continue to reduce the losses it has experienced on the NOARK project and expects its investment in NOARK to be realized over the life of the system (see Note 7 of the financial statements for additional discussion). As further explained in Note 11 of the financial statements, the Company has severally guaranteed the debt service on a portion of NOARK's outstanding debt. The outstanding balance was $73.0 million at December 31, 2001, and the Company's share of the guarantee relates to $43.8 million of that amount. This debt financed a portion of the original cost to construct the NOARK Pipeline. Other Income, Costs and Expenses Interest costs, net of capitalization, were up 2% in 2001 and 34% in 2000, both as compared to prior years. A decrease in interest costs in 2001 that resulted from lower average borrowings and a lower average interest rate was slightly more than offset by a lower level of capitalized interest related to the Company's oil and gas properties. The increase in 2000 was caused primarily by higher average borrowings that resulted from payment of the Hales judgment and a lower level of capitalized interest. Interest capitalized decreased 35% in 2001 and 26% in 2000. The reductions in capitalized interest are primarily due to decreases in the level of costs excluded from amortization in the Company's exploration and production segment. Other income (expense) in 2001 resulted from the Company's share of NOARK's operating loss, as discussed above, offset by interest income in the gas distribution segment related to under-recovered gas purchase costs. The increase in other income in 2000 resulted from the $3.2 million gain on the sale of the Company's Missouri gas distribution assets and gains from the sale of other miscellaneous assets. Other income (expense) in 1999 related primarily to the Company's share of NOARK's operating loss and certain costs incurred related to a judgment bond that the Company was required to post after receiving the initial adverse verdict in the Hales case. The Hales judgment was the primary cause for the Company's deferred tax benefit of $28.9 million in 2000. Excluding the impact of this change in deferred income taxes, the changes in the provisions for current and deferred income taxes recorded each year result primarily from the level of taxable income, the collection of under-recovered purchased gas costs, abandoned property costs, and the deduction of intangible drilling costs in the year incurred for tax purposes, netted against the turnaround of intangible drilling costs deducted for tax purposes in prior years. Intangible drilling costs are capitalized and amortized over future years for financial reporting purposes under the full cost method of accounting. LIQUIDITY AND CAPITAL RESOURCES The Company depends on internally-generated funds and its revolving line of credit discussed under Financing Requirements as its major sources of liquidity. Net cash provided by operating activities was $144.6 million in 2001, compared to cash used in operating activities of $53.2 million in 2000 and cash provided by operating activities of $58.1 million in 1999. The net cash used in operating activities in 2000 was a result of the Hales judgment and the impact of high year-end gas prices on working capital. The primary components of cash generated from operations are net income, depreciation, depletion and amortization, the provision for deferred income taxes and changes in current assets and current liabilities. Net cash from operating activities provided over 100% of the Company's capital requirements for routine capital expenditures, cash dividends, and scheduled debt retirements in 2001 and 89% in 1999. 26 The Company's cash flow from operating activities is highly dependent upon market prices that the Company receives for its gas and oil production. The price that the Company receives for its production is also influenced by the Company's commodity hedging activities, as more fully discussed in Item 7A of this Form 10-K and Note 8 to the financial statements. Natural gas and oil prices are subject to wide fluctuations and have declined significantly in the first quarter of 2002 as compared to prices received during 2001. The Company expects 2002 cash flow from operating activities to decline from the 2001 level although it is unable to predict with any degree of accuracy the impact of the decline. Capital Expenditures Capital expenditures totaled $106.1 million in 2001, $75.7 million in 2000, and $67.0 million in 1999. The Company's exploration and production segment expenditures included acquisitions of interests in oil and gas producing properties totaling $5.8 million in 2001, $6.7 million in 2000 and $9.4 million in 1999. The Company's reported capital investments in 2001 include the gross expenditures in the Overton Field partnership discussed previously. The owner of the minority interest in the Overton partnership funded $13.5 million of the Company's exploration and development expenditures during 2001.
2001 2000 1999 ------------------------------- (in thousands) Exploration and production $ 98,964 $ 69,211 $ 59,004 Gas distribution 5,347 5,994 7,124 Other 1,749 512 839 - -------------------------------------------------------------------------------- $ 106,060 $ 75,717 $ 66,967 - --------------------------------------------------------------------------------
Capital investments planned for 2002 total approximately $68.0 million, consisting of $61.3 million for exploration and production, $5.7 million for gas distribution system improvements and $1.0 million for general purposes. The Company expects that its level of capital investments will be adequate to allow the Company to maintain its present markets, explore and develop its existing gas and oil properties as well as generate new drilling prospects, and finance improvements necessary due to normal customer growth in its gas distribution segment. The Company may adjust its level of future capital investments dependent upon the level of cash flow generated from operations. Financing Requirements Southwestern's total debt outstanding was $350.0 million at December 31, 2001. This compares to total debt of $396.0 million at December 31, 2000, including $171.0 million under a short-term credit facility. In 2001, the Company's strong cash flow from operations allowed it to fund its capital program and pay down $46 million of debt. In July 2001, the Company arranged a new unsecured revolving credit facility with a group of banks to replace its existing short-term credit facility that was put in place in July 2000. The new revolving credit facility has a current capacity of $155 million and expires in July 2004. The capacity of the revolving credit facility decreases to $140 million in June 2002 and to $125 million in June 2003. The interest rate on the new facility is calculated based upon the debt rating of the Company. The Company is currently paying 137.5 basis points over the London Interbank Offered Rate (LIBOR). The new credit facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 70% of its total capital, must maintain a certain level of shareholders' equity, and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense at or above a stated ratio. The ratio of EBITDA to interest expense in effect through December 31, 2002 is 3.75. These covenants change over the term of the credit facility and generally become more restrictive. The Company was in compliance with its debt agreements at December 31, 2001. The Company has also entered into interest rate swaps for calendar year 2002 that allow the Company to pay a fixed average interest rate of 4.8% (based upon current rates under the revolving credit facility) on $100 million of its outstanding revolving debt. In July 2000, the Company replaced its then existing revolving credit facilities that had previously provided the Company access to $80.0 million of variable rate capital with a new credit facility that had a capacity of $180.0 million. This facility was used to fund the Hales judgment of $109.3 million, pay off the existing revolver balance and retire $22.0 million of private placement debt. The credit facility was also used to fund normal working capital needs. The interest rate on the facility was 112.5 basis points over the LIBOR rate and was 7.85% at December 31, 2000. The credit facility had a term of 364 days and expired in July 2001. In August 2000, the Company retired $22.0 million of 9.36% private placement notes. Certain costs of the redemption were expensed and are classified as an extraordinary loss, net of related income tax effects. 27 In 1997, the Company issued $60.0 million of 7.625% Medium-Term Notes due 2027 and $40.0 million of 7.21% Medium-Term Notes due 2017. These notes were issued under a supplement to the Company's $250.0 million shelf registration statement filed with the Securities and Exchange Commission in February 1997, for the issuance of up to $125.0 million of Medium-Term Notes. The Company has $25.0 million of capacity remaining under the shelf registration statement. The Company also has $125.0 million of 6.7% Notes due in 2005 that were issued under the shelf registration. The Company's public notes are rated BBB by Standard and Poor's and Baa3 by Moody's. If the Company were unable to comply with any of the covenants of its various debt agreements, a waiver would have to be requested to avoid a default under the agreements. Further, the Company's public debt could be downgraded by the rating agencies which could increase the cost of funds under its revolving credit facility. In June 1998, the NOARK partnership issued $80.0 million of 7.15% Notes due 2018. The notes require semi-annual principal payments of $1.0 million that began in December 1998. The Company accounts for its investment in NOARK under the equity method of accounting and does not consolidate the results of NOARK. The Company and the other general partner of NOARK have severally guaranteed the principal and interest payments on the NOARK debt. The Company's share of the several guarantee is 60% and amounted to $43.8 million at December 31, 2001. The Company advanced $1.4 million to NOARK to fund its share of debt service payments in 2001 and advanced $3.3 million in 2000. If NOARK is unable to generate sufficient cash in the future to service its debt and the Company is required to continue contributing cash to fund its debt service guarantee, the Company could be required to record its share of the NOARK debt commitment under current accounting rules. At the end of 2001, the Company's capital structure consisted of 65.7% debt (excluding the Company's several guarantee of NOARK's obligations) and 34.3% equity, with a ratio of EBITDA to interest expense of 5.69. As part of its strategy to insure cash flow to fund its operations and meet the restrictive covenant tests under its debt agreements, the Company has hedged approximately 65% of its expected 2002 gas production and 40% of its expected 2002 oil production. The Company does not expect to reduce its long-term debt materially in 2002, assuming commodity prices remain at or near current levels and the Company's capital investment plans do not change from current expectations. Working Capital The Company maintains access to funds that may be needed to meet seasonal requirements through its credit facility explained above. The Company had positive working capital of $21.7 million at the end of 2001, compared to net negative working capital of $127.0 million at the end of 2000 caused by the short-term revolving credit facility balance of $171.0 million. Current assets decreased by 17% in 2001, while current liabilities (without consideration of short-term debt) increased 4%. The decrease in current assets and the slight increase in current liabilities at December 31, 2001, was due primarily to decreases in accounts receivable, accounts payable and under-recovered purchased gas costs that resulted from extremely high market prices for natural gas at year-end 2000, offset by increases in gas stored underground, over-recovered purchased gas costs, and current assets and liabilities recorded for derivatives at December 31, 2001. At December 31, 2001, Southwestern had over-recovered purchased gas costs of $8.2 million, which will be refunded to its customers during 2002. FORWARD-LOOKING INFORMATION All statements, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for gas and oil, the timing and extent of the Company's success in discovering, developing, producing, and estimating reserves, property acquisition or divestiture activities that may occur, the effects of weather and regulation on the Company's gas distribution segment, increased competition, legal and economic factors, governmental regulation, the financial impact of accounting regulations for derivative instruments, changing market conditions, the comparative cost of alternative fuels, conditions in capital markets and changes in interest rates, availability of oil field services, drilling rigs and other equipment, as well as various other factors beyond the Company's control. 28 ITEM 7.A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS Market risks relating to the Company's operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as credit risk concentrations. The Company uses natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. The Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price and interest rate risks. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. Credit Risks The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of customers and their dispersion across geographic areas. No single customer accounts for greater than 3% of accounts receivable. See the discussion of credit risk associated with commodities trading below. Interest Rate Risk The following table provides information on the Company's financial instruments that are sensitive to changes in interest rates. The table presents the Company's debt obligations, principal cash flows and related weighted-average interest rates by expected maturity dates. Variable average interest rates reflect the rates in effect at December 31, 2001 for borrowings under the Company's credit facility. The Company's policy is to manage interest rates through use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposures when appropriate. The Company has entered into interest rate swaps for the calendar year 2002 that allow the Company to pay a fixed average interest rate of 4.8% (based upon current rates under the revolving credit facility) on $100 million of its outstanding revolving debt.
Expected Maturity Date Fair Value ------------------------------------------------------------------------------- 2002 2003 2004 2005 2006 Thereafter Total 12/31/01 ------------------------------------------------------------------------------- ($ in millions) Fixed Rate - - - $ 125.0 - $ 100.0 $ 225.0 $ 231.2 Average Interest Rate - - - 6.70% - 7.46% 7.04% Variable Rate - - $ 125.0 - - - $ 125.0 $ 125.0 Average Interest Rate - - 5.47% - - - 5.47%
Commodities Risk The Company uses over-the-counter natural gas and crude oil swap agreements and options to hedge sales of Company production, to hedge activity in its marketing segment, and to hedge the purchase of gas in its utility segment against the inherent price risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX (New York Mercantile Exchange) futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps), and (3) the purchase and sale of index-related puts and calls (collars) that provide a "floor" price below which the counterparty pays (production hedge) or receives (gas purchase hedge) funds equal to the amount by which the price of the commodity is below the contracted floor, and a "ceiling" price above which the Company pays to (production hedge) or receives from (gas purchase hedge) the counterparty the amount by which the price of the commodity is above the contracted ceiling. The primary market risks related to the Company's derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged. Credit risk relates to the risk of loss as a result of non-performance by the Company's counterparties. The counterparties are primarily major investment and commercial banks which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure the Company has to each counterparty are periodically reviewed to ensure limited credit risk exposure. The following table provides information about the Company's financial instruments that are sensitive to changes in commodity prices. The table presents the notional amount in Bcf (billion cubic feet) and MBbls (thousand barrels), the weighted average contract prices, and the total dollar contract amount by expected maturity dates. The "Carrying Amount" 29 for the contract amounts is calculated as the contractual payments for the quantity of gas or oil to be exchanged under futures contracts and does not represent amounts recorded in the Company's financial statements. The "Fair Value" represents values for the same contracts using comparable market prices at December 31, 2001. At December 31, 2001, the "Fair Value" exceeded the "Carrying Amount" of these financial instruments by $4.2 million.
Expected Maturity Date 2002 2003 -------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value -------------------------------------- PRODUCTION AND MARKETING Natural Gas Swaps with a fixed-price receipt Contract volume (Bcf) 13.4 9.2 Weighted average price per Mcf $ 2.88 $ 3.18 Contract amount (in millions) $ 38.6 $ 40.2 $ 29.3 $ 29.3 Swaps with a fixed-price payment Contract volume (Bcf) .3 - Weighted average price per Mcf $ 2.96 - Contract amount (in millions) $ .7 $ .6 - - Price collars Contract volume (Bcf) 6.0 4.1 Weighted average floor price per Mcf $ 4.00 $ 3.00 Contract amount of floor (in millions) $ 24.0 $ 32.2 $ 12.3 $ 14.2 Weighted average ceiling price per Mcf $ 4.72 $ 4.65 Contract amount of ceiling (in millions) $ 28.3 $ 27.8 $ 19.0 $ 17.9 NATURAL GAS PURCHASES Swaps with a fixed-price payment Contract volume (Bcf) 3.3 - Weighted average price per Mcf $ 4.20 - Contract amount (in millions) $ 13.9 $ 8.1 - -
At December 31, 2001, the Company had a single financial instrument that is sensitive to changes in interest rates. This $50 million notional interest rate swap has a fixed rate of 4.33%. Its carrying amount of $2.2 million is calculated as the contractual payments for interest on the notional amount to be exchanged under futures contracts and does not represent amounts recorded in the Company's financial statements. The fair value of $1.2 million represents the value for the same contract using comparable market prices at December 31, 2001. At December 31, 2001, the "Carrying Amount" exceeded the "Fair Value" of this interest rate swap by $1.0 million. Subsequent to December 31, 2001, the Company entered into additional interest rate swaps totaling $50 million that have an average fixed rate of 2.58%. Subsequent to December 31, 2001 and prior to March 13, 2002, the Company entered into additional derivative contracts to hedge gas and oil production sales and utility gas purchases. Price collar hedges on 4.0 Bcf of 2002 gas production sales have floor prices ranging from $2.25 to $2.50 per Mcf and ceiling prices ranging from $3.00 to $3.75 per Mcf and a collar on 4.0 Bcf of 2003 gas production has a $3.00 per Mcf floor and a $4.75 per Mcf ceiling. Fixed price swaps on gas production sales of 2.5 Bcf in the second quarter of 2002 will yield a weighted average price of $2.61 per Mcf. Natural gas swaps on notional gas purchase volumes of .3 Bcf in 2002 and .7 Bcf in 2003 were executed under which the Company will pay a fixed price of $2.91 per Mcf. Under a crude oil swap the Company will receive a fixed price of $20.07 per barrel on a notional volume of 277,500 barrels. 30 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS pg. Reports of Management and Independent Public Accountants 32 Consolidated Statements of Operations for the years ended December 31, 2001, 2000 and 1999 33 Consolidated Balance Sheets as of December 31, 2001 and 2000 34 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999 35 Consolidated Statements of Retained Earnings for the years ended December 31, 2001, 2000 and 1999 36 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2001, 2000 and 1999 36 Notes to Consolidated Financial Statements, December 31, 2001, 2000 and 1999 37
31 Report of Management Management is responsible for the preparation and integrity of the Company's financial statements. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States consistently applied, and necessarily include some amounts that are based on management's best estimates and judgment. The Company maintains a system of internal accounting and administrative controls and an ongoing program of internal audits that management believes provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with management's authorization. The Company's financial statements have been audited by its independent public accountants, Arthur Andersen LLP. In accordance with auditing standards generally accepted in the United States, the independent auditors obtained a sufficient understanding of the Company's internal controls to plan their audit and determine the nature, timing, and extent of other tests to be performed. The Audit Committee of the Board of Directors, composed solely of outside directors, meets with management, internal auditors, and Arthur Andersen LLP to review planned audit scopes and results and to discuss other matters affecting internal accounting controls and financial reporting. The independent auditors have direct access to the Audit Committee and periodically meet with it without management representatives present. Report of Independent Public Accountants 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, 2001 and 2000, and the related consolidated statements of operations, retained earnings, cash flows and comprehensive income (loss) for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the United States. 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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As discussed in Note 8 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivatives to adopt the requirements of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." ARTHUR ANDERSEN LLP Tulsa, Oklahoma February 4, 2002 32
Statements of Operations Southwestern Energy Company and Subsidiaries For the years ended December 31, 2001 2000 1999 - ------------------------------------------------------------------------------------------------- (in thousands, except share/ per share amounts) Operating revenues Gas sales $ 248,952 $ 200,269 $ 165,898 Gas marketing 71,839 137,234 96,570 Oil sales 16,932 15,537 9,891 Gas transportation and other 7,204 10,843 8,037 - -------------------------------------------------------------------------------------------------- 344,927 363,883 280,396 - -------------------------------------------------------------------------------------------------- Operating costs and expenses Gas purchases - utility 68,161 58,669 45,370 Gas purchases - marketing 68,010 133,221 92,851 Operating expenses 39,035 34,808 33,783 General and administrative expenses 25,073 24,982 24,174 Unusual items - 111,288 - Depreciation, depletion and amortization 52,899 45,869 41,603 Taxes, other than income taxes 9,080 8,515 6,557 - -------------------------------------------------------------------------------------------------- 262,258 417,352 244,338 - -------------------------------------------------------------------------------------------------- Operating income (loss) 82,669 (53,469) 36,058 - -------------------------------------------------------------------------------------------------- Interest expense Interest on long-term debt 23,920 24,089 19,735 Other interest charges 1,374 1,588 923 Interest capitalized (1,595) (2,447) (3,307) - -------------------------------------------------------------------------------------------------- 23,699 23,230 17,351 - -------------------------------------------------------------------------------------------------- Other income (expense) (799) 1,997 (2,331) - -------------------------------------------------------------------------------------------------- Income (loss) before income taxes and minority interest 58,171 (74,702) 16,376 Minority interest in partnership (930) - - - -------------------------------------------------------------------------------------------------- Income (loss) before income taxes 57,241 (74,702) 16,376 - -------------------------------------------------------------------------------------------------- Provision (benefit) for income taxes Current - - 537 Deferred 21,917 (28,905) 5,912 - -------------------------------------------------------------------------------------------------- 21,917 (28,905) 6,449 - -------------------------------------------------------------------------------------------------- Income (loss) before extraordinary item 35,324 (45,797) 9,927 Extraordinary loss due to early retirement of debt (net of $569,000 tax benefit) - (890) - - -------------------------------------------------------------------------------------------------- Net income (loss) $ 35,324 $ (46,687) $ 9,927 - -------------------------------------------------------------------------------------------------- Basic earnings per share Income (loss) before extraordinary item $ 1.40 $ (1.82) $ .40 Extraordinary loss due to early retirement of debt (net of $569,000 tax benefit) - (.04) - Net income (loss) $ 1.40 $ (1.86) $ .40 - -------------------------------------------------------------------------------------------------- Basic weighted average common shares outstanding 25,198,105 25,043,586 24,941,550 - -------------------------------------------------------------------------------------------------- Diluted earnings per share Income (loss) before extraordinary item $ 1.38 $ (1.82) $ .40 Extraordinary loss due to early retirement of debt (net of $569,000 tax benefit) - (.04) - - -------------------------------------------------------------------------------------------------- Net income (loss) $ 1.38 $ (1.86) $ .40 - -------------------------------------------------------------------------------------------------- Diluted weighted average common shares outstanding 25,601,110 25,043,586 24,947,021 - -------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of the financial statements.
33
Balance Sheets Southwestern Energy Company and Subsidiaries December 31, 2001 2000 - --------------------------------------------------------------------------------------------------------------------------------- (in thousands) ASSETS Current assets Cash $ 3,641 $ 2,386 Accounts receivable 42,763 77,041 Inventories, at average cost 26,606 17,000 Under-recovered purchased gas costs - 12,942 Hedging asset - SFAS No. 133 9,381 - Regulatory asset - hedges 5,817 - Other 4,996 3,486 - --------------------------------------------------------------------------------------------------------------------------------- Total current assets 93,204 112,855 - --------------------------------------------------------------------------------------------------------------------------------- Investments 15,538 15,574 Property, plant and equipment, at cost Gas and oil properties, using the full cost method, including $21,102,000 in 2001 and $27,692,000 in 2000 excluded from amortization 970,680 872,023 Gas distribution systems 192,784 190,893 Gas in underground storage 32,046 27,867 Other 30,110 27,940 - --------------------------------------------------------------------------------------------------------------------------------- 1,225,620 1,118,723 Less: Accumulated depreciation, depletion and amortization 605,790 554,616 - --------------------------------------------------------------------------------------------------------------------------------- 619,830 564,107 - --------------------------------------------------------------------------------------------------------------------------------- Other assets 14,551 12,842 - --------------------------------------------------------------------------------------------------------------------------------- $ 743,123 $ 705,378 - --------------------------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Short-term debt $ - $ 171,000 Accounts payable 41,644 54,304 Taxes payable 4,400 4,346 Interest payable 2,653 2,806 Customer deposits 4,845 4,799 Hedging liability - SFAS No. 133 6,990 - Over-recovered purchased gas costs 8,184 - Other 2,752 2,629 - --------------------------------------------------------------------------------------------------------------------------------- Total current liabilities 71,468 239,884 - --------------------------------------------------------------------------------------------------------------------------------- Long-term debt 350,000 225,000 - --------------------------------------------------------------------------------------------------------------------------------- Other liabilities Deferred income taxes 122,381 97,431 Other 3,187 1,772 - --------------------------------------------------------------------------------------------------------------------------------- 125,568 99,203 - --------------------------------------------------------------------------------------------------------------------------------- Commitments and contingencies - --------------------------------------------------------------------------------------------------------------------------------- Minority interest in partnership 13,001 - - --------------------------------------------------------------------------------------------------------------------------------- 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 19,764 20,220 Retained earnings, per accompanying statements 183,677 148,353 Accumulated other comprehensive income 5,763 - - --------------------------------------------------------------------------------------------------------------------------------- 211,978 171,347 Less: Common stock in treasury, at cost, 2,261,766 shares in 2001 and 2,556,908 shares in 2000 25,196 28,485 Unamortized cost of restricted shares issued under stock incentive plan, 416,537 shares in 2001 and 241,452 shares in 2000 3,696 1,571 - --------------------------------------------------------------------------------------------------------------------------------- 183,086 141,291 - --------------------------------------------------------------------------------------------------------------------------------- $ 743,123 $ 705,378 - --------------------------------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of the financial statements.
34
Statements of Cash Flows Southwestern Energy Company and Subsidiaries For the years ended December 31, 2001 2000 1999 - --------------------------------------------------------------------------------------------------------- (in thousands) Cash flows from operating activities Net income (loss) $ 35,324 $ (46,687) $ 9,927 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation, depletion and amortization 54,505 47,227 42,971 Deferred income taxes 21,917 (28,905) 5,912 Equity in loss of NOARK partnership 1,484 1,767 2,008 Gain on sale of Missouri utility assets - (3,209) - Extraordinary loss due to early retirement of debt (net of tax) - 890 - Minority interest in partnership (533) - - Change in assets and liabilities: Accounts receivable 34,278 (36,693) (2,684) Income taxes receivable - 85 1,658 Under/over-recovered purchased gas costs 21,126 (14,104) (273) Inventories (9,606) 2,290 1,292 Accounts payable (12,660) 22,156 (4,711) Other current assets and liabilities (1,252) 1,980 2,031 - --------------------------------------------------------------------------------------------------------- Net cash provided by (used in) operating activities 144,583 (53,203) 58,131 - --------------------------------------------------------------------------------------------------------- Cash flows from investing activities Capital expenditures (106,060) (75,717) (66,967) Sale of Missouri utility assets - 32,000 - Sale of oil and gas properties - 13,651 - Investment in NOARK partnership (1,449) (3,250) (2,273) (Increase) decrease in gas stored underground (4,179) 845 (4,433) Other items 826 (1,066) 2,380 - --------------------------------------------------------------------------------------------------------- Net cash used in investing activities (110,862) (33,537) (71,293) - --------------------------------------------------------------------------------------------------------- Cash flows from financing activities Net increase (decrease) in revolving debt and short-term note (46,000) 115,800 20,300 Retirement of notes and payments on long-term debt - (24,910) (1,535) Contribution from minority interest owner in partnership 13,534 - - Dividends paid - (3,004) (5,985) - --------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (32,466) 87,886 12,780 - --------------------------------------------------------------------------------------------------------- Increase (decrease) in cash 1,255 1,146 (382) Cash at beginning of year 2,386 1,240 1,622 - --------------------------------------------------------------------------------------------------------- Cash at end of year $ 3,641 $ 2,386 $ 1,240 The accompanying notes are an integral part of the financial statements.
35
Statements of Retained Earnings Southwestern Energy Company and Subsidiaries For the years ended December 31, 2001 2000 1999 - --------------------------------------------------------------------------------------------------------- (in thousands) Retained earnings, beginning of year $ 148,353 $ 198,044 $ 194,102 Net income (loss) 35,324 (46,687) 9,927 Cash dividends declared ($.12 per share in 2000, $.24 per share in 1999) - (3,004) (5,985) Retained earnings, end of year $ 183,677 $ 148,353 $ 198,044 Statements of Comprehensive Income (Loss) Southwestern Energy Company and Subsidiaries For the years ended December 31, 2001 2000 1999 - --------------------------------------------------------------------------------------------------------- (in thousands) Net income (loss) $ 35,324 $ (46,687) $ 9,927 Other comprehensive income: Transition adjustment from adoption of SFAS No. 133 (36,963) - - Unrealized gain on derivative instruments 19,852 - - - --------------------------------------------------------------------------------------------------------- Comprehensive income (loss) $ 18,213 $ (46,687) $ 9,927 - --------------------------------------------------------------------------------------------------------- Reconciliation of accumulated other comprehensive income (loss): Balance, beginning of year $ - $ - $ - Transition adjustment from adoption of SFAS No. 133 (36,963) - - Current period reclassification to earnings 22,874 - - Current period change in derivative instruments 19,852 - - - --------------------------------------------------------------------------------------------------------- Balance, end of year $ 5,763 $ - $ - - --------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of the financial statements.
36 Notes to Financial Statements Southwestern Energy Company and Subsidiaries December 31, 2001, 2000 and 1999 (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations and Consolidation Southwestern Energy Company (Southwestern or the Company) is an integrated energy company primarily focused on natural gas. Through its wholly-owned subsidiaries, the Company is engaged in oil and gas exploration and production, natural gas gathering, transmission and marketing, and natural gas distribution. Southwestern's exploration and production activities are concentrated in Arkansas, Louisiana, Texas, New Mexico and Oklahoma. The gas distribution segment operates in northern Arkansas and, depending upon weather conditions and current supply contracts, can obtain approximately 50% of its gas supply from one of the Company's exploration and production subsidiaries. The customers of the gas distribution segment consist of residential, commercial and industrial users of natural gas. Southwestern's marketing and transportation business is concentrated in its core areas of operations. On May 31, 2000, the Company completed the sale of its Missouri gas distribution assets for $32.0 million resulting in a pretax gain of approximately $3.2 million. Proceeds from the sale of the Missouri assets were used to reduce the Company's outstanding debt. As a result of the adverse Hales judgment in June 2000, the Company's Board of Directors authorized management to pursue the sale of the Company's remaining gas distribution assets. The sale process did not result in an acceptable bid. The Company currently plans to operate these assets as a continuing part of its business. The consolidated financial statements include the accounts of Southwestern Energy Company and its wholly-owned subsidiaries, Southwestern Energy Production Company (SEPCO), SEECO, Inc., Arkansas Western Gas Company, Southwestern Energy Services Company, Diamond "M" Production Company, Southwestern Energy Pipeline Company, and A.W. Realty Company. The consolidated financial statements also include the results for a limited partnership, Overton Partners, L.P., in which SEPCO is the sole general partner. All significant intercompany accounts and transactions have been eliminated. The Company accounts for its general partnership interest 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. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Minority Interest in Partnership In 2001, SEPCO formed a limited partnership, Overton Partners, L.P., with an investor to drill and complete the first 14 development wells in SEPCO's Overton Field located in Smith County, Texas. Because SEPCO is the sole general partner and owns a majority interest in the partnership, the operating and financial results are consolidated with the Company's exploration and production results and the investor's share of the partnership activity is reported as a minority interest item in the financial statements. SEPCO contributed 50% of the capital required to drill the first 14 wells. Revenues and expenses are allocated 65% to SEPCO prior to payout of the investor's initial investment and 85% thereafter. Unusual Items In June 2000, the Company reported that the Arkansas Supreme Court ruled to affirm the 1998 decision of the Sebastian County Circuit Court awarding $109.3 million in a class action to royalty owners of SEECO, Inc. (Hales judgment). The Company fully satisfied the judgment and the Circuit Court in Sebastian County issued an order in complete satisfaction of the judgment effective July 18, 2000. Additionally, the Company incurred an unusual charge of $2.0 million during 2000 related to other litigation. 37 Property, Depreciation, Depletion and Amortization Gas and Oil Properties. The Company follows the full cost method of accounting for the exploration, development, and acquisition of gas and oil reserves. Under this method, all such costs (productive and nonproductive) including salaries, benefits, and other internal costs directly attributable to these activities 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. The Company's unamortized costs of oil and gas properties are limited to the sum of the future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of any unproved properties. If the Company's unamortized costs in oil and gas properties exceed this ceiling amount, a provision for additional depreciation, depletion and amortization is required. At December 31, 2001, the Company's net book value of oil and gas properties did not exceed the ceiling amount. Decreases in market prices from December 31, 2001 levels, as well as changes in production rates, levels of reserves, and the evaluation of costs excluded from amortization, could result in future ceiling test impairments. 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 1.5% to 5.8%. 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 cost 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 136,000 gas distribution customers are located in northern Arkansas and represent a diversified base of residential, commercial, and industrial users. The Company records gas distribution revenues on an accrual basis, as gas volumes are used, to provide a proper matching of revenues with expenses. The gas distribution subsidiary's rate schedules include purchased gas adjustment clauses whereby the actual cost of purchased gas above or below the level included in the base rates is permitted to be billed or is 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. Rate schedules include a weather normalization clause to lessen the impact of revenue increases and decreases which might result from weather variations during the winter heating season. The pass-through of gas costs to customers is not affected by this normalization clause. 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 revenue interest 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, 2001 and 2000 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. 38 Risk Management The Company uses derivative financial instruments to manage defined commodity price risks and interest rate risks and does not use them for trading purposes. The Company uses commodity swap agreements and options to hedge sales and purchases of natural gas and sales of crude oil. Gains and losses resulting from hedging activities have been recognized in the statements of operations when the related physical transactions of commodities were recognized. Gains or losses from commodity swap agreements and options that do not qualify for accounting treatment as hedges would be recognized currently as other income or expense. See Note 8 for a discussion of the Company's hedging activities and the effects of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." Earnings Per Share and Shareholders' Equity Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding the incremental shares that would have been outstanding assuming the exercise of dilutive stock options. The Company had options for 2,602,800 shares with an average exercise price of $9.79 outstanding at December 31, 2000 that, due to the Company's net loss for 2000, would have had an anti-dilutive effect and were, therefore, not considered. The Company had options for 1,006,234 shares of common stock with a weighted average exercise price of $13.83 per share at December 31, 2001, and options for 1,275,899 shares of common stock with a weighted average exercise price of $12.97 per share at December 31, 1999, that were not included in the calculation of diluted shares because they would have had an anti-dilutive effect. The remaining 1,665,952 options at December 31, 2001 with a weighted average exercise price of $7.43, and 785,300 options at December 31, 1999 with a weighted average exercise price of $6.46 were included in the calculation of diluted shares. During 2001 and 2000, the Company issued 299,850 and 154,438 treasury shares, respectively, under a compensatory plan and for stock awards and returned to treasury 18,184 and 10,955 shares, respectively, canceled from earlier issues under the compensatory plan. The net effect of these transactions was a reduction in treasury stock of $3.3 million and $1.6 million in 2001 and 2000, respectively. Dividend on Common Stock As a result of the adverse Hales judgment in June 2000, the Company has indefinitely suspended payment of quarterly dividends on its common stock. (2) DEBT
Debt balances as of December 31, 2001 and 2000 consisted of the following: 2001 2000 ------------------------ (in thousands) Senior notes 6.70% Series due 2005 $ 125,000 $ 125,000 7.625% Series due 2027, putable at the holders' option in 2009 60,000 60,000 7.21% Series due 2017 40,000 40,000 - ------------------------------------------------------------------------------------------------------------- 225,000 225,000 Other Variable rate (3.44% at December 31, 2001) unsecured revolving credit arrangements 125,000 - - ------------------------------------------------------------------------------------------------------------- Total long-term debt $ 350,000 $ 225,000 - ------------------------------------------------------------------------------------------------------------- Short-term debt Variable rate unsecured revolving credit arrangements $ - $ 171,000 - -------------------------------------------------------------------------------------------------------------
In July 2001, the Company arranged a new unsecured revolving credit facility with a group of banks to replace its existing short-term credit facility that was put in place in July 2000. The new revolving credit facility has a current capacity of $155 million and a three-year term. The capacity of the revolving credit facility decreases to $140 million in June 2002 and to $125 million in June 2003. The interest rate on the new facility is 137.5 basis points over the current London Interbank 39 Offered Rate (LIBOR). The new credit facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 70% of its total capital, must maintain a certain level of shareholders' equity, and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of at least 3.75 or higher through December 31, 2002. These covenants change over the term of the credit facility and generally become more restrictive. The Company was in compliance with its debt agreements at December 31, 2001. The Company has entered into interest rate swaps for calendar year 2002 that allow the Company to pay an average fixed interest rate of 4.8% (based upon current rates under the revolving credit facility) on $100 million of its outstanding revolving debt. There are no aggregate maturities of long-term debt for each of the years ending December 31, 2002, 2003 and 2006. For each of the years ended December 31, 2004 and 2005, the aggregate maturity is $125.0 million. Total interest payments were $24.4 million in 2001, $23.6 million in 2000, and $19.6 million in 1999. (3) INCOME TAXES
The provision (benefit) for income taxes included the following components: 2001 2000 1999 -------------------------------------- (in thousands) Federal: Current $ - $ - $ - Deferred 19,461 (23,723) 5,236 State: Current - - 537 Deferred 2,575 (5,063) 795 Investment tax credit amortization (119) (119) (119) - ------------------------------------------------------------------------------------------------------ Provision (benefit) for income taxes $ 21,917 $ (28,905) $ 6,449 - ------------------------------------------------------------------------------------------------------
The provision (benefit) for income taxes was an effective rate of 38.3% in 2001, 38.7% in 2000, and 39.4% in 1999. The following reconciles the provision (benefit) for income taxes included in the consolidated statements of operations with the provision (benefit) which would result from application of the statutory federal tax rate to pretax financial income:
2001 2000 1999 -------------------------------------- (in thousands) Expected provision (benefit) at federal statutory rate of 35% $ 20,034 $ (26,145) $ 5,732 Increase (decrease) resulting from: State income taxes, net of federal income tax effect 1,674 (3,291) 866 Other 209 531 (149) - ------------------------------------------------------------------------------------------------------ Provision (benefit) for income taxes $ 21,917 $ (28,905) $ 6,449 - ------------------------------------------------------------------------------------------------------
The components of the Company's net deferred tax liability as of December 31, 2001 and 2000 were as follows: 2001 2000 ------------------------- (in thousands Deferred tax liabilities: Differences between book and tax basis of property $ 148,330 $ 129,702 Stored gas 8,037 8,883 Deferred purchased gas costs - 11,313 Prepaid pension costs 1,908 1,884 Book over tax basis in partnerships 11,148 11,755 Other 6,694 1,072 - ------------------------------------------------------------------------------------------------------ 176,117 164,609 - ------------------------------------------------------------------------------------------------------ Deferred tax assets: Accrued compensation 721 884 Alternative minimum tax credit carryforward 3,766 3,046 Net operating loss carryforward 48,595 63,449 Other 1,849 1,671 - ------------------------------------------------------------------------------------------------------ 54,931 69,050 - ------------------------------------------------------------------------------------------------------ Net deferred tax liability $ 121,186 $ 95,559 - ------------------------------------------------------------------------------------------------------
40 There were no income tax payments in 2001. Total income tax payments of $.5 million and $.6 million were made in 2000 and 1999, respectively. (4) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS The Company applies SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits." Substantially all employees are covered by the Company's defined benefit pension and postretirement benefit plans. The following provides a reconciliation of the changes in the plans' benefit obligations, fair value of assets, and funded status as of December 31, 2001 and 2000:
Other Postretirement Pension Benefits Benefits ------------------------------------------------- 2001 2000 2001 2000 ------------------------------------------------- (in thousands) Change in benefit obligations: Benefit obligation at January 1 $ 56,571 $ 61,515 $ 2,011 $ 3,759 Service cost 1,318 1,682 71 85 Interest cost 4,133 4,509 138 268 Actuarial loss (gain) 3,338 1,438 10 (226) Benefits paid (4,435) (7,256) (131) (138) Amount transferred - (5,317) - - Effect of settlement - - - (1,737) - -------------------------------------------------------------------------------------------------------- Benefit obligation at December 31 $ 60,925 $ 56,571 $ 2,099 $ 2,011 - -------------------------------------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at January 1 $ 66,283 $ 70,478 $ 573 $ 615 Actual return on plan assets (2,478) 8,716 2 4 Employer contributions 18 13 228 308 Benefit payments (4,435) (7,256) (131) (138) Amount transferred (378) (5,668) - - Effect of settlement - - - (216) - -------------------------------------------------------------------------------------------------------- Fair value of plan assets at December 31 $ 59,010 $ 66,283 $ 672 $ 573 - -------------------------------------------------------------------------------------------------------- Funded status: Funded status at December 31 $ (1,916) $ 9,712 $ (1,427) $ (1,438) Unrecognized net actuarial (gain) loss 2,288 (9,832) 322 299 Unrecognized prior service cost 4,514 4,965 - - Unrecognized transition obligation - (37) 946 1,032 - -------------------------------------------------------------------------------------------------------- Prepaid (accrued) benefit cost $ 4,886 $ 4,808 $ (159) $ (107) - --------------------------------------------------------------------------------------------------------
The Company's supplemental retirement plan has an accumulated benefit obligation in excess of plan assets. The plan's accumulated benefit obligation was $326,000 and $286,000 at December 31, 2001 and 2000, respectively. There are no plan assets in the supplemental retirement plan due to the nature of the plan. Net periodic pension and other postretirement benefit costs include the following components for 2001, 2000 and 1999:
Other Postretirement Pension Benefits Benefits ---------------------------------------------------------- 2001 2000 1999 2001 2000 1999 ---------------------------------------------------------- (in thousands) Service cost $ 1,318 $ 1,682 $ 1,881 $ 71 $ 85 $ 99 Interest cost 4,133 4,509 4,130 138 268 261 Expected return on plan assets (5,829) (6,190) (6,259) (34) (39) (28) Amortization of transition obligation (36) (183) (183) 86 103 103 Recognized net actuarial (gain) loss (97) (142) (142) 19 63 111 Amortization of prior service cost 451 451 451 - - - - -------------------------------------------------------------------------------------------------------- $ (60) $ 127 $ (122) $ 280 $ 480 $ 546 - --------------------------------------------------------------------------------------------------------
41 The Company's pension plans provide for benefits on a "cash balance" basis. A cash balance plan provides benefits based upon a fixed percentage of an employee's annual compensation. 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. The postretirement benefit plans provide contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages. The Company has established trusts to partially fund its postretirement benefit obligations. The weighted average assumptions used in the measurement of the Company's benefit obligations for 2001 and 2000 are as follows:
Other Postretirement Pension Benefits Benefits -------------------------------------------------- 2001 2000 2001 2000 -------------------------------------------------- Discount rate 7.00% 7.25% 7.00% 7.25% Expected return on plan assets 9.00% 9.00% 5.00% 5.00% Rate of compensation increase 4.50% 4.50% n/a n/a - ---------------------------------------------------------------------------------------------
For measurement purposes an 8% annual rate of increase in the per capita cost of covered medical benefits and a 7.5% annual rate of increase in the per capita cost of dental benefits was assumed for 2002. These rates were assumed to gradually decrease to 6% for medical benefits and 5% for dental benefits for 2011 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
1% 1% Increase Decrease ------------------------- (in thousands) Effect on the total service and interest cost components $ 29 $ (25) Effect on postretirement benefit obligation $ 265 $(230) - ---------------------------------------------------------------------------------------------
(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:
2001 2000 1999 ------------------------------------ (in thousands) Sales $ 153,937 $ 110,920 $ 75,039 Production (lifting) costs (23,604) (19,804) (14,039) Depreciation, depletion and amortization (46,530) (39,048) (34,230) - --------------------------------------------------------------------------------------------- 83,803 52,068 26,770 Income tax expense (31,819) (20,023) (10,528) - --------------------------------------------------------------------------------------------- Results of operations $ 51,984 $ 32,045 $ 16,242 - ---------------------------------------------------------------------------------------------
The results of operations shown above exclude unusual items in 2000 and overhead and interest costs in all years. 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 2001, 2000 and 1999:
2001 2000 1999 ------------------------------------ (in thousands Proved property acquisition costs $ 7,323 $ 7,428 $ 10,456 Unproved property acquisition costs 4,482 5,941 9,389 Exploration costs 23,490 27,853 19,519 Development costs 63,103 27,519 19,059 - --------------------------------------------------------------------------------------------- Capitalized costs incurred $ 98,398 $ 68,741 $ 58,423 - --------------------------------------------------------------------------------------------- Amortization per Mcf equivalent $1.14 $1.06 $1.00 - ---------------------------------------------------------------------------------------------
42 Capitalized interest is included as part of the cost of oil and gas properties. The Company capitalized $1.6 million, $2.4 million and $3.3 million during 2001, 2000 and 1999, respectively, based on the Company's weighted average cost of borrowings used to finance the expenditures. In addition to capitalized interest, the Company also capitalized internal costs of $8.3 million, $7.3 million and $7.4 million during 2001, 2000 and 1999, respectively. These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of oil and gas properties. The following table shows the capitalized costs of gas and oil properties and the related accumulated depreciation, depletion and amortization at December 31, 2001 and 2000:
2001 2000 ------------------------- (in thousands) Proved properties $ 944,502 $ 841,875 Unproved properties 26,178 30,148 - ---------------------------------------------------------------------------------------------------------------------------- Total capitalized costs 970,680 872,023 Less: Accumulated depreciation, depletion and amortization 502,882 457,551 - ---------------------------------------------------------------------------------------------------------------------------- Net capitalized costs $ 467,798 $ 414,472 - ----------------------------------------------------------------------------------------------------------------------------
The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2001. Of the total, approximately $11.5 million is invested in Louisiana. The majority of Louisiana costs are related to seismic projects that will be evaluated over several years as the seismic data is interpreted and the acreage is explored. 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.
2001 2000 1999 Prior Total ----------------------------------------------------------- (in thousands) Property acquisition costs $ 4,385 $ 1,880 $ 913 $ 2,432 $ 9,610 Exploration costs 725 1,891 3,434 2,155 8,205 Capitalized interest 225 566 782 1,714 3,287 - ---------------------------------------------------------------------------------------------------------------------------- $ 5,335 $ 4,337 $ 5,129 $ 6,301 $ 21,102 - ----------------------------------------------------------------------------------------------------------------------------
(6) NATURAL GAS AND OIL RESERVES (UNAUDITED) The following table summarizes the changes in the Company's proved natural gas and oil reserves for 2001, 2000 and 1999:
2001 2000 1999 --------------------------------------------------------------------- Gas Oil Gas Oil Gas Oil (MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls) --------------------------------------------------------------------- Proved reserves, beginning of year 331,754 8,130 307,523 7,859 303,667 6,850 Revisions of previous estimates (21,598) (979) 5,357 (22) (7,464) 1,155 Extensions, discoveries, and other additions 77,187 1,272 53,389 1,347 34,730 225 Production (35,477) (719) (31,602) (676) (29,444) (578) Acquisition of reserves in place 4,325 21 8,100 82 9,762 576 Disposition of reserves in place (378) (21) (11,013) (460) (3,728) (369) Proved reserves, end of year 355,813 7,704 331,754 8,130 307,523 7,859 Proved, developed reserves: Beginning of year 270,830 7,100 250,290 7,154 258,092 6,370 End of year 281,461 6,429 270,830 7,100 250,290 7,154
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 or audited by the independent petroleum engineering firm of K & A Energy Consultants, Inc. 43 Following is the standardized measure relating to proved gas and oil reserves at December 31, 2001, 2000 and 1999:
2001 2000 1999 ---------------------------------------- (in thousands) Future cash inflows $ 1,095,843 $ 3,366,304 $ 989,997 Future production costs (313,357) (461,808) (195,131) Future development costs (57,136) (44,609) (32,230) Future income tax expense (182,103) (974,273) (247,408) - ------------------------------------------------------------------------------------------------------------------ Future net cash flows 543,247 1,885,614 515,228 10% annual discount for estimated timing of cash flows (235,087) (990,472) (253,153) - ------------------------------------------------------------------------------------------------------------------ Standardized measure of discounted future net cash flows $ 308,160 $ 895,142 $ 262,075 - ------------------------------------------------------------------------------------------------------------------
Under the standardized measure, future cash inflows were estimated by applying year-end prices, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pretax cash inflows. Future income taxes were computed by applying the year-end statutory rate, after consideration of permanent differences, to the excess of pretax cash inflows over the Company's tax basis in the associated proved gas and oil properties. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the standardized measure. Following is an analysis of changes in the standardized measure during 2001, 2000 and 1999:
2001 2000 1999 ---------------------------------------- (in thousands) Standardized measure, beginning of year $ 895,142 $ 262,075 $ 222,793 Sales and transfers of gas and oil produced, net of production costs (130,333) (91,116) (61,000) Net changes in prices and production costs (979,522) 837,691 48,506 Extensions, discoveries, and other additions, net of future production and development costs 102,832 259,212 48,279 Acquisition of reserves in place 5,406 33,032 14,765 Revisions of previous quantity estimates (24,966) 20,178 (612) Accretion of discount 133,136 38,076 32,447 Net change in income taxes 349,862 (317,527) (17,015) Changes in production rates (timing) and other (43,397) (146,479) (26,088) - ------------------------------------------------------------------------------------------------------------------ Standardized measure, end of year $ 308,160 $ 895,142 $ 262,075 - ------------------------------------------------------------------------------------------------------------------
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP The Company holds a 25% general partnership interest in NOARK. NOARK Pipeline was formerly a 258-mile intrastate gas transmission system which extended across northern Arkansas. In January 1998, the Company entered into an agreement with Enogex Inc. (Enogex) that resulted in the expansion of the NOARK Pipeline and provided the pipeline with access to Oklahoma gas supplies through an integration of NOARK with the Ozark Gas Transmission System (Ozark). Enogex is a subsidiary of OGE Energy Corp. Ozark was a 437-mile interstate pipeline system which began in eastern Oklahoma and terminated in eastern Arkansas. Enogex acquired the Ozark system and contributed it to NOARK. Enogex also acquired the NOARK partnership interests not owned by Southwestern. The acquisition of Ozark and its integration with NOARK Pipeline was approved by the Federal Energy Regulatory Commission in late 1998 at which time NOARK Pipeline was converted to an interstate pipeline and operated in combination with Ozark. Enogex funded the acquisition of Ozark and the expansion and integration with NOARK Pipeline which resulted in the Company's ownership interest in the partnership decreasing to 25% from 48%. The Company's investment in NOARK totaled $15.5 million at December 31, 2001 and 2000, including advances of $1.4 million made during 2001, $3.3 million made during 2000 and $2.3 million made during 1999. Advances are made primarily to service NOARK's long-term debt. See Note 11 for further discussion of NOARK's funding requirements and the Company's investment in NOARK. 44 NOARK's financial position at December 31, 2001 and 2000 is summarized below:
2001 2000 -------------------------- (in thousands) Current assets $ 8,363 $ 9,532 Noncurrent assets 175,299 179,136 - -------------------------------------------------------------------------------- $ 183,662 $ 188,668 - -------------------------------------------------------------------------------- Current liabilities $ 7,403 $ 11,803 Long-term debt 71,000 73,000 Partners' capital 105,259 103,865 - -------------------------------------------------------------------------------- $ 183,662 $ 188,668 - --------------------------------------------------------------------------------
The Company's share of NOARK's pretax loss was $1.5 million, $1.8 million and $2.0 million for 2001, 2000 and 1999, respectively. The Company records its share of NOARK's pretax loss in other income (expense) on the statements of operations. NOARK's results of operations for 2001, 2000 and 1999 are summarized below:
2001 2000 1999 ------------------------------------- (in thousands) Operating revenues $ 81,662 $ 73,633 $ 40,358 Pretax net loss $ (1,047) $ (1,391) $ (3,564) - --------------------------------------------------------------------------------
(8) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT 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, Customer Deposits, and Short-Term Debt: 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. Commodity and Interest Hedges: The fair value of all hedging financial instruments is the amount at which they could be settled, based on quoted market prices or estimates obtained from dealers. The carrying amounts and estimated fair values of the Company's financial instruments as of December 31, 2001 and 2000 were as follows:
2001 2000 ----------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value ----------------------------------------------- (in thousands) Cash $ 3,641 $ 3,641 $ 2,386 $ 2,386 Customer deposits $ 4,845 $ 4,845 $ 4,799 $ 4,799 Short-term debt - - $ 171,000 $ 171,000 Long-term debt $ 350,000 $ 356,179 $ 225,000 $ 226,309 Commodity and interest hedges $ 3,246 $ 3,246 $ (160) $ (60,596) - --------------------------------------------------------------------------------
Derivatives and Risk Management SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137 and SFAS No. 138, was adopted by the Company on January 1, 2001. SFAS No. 133 requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at its fair value. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a transition obligation of $60.6 million related to cash flow hedges in place that are intended to reduce the volatility in commodity prices for the Company's forecasted oil and gas production. At December 31, 2001, the Company recorded hedging assets of $10.3 million, hedging liabilities of $7.1 million, a regulatory asset of $5.8 million related to its utility gas purchase hedges, and a net of tax gain to other comprehensive income (equity section of the balance sheet) of $5.8 million. The amount recorded in other comprehensive income will be relieved over time and taken to the income statement as the physical transactions being hedged occur. There was no significant ineffectiveness during 2001 related to the Company's cash flow hedges and there were no discontinued hedges. Additional volatility in earnings and other comprehensive income may occur in the future as a result of the adoption of SFAS No. 133. 45 The Company uses natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. The Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price and interest rate risks. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. The Company uses over-the-counter natural gas and crude oil swap agreements and options to hedge sales of Company production, to hedge activity in its marketing segment, and to hedge the purchase of gas in its utility segment against the inherent price risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX (New York Mercantile Exchange) futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps), and (3) the purchase and sale of index-related puts and calls (collars) that provide a "floor" price below which the counterparty pays (production hedge) or receives (gas purchase hedge) funds equal to the amount by which the price of the commodity is below the contracted floor, and a "ceiling" price above which the Company pays to (production hedge) or receives from (gas purchase hedge) the counterparty the amount by which the price of the commodity is above the contracted ceiling. At December 31, 2001, the Company had outstanding natural gas price swaps on total notional volumes of 13.4 Bcf in 2002 and 9.2 Bcf in 2003 for which the Company will receive fixed prices ranging from $2.57 to $3.20 per MMBtu. Under contracts on .3 Bcf in 2002, the Company will make average fixed price payments of $2.96 per MMBtu and receive variable prices based on the NYMEX futures market. At December 31, 2001, the Company also had outstanding natural gas price swaps on total notional gas purchase volumes of 3.3 Bcf in 2002 for which the Company will pay an average fixed price of $4.20 per Mcf. At December 31, 2001, the Company had collars in place on 6.0 Bcf in 2002 and 4.1 Bcf in 2003 of future gas production. The 6.0 Bcf in 2002 had a floor and ceiling of $4.00 and $4.72, respectively. The 4.1 Bcf in 2003 had a floor and ceiling of $3.00 and $4.65, respectively. The Company's price risk management activities reduced revenues $10.3 million in 2001, $39.3 million in 2000, and $1.1 million in 1999. The Company has outstanding interest rate swaps on a notional amount of $100 million. Under these contracts the Company will make average fixed interest payments at 3.4% and receive variable prices based on the one-month LIBOR rate. The Company currently pays an additional 1.4% above LIBOR on its revolving credit facility. The primary market risks related to the Company's derivative contracts are the volatility in commodity prices, basis differentials and interest rates. However these market risks are offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of oil that is hedged, and payment of variable rate interest. Credit risk relates to the risk of loss as a result of non-performance by the Company's counterparties. The counterparties are primarily major investment and commercial banks which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure the Company has to each counterparty are periodically reviewed to ensure limited credit risk exposure. (9) STOCK OPTIONS The Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan) was adopted in February 2000 and provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2000 Plan replaces the Southwestern Energy Company 1993 Stock Incentive Plan (1993 Plan) and the Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors (1993 Director Plan). The 2000 Plan provides for grants of options, stock appreciation rights, shares of phantom stock, and shares of restricted stock that in the aggregate do not exceed 1,250,000 shares. 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 term of the 2000 Plan. The 1993 Plan provided for the compensation of officers and key employees of the Company and its subsidiaries through grants of options, shares of restricted stock, and stock bonuses that in the aggregate did not exceed 1,700,000 shares, the grant of stand-alone stock appreciation rights (SARs), shares of phantom stock and cash awards, the shares 46 related to which in the aggregate did not exceed 1,700,000 shares, and the grant of limited and tandem SARs (all terms as defined in the 1993 Plan). The Company has also awarded stock option grants outside the 2000 Plan and the 1993 Plan to certain non-officer employees and to certain officers at the time of their hire. The 2000 Plan awards each non-employee director who is eligible to participate in the plan an annual Director's Option with respect to 8,000 shares of common stock. Previously, the 1993 Director Plan provided for annual stock option grants of 12,000 shares (with 12,000 limited SARs) to each non-employee director. Options under the 1993 Director Plan were limited to no more than 240,000 shares. The Company's 1985 Nonqualified Stock Option Plan expired in 1992, except with respect to awards then outstanding. The following tables summarize stock option activity for the years 2001, 2000 and 1999 and provide information for options outstanding at December 31, 2001:
2001 2000 1999 ------------------------------------------------------------------ Weighted Weighted Weighted Number Average Number Average Number Average of Exercise of Exercise of Exercise Shares Price Shares Price Shares Price ------------------------------------------------------------------- Options outstanding at January 1 2,602,800 $ 9.79 2,061,199 $ 10.49 1,634,901 $ 12.15 Granted 170,200 $ 10.13 666,100 $ 7.58 562,250 $ 6.18 Exercised 11,252 $ 7.00 - - 1,333 $ 7.31 Canceled 89,562 $ 9.22 124,499 $ 9.55 134,619 $ 12.68 - ------------------------------------------------------------------------------------------------------------ Options outstanding at December 31 2,672,186 $ 9.84 2,602,800 $ 9.79 2,061,199 $ 10.49 - ------------------------------------------------------------------------------------------------------------
Options Outstanding Options Exercisable ------------------------------------------------------------------- Weighted Weighted Average Weighted Weighted Options Average Remaining Options Average Range of Outstanding Exercise Contractual Exercisable Exercise Exercise Prices at Year End Price Life (Years) at Year End Price - -------------------- ------------------------------------------------------------------- $6.00 - $7.00 558,018 $6.15 7.8 368,226 $6.15 $7.06 - $8.75 834,934 $7.41 8.2 441,229 $7.39 $9.06 - $13.38 740,300 $11.65 6.4 536,267 $12.26 $14.00 - $17.50 538,934 $14.95 3.3 480,372 $14.99 - -------------------- ------------------------------------------------------------------- 2,672,186 $9.84 1,826,094 $10.57 - ------------------------------------------------------------------------------------------------------------
All options are issued at fair market value at the date of grant and expire ten years from the date of grant. Options generally vest to employees and directors over a three to four year period from the date of grant. Of the total options outstanding, 325,000 performance accelerated options were granted in 1994 at an option price of $14.63. These options vest over a four-year period beginning in 2000. The Company applies the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation." Accordingly, no compensation cost has been recognized for the stock option plans. Had compensation cost for the Company's stock option plans been determined consistent with the provisions of SFAS No. 123, the Company's net income (loss) and earnings (loss) per share would have been reduced to the pro forma amounts indicated below:
2001 2000 1999 ------------------------------- Net income (loss), in thousands As reported $ 35,324 $(46,687) $ 9,927 Pro forma $ 34,373 $(47,444) $ 9,241 Basic earnings (loss) per share As reported $1.40 $(1.86) $.40 Pro forma $1.36 $(1.90) $.37 Diluted earnings (loss) per share As reported $1.38 $(1.86) $.40 Pro forma $1.34 $(1.90) $.37 - ------------------------------------------------------------------------------------------------------------
47 Because the SFAS No. 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: no dividend yield; expected volatility of 46.4%; risk-free interest rate of 4.8%; and expected lives of 6 years. The Company has granted 752,995 shares of restricted stock to employees through 2001. Of this total, 421,895 shares vest over a three-year period, 288,550 shares vest over a four-year period, and the remaining shares vest over a five-year period. The related compensation expense is being amortized over the vesting periods. As of December 31, 2001, 295,146 shares have vested to employees and 41,480 shares have been canceled and returned to treasury shares. (10) COMMON STOCK PURCHASE RIGHTS In 1999, the Company's Common Share Purchase Rights Plan was amended and extended for an additional ten years. Per the terms of the amended plan, 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 $40.00, subject to adjustment. These rights will become exercisable in the event that a person or group acquires or commences a tender or exchange offer for 15% 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 15% of the common stock (10% or more if the Board determines such acquiror is adverse), rightholders (other than the 15% 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 $.01 per right or exchanged for common shares on a one-for-one basis 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 2009. (11) CONTINGENCIES AND COMMITMENTS The Company and the other general partner of NOARK have severally guaranteed the principal and interest payments on NOARK's 7.15% Notes due 2018. The Company's share of the several guarantee is 60%. At December 31, 2001 and 2000, the principal outstanding for these Notes was $73.0 million and $75.0 million, respectively. The Notes were issued in June 1998 and require semi-annual principal payments of $1.0 million. Under the several guarantee, the Company is required to fund its share of NOARK's debt service which is not funded by operations of the pipeline. As a result of the integration of NOARK Pipeline with the Ozark Gas Transmission System, as discussed further in Note 7, management of the Company believes that it will realize its investment in NOARK over the life of the system. Therefore, no provision for any loss has been made in the accompanying financial statements. Additionally, the Company's gas distribution subsidiary has transportation contracts for firm capacity of 66.9 MMcfd on NOARK's integrated pipeline system. These contracts expire in 2002 and 2003, and are renewable year-to-year thereafter until terminated by 180 days' notice. The Company recently settled litigation, subject to court approval, in a case filed against the Company and two of its subsidiaries in a state court in Sebastian County, Arkansas related to the Company's Stockton Gas Storage Facility in Franklin County, Arkansas (the "Stockton Storage Facility"). As previously disclosed, this class action suit was filed on August 25, 2000 on behalf of a class of plaintiffs comprised of all surface owners, mineral owners, royalty owners and overriding royalty owners in the Stockton Storage Facility. Plaintiffs alleged various wrongful, intentional and fraudulent acts relating to the operation of the storage pool beginning in 1968 and continuing to the present, and claimed ownership rights in the gas that the Company has stored in the storage pool in an amount in excess of $5 million in actual damages, interest, attorney's fees and punitive damages. Under the terms of the settlement, the Company has agreed to pay the plaintiffs a cash settlement amount and enter into new gas storage agreements at rental rates commensurate with current market prices. The settlement of this litigation did not have a material impact on the Company's result of operations for 2001. 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. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or reported results of operations of the Company. 48 The Company is subject to other litigation and claims that have arisen in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such litigation and claims will not have a material effect on the results of operations or the financial position of the Company. (12) SEGMENT INFORMATION The Company applies SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information." The Company's reportable business segments have been identified based on the differences in products or services provided. Revenues for the exploration and production segment are derived from the production and sale of natural gas and crude oil. Revenues for the gas distribution segment arise from the transportation and sale of natural gas at retail. The marketing segment generates revenue through the marketing of both Company and third party produced gas volumes. Summarized financial information for the Company's reportable segments is shown in the following table. The "Other" column includes items related to non-reportable segments (real estate and pipeline operations) and corporate items.
Exploration and Gas Production Distribution Marketing Other Total --------------------------------------------------------------------- 2001 (in thousands) Revenues from external customers $ 126,006 $ 147,082 $ 71,839 $ - $ 344,927 Intersegment revenues 27,931 200 118,486 448 147,065 Operating income 69,340 10,346 2,703 280 82,669 Depreciation, depletion and amortization expense 46,530 6,163 111 95 52,899 Interest expense (1) 18,238 4,413 34 1,014 23,699 Provision (benefit) for income taxes (1) 19,164 2,505 996 (748) 21,917 Assets 526,346 169,931 8,026 38,820(2) 743,123 Capital expenditures 98,964(3) 5,347 - 1,749 106,060 - --------------------------------------------------------------------------------------------------------------------------------- 2000 Revenues from external customers $ 75,597 $ 151,052 $ 137,234 $ - $ 363,883 Intersegment revenues 35,323 182 70,514 448 106,467 Unusual items (4) 111,288 - - - 111,288 Operating income (loss) (70,584) 14,655 2,460 - (53,469) Depreciation, depletion and amortization expense 39,048 6,625 109 87 45,869 Interest expense (1) 17,472 4,608 16 1,134 23,230 Provision (benefit) for income taxes (1) (34,153) 4,869 912 (533) (28,905) Assets 460,296 188,811 20,929 35,342(2) 705,378 Capital expenditures 69,211 5,994 24 488 75,717 - --------------------------------------------------------------------------------------------------------------------------------- 1999 Revenues from external customers $ 51,533 $ 132,293 $ 96,570 $ - $ 280,396 Intersegment revenues 23,506 127 40,956 416 65,005 Operating income 16,451 17,187 2,142 278 36,058 Depreciation, depletion and amortization expense 34,230 7,186 92 95 41,603 Interest expense (1) 11,345 5,027 - 979 17,351 Provision (benefit) for income taxes (1) 1,806 4,569 859 (785) 6,449 Assets 435,022 190,731 11,212 34,481(2) 671,446 Capital expenditures 59,004 7,124 9 830 66,967 - --------------------------------------------------------------------------------------------------------------------------------- (1) Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as debt and income tax expense (benefit) are incurred at the corporate level. (2) Other assets include the Company's equity investment in the operations of NOARK (see Note 7), corporate assets not allocated to segments, and assets for non-reportable segments. (3) Includes $13.5 million funded by the owner of the minority interest in Overton partnership. (4) Includes $109.3 million for the Hales judgment and $2.0 million for other litigation.
Intersegment sales by the exploration and production segment and marketing segment to the gas distribution segment are priced in accordance with terms of existing contracts and current market conditions. Parent company assets include furniture and fixtures, prepaid debt costs, and prepaid pension costs. Parent company general and administrative costs, depreciation expense and taxes other than income are allocated to segments. All of the Company's operations are located within the United States. 49 (13) QUARTERLY RESULTS (UNAUDITED) The following is a summary of the quarterly results of operations for the years ended December 31, 2001 and 2000:
--------------------------------------------------------- March 31 June 30 September 30 December 31 --------------------------------------------------------- (in thousands, except per share amounts) 2001 --------------------------------------------------------- Operating revenues $ 137,129 $ 76,023 $ 59,396 $ 72,379 Operating income $ 32,599 $ 18,015 $ 14,263 $ 17,792 Net income $ 16,013 $ 6,869 $ 5,018 $ 7,424 Basic earnings per share $.64 $.27 $.20 $.29 Diluted earnings per share $.63 $.27 $.20 $.29 2000 --------------------------------------------------------- Operating revenues $ 96,913 $ 78,483 $ 75,342 $ 113,145 Operating income (loss) $ 21,056 $(101,849) $ 5,884 $ 21,440 Net income (loss) $ 9,186 $ (64,199) $ (754) $ 9,080 Basic and diluted earnings (loss) per share $.37 $(2.57) $(.03) $.36 - ----------------------------------------------------------------------------------------------------------
(14) NEW ACCOUNTING STANDARDS In July 2001, the FASB issued Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS No. 141), Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), and Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). In October, 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead be tested for impairment at least annually in accordance with the provisions of SFAS No. 142. The Company was required to adopt the provisions of SFAS No. 141 immediately, and SFAS No. 142 effective January 1, 2002. Adoption of SFAS No. 141 and SFAS No. 142 had no impact on the Company's results of operations or financial condition. SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends FASB Statement No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. The effect of this standard on the Company's results of operations and financial condition is being evaluated. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and amends Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - - Reporting the Effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS No. 144 retains the basic framework of SFAS No. 121, resolves certain implementation issues of SFAS No. 121, extends applicability to discontinued operations, and broadens the presentation of discontinued operations to include a component of an entity. SFAS No. 144 is effective for financial statements issued for fiscal years beginning after December 15, 2001. Adoption of SFAS No. 144 had no impact on the Company's results of operations or financial position. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There have been no changes in or disagreements with the Company's independent public accountants on accounting and financial disclosure. 50 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 15, 2002 (the 2002 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 "Share Ownership of Management and Directors" 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 2002 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 2002 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 sections "Security Ownership of Certain Beneficial Owners" and "Share Ownership of Management and Directors" for information about security ownership of certain beneficial owners and management. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The 2002 Proxy Statement is hereby incorporated by reference for the purpose of providing information about related transactions. Refer to the section "Share Ownership of Management and Directors" 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 consolidated financial statements of the Company and its subsidiaries and the report of independent public accountants are included in Item 8 of this Report. (2) The consolidated financial statement schedules have been omitted because they are not required under the related instructions, or are not applicable. (3) The exhibits listed on the accompanying Exhibit Index (pages 53 and 54) are filed as part of, or incorporated by reference into, this Report. (b) Reports on Form 8-K: A Current Report on Form 8-K was filed on October 18, 2001, referencing a conference call conducted on October 17, 2001, announcing the results of the Company's third quarter 2001 activity. 51 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused the report to be signed on its behalf by the undersigned, thereunto duly authorized. SOUTHWESTERN ENERGY COMPANY -------------------------------- (Registrant) Dated: March 29, 2002 BY: /s/ Greg D. Kerley -------------------------------- Greg D. Kerley Executive Vice President 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 29, 2002. /s/ Harold M. Korell President, Chief Executive Officer - ------------------------------------ and Director Harold M. Korell /s/ Greg D. Kerley Executive Vice President - ------------------------------------ and Chief Financial Officer Greg D. Kerley /s/ Stanley T. Wilson Controller and Chief Accounting Officer - ------------------------------------ Stanley T. Wilson /s/ Charles E. Scharlau Director and Chairman - ------------------------------------ Charles E. Scharlau /s/ Lewis E. Epley, Jr. Director - ------------------------------------ Lewis E. Epley, Jr. /s/ John Paul Hammerschmidt Director - ------------------------------------ John Paul Hammerschmidt /s/ Robert L. Howard Director - ------------------------------------ Robert L. Howard /s/ Kenneth R. Mourton Director - ------------------------------------ Kenneth R. Mourton Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant of Section 12 of the Act. Not Applicable 52 EXHIBIT INDEX Exhibit No. Description ------- ----------- 3. Articles of Incorporation and Bylaws of the Company (amended and restated Articles of Incorporation incorporated by reference to Exhibit 3 to Annual Report on Form 10-K for the year ended December 31, 1993); Bylaws of the Company (amended Bylaws of the Company incorporated by reference to Exhibit 3 to Annual Report on Form 10-K for the year ended December 31, 1994). 4.1 Amended and Restated Rights Agreement dated April 12, 1999 (incorporated by reference to Exhibit 4.1 to Annual Report on Form 10-K for the year ended December 31, 1999), as amended by Amendment No. 1 to the Amended and Restated Rights Agreement dated March 15, 2002 (filed herewith). 4.2 Prospectus, Registration Statement, and Indenture on 6.70% Senior Notes due December 1, 2005 and issued December 5, 1995 (incorporated by reference to the Company's Forms S-3 and S-3/A filed on November 1, 1995, and November 17, 1995, respectively, and also to the Company's filings of a Prospectus and Prospectus Supplement on November 22, 1995, and December 4, 1995, respectively). 4.3 Prospectus Supplement and Form of Distribution Agreement on $125,000,000 of Medium-Term Notes dated February 21, 1997 (Prospectus Supplement incorporated by reference to the Company's filing of a Prospectus Supplement on February 21, 1997, Form of Distribution Agreement incorporated by reference to Exhibit 10 filed with the Company's Form 8-K dated February 21, 1997). 4.4 Short-Term Credit Agreement dated July 17, 2000 between Southwestern Energy Company and Bank One, N.A., as administrative agent, and Bank of America, N.A., as syndication agent (incorporated by reference to Exhibit 4.4 to Annual Report on Form 10-K for the year ended December 31, 2000). 4.5 Credit Agreement dated July 12, 2001 between Southwestern Energy Company and The Lenders; Bank One, N.A., as administrative agent, and Royal Bank of Canada, as syndication agent (filed herewith). 10.1 Compensation Plans: (a) Southwestern Energy Company Incentive Compensation Plan, effective January 1, 1993, and Amended and Restated as of January 1, 1999 (incorporated by reference to Exhibit 10.2(b) to Annual Report on Form 10-K for the year ended December 31, 1998). (b) Nonqualified Stock Option Plan, effective February 22, 1985, as amended July 10, 1989 (replaced by Southwestern Energy Company 1993 Stock Incentive Plan, dated April 7, 1993, which was replaced by the Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000) (original plan incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for the year ended December 31, 1985; amended plan incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for the year ended December 31, 1989). (c) Southwestern Energy Company 1993 Stock Incentive Plan, dated April 7, 1993 and Amended and Restated as of February 18, 1998 (replaced by the Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000) (incorporated by reference to Exhibit 10.2(d) to Annual Report on Form 10-K for the year ended December 31, 1998). (d) Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors, dated April 7, 1993 (replaced by the Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000) (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). (e) Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000 (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 24, 2000). 53 Exhibit No. Description ------- ----------- 10.2 Southwestern Energy Company Supplemental Retirement Plan, adopted May 31, 1989, and Amended and Restated as of December 15, 1993, and as further amended February 1, 1996 (amended and restated plan incorporated by reference to Exhibit 10.5 to Annual Report on Form 10-K for the year ended December 31, 1993; amendment dated February 1, 1996, incorporated by reference to Exhibit 10.5 to Annual Report on Form 10-K for the year ended December 31, 1995). 10.3 Southwestern Energy Company Supplemental Retirement Plan Trust, dated December 30, 1993 (incorporated by reference to Exhibit 10.6 to Annual Report on Form 10-K for the year ended December 31, 1993). 10.4 Southwestern Energy Company Nonqualified Retirement Plan, effective October 4, 1995 (incorporated by reference to Exhibit 10.7 to Annual Report on Form 10-K for the year ended December 31, 1995). 10.5 Employment and Consulting Agreement for Charles E. Scharlau, dated May 21, 1998 (incorporated by reference to Exhibit 10.9 to Annual Report on Form 10-K for the year ended December 31, 1998). 10.6 Form of Indemnity Agreement, between the Company and each officer and director of the Company (incorporated by reference to Exhibit 10.20 to Annual Report on Form 10-K for the year ended December 31, 1991). 10.7 Form of Executive Severance Agreement for the Executive Officers of the Company, effective February 17, 1999 (incorporated by reference to Exhibit 10.12 to Annual Report on Form 10-K for the year ended December 31, 1998). 10.8 Amended and Restated Limited Partnership Agreement of NOARK Pipeline System, Limited Partnership dated January 12, 1998 and amended June 18, 1998 (amended and restated agreement incorporated by reference to Exhibit 10.18 to Annual Report on Form 10-K for the year ended December 31, 1997; first amendment thereto incorporated by reference to Exhibit 10.14 to Annual Report on Form 10-K for the year ended December 31, 1998). 21. Subsidiaries of the Registrant (filed herewith). 23. Consent of Arthur Andersen LLP (filed herewith). 99.1 Letter to Commission pursuant to Temporary Note 3T dated March 29, 2002 (filed herewith). 54 SOUTHWESTERN ENERGY COMPANY AND EQUISERVE TRUST COMPANY, N.A. Rights Agent ------------------------- Amendment No. 1 to the Amended and Restated Rights Agreement Dated as of March 15, 2002 AMENDMENT NO. 1 TO THE AMENDED AND RESTATED RIGHTS AGREEMENT This Amendment No. 1 to the Amended and Restated Rights Agreement (this "Amendment"), dated as of March 15, 2002, between Southwestern Energy Company, an Arkansas corporation (the "Company"), and Equiserve Trust Company, N.A., successor to The First National Bank of Chicago (the "Rights Agent"). All capitalized terms used in this Amendment and not otherwise defined shall have the respective meanings set forth in the Amended and Restated Rights Agreement (as defined below). W I T N E S S E T H: - - - - - - - - - - WHEREAS, on May 5, 1989 (the "Declaration Date"), the Board of Directors of the Company authorized and declared a dividend of one right representing the right to purchase one share of Common Stock upon the terms and subject to the conditions set forth in a Rights Agreement, dated May 5, 1989, between the Company and the Rights Agent (the "1989 Rights Agreement") for each outstanding share of common stock, $2.50 par value, of the Company outstanding at the close of business on May 19, 1989 (the "Record Date"), and authorized the issuance of one Right with respect to each share of Common Stock that shall become outstanding between the Record Date and the earlier of the Distribution Date and the Expiration Date, each Right initially representing the right to purchase one share of Common Stock upon the terms and subject to the conditions hereinafter set forth; WHEREAS, the Company declared a three-for-one stock split in 1993 and, in connection with such split, the number of Rights was adjusted pursuant to Section 11 of the 1989 Rights Agreement such that each certificate for Common Stock outstanding as of the date of this Amended and Restated Rights Agreement also represents one Right under the 1989 Rights Agreement representing the right to purchase one share of Common Stock upon the terms and subject to the conditions set forth in the 1989 Rights Agreement; WHEREAS, on April 12, 1999, in compliance with the terms of Section 27 of the 1989 Rights Agreement, the Company and the Rights Agent entered into an Amended and Restated Rights Agreement (the "Amended and Restated Rights Agreement") which amended and restated the 1989 Rights Agreement in its entirety in order to extend the Expiration Date until April 12, 2009 and to make other changes and provisions that they determined were necessary or desirable and did not adversely affect the interests of the holders of the Rights; WHEREAS, the Company wishes to amend the Amended and Restated Rights Agreement in order to eliminate the requirement of all required approvals of Independent Directors; WHEREAS, in compliance with the terms of Section 27 of the Amended and Restated Rights Agreement, the Company has (i) delivered to the Rights Agent a certificate from an appropriate officer of the Company which states that this Amendment has been approved by the Company's Board of Directors and is in compliance with the terms of Section 27 of the 1 Amended and Restated Rights Agreement and (ii) instructed the Rights Agent to execute this Amendment; NOW, THEREFORE, in consideration of the premises and the mutual agreements herein set forth, the parties hereby agree as follows: Section l. Definitions. (a) The definition of "Approved Offer" contained in subparagraph (d) of Section 1 of the Amended and Restated Rights Agreement is hereby amended in its entirety to read as follows: ""Approved Offer" shall mean a tender or exchange offer for all outstanding shares of Common Stock that is at a price and on terms approved, prior to the acceptance for payment of shares under such tender or exchange offer, by the Board of Directors of the Company based upon the prior recommendation of a majority of the board of directors." (b) The references to the defined terms "Independent Directors" and "Proposed Acquiror" contained in subparagraph (m) of Section 1 are hereby deleted. Section 2. Redemption. Subparagraph (a) of Section 23 of the Amended and Restated Rights Agreement is amended in its entirety to read as follows: "(a) The Company may, by resolution of its Board of Directors, at its option, at any time prior to the earlier of (x) the Stock Acquisition Date or (y) the close of business on the Final Expiration Date, redeem all but not less than all of the then outstanding Rights at a redemption price of $0.01 per Right, as such amount may be appropriately adjusted to reflect any stock split, stock dividend or similar transaction occurring after the date of this Amended and Restated Rights Agreement (such redemption price being hereinafter referred to as the "Redemption Price"). The Company may , at its option, pay the Redemption Price in cash, shares of Common Stock (based on the "current market price", as defined in Section 11(d)(i) hereof, of the Common Stock at the time of such Board resolution) or any other form of consideration deemed appropriate by the Board of Directors." Section 3. Exchange. Subparagraph (a) of Section 24 of the Amended and Restated Rights Agreement is amended in its entirety to read as follows: "(a) The Board of Directors of the Company may, at its option, at any time after the Stock Acquisition Date exchange all or part of the then-outstanding and exercisable Rights (which shall not include Rights that have become void pursuant to the provisions of Section 11(a)(iii) hereof) for Common Stock (or Common Stock Equivalents) at an exchange ratio of one share of Common Stock per Right, appropriately adjusted to reflect any stock split, stock dividend or similar transaction occurring after the date of this Amended and Restated Rights Agreement (such exchange ratio being hereinafter referred to as the "Exchange Ratio"). Notwithstanding the foregoing, the Board of Directors of the Company shall not be empowered to effect such exchange at any time after any Person (other than a Company Entity), together with all Affiliates and Associates of such Person, becomes the Beneficial Owner of 50% or more of the Common Stock then outstanding." 2 Section 4. Supplements and Amendments. Section 27 of the Amended and Restated Rights Agreement is amended in its entirety to read as follows: "The Company and the Rights Agent shall, if the Company so directs, from time to time supplement or amend this Agreement without the approval of any holders of Rights in order (i) to cure any ambiguity, (ii) to correct or supplement any provision contained herein which may be defective or inconsistent with any other provisions herein (provided that any amendment made pursuant to clause (i) or (ii) hereof after a Stock Acquisition Date, shall not materially adversely affect the interests of the holders of Right Certificates (other than an Acquiring Person or any Affiliate or Associate thereof)), (iii) prior to the Stock Acquisition Date, to effect any other change or modification which the Company may deem necessary or desirable, or (iv) after the Stock Acquisition Date, to make any other provisions in regard to matters or questions arising hereunder which the Company may deem necessary or desirable and which shall not adversely affect the interests of the holders of Right Certificates (other than an Acquiring Person or any Affiliate or Associate thereof). Notwithstanding anything contained in this Agreement to the contrary, this Agreement may not be amended or supplemented (x) to reinstate a right of redemption if the Rights are not then redeemable or (y) to decrease the Redemption Price. Upon the delivery of a certificate from an appropriate officer of the Company which states that the proposed supplement or amendment has been approved by the Company's Board of Directors and is in compliance with the terms of this Section 27, the Rights Agent shall execute such supplement or amendment; provided, however, that the Rights Agent may, but shall not be obligated to, enter into any such supplement or amendment that adversely affects its rights, duties or immunities under this Agreement. Prior to the Distribution Date, the interests of the holders of Rights shall be deemed to coincide with the interests of holders of shares of Common Stock (other than an Acquiring Person, an Adverse Person or any Affiliate or Associate thereof)." Section 5. Determinations and Actions by the Board of Directors, etc. Section 31 of the Amended and Restated Rights Agreement is amended in its entirety to read as follows: "The Board of Directors of the Company shall have the exclusive power and authority to administer this Agreement and to exercise all rights and powers specifically granted to the Board of Directors or to the Company, or as may be necessary or advisable in the administration of this Agreement, including, without limitation, the right and power to (i) interpret the provisions of this Agreement, and (ii) make all determinations deemed necessary or advisable for the administration of this Agreement (including, without limitation, a determination to redeem or not to redeem the Rights pursuant to Section 23 hereof or to supplement or amend the Agreement and whether any proposed supplement or amendment adversely affects the interests of the holders of Right Certificates and comports with the requirements of Section 27 hereof or to find or to announce publicly that any Person has become an Acquiring Person or an Adverse Person). For all purposes of this Agreement, any calculation of the number of shares of Common Stock or other securities outstanding at any particular time, including for purposes of determining the particular percentage of such outstanding shares of Common Stock or any other securities of which any Person is the Beneficial Owner, shall be made in accordance with the last sentence of Rule 13d-3(d)(1)(i) of the General Rules and Regulations under the Exchange Act as in effect on the date of this Agreement. All such actions, calculations, interpretations and determinations (including for purpose of clause (y) below, all omissions with respect to the 3 foregoing) which are done or made by the Board of Directors of the Company in good faith, shall (x) be final, conclusive and binding on the Company, the Rights Agent, the holders of the Rights and all other parties, and (y) no subject the Board of Directors or any director to any liability to the holders of the Rights." Section 6. Governing Law. This Amendment shall be deemed to be a contract made under the laws of the State of Arkansas and for all purposes shall be governed by and construed in accordance with the laws of such state applicable to contracts to be made and performed entirely within such state. Section 7. Counterparts. This Amendment may be executed in any number of counterparts and each of such counterparts shall for all purposes be deemed to be an original, and all such counterparts shall together constitute but one and the same instrument. Section 8. Descriptive Headings. Descriptive headings of the several Sections of this Agreement are inserted for convenience only and shall not control or affect the meaning or construction of any of the provisions hereof. Section 9. Ratification of the Amended and Restated Rights Agreement. Except as expressly amended hereby, the Amended and Restated Rights Agreement is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and their respective corporate seals to be hereunto affixed and attested, all as of the date and the year first above written. Attest: SOUTHWESTERN ENERGY COMPANY By: /S/ MARK K. BOLING By: /S/ GREG D. KERLEY ---------------------------- -------------------------------- Mark K. Boling, Secretary Gregory D. Kerley, Executive Vice President and Chief Financial Officer Attest: EQUISERVE TRUST COMPANY, N.A. By: By: -------------------------- -------------------------------- Title: Title: 4 ================================================================================ CREDIT AGREEMENT DATED AS OF JULY 12, 2001 AMONG SOUTHWESTERN ENERGY COMPANY, THE LENDERS, BANK ONE, NA, AS ADMINISTRATIVE AGENT, AND ROYAL BANK OF CANADA, AS SYNDICATION AGENT BANC ONE CAPITAL MARKETS, INC. AS LEAD ARRANGER AND BOOK RUNNER ================================================================================ CREDIT AGREEMENT This Agreement, dated as of July 12, 2001, is among Southwestern Energy Company, the Lenders, Bank One, NA, a national banking association having its principal office in Chicago, Illinois, as Administrative Agent, and Royal Bank of Canada, as Syndication Agent. The parties hereto agree as follows: ARTICLE I DEFINITIONS As used in this Agreement: "Administrative Agent" means Bank One in its capacity as administrative agent for the Lenders pursuant to Article X, and not in its individual capacity as a Lender, and any successor Administrative Agent appointed pursuant to Article X. "Advance" means a group of Loans (i) made by the Lenders on the same Borrowing Date or (ii) converted or continued by the Lenders on the same date of conversion or continuation and, in either case, consisting of Ratable Loans of the same Type and, in the case of Eurodollar Loans, for the same Interest Period. "Affected Lender" is defined in Section 2.20. "Affiliate" of any Person means any other Person directly or indirectly controlling, controlled by or under common control with such Person. A Person shall be deemed to control another Person if the controlling Person owns 10% or more of any class of voting securities (or other ownership interests) of the controlled Person or possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of the controlled Person, whether through ownership of stock, by contract or otherwise. "Aggregate Commitment" means the aggregate of the Commitments of all the Lenders, as reduced from time to time pursuant to the terms hereof. "Agreement" means this credit agreement, as it may be amended or modified and in effect from time to time. "Agreement Accounting Principles" means generally accepted accounting principles as in effect from time to time; provided that if the Borrower notifies the Administrative Agent that the Borrower does not want to give effect to any change in generally accepted accounting principles (or if the Administrative Agent notifies the Borrower that the Required Lenders do not want to give effect to any such change), then Agreement Accounting Principles shall mean generally accepted accounting principles as in effect immediately before the relevant change in generally accepted accounting principles became effective, until either such notice is withdrawn or this Agreement is amended in a manner satisfactory to the Borrower and the Required Lenders. "Alternate Base Rate" means, for any day, a rate of interest per annum equal to the higher of (i) the Prime Rate for such day and (ii) the sum of the Federal Funds Effective Rate for such day plus 0.5% per annum. "Applicable Margin" means the "Applicable Margin" as determined in accordance with Schedule 1B. "Arranger" means Banc One Capital Markets, Inc. "Article" means an article of this Agreement unless another document is specifically referenced. "Asset Sale" means any sale, lease, assignment for value or other disposition by the Borrower or any Subsidiary, excluding (a) sales and other dispositions in the ordinary course of business and (b) any sale or other disposition of any asset listed on Schedule 2.8(a). "Authorized Officer" means any of the following officers of the Borrower, acting singly: the Chief Executive Officer, the President, the Chief Financial Officer, the Treasurer or any Executive Vice President, Senior Vice President or Vice President. "Bank One" means Bank One, NA, a national banking association having its principal office in Chicago, Illinois, in its individual capacity, and its successors. "Borrower" means Southwestern Energy Company, an Arkansas corporation, and its successors and assigns. "Borrowing Date" means a date on which an Advance or a Swing Line Loan is made hereunder. "Borrowing Notice" is defined in Section 2.4. "Business Day" means (i) with respect to any borrowing, payment or rate selection of Eurodollar Advances, a day (other than a Saturday or Sunday) on which banks generally are open in Chicago, Dallas and New York for the conduct of substantially all of their commercial lending activities, interbank wire transfers can be made on the Fedwire system and dealings in United States dollars are carried on in the London interbank market and (ii) for all other purposes, a day (other than a Saturday or Sunday) on which banks generally are open in Chicago and Dallas for the conduct of substantially all of their commercial lending activities and interbank wire transfers can be made on the Fedwire system. -2- "Capitalized Lease" of a Person means any lease of Property, except oil and gas leases, by such Person as lessee which would be capitalized on a balance sheet of such Person prepared in accordance with Agreement Accounting Principles. "Capitalized Lease Obligations" of a Person means the amount of the obligations of such Person under Capitalized Leases which would be shown as a liability on a balance sheet of such Person prepared in accordance with Agreement Accounting Principles. "Cash Equivalent Investments" means, at any time, (a) any evidence of Debt, maturing not more than one year after such time, issued or guaranteed by the United States Government or any agency thereof, (b) commercial paper, maturing not more than one year from the date of issue, or corporate demand notes, in each case (unless issued by a Lender or its holding company) rated at least A-l by Standard & Poor's Ratings Group or P-l by Moody's Investors Service, Inc., (c) any certificate of deposit (or time deposits represented by such certificates of deposit) or bankers acceptance, maturing not more than one year after such time, or overnight Federal Funds transactions that are issued or sold by a commercial banking institution that is a member of the Federal Reserve System and has a combined capital and surplus and undivided profits of not less than $500,000,000, (d) any repurchase agreement entered into with any Lender (or other commercial banking institution of the stature referred to in clause (c)) which (i) is secured by a fully perfected security interest in any obligation of the type described in any of clauses (a) through (c) and (ii) has a market value at the time such repurchase agreement is entered into of not less than 100% of the repurchase obligation of such Lender (or other commercial banking institution) thereunder and (e) investments in short-term asset management accounts offered by any Lender for the purpose of investing in loans to any corporation (other than the Company or an Affiliate of the Company), state or municipality, in each case organized under the laws of any state of the United States or of the District of Columbia. "Change of Control" means that (i) any Person or group (within the meaning of Rule 13d-5 under the Securities Exchange Act of 1934, as amended) shall beneficially own, directly or indirectly, 25% or more of the common stock or other voting securities of the Borrower; or (ii) Continuing Directors shall fail to constitute a majority of the Board of Directors of the Borrower. For purposes of the foregoing, "Continuing Director" means an individual who (x) is a member of the Board of Directors of the Borrower on the date of this Agreement or (y) is nominated to be a member of such Board of Directors after the date hereof by a majority of the Continuing Directors then in office. "Code" means the Internal Revenue Code of 1986, as amended, reformed or otherwise modified from time to time. "Commitment" means, for each Lender, the obligation of such Lender to make Ratable Loans, and participate in Swing Line Loans, not exceeding the amount set forth on Schedule 1A or as set forth in any assignment that has become effective pursuant to Section 12.3.2, as such amount may be modified from time to time pursuant to the terms hereof. -3- "Commitment Fee Rate" means the "Commitment Fee Rate" as determined in accordance with Schedule 1B. "Commitment Reduction Date" is defined in Section 2.8. "Contingent Obligation" of a Person means any agreement, undertaking or arrangement by which such Person assumes, guarantees, endorses, contingently agrees to purchase or provide funds for the payment of, or otherwise becomes or is contingently liable upon, the obligation or liability of any other Person, or agrees to maintain the net worth or working capital or other financial condition of any other Person, or otherwise assures any creditor of such other Person against loss, including, without limitation, any comfort letter, operating agreement, take or pay contract, application for a Letter of Credit or the obligations of any such Person as general partner of a partnership with respect to the liabilities of the partnership. "Conversion/Continuation Notice" is defined in Section 2.5. "Controlled Group" means all members of a controlled group of corporations or other business entities and all trades or businesses (whether or not incorporated) under common control which, together with the Borrower or any of its Subsidiaries, are treated as a single employer under Section 414 of the Code. "Debt Issuance " means the issuance by the Borrower or any Subsidiary of any Indebtedness other than: (a) Indebtedness under the Loan Documents; (b) Indebtedness existing on the date hereof and extensions, renewals, refinancings and replacements thereof that do not increase the outstanding principal amount thereof or result in an earlier maturity date or a decreased weighted average life thereof; (c) Indebtedness under the revolving credit facility between the Borrower and McIlroy Bank & Trust and any extension, renewal, refinancing or replacement thereof so long as the aggregate principal amount thereof does not at any time exceed $4,500,000; (d) Indebtedness of the Borrower to any Subsidiary or of any Subsidiary to the Borrower or any other Subsidiary; (e) Indebtedness described in clause (ii), (iii), (v), (vi), (viii) or (xi) of the definition of "Indebtedness"; and (f) Indebtedness of the Borrower or any Subsidiary that was Indebtedness of any other Person existing at the time such other Person was merged with or became a Subsidiary and extensions, renewals, refinancings and replacements of any such -4- Indebtedness that do not increase the outstanding principal amount thereof or result in an earlier maturity date or decreased weighted average life thereof, excluding Indebtedness incurred in connection with, or in contemplation of, such other Person's merging with or becoming a Subsidiary. "Debt to Capitalization Ratio" means the ratio of (a) Total Debt to (b) the sum of Total Debt plus Stockholders' Equity. "Default" means an event described in Article VII. "Designated Proceeds" means, at any time, all Net Cash Proceeds from Asset Sales received by the Borrower or any Subsidiary after the date of this Agreement, excluding any portion of such Net Cash Proceeds previously applied to reduce the Aggregate Commitment pursuant to Section 2.8(b). "Environmental Laws" means any and all federal, state, local and foreign statutes, laws, judicial decisions, regulations, ordinances, rules, judgments, orders, decrees, plans, injunctions, permits, concessions, grants, franchises, licenses, agreements and other governmental restrictions relating to (i) the protection of the environment, (ii) the effect of the environment on human health, (iii) emissions, discharges or releases of pollutants, contaminants, hazardous substances or wastes into surface water, ground water or land, or (iv) the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollutants, contaminants, hazardous substances or wastes or the clean-up or other remediation thereof. "Equity Issuance " means any issuance by the Borrower or any Subsidiary of any equity securities other than (a) pursuant to and in accordance with stock option plans or other benefit plans for directors, officers or employees of the Borrower or any Subsidiary, (b) in connection with a merger, acquisition, joint venture, asset purchase or other investment by the Borrower or any Subsidiary permitted under this Agreement or (c) any issuance by a Subsidiary to the Borrower or to another Subsidiary. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time, and any rule or regulation issued thereunder. "Eurodollar Advance" means an Advance which, except as otherwise provided in Section 2.11, bears interest at the applicable Eurodollar Rate. "Eurodollar Base Rate" means, with respect to a Eurodollar Advance for the relevant Interest Period, the applicable British Bankers' Association Interest Settlement Rate for deposits in U.S. dollars appearing on Reuters Screen FRBD as of 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, provided that, (i) if Reuters Screen FRBD is not available to the Administrative Agent for any reason, the applicable Eurodollar Base Rate for the relevant Interest Period shall instead be the applicable British Bankers' Association Interest Settlement Rate for deposits in U.S. -5- dollars as reported by any other generally recognized financial information service as of 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, and (ii) if no such British Bankers' Association Interest Settlement Rate is available to the Administrative Agent, the applicable Eurodollar Base Rate for the relevant Interest Period shall instead be the rate determined by the Administrative Agent to be the rate at which Bank One or one of its Affiliate banks offers to place deposits in U.S. dollars with first-class banks in the London interbank market at approximately 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, in the approximate amount of the relevant Eurodollar Loan and having a maturity equal to such Interest Period. "Eurodollar Loan" means a Ratable Loan which, except as otherwise provided in Section 2.11, bears interest at the applicable Eurodollar Rate. "Eurodollar Rate" means, with respect to a Eurodollar Advance for the relevant Interest Period, the sum of the Eurodollar Base Rate applicable to such Interest Period plus the Applicable Margin as in effect from time to time. "Excluded Taxes" means, in the case of each Lender or applicable Lending Installation and the Administrative Agent, taxes imposed on its overall net income, and franchise taxes imposed on it, by (i) the jurisdiction under the laws of which such Lender or the Administrative Agent is incorporated or organized or (ii) the jurisdiction in which the Administrative Agent's or such Lender's principal executive office or such Lender's applicable Lending Installation is located. "Exhibit" refers to an exhibit to this Agreement, unless another document is specifically referenced. "Federal Funds Effective Rate" means, for any day, an interest rate per annum equal to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers on such day, as published for such day (or, if such day is not a Business Day, for the immediately preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a Business Day, the average of the quotations at approximately 10:00 a.m. (Chicago time) on such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by the Administrative Agent in its sole discretion. "Floating Rate" means, for any day, a rate per annum equal to the Alternate Base Rate for such day, changing when and as the Alternate Base Rate changes, plus the Applicable Margin as in effect on such day. "Floating Rate Advance" means an Advance which, except as otherwise provided in Section 2.11, bears interest at the Floating Rate. -6- "Floating Rate Loan" means a Ratable Loan which, except as otherwise provided in Section 2.11, bears interest at the Floating Rate. "Guarantor" means each Subsidiary which is a party to the Subsidiary Guaranty. "Indebtedness" of a Person means such Person's (i) obligations for borrowed money, (ii) obligations representing the deferred purchase price of Property or services, (iii) obligations, whether or not assumed, secured by Liens or payable out of the proceeds or production from Property now or hereafter owned or acquired by such Person, (iv) obligations which are evidenced by notes, acceptances, or other instruments, (v) obligations of such Person to purchase accounts, securities or other Property arising out of or in connection with the sale of the same or substantially similar accounts, securities or Property, (vi) Capitalized Lease Obligations, (vii) any other obligation for borrowed money or other financial accommodation which in accordance with Agreement Accounting Principles would be shown as a liability on the consolidated balance sheet of such Person, (viii) net liabilities under interest rate swap, exchange or cap agreements, obligations or other liabilities with respect to accounts or notes, (ix) Sale and Leaseback Transactions which do not create a liability on the consolidated balance sheet of such Person, (x) other transactions which are the functional equivalent, or take the place, of borrowing but which do not constitute a liability on the consolidated balance sheet of such Person, (xi) Contingent Obligations and (xii) Mandatorily Redeemable Stock; provided that, notwithstanding any of the foregoing, accounts payable arising in the ordinary course of business payable on terms customary in the trade, and Contingent Obligations in respect thereof, shall not constitute Indebtedness; and provided, further, that Indebtedness shall not include accounts payable which the Borrower is required to reflect on its balance sheet in accordance with Agreement Accounting Principles to the extent that (i) such accounts payable consist solely of contingent obligations under oil and gas hedge transactions for future periods and (ii) as of any date of calculation thereof, the volume of oil and gas subject to such hedge transactions is not greater than 90% of the Borrower's anticipated production from proved, producing, oil and gas reserves owned by the Borrower and its Subsidiaries as of such date over the term covered by such hedge transactions. "Intercompany Indebtedness" means any Indebtedness of the Borrower owing to any Subsidiary or of any Subsidiary owing to the Borrower or to any other Subsidiary; provided that in the case of any Indebtedness owed by the Borrower or any Subsidiary to a Subsidiary which is not a Wholly-Owned Subsidiary, such Indebtedness shall constitute Intercompany Indebtedness only to the extent of the Borrower's ownership percentage (whether direct or indirect) of the Subsidiary holding such Indebtedness. "Interest Coverage Ratio" means, for any period of four fiscal quarters of the Borrower ending on the last day of a fiscal quarter, the ratio of (a) the sum of (i) the Borrower's consolidated net income before interest, taxes, depreciation and amortization of non-cash charges, all determined on a consolidated basis and in accordance with Agreement Accounting Principles for such period, but excluding, to the extent otherwise included therein, any non-cash gain or loss on any hedging agreement resulting from the requirements of SFAS 133, plus (ii) to -7- the extent deducted in determining such consolidated net income, any non-cash charge after the date hereof resulting from any write-down of the Borrower's oil and gas properties to the full cost ceiling limitation required by the full cost method of accounting for such properties, to (b) the Borrower's interest expense for such period. "Interest Period" means, with respect to a Eurodollar Advance, a period of one, two, three or six months commencing on a Business Day selected by the Borrower pursuant to this Agreement. Such Interest Period shall end on the day which corresponds numerically to such date one, two, three or six months thereafter, provided that if there is no such numerically corresponding day in such next, second, third or sixth succeeding month, such Interest Period shall end on the last Business Day of such next, second, third or sixth succeeding month. If an Interest Period would otherwise end on a day which is not a Business Day, such Interest Period shall end on the next succeeding Business Day, provided that if said next succeeding Business Day falls in a new calendar month, such Interest Period shall end on the immediately preceding Business Day. Notwithstanding any other provision of this Agreement, the Borrower may not select any Interest Period (a) which would end after the scheduled Termination Date or (b) if, after giving effect to such selection, the aggregate principal amount of all Eurodollar Loans having Interest Periods ending after any Commitment Reduction Date would exceed the Aggregate Commitment scheduled to be in effect at the close of business on such Commitment Reduction Date. "Investment" of a Person means any loan, advance (other than commission, travel and similar advances to officers and employees made in the ordinary course of business), extension of credit (other than accounts receivable arising in the ordinary course of business on terms customary in the trade) or contribution of capital by such Person; stocks, bonds, mutual funds, partnership interests, notes, debentures or other securities owned by such Person; any deposit accounts and certificate of deposit owned by such Person; and structured notes, derivative financial instruments and other similar instruments or contracts owned by such Person. "Knowledge" means, with respect to the Borrower, the actual knowledge of (i) any Authorized Officer, (ii) any vice president of the Borrower in charge of a principal business unit, division or function (such as sales, administration or finance), (iii) any other officer who performs a policy making function or (iv) any other person who performs similar policy making functions for the Borrower. "Lenders" means the lending institutions listed on the signature pages of this Agreement and their respective successors and assigns. Unless otherwise specified, the term "Lenders" includes Bank One in its capacity as Swing Line Lender. "Lending Installation" means, with respect to a Lender or the Administrative Agent, the office, branch, subsidiary or affiliate of such Lender or the Administrative Agent listed on its administrative questionnaire or on the signature pages hereof or otherwise selected by such Lender or the Administrative Agent pursuant to Section 2.18. -8- "Letter of Credit" of a Person means a letter of credit or similar instrument which is issued upon the application of such Person or upon which such Person is an account party or for which such Person is in any way liable. "Lien" means any lien (statutory or other), mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance or other security arrangement (including, without limitation, the interest of a vendor or lessor under any conditional sale, Capitalized Lease or other title retention agreement). "Loan" means a Ratable Loan or a Swing Line Loan. "Loan Documents" means this Agreement, any Note and the Subsidiary Guaranty. "Mandatorily Redeemable Stock" means, with respect to any Person, any share of such Person's capital stock or other equity interest to the extent that it is (a) redeemable, payable or required to be purchased or otherwise retired or extinguished, or convertible into any Indebtedness or other liability of such Person, (i) at a fixed or determinable date, whether by operation of a sinking fund or otherwise, (ii) at the option of any Person other than such Person or (iii) upon the occurrence of a condition not solely within the control of such Person, such as a redemption required to be made out of future earnings or (b) convertible into Mandatorily Redeemable Stock. "Material Adverse Effect" means a material adverse effect on (i) the business, Property, condition (financial or otherwise) or results of operations of the Borrower and its Subsidiaries taken as a whole, (ii) the prospect that the Borrower will have the ability to fully and timely pay the Obligations or (iii) the validity or enforceability of any of the Loan Documents or the rights or remedies of the Administrative Agent or the Lenders thereunder. "Material Group of Subsidiaries" means two or more Subsidiaries which, if merged as of any relevant date of determination, would constitute a Significant Subsidiary. "Multiemployer Plan" means a Plan maintained pursuant to a collective bargaining agreement or any other arrangement to which the Borrower or any member of the Controlled Group is a party to which more than one employer is obligated to make contributions. "Net Cash Proceeds" means (a) with respect to any Asset Sale, the aggregate cash proceeds (including cash proceeds received by way of deferred payment of principal pursuant to a note, installment receivable or otherwise, but only as and when received) received by the Borrower or any Subsidiary pursuant to such Asset Sale net of (i) the direct costs relating to such Asset Sale (including sales commissions and legal, accounting and investment banking fees), (ii) taxes paid or reasonably estimated by the Borrower to be payable as a result thereof (after taking into account any available tax credits or deductions and any tax sharing arrangements), (iii) amounts required to be applied to the repayment of any Indebtedness secured by a Lien on any asset subject to such Asset Sale and (iv) the proceeds of any sale of any of the assets listed -9- on Schedule 2.8(b) to the extent that such proceeds are applied within 150 days to acquire oil or gas producing properties; and (b) with respect to any Debt Issuance or Equity Issuance, the aggregate cash proceeds received by the Borrower pursuant to such Debt Issuance or Equity Issuance, net of the direct costs relating to such Debt Issuance or Equity Issuance (including registration fees, filing fees, underwriting commissions and discounts and legal, accounting and investment banking fees). "Non-U.S. Lender" is defined in Section 3.5(iv). "Note" means a promissory note, substantially in the form of Exhibit E, issued at the request of a Lender pursuant to Section 2.14. "Obligations" means all unpaid principal of and accrued and unpaid interest on the Loans, all accrued and unpaid fees and all expenses, reimbursements, indemnities and other obligations of the Borrower to the Lenders or to any Lender, the Administrative Agent or any indemnified party arising under the Loan Documents. "Other Taxes" is defined in Section 3.5(ii). "Participants" is defined in Section 12.2.1. "Payment Date" means the last day of each March, June, September and December. "PBGC" means the Pension Benefit Guaranty Corporation, or any successor thereto. "Person" means any natural person, corporation, firm, joint venture, partnership, limited liability company, association, enterprise, trust or other entity or organization, or any government or political subdivision or any agency, department or instrumentality thereof. "Plan" means an employee pension benefit plan which is covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 of the Code as to which the Borrower or any member of the Controlled Group may have any liability. "Prime Rate" means a rate per annum equal to the prime rate of interest announced by Bank One or by its parent, BANK ONE CORPORATION, which is not necessarily the lowest rate charged to any customer, changing when and as said prime rate changes. "Principal Transmission Facility" means any transportation or distribution facility, including pipelines, of the Borrower or any Subsidiary located in the United States of America other than (a) any such facility which in the opinion of the Board of Directors of the Borrower is not of material importance to the business conducted by the Borrower and its Subsidiaries taken as a whole, or (b) any such facility in which interests are held by the Borrower or by one or more -10- Subsidiaries or by the Borrower and one or more Subsidiaries and by others and the aggregate interest held by the Borrower and all Subsidiaries does not exceed 50%. "Productive Property" means any property interest owned by the Borrower or a Subsidiary in land (including submerged land and rights in and to oil, gas and mineral leases) located in the United States of America and classified by the Borrower or such Subsidiary, as the case may be, as productive of crude oil, natural gas or other petroleum hydrocarbons in paying quantities; provided that such term shall not include any exploration or production facilities on said land, including any drilling or producing platform. "Property" of a Person means any and all property, whether real, personal, tangible, intangible, or mixed, of such Person, or other assets owned, leased or operated by such Person. "Pro Rata Share" means, with respect to any Lender, the percentage which the amount of such Lender's Commitment is of the Aggregate Commitment (or, if the Commitments have been terminated, the percentage which the sum of the principal amount of such Lender's Ratable Loans plus such Lender's participation interest in the principal amount of all Swing Line Loans is of the aggregate principal amount of all Loans). "Purchasers" is defined in Section 12.3.1. "Ratable Loan" is defined in Section 2.1. "Regulation D" means Regulation D of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor thereto or other regulation or official interpretation of said Board of Governors relating to reserve requirements applicable to member banks of the Federal Reserve System. "Regulation U" means Regulation U of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor or other regulation or official interpretation of said Board of Governors relating to the extension of credit by banks for the purpose of purchasing or carrying margin stocks applicable to member banks of the Federal Reserve System. "Reportable Event" means a reportable event as defined in Section 4043 of ERISA and the regulations issued under such section, with respect to a Plan, excluding, however, such events as to which the PBGC has by regulation waived the requirement of Section 4043(a) of ERISA that it be notified within 30 days of the occurrence of such event, provided that a failure to meet the minimum funding standard of Section 412 of the Code and of Section 302 of ERISA shall be a Reportable Event regardless of the issuance of any such waiver of the notice requirement in accordance with either Section 4043(a) of ERISA or Section 412(d) of the Code. -11- "Required Lenders" means Lenders in the aggregate having at least 66-2/3% of the Aggregate Commitment or, if the Aggregate Commitment has been terminated, Lenders in the aggregate holding at least 66-2/3% of the aggregate unpaid principal amount of the outstanding Advances. "Reserve Requirement" means, with respect to an Interest Period, the daily average during such Interest Period of the maximum aggregate reserve requirement (including all basic, supplemental, marginal and other reserves) which is imposed under Regulation D on Eurocurrency liabilities. "Sale and Leaseback Transaction" means any sale or other transfer of Property by any Person with the intent to lease such Property as lessee. "Schedule" refers to a specific schedule to this Agreement, unless another document is specifically referenced. "SEC" means the Securities and Exchange Commission. "Section" means a numbered section of this Agreement, unless another document is specifically referenced. "Securities Proceeds" means the Net Cash Proceeds of any Debt Issuance or Equity Issuance. "Significant Subsidiary" means, as of any date of determination, each Subsidiary of the Borrower that meets any of the following criteria: (i) the Borrower's and its other Subsidiaries' Investments in and to such Subsidiary (and its respective Subsidiaries), as shown in the consolidated financial statements of the Borrower and its Subsidiaries prepared as of the end of the fiscal quarter ended most recently prior to such date of determination, exceed 10% of the total consolidated assets of the Borrower and its Subsidiaries; or (ii) the assets of such Subsidiary (and its respective Subsidiaries) represent more than 10% of the consolidated assets of the Borrower and its Subsidiaries as would be shown in the consolidated financial statements referred to in clause (i) above; or (iii) such Subsidiary (and its respective Subsidiaries) is responsible for more than 10% of the consolidated net sales or of the consolidated net income of the Borrower and its Subsidiaries as reflected in the financial statements referred to in clause (i) above; -12- provided that each such determination of such sales or assets shall be made after deducting all intercompany transactions which, in accordance with Agreement Accounting Principles, would be eliminated in preparing consolidated financial statements for the Borrower and its Subsidiaries. "Single Employer Plan" means a Plan maintained by the Borrower or any member of the Controlled Group for employees of the Borrower or any member of the Controlled Group. "Specific Proceeds" means the amount of the Net Cash Proceeds received from any Asset Sale (or series of related Asset Sales) in excess of $1,000,000, rounded down, if necessary, to an integral multiple of $500,000. "Stockholders' Equity" means the Borrower's stockholders' equity, determined in accordance with Agreement Accounting Principles, but without giving effect to (1) any non-cash charge after the date hereof resulting from any write-down of the Borrower's oil and gas properties to the full cost ceiling limitations required by the full cost method of accounting for such properties and (ii) any non-cash gain or loss on any hedging agreement resulting from the requirements of SFAS 133. "Subsidiary" of a Person means (i) any corporation more than 50% of the outstanding securities having ordinary voting power of which shall at the time be owned or controlled, directly or indirectly, by such Person or by one or more of its Subsidiaries or by such Person and one or more of its Subsidiaries, or (ii) any partnership, limited liability company, association, joint venture or similar business organization more than 50% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled. Unless otherwise expressly provided, all references herein to a "Subsidiary" shall mean a Subsidiary of the Borrower. "Subsidiary Guaranty" means the Subsidiary Guaranty executed by various Subsidiaries in favor of the Administrative Agent, for the ratable benefit of the Lenders, substantially in the form of Exhibit F hereto. "Swing Line Borrowing Notice" is defined in Section 2.6.2. "Swing Line Commitment" means the obligation of the Swing Line Lender to make Swing Line Loans up to a maximum principal amount of $15,000,000 at any one time outstanding. "Swing Line Lender" means Bank One or such other Lender which may succeed to its rights and obligations as Swing Line Lender pursuant to the terms of this Agreement. "Swing Line Loan" means a loan made available to the Borrower by the Swing Line Lender pursuant to Section 2.6. -13- "Taxes" means any and all present or future taxes, duties, levies, imposts, deductions, charges or withholdings, and any and all liabilities with respect to the foregoing, but excluding Excluded Taxes and Other Taxes. "Termination Date" means July 12, 2004 or such earlier date when the Aggregate Commitment has been reduced to zero. "Total Debt" means all Indebtedness of the Borrower and its Subsidiaries, determined on a consolidated basis in accordance with Agreement Accounting Principles. "Total Outstandings" means, at any time, the aggregate principal amount of all Loans hereunder at such time. "Transferee" is defined in Section 12.4. "Type" means, with respect to any Advance, its nature as a Floating Rate Advance or a Eurodollar Advance. "Unmatured Default" means an event which but for the lapse of time or the giving of notice, or both, would, unless cured or waived, constitute a Default. "Wholly-Owned Subsidiary" of a Person means (i) any Subsidiary all of the outstanding voting securities of which shall at the time be owned or controlled, directly or indirectly, by such Person or one or more Wholly-Owned Subsidiaries of such Person, or by such Person and one or more Wholly-Owned Subsidiaries of such Person, or (ii) any partnership, limited liability company, association, joint venture or similar business organization 100% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled. The foregoing definitions shall be equally applicable to both the singular and plural forms of the defined terms. ARTICLE II THE CREDITS 2.1 Commitments. From and including the date of this Agreement and to the Termination Date, each Lender severally agrees, on the terms and conditions set forth in this Agreement, to make loans to the Borrower from time to time (each such loan, a "Ratable Loan") in an amount equal to its Pro Rata Share of all Ratable Loans requested by the Borrower (but not exceeding in the aggregate at any one time outstanding the amount of its Commitment). Subject to the terms of this Agreement, the Borrower may borrow, repay and reborrow at any time prior to the Termination Date. -14- 2.2 Types of Advances. Advances may be Floating Rate Advances or Eurodollar Advances, or a combination thereof, as selected by the Borrower in accordance with Sections 2.4 and 2.5. 2.3 Minimum Amount of Each Advance. Each Eurodollar Advance shall be in the amount of $1,000,000 or a higher integral multiple thereof and each Floating Rate Advance (other than an Advance made to repay Swing Line Loans) shall be in the amount of $1,000,000 or a higher integral multiple of $500,000, provided that any Floating Rate Advance may be in the amount of the unused Aggregate Commitment. 2.4 Method of Selecting Types and Interest Periods for New Advances. The Borrower shall select the Type of Advance and, in the case of each Eurodollar Advance, the Interest Period applicable thereto from time to time. The Borrower shall give the Administrative Agent irrevocable notice (a "Borrowing Notice") not later than 10:00 a.m. (Chicago time) on the Borrowing Date of each Floating Rate Advance and three Business Days before the Borrowing Date of each Eurodollar Advance, specifying: (i) the Borrowing Date, which shall be a Business Day, of such Advance, (ii) the aggregate amount of such Advance, (iii) the Type of Advance selected, and (iv) in the case of a Eurodollar Advance, the Interest Period applicable thereto. Each Borrowing Notice shall be in writing (or by telephone promptly confirmed in writing) substantially in the form of Exhibit A. Not later than noon (Chicago time) on the Borrowing Date for an Advance, each Lender shall make available its Pro Rata Share of such Advance in funds immediately available in Chicago to the Administrative Agent at its address specified pursuant to Article XIII. The Administrative Agent will make the funds so received from the Lenders available to the Borrower at the Administrative Agent's aforesaid address. 2.5 Conversion and Continuation of Outstanding Advances. Floating Rate Advances shall continue as Floating Rate Advances unless and until such Floating Rate Advances are converted into Eurodollar Advances pursuant to this Section 2.5 or are repaid. Each Eurodollar Advance shall continue as a Eurodollar Advance, until the end of the then applicable Interest Period therefor, at which time such Eurodollar Advance shall be automatically converted into a Floating Rate Advance unless (x) such Advance is or was repaid or (y) the Borrower shall have given the Administrative Agent a Conversion/Continuation Notice requesting that, at the end of such Interest Period, such Advance continue as a Eurodollar Advance for the same or another Interest Period. Subject to the terms of Section 2.3, the Borrower may elect from time to time to convert all or any part of any Advance into an Advance of the other Type. The Borrower shall give the Administrative Agent irrevocable notice (a "Conversion/Continuation Notice") of each continuation or conversion of an Advance (other than an automatic continuation or conversion as -15- provided in this Section 2.5) not later than the time specified in Section 2.4 for the making of the Type of Advance to be continued or converted into, specifying: (i) the requested date, which shall be a Business Day, of such conversion or continuation, (ii) the aggregate amount and Type of the Advance which is to be converted or continued, (iii) in the case of conversion of an Advance, the Type of Advance to be converted into, (iv) the amount of the Advance which is to be converted or continued, and (v) in the case of conversion into or continuation of a Eurodollar Advance, the duration of the Interest Period applicable thereto. Each Conversion/Continuation Notice given by the Borrower shall constitute a representation and warranty by the Borrower that no Default or Unmatured Default exists. 2.6 Swing Line Loans. 2.6.1 Amount of Swing Line Loans. Upon the satisfaction of the applicable conditions precedent set forth in Article IV, from and including the date of this Agreement and prior to the Termination Date, the Swing Line Lender agrees, on the terms and conditions set forth in this Agreement, to make Swing Line Loans to the Borrower from time to time in an aggregate principal amount not to exceed the Swing Line Commitment, provided that the Total Outstandings shall not at any time exceed the Aggregate Commitment. Subject to the terms of this Agreement, the Borrower may borrow, repay and reborrow Swing Line Loans at any time prior to the Termination Date. 2.6.2 Method of Borrowing. Not later than noon (Chicago time) on the Borrowing Date of each Swing Line Loan, the Borrower shall deliver to the Administrative Agent and the Swing Line Lender irrevocable notice (a "Swing Line Borrowing Notice") specifying (i) the applicable Borrowing Date (which date shall be a Business Day), and (ii) the aggregate amount of the requested Swing Line Loan, which shall be an integral multiple of $100,000. 2.6.3 Making of Swing Line Loans. Promptly after receipt of a Swing Line Borrowing Notice, the Administrative Agent shall notify each Lender by fax, or other similar form of transmission, of the requested Swing Line Loan. Not later than 2:00 p.m. (Chicago time) on the applicable Borrowing Date, the Swing Line Lender shall make available the Swing Line Loan, in funds immediately available in Chicago, to the Administrative Agent at its address specified pursuant to Article XIII. The Administrative Agent will promptly make the funds so received -16- from the Swing Line Lender available to the Borrower on the Borrowing Date at the Administrative Agent's aforesaid address. 2.6.4 Repayment of Swing Line Loans. The Swing Line Lender may, at any time in its sole discretion, by notice to the Administrative Agent (which shall promptly notify each Lender), require each Lender (including the Swing Line Lender) to make a Ratable Loan in the amount of such Lender's Pro Rata Share of such Swing Line Loan (including, without limitation, any interest accrued and unpaid thereon), for the purpose of repaying such Swing Line Loan. Not later than noon (Chicago time) on the date of any notice received pursuant to this Section 2.6.4, each Lender shall make available its required Ratable Loan, in funds immediately available in Chicago to the Administrative Agent at its address specified pursuant to Article XIII. Ratable Loans made pursuant to this Section 2.6.4 shall initially be Floating Rate Loans and thereafter may be continued as Floating Rate Loans or converted into Eurodollar Loans in the manner provided in Section 2.5 and subject to the other conditions and limitations set forth in this Article II. Unless a Lender shall have notified the Swing Line Lender, prior to the making of any Swing Line Loan, that any applicable condition precedent set forth in Article IV had not then been satisfied, such Lender's obligation to make Ratable Loans pursuant to this Section 2.6.4 to repay Swing Line Loans shall be unconditional, continuing, irrevocable and absolute and shall not be affected by any circumstance, including, without limitation, (a) any set-off, counterclaim, recoupment, defense or other right which such Lender may have against the Administrative Agent, the Swing Line Lender or any other Person, (b) the occurrence or continuance of a Default or Unmatured Default, (c) any adverse change in the condition (financial or otherwise) of the Borrower, or (d) any other circumstance, happening or event whatsoever. If any Lender fails to make payment to the Administrative Agent of any amount due under this Section 2.6.4, the Administrative Agent shall be entitled to receive, retain and apply against such obligation the principal and interest otherwise payable to such Lender hereunder until the Administrative Agent receives such payment from such Lender or such obligation is otherwise fully satisfied. In addition to the foregoing, if for any reason any Lender fails to make payment to the Administrative Agent of any amount due under this Section 2.6.4, such Lender shall be deemed, at the option of the Administrative Agent, to have unconditionally and irrevocably purchased from the Swing Line Lender, without recourse or warranty, an undivided interest and participation in the applicable Swing Line Loan in the amount of such Ratable Loan, and such interest and participation may be recovered from such Lender together with interest thereon at the Federal Funds Effective Rate for each day during the period commencing on the date of demand and ending on the date such amount is received. 2.7 Commitment Fee; Voluntary Reductions in Aggregate Commitment. The Borrower agrees to pay to the Administrative Agent for the account of each Lender a commitment fee at a per annum rate equal to the Commitment Fee Rate on the daily unused portion of such Lender's Commitment from the date hereof to and including the Termination Date, payable on each Payment Date hereafter and on the Termination Date. The Borrower may permanently reduce the Aggregate Commitment in whole, or in part ratably among the Lenders in accordance with their respective Pro Rata Shares, in integral multiples of $1,000,000, upon at least three Business Days' written notice to the Administrative Agent, which notice shall specify -17- the amount of any such reduction, provided that the amount of the Aggregate Commitment may not be reduced below the Total Outstandings. All accrued commitment fees shall be payable on the effective date of any termination of the obligations of the Lenders to make Loans hereunder. -18- 2.8 Mandatory Reductions in Aggregate Commitment.(a) The Aggregate Commitment shall be reduced by the following amounts on the following dates (each a "Commitment Reduction Date"):
Commitment Reduction Date Amount of Reduction ========================= =================== December 31, 2001 $ 5,000,000 June 30, 2002 $15,000,000 June 30, 2003 $15,000,000
The amount of any Aggregate Commitment reduction pursuant to Section 2.8(b) shall be applied to reduce any remaining Aggregate Commitment Reductions contemplated by this subsection (a), commencing with the next succeeding Aggregate Commitment reduction so contemplated. (b) Within five Business Days after the receipt by the Borrower or any Subsidiary of any Specific Proceeds, Designated Proceeds or Securities Proceeds (any of the foregoing, "Proceeds"), the Aggregate Commitment shall be reduced by an amount equal to such Proceeds; provided that (i) no such reduction shall be required from (x) the first $5,000,000 of Designated Proceeds received after the date of this Agreement; or (y) the first $5,000,000 of Securities Proceeds received after the date of this Agreement; (ii) the amount of Proceeds to be applied on any single occasion shall be rounded down, if necessary, to an integral multiple of $500,000 (it being understood that the amount of the applicable Proceeds in excess of any such integral multiple shall be applied on the next date on which such type of Proceeds is applied); and (iii) no Net Cash Proceeds of any Equity Issuance shall be required to be applied to reduce the Aggregate Commitment pursuant to this subsection (b) to the extent that, after applying such Net Cash Proceeds to the prepayment of Indebtedness, the Debt to Capitalization Ratio would be less than 0.65 to 1. (c) Notwithstanding subsections (a) and (b) above, no reduction of the Aggregate Commitment shall be required pursuant to subsection (a) or (b) to the extent that the Aggregate Commitment would be reduced to less than $125,000,000 as a result thereof. (d) On any date on which a Change of Control occurs, the Aggregate Commitment shall be immediately reduced to zero. 2.9 Prepayments. (a) The Borrower may from time to time prepay, without penalty or premium, all outstanding Floating Rate Advances or, in an aggregate amount of $1,000,000 or a higher integral multiple of $500,000 (or, in the case of any prepayment of an Advance made to repay a Swing Line Loan, in such other amount as is necessary to repay such Advance in full), any portion of the outstanding Floating Rate Advances upon notice to the Administrative Agent not later than 11:00 a.m. (Chicago time) on the date of prepayment. The Borrower may from -19- time to time prepay, without penalty or premium, all outstanding Eurodollar Advances or, in an aggregate amount of $1,000,000 or a higher integral multiple thereof, any portion of the outstanding Eurodollar Advances upon three Business Days' prior notice to the Administrative Agent. The Borrower may at any time pay, without penalty or premium, all outstanding Swing Line Loans or, in the amount of $100,000 or a higher integral multiple thereof, any portion of the outstanding Swing Line Loans, with notice to the Administrative Agent and the Swing Line Lender by 11:00 a.m. (Chicago time) on the date of repayment. (b) On any date on which the Aggregate Commitment is reduced pursuant to Section 2.8, the Borrower shall make a prepayment of Loans in the amount, if any, by which the Total Outstandings exceed the Aggregate Commitment as so reduced. Any partial prepayment pursuant to this subsection (b) shall be applied to such Loans as the Borrower may direct or, in the absence of such direction, as the Administrative Agent may reasonably determine. (c) Any prepayment of a Eurodollar Loan on a day other than the last day of an Interest Period therefor shall be subject to Section 3.4. 2.10 Interest Rates, etc. Each Floating Rate Advance shall bear interest on the outstanding principal amount thereof, for each day from and including the date such Advance is made or is converted from a Eurodollar Advance into a Floating Rate Advance pursuant to Section 2.5, to but excluding the date it is paid or is converted into a Eurodollar Advance pursuant to Section 2.5, at a rate per annum equal to the Floating Rate for such day. Each Swing Line Loan shall bear interest on the outstanding principal amount thereof, for each day from and including the day such Swing Line Loan is made to but excluding the date it is paid, at a rate per annum equal to the Alternate Base Rate for such day or such other rate as may be mutually agreed upon by the Borrower and the Swing Line Lender from time to time; provided that the rate applicable to any Swing Line Loan on any day shall not be less than the Eurodollar Rate which would be applicable to a Eurodollar Loan with a one-month Interest Period beginning on such day (or on the immediately preceding Business Day). Changes in the rate of interest on that portion of any Advance maintained as a Floating Rate Advance and on any Swing Line Loan bearing interest at the Alternate Base Rate will take effect simultaneously with each change in the Alternate Base Rate. Each Eurodollar Advance shall bear interest on the outstanding principal amount thereof from and including the first day of each Interest Period applicable thereto to (but not including) the last day of such Interest Period at the interest rate determined by the Administrative Agent as applicable to such Eurodollar Advance based upon the Borrower's selections under Sections 2.4 and 2.5 and otherwise in accordance with the terms hereof. 2.11 Rates Applicable After Default. Notwithstanding anything to the contrary herein, during the continuance of a Default or Unmatured Default the Required Lenders may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision ofSection 8.2 requiring unanimous consent of the Lenders to changes in interest rates), declare that no Advance may be made as, converted into or continued as a Eurodollar Advance. During the continuance of a Default the Required Lenders -20- may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision of Section 8.2 requiring unanimous consent of the Lenders to changes in interest rates), declare that (i) each Eurodollar Advance shall bear interest for the remainder of the applicable Interest Period at the rate otherwise applicable to such Interest Period plus 2% per annum and (ii) each Floating Rate Advance and each Swing Line Loan shall bear interest at a rate per annum equal to the Floating Rate in effect from time to time plus 2% per annum, provided that, during the continuance of a Default under Section 7.1.6 or 7.1.7, the interest rates set forth in clauses (i) and (ii) above shall be applicable to all Advances and Swing Line Loans without any election or action on the part of the Administrative Agent or any Lender. 2.12 Maturity. Any outstanding Advances and Swing Line Loans and all other accrued and unpaid Obligations shall be paid in full by the Borrower on the scheduled Termination Date or such earlier date required by Section 2.9 or Section 8.1. 2.13 Method of Payment. All payments of the Obligations hereunder shall be made, without setoff, deduction, or counterclaim, in immediately available funds to the Administrative Agent at the Administrative Agent's address specified pursuant to Article XIII, or at any other Lending Installation of the Administrative Agent specified in writing by the Administrative Agent to the Borrower, by noon (local time) on the date when due and (except for payments with respect to Swing Line Loans or as otherwise specifically required hereunder) shall be applied ratably by the Administrative Agent among the Lenders in accordance with their respective Pro Rata Shares. Each payment delivered to the Administrative Agent for the account of any Lender shall be delivered promptly by the Administrative Agent to such Lender in the same type of funds that the Administrative Agent received at its address specified pursuant to Article XIII or at any Lending Installation specified in a notice received by the Administrative Agent from such Lender. The Administrative Agent is hereby authorized to charge the account of the Borrower maintained with Bank One for each payment of principal, interest and fees as it becomes due hereunder. 2.14 Noteless Agreement; Evidence of Indebtedness. (i) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder. (ii) The Administrative Agent shall also maintain accounts in which it will record (a) the amount of each Loan made hereunder, the Type thereof and, if applicable, each Interest Period with respect thereto, (b) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (c) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender's share thereof. -21- (iii) The entries maintained in the accounts maintained pursuant to subsections (i) and (ii) above shall be prima facie evidence of the existence and amounts of the Obligations therein recorded; provided that the failure of the Administrative Agent or any Lender to maintain such accounts or any error therein shall not in any manner affect the obligation of the Borrower to repay the Obligations in accordance with their terms. (iv) Any Lender may request that its Loans be evidenced by a Note. In such event, the Borrower shall prepare, execute and deliver to such Lender a Note payable to the order of such Lender. Thereafter, the Loans evidenced by such Note and interest thereon shall at all times (including after any assignment pursuant to Section 12.3) be represented by one or more Notes payable to the order of the payee named therein or any assignee pursuant to Section 12.3, except to the extent that any such Lender or assignee subsequently returns any such Note for cancellation and requests that such Loans once again be evidenced as described in subsections (i) and (ii) above. 2.15 Telephonic Notices. The Borrower hereby authorizes the Lenders and the Administrative Agent to extend, convert or continue Advances and Swing Line Loans, to effect selections of Types of Advances and to transfer funds based on telephonic notices made by any person or persons the Administrative Agent or any Lender in good faith believes to be acting on behalf of the Borrower, it being understood that the foregoing authorization is specifically intended to allow Borrowing Notices, Swing Line Borrowing Notices and Conversion/Continuation Notices to be given telephonically. The Borrower agrees to deliver promptly to the Administrative Agent a written confirmation, if such confirmation is requested by the Administrative Agent or any Lender, of each telephonic notice signed by an Authorized Officer. If the written confirmation differs in any material respect from the action taken by the Administrative Agent and the Lenders, the records of the Administrative Agent and the Lenders shall govern absent manifest error. 2.16 Interest Payment Dates; Interest and Fee Basis. Interest accrued on each Floating Rate Advance and Swing Line Loan shall be payable on each Payment Date, on any date on which such Floating Rate Advance or Swing Line Loan is prepaid, whether due to acceleration or otherwise, and at maturity. Interest accrued on each Eurodollar Advance shall be payable on the last day of each applicable Interest Period, on any date on which such Advance is prepaid, whether by acceleration or otherwise, or is converted into a Floating Rate Advance, and at maturity. Interest accrued on each Eurodollar Advance having an Interest Period longer than three months shall also be payable on the last day of each three-month interval during such Interest Period. Interest and commitment fees shall be calculated for actual days elapsed on the basis of a 360-day year, except that interest accruing at the Prime Rate shall be calculated for actual days elapsed on the basis of a 365, or when appropriate 366, day year. Interest shall be payable for the day an Advance or a Swing Line Loan is made but not for the day of any payment on the amount paid if payment is received prior to noon (local time) at the place of payment. If any payment of principal of or interest on an Advance or a Swing Line Loan shall become due on a day which is not a Business Day, such payment shall be made on the next -22- succeeding Business Day and, in the case of a principal payment, such extension of time shall be included in computing interest in connection with such payment. 2.17 Notification of Advances, Interest Rates, Prepayments and Commitment Reductions. Promptly after receipt thereof, the Administrative Agent will notify each Lender of the contents of each Aggregate Commitment reduction notice, Borrowing Notice, Swing Line Borrowing Notice, Conversion/Continuation Notice, and repayment notice received by it hereunder. The Administrative Agent will notify each Lender of the interest rate applicable to each Eurodollar Advance promptly upon determination of such interest rate and will give each Lender prompt notice of each change in the Alternate Base Rate. 2.18 Lending Installations. Each Lender may book its Loans at any Lending Installation selected by such Lender and may change its Lending Installation from time to time. All terms of this Agreement shall apply to any such Lending Installation and the Loans and any Notes issued hereunder shall be deemed held by each Lender for the benefit of any such Lending Installation. Each Lender may, by written notice to the Administrative Agent and the Borrower in accordance with Article XIII, designate replacement or additional Lending Installations through which Loans will be made by it and for whose account Loan payments are to be made. 2.19 Non-Receipt of Funds by the Administrative Agent. Unless the Borrower or Lender, as the case may be, notifies the Administrative Agent prior to the date on which it is scheduled to make payment to the Administrative Agent of (i) in the case of a Lender, the proceeds of a Loan or (ii) in the case of the Borrower, a payment of principal, interest or fees to the Administrative Agent for the account of the Lenders, that it does not intend to make such payment, the Administrative Agent may assume that such payment has been made. The Administrative Agent may, but shall not be obligated to, make the amount of such payment available to the intended recipient in reliance upon such assumption. If such Lender or the Borrower, as the case may be, has not in fact made such payment to the Administrative Agent, the recipient of such payment shall, on demand by the Administrative Agent, repay to the Administrative Agent the amount so made available together with interest thereon in respect of each day during the period commencing on the date such amount was so made available by the Administrative Agent until the date the Administrative Agent recovers such amount at a rate per annum equal to (x) in the case of payment by a Lender, the Federal Funds Effective Rate for such day for the first three days and, thereafter, the interest rate applicable to the relevant Loan or (y) in the case of payment by the Borrower, the interest rate applicable to the relevant Loan. 2.20 Replacement of Lender. If the Borrower is required pursuant to Section 3.1, 3.2 or 3.5 to make any additional payment to any Lender or if any Lender's obligation to make or continue, or to convert Advances into, Eurodollar Advances shall be suspended pursuant to Section 3.3 (any Lender so affected an "Affected Lender"), the Borrower may elect, if such amounts continue to be charged or such suspension is still effective, to replace such Affected Lender as a Lender party to this Agreement, provided that no Default or Unmatured Default shall have occurred and be continuing at the time of such replacement, and provided, further, that, -23- concurrently with such replacement, (i) another bank or other entity which is reasonably satisfactory to the Borrower and the Administrative Agent shall agree, as of such date, to purchase for cash the Advances and other Obligations due to the Affected Lender pursuant to an assignment substantially in the form of Exhibit C and to become a Lender for all purposes under this Agreement and to assume all obligations of the Affected Lender to be terminated as of such date and to comply with the requirements of Section 12.3 applicable to assignments, and (ii) the Borrower shall pay to such Affected Lender in same day funds on the day of such replacement (A) all interest, fees and other amounts then accrued but unpaid to such Affected Lender by the Borrower hereunder to and including the date of termination, including without limitation payments due to such Affected Lender under Sections 3.1, 3.2 and 3.5, and (B) an amount, if any, equal to the payment which would have been due to such Lender on the day of such replacement under Section 3.4 had the Loans of such Affected Lender been prepaid on such date rather than sold to the replacement Lender. ARTICLE III YIELD PROTECTION; TAXES 3.1 Yield Protection. (a) If, on or after the date of this Agreement, (x) the adoption of or any change in any law or any governmental or quasi-governmental rule, regulation, policy, guideline or directive (whether or not having the force of law), or (y) any change in the interpretation or administration thereof by any governmental or quasi-governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or (z) compliance by any Lender or applicable Lending Installation with any request or directive (whether or not having the force of law) issued on or after the date hereof of any such authority, central bank or comparable agency: (i) subjects any Lender or any applicable Lending Installation to any Taxes, or changes the basis of taxation of payments (other than with respect to Excluded Taxes) to any Lender in respect of its Eurodollar Loans, or (ii) imposes or increases or deems applicable any reserve, assessment, insurance charge, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any reserves and assessments taken into account in determining the interest rate applicable to Eurodollar Advances), or (iii) imposes any other condition the result of which is to increase the cost to any Lender or any applicable Lending Installation of making, funding or maintaining its Eurodollar Loans or reduces any amount receivable by any Lender or any applicable Lending Installation i connection with its Eurodollar Loans, or requires any Lender or any applicable Lending Installation to make any payment -24- calculated by reference to the amount of Eurodollar Loans held or interest received by it, by an amount deemed material by such Lender, and the result of any of the foregoing is to increase the cost to such Lender or applicable Lending Installation of making or maintaining its Eurodollar Loans or Commitment or to reduce the return received by such Lender or applicable Lending Installation in connection with such Eurodollar Loans or Commitment, then, within 15 days of demand by such Lender, the Borrower shall pay such Lender such additional amount or amounts as will compensate such Lender for such increased cost or reduction in amount received. A Lender shall not be entitled to demand compensation or be compensated hereunder to the extent that such compensation relates to any period of time more than 60 days prior to the date upon which such Lender first notified the Borrower of the occurrence of the event entitling such Lender to such compensation (unless, and to the extent, that any such compensation so demanded shall relate to the retroactive application of any event so notified to the Borrower). (b) Without limiting subsection (a) above, any Lender may require the Borrower to pay, contemporaneously with each payment of interest on any Eurodollar Loan of such Lender, additional interest on such Eurodollar Loan at a rate per annum determined by such Lender up to but not exceeding the excess of (i) (A) the applicable Eurodollar Base Rate divided by (B) one minus the Reserve Requirement over (ii) the applicable Eurodollar Base Rate. Any Lender wishing to require payment of such additional interest (x) shall so notify the Borrower and the Administrative Agent, in which case such additional interest on the Eurodollar Loans of such Lender shall be payable to such Lender at the place indicated in such notice with respect to each Interest Period commencing at least three Business Days after the giving of such notice and (y) shall notify the Borrower at least five Business Days prior to each date on which interest is payable on any Eurodollar Loan of the amount then due it under this Section 3.1. 3.2 Changes in Capital Adequacy Regulations. If a Lender determines the amount of capital required or expected to be maintained by such Lender, any Lending Installation of such Lender or any corporation controlling such Lender is increased as a result of a Change, then, within 15 days of demand by such Lender, the Borrower shall pay such Lender the amount necessary to compensate for any shortfall in the rate of return on the portion of such increased capital which such Lender determines is attributable to this Agreement, its Loans or its Commitment to make Loans hereunder (after taking into account such Lender's policies as to capital adequacy). "Change" means (i) any change after the date of this Agreement in the Risk-Based Capital Guidelines or (ii) any adoption of or change in any other law, governmental or quasi-governmental rule, regulation, policy, guideline, interpretation, or directive (whether or not having the force of law) after the date of this Agreement which affects the amount of capital required or expected to be maintained by any Lender or any Lending Installation or any corporation controlling any Lender. "Risk-Based Capital Guidelines" means (i) the risk-based capital guidelines in effect in the United States on the date of this Agreement, including transition rules, and (ii) the corresponding capital regulations promulgated by regulatory authorities outside the United States implementing the July 1988 report of the Basle Committee on Banking Regulation and Supervisory Practices Entitled "International Convergence of Capital -25- Measurements and Capital Standards," including transition rules, and any amendments to such regulations adopted prior to the date of this Agreement. 3.3 Availability of Types of Advances. If any Lender reasonably determines that maintenance of its Eurodollar Loans at a suitable Lending Installation would violate any applicable law, rule, regulation, or directive, whether or not having the force of law, or if the Required Lenders reasonably determine that (i) deposits of a type and maturity appropriate to match fund Eurodollar Advances are not available or (ii) the Eurodollar Base Rate does not accurately reflect the cost of obtaining funds to make or maintain Eurodollar Advances, then the Administrative Agent shall suspend the availability of Eurodollar Advances and require any affected Eurodollar Advances to be repaid or converted to Floating Rate Advances (on or before the date required by such law, rule, regulation or directive), subject to the payment of any funding indemnification amounts required by Section 3.4. 3.4 Funding Indemnification. If any payment of a Eurodollar Advance occurs on a date which is not the last day of the applicable Interest Period, whether because of acceleration, prepayment or otherwise, or a Eurodollar Advance is not made, continued or converted on a date specified by the Borrower for any reason other than default by the Lenders, the Borrower will indemnify each Lender for any loss or cost incurred by it resulting therefrom, including, without limitation, any loss or cost in liquidating or employing deposits acquired to fund or maintain such Eurodollar Rate Advance. 3.5 Taxes. (i) All payments by the Borrower to or for the account of any Lender or the Administrative Agent hereunder or under any Note shall be made free and clear of and without deduction for any and all Taxes. If the Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder to any Lender or the Administrative Agent, (a) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 3.5) such Lender or the Administrative Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (b) the Borrower shall make such deductions, (c) the Borrower shall pay the full amount deducted to the relevant authority in accordance with applicable law and (d) the Borrower shall furnish to the Administrative Agent the original copy of a receipt evidencing payment thereof within 30 days after such payment is made. (ii) In addition, the Borrower hereby agrees to pay any present or future stamp or documentary taxes and any other excise or property taxes, charges or similar levies which arise from any payment made hereunder or under any Note or from the execution or delivery of, or otherwise with respect to, this Agreement or any Note ("Other Taxes"). (iii) The Borrower hereby agrees to indemnify the Administrative Agent and each Lender for the full amount of Taxes or Other Taxes (including, without limitation, any Taxes or Other Taxes imposed on amounts payable under this Section 3.5) paid by the Administrative Agent or such Lender and any liability (including penalties, interest and expenses) arising therefrom or -26- with respect thereto. Payments due under this indemnification shall be made within 30 days of the date the Administrative Agent or such Lender makes demand therefor pursuant to Section 3.6. (iv) Each Lender that is not incorporated under the laws of the United States of America or a state thereof (each a "Non-U.S. Lender") agrees that it will, not less than ten Business Days after the date of this Agreement, (i) deliver to each of the Borrower and the Administrative Agent two duly completed copies of United States Internal Revenue Service Form W-8 BEN or W-8 ECI, certifying in either case that such Lender is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, and (ii) deliver to each of the Borrower and the Administrative Agent a United States Internal Revenue Form W-8 or W-9, as the case may be, and certify that it is entitled to an exemption from United States backup withholding tax. Each Non-U.S. Lender further undertakes to deliver to each of the Borrower and the Administrative Agent (x) renewals or additional copies of such form (or any successor form) on or before the date that such form expires or becomes obsolete, and (y) after the occurrence of any event requiring a change in the most recent forms so delivered by it, such additional forms or amendments thereto as may be reasonably requested by the Borrower or the Administrative Agent. All forms or amendments described in the preceding sentence shall certify that such Lender is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, unless an event (including without limitation any change in treaty, law or regulation) has occurred prior to the date on which any such delivery would otherwise be required which renders all such forms inapplicable or which would prevent such Lender from duly completing and delivering any such form or amendment with respect to it and such Lender advises the Borrower and the Administrative Agent that it is not capable of receiving payments without any deduction or withholding of United States federal income tax. (v) For any period during which a Non-U.S. Lender has failed to provide the Borrower with an appropriate form pursuant to subsection (iv), above (unless such failure is due to a change in treaty, law or regulation, or any change in the interpretation or administration thereof by any governmental authority, occurring subsequent to the date on which a form originally was required to be provided), such Non-U.S. Lender shall not be entitled to indemnification under this Section 3.5 with respect to Taxes imposed by the United States; provided that, should a Non-U.S. Lender which is otherwise exempt from or subject to a reduced rate of withholding tax become subject to Taxes because of its failure to deliver a form required under subsection (iv), above, the Borrower shall take such steps as such Non-U.S. Lender shall reasonably request to assist such Non-U.S. Lender to recover such Taxes. (vi) Any Lender that is entitled to an exemption from or reduction of withholding tax with respect to payments under this Agreement or any Note pursuant to the law of any relevant jurisdiction or any treaty shall deliver to the Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law as will permit such payments to be made without withholding or at a reduced rate. -27- (vii) If the U.S. Internal Revenue Service or any other governmental authority of the United States or any other country or any political subdivision thereof asserts a claim that the Administrative Agent did not properly withhold tax from amounts paid to or for the account of any Lender (because the appropriate form was not delivered or properly completed, because such Lender failed to notify the Administrative Agent of a change in circumstances which rendered its exemption from withholding ineffective, or for any other reason), such Lender shall indemnify the Administrative Agent fully for all amounts paid, directly or indirectly, by the Administrative Agent as tax, withholding therefor, or otherwise, including penalties and interest, and including taxes imposed by any jurisdiction on amounts payable to the Administrative Agent under this subsection, together with all costs and expenses related thereto (including attorneys fees and time charges of attorneys for the Administrative Agent, which attorneys may be employees of the Administrative Agent). The obligations of the Lenders under this Section 3.5(vii) shall survive the payment of the Obligations and termination of this Agreement. 3.6 Lender Statements; Survival of Indemnity. To the extent reasonably possible, each Lender shall designate an alternate Lendin Installation with respect to its Eurodollar Loans to reduce any liability of the Borrower to such Lender under Sections 3.1, 3.2 and 3.5 or to avoid the unavailability of Eurodollar Advances under Section 3.3, so long as such designation is not, in the reasonable judgment of such Lender, disadvantageous to such Lender. Each Lender shall deliver a written statement of such Lender to the Borrower (with a copy to the Administrative Agent) as to the amount due, if any, under Section 3.1, 3.2, 3.4 or 3.5. Such written statement shall set forth in reasonable detail the calculations upon which such Lender determined such amount and shall be rebuttable presumptive evidence of the amount thereof. Determination of amounts payable under such Sections in connection with a Eurodollar Loan shall be calculated as though each Lender funded its Eurodollar Loan through the purchase of a deposit of the type and maturity corresponding to the deposit used as a reference in determining the Eurodollar Base Rate applicable to such Eurodollar Loan, whether in fact that is the case or not. The obligations of the Borrower under Sections 3.1, 3.2, 3.4 and 3.5 shall survive payment of the Obligations and termination of this Agreement. ARTICLE IV CONDITIONS PRECEDENT 4.1 Initial Loan. The Lenders (or, if applicable, the Swing Line Lender) shall not be required to make the initial Loan hereunder unless (a) concurrently with the making of such Loan, the Borrower shall have paid in full all principal, interest, fees and other amounts payable under the Credit Agreement dated as of July 17, 2000 among between the Borrower, various lenders and Bank One, as administrative agent, and (b) the Borrower shall have furnished to the Administrative Agent with sufficient copies for the Lenders: (i) Copies of the articles or certificate of incorporation or other organizational documents of the Borrower and each Guarantor, together with all amendments, -28- and a certificate of good standing, each certified by the appropriate governmental officer in its jurisdiction of organization. (ii) Copies certified by the Secretary or Assistant Secretary of the Borrower and each Guarantor, of its by-laws (to the extent applicable) and of its Board of Directors' resolutions, members' resolutions or similar documents authorizing the execution of the Loan Documents to which the Borrower or such Guarantor is a party. (iii) An incumbency certificate, executed by the Secretary or Assistant Secretary of the Borrower and each Guarantor, which shall identify by name and title and bear the signatures of the officers of the Borrower or such Guarantor authorized to sign the Loan Documents to which the Borrower or such Guarantor is a party, upon which certificate the Administrative Agent and the Lenders shall be entitled to rely until informed of any change in writing by the Borrower or such Guarantor. (iv) Evidence, in form and substance satisfactory to the Administrative Agent, that the Borrower has obtained all governmental approvals necessary for it to enter into the Loan Documents. (v) A certificate, signed by an Authorized Officer, stating that on the initial Borrowing Date (x) no Default or Unmatured Default has occurred and is continuing and (y) the representations and warranties set forth in Article V are true and correct as of such date. (vi) A written opinion of counsel to the Borrower and the Guarantors, addressed to the Lenders in substantially the form of Exhibit B. (vii) Any Notes requested by a Lender pursuant to Section 2.14 payable to the order of each such requesting Lender. (viii) Written money transfer instructions, in substantially the form of Exhibit D, addressed to the Administrative Agent and signed by an Authorized Officer, together with such other related money transfer authorizations as the Administrative Agent may have reasonably requested. (ix) The Subsidiary Guaranty signed by sufficient Subsidiaries so that the Borrower is in compliance with Section 6.3.4. (x) Copies, certified as being correct and complete by an Authorized Officer, of the Indenture dated as of December 1, 1995, between the Borrower and Bank One (then known as The First National Bank of Chicago), as trustee, and all supplements thereto. -29- (xi) Such other documents as any Lender or its counsel may have reasonably requested. 4.2 Each Loan. No Lender shall be required to make any Loan (other than a Ratable Loan made to repay a Swing Line Loan pursuant to Section 2.6.4) unless on the applicable Borrowing Date: (i) No Default or Unmatured Default exists or will result therefrom. (ii) The representations and warranties contained in Article V are true and correct as of such Borrowing Date except to the extent any such representation or warranty is stated to relate solely to an earlier date, in which case such representation or warranty shall have been true and correct on and as of such earlier date. (iii) All legal matters incident to the making of such Loan shall be reasonably satisfactory to the Administrative Agent and its counsel. Each Borrowing Notice with respect to an Advance and each request for a Swing Line Loan shall constitute a representation and warranty by the Borrower that the conditions contained in subsections (i) and (ii) above have been satisfied. For the avoidance of doubt, the conversion or continuation of a Ratable Loan shall not constitute the making of a Loan. ARTICLE V REPRESENTATIONS AND WARRANTIES The Borrower represents and warrants to the Lenders that: 5.1 Organization. The Borrower and each of its Subsidiaries are duly organized, validly existing and in good standing under the laws of the states of their organization and have all requisite authority to conduct their respective businesses in each jurisdiction in which the failure to have such authority, singly or in the aggregate, could reasonably be expected to have a Material Adverse Effect. The Borrower and each of its Subsidiaries have full power and authority to carry on their business as now conducted. 5.2 Authorization and Validity. The Borrower and each Guarantor has the power and authority and egal right to execute and deliver the Loan Documents to which it is a party and to perform its obligations thereunder. The execution and delivery by the Borrower and each Guarantor of the Loan Documents to which it is a party have been duly authorized by proper organizational proceedings, and the Loan Documents to which the Borrower and such Guarantor is a party constitute legal, valid and binding obligations of the Borrower or such Guarantor, as the case may be, enforceable against the Borrower or such Guarantor, as the case may be, in accordance with their terms, except as enforceability may be limited by bankruptcy, insolvency or similar laws affecting the enforcement of creditors' rights generally. -30- 5.3 Financial Statements. The December 31, 2000 and the March 31, 2001 consolidated financial statements of the Borrower and the Subsidiaries heretofore delivered to the Administrative Agent and the Lenders were prepared in accordance with generally accepted accounting principles in effect on the date such statements were prepared and fairly present the financial position and results of operations of the Borrower and its Subsidiaries at such dates and the consolidated results of their operations for the periods then ended. 5.4 Subsidiaries. Schedule 5.4 hereto contains an accurate list of all of the presently existing Subsidiaries, setting forth their respective jurisdictions of organization and the percentage of their respective capital stock or membership interests owned by the Borrower or other Subsidiaries. All of the issued and outstanding shares of capital stock of each corporate Subsidiary have been duly authorized and issued and are fully paid and nonassessable. 5.5 ERISA. Each Plan is in material compliance with, an has been administered in material compliance with, all applicable provisions of ERISA, the Code and any other applicable federal or state law, except where the failure to so comply would not (individually or in the aggregate) reasonably be expected to have a Material Adverse Effect, and no event or condition has occurred and is continuing as to which the Borrower is under an obligation to furnish a report to the Administrative Agent and the Lenders under Section 6.1(d) and which would reasonably be expected (individually or in the aggregate) to have a Material Adverse Effect. 5.6 Defaults. No Default or Unmatured Default has occurred and is continuing. 5.7 Accuracy of Information. No information, exhibit or report furnished by the Borrower or any Subsidiary to the Administrative Agent or any Lender in connection with the negotiation of this Agreement contains any material misstatement of fact or omitted to state a material fact necessary to make the statements contained therein not misleading. 5.8 Regulation U. Neither the Borrower nor any Subsidiary is engaged principally, or as one of its important activities, in the business of extending credit for the purpose of purchasing or carrying Margin Stock. Margin Stock constitutes less than 25% of the consolidated assets of the Borrower and its Subsidiaries which are subject to any limitation on sale or pledge or any other restriction hereunder. No part of the proceeds of any Loan will be used to purchase or carry any Margin Stock in violation of Regulation U. 5.9 No Adverse Change. Since March 31, 2001 there has been no change in the business, property, condition (financial or otherwise) or results of operations of the Borrower and its Subsidiaries which could reasonably be expected to have a Material Adverse Effect. 5.10 Taxes. The Borrower and its Subsidiaries have filed all United States federal tax returns and all other tax returns which, to the Knowledge of the Borrower, are required to be filed and have paid all taxes due pursuant to said returns or material taxes due pursuant to any assessment received by the Borrower or any Subsidiary, except in both cases such taxes, if any, as are being contested in good faith and as to which adequate reserves have been provided in -31- accordance with Agreement Accounting Principles. The charges, accruals and reserves on the books of the Borrower and its Subsidiaries in respect of any taxes or other governmental charges are adequate in accordance with Agreement Accounting Principles. 5.11 Liens. There are no Liens on any of the properties or assets of the Borrower or any Subsidiary except (i) Liens permitted by Section 6.3.5 and (ii) with respect to properties and assets other than Productive Properties, Principal Transmission Facilities and the stock of any Subsidiary, Liens that could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect. All easements, rights of way, licenses and other real property rights required for operation of the businesses of the Borrower and its Subsidiaries (collectively the "Rights of Way") are owned free and clear of any Lien, other than Liens permitted by this Agreement and Liens already on any parcel of real property with respect to which the Rights of Way have been granted, which will not, in the aggregate, at any time materially detract from the value of the Rights of Way or materially impair the use of the Rights of Way in the operation of the businesses of the Borrower and its Subsidiaries. 5.12 Compliance with Orders. Neither the Borrower nor any Subsidiary is in default under the terms of any order of any federal or state court or administrative agency by which it or any of its properties may be bound, except for any defaults which could not, individually or in the aggregate, be reasonably expected to have a Material Adverse Effect. 5.13 Litigation. Except as set forth in Schedule 5.13, there are no actions at law or in equity pending or, to the Knowledge of the Borrower, threatened involving the likelihood of any judgment or liability against the Borrower or any Subsidiary which could reasonably be expected to have a Material Adverse Effect. 5.14 Burdensome Agreements. The Borrower is not a party to any contract or agreement which, in the opinion of management of the Borrower, could reasonably be expected to have a Material Adverse Effect. 5.15 No Conflict. Neither the execution and delivery by the Borrower or any Guarantor of the Loan Documents to which it is a party, nor the consummation of the transactions therein contemplated, nor compliance with the provisions thereof will conflict with or result in the breach of any of the terms, conditions or provisions of, or constitute a default under, the charter or bylaws of the Borrower or any Subsidiary, or any indenture, loan agreement or other agreement or instrument to which the Borrower or any Subsidiary is a party or by which it may be bound, or result in creation of any Lien on any property of the Borrower or any Subsidiary, and neither the Borrower nor any Subsidiary is in default (after the expiration of any applicable grace period) in the performance, observance or fulfillment of any of the obligations, covenants or conditions contained in (i) any agreement to which it is a party, which default could reasonably be expected to have a Material Adverse Effect, or (ii) any agreement or instrument evidencing or governing Indebtedness in a principal amount exceeding $5,000,000. -32- 5.16 Title to Properties. The Borrower and its Subsidiaries have good and marketable title to all real properties purported to be owned by them and good title to all other assets purported to be owned by them, subject to such minor defects as are common to property of the type owned by the Borrower and its Subsidiaries and Liens permitted by this Agreement and such defects and Liens in the aggregate do not materially interfere with or impair the Borrower's or any Subsidiary's business as presently conducted. 5.17 Public Utility Holding Company Act. The Borrower and the Subsidiaries are exempt from registration under the provisions of the Public Utility Holding Company Act of 1935 pursuant to Section 3(a) thereof. 5.18 Regulatory Approval. No consent or authorization of, filing with, or any other act by or in respect of any Person is required in connection with the enforceability, execution, delivery, performance or validity of this Agreement or the transactions contemplated thereby. 5.19 Negative Pledge. Except as set forth in Schedule 5.19 hereto, neither the Borrower nor any Subsidiary is subject to any agreement, indenture, instrument, undertaking or security (other than this Agreement) which prohibits the creation, incurrence or sufferance to exist of any Lien. 5.20 Investment Company Act. The Borrower is not an "investment company" or a Borrower "controlled" by an "investment company", within the meaning of the Investment Company Act of 1940, as amended. 5.21 Compliance with Laws. The Borrower and its Subsidiaries have all franchises, licenses and permits necessary for the conduct of their respective businesses, and are in compliance with all laws, rules, regulations, orders, writs, judgments, injunctions, decrees or awards to which it may be subject, including, without limitation, (i) all provisions of ERISA, which, if violated, might result in a Lien or charge upon any property of the Borrower or any Subsidiary, and (ii) all material provisions of the Occupational Safety and Health Act of 1970 and the rules and regulations thereunder and applicable statutes, regulations, orders and restrictions relating to environmental standards or controls, except to the extent that failure to maintain or comply with any of the foregoing, singly and in the aggregate, could not reasonably be expected to have a Material Adverse Effect. ARTICLE VI COVENANTS During the term of this Agreement, unless the Required Lenders shall otherwise consent in writing: 6.1 Information. The Borrower will furnish to each Lender: -33- (a) As soon as reasonably practicable and in any event within 120 days after the close of each of its fiscal years, financial statements of the Borrower for such fiscal year on a consolidated and consolidating basis (consolidating statements need not be certified by such accountants) for itself and its Subsidiaries, including balance sheets as of the end of such period, statements of income and statements of retained earnings, and statements of cash flows, and, as to the consolidated statements, prepared in accordance with generally accepted accounting principles (except as expressly set forth therein) and accompanied by an unqualified (as to going concern or the scope of the audit) opinion of independent certified public accountants of recognized standing, which opinion shall state that such audit was conducted in accordance with generally accepted auditing standards and said financial statements fairly present the financial condition and results of operation of the Borrower as at the end of, and for, such fiscal year and a certificate of said accountants that, in the course of their examination necessary for their opinion, they have obtained no knowledge of any Default or Unmatured Default relating to accounting matters, or if, in the opinion of such accountants, any such Default or Unmatured Default shall exist, said certificate shall state the nature and status thereof; provided that delivery pursuant to subsection (e) below of copies of the Annual Report on Form 10-K of the Borrower for such fiscal year filed with the Securities and Exchange Commission (together with copies of the financial statements required to be included therein) shall be deemed to satisfy the requirement of this subsection (a) to deliver consolidated financial statements (but not the requirement to deliver consolidating statements or the accountants' certificate as to the presence or absence of any Default or Unmatured Default). (b) As soon as reasonably practicable and in any event within 60 days after the close of each of the first three quarterly accounting periods of each of its fiscal years, for itself and its Subsidiaries, consolidated and consolidating unaudited balance sheets as at the close of each such period and consolidated and consolidating statements of income and statements of retained earnings and statements of cash flows for the period from the beginning of such fiscal year to the end of such quarter; provided that delivery pursuant to subsection (e) below of copies of the Quarterly Report on Form 10-Q of the Borrower for such quarterly period filed with the Securities and Exchange Commission shall be deemed to satisfy the requirements of this subsection (b) to deliver consolidated financial statements (but not the requirement to deliver the certificate of the Borrower's chief financial officer or chief accounting officer with respect thereto). (c) Simultaneously with the delivery of each set of financial statements referred to in Sections 6.1(a) and 6.1(b), a certificate of the chief financial officer or the chief accounting officer of the Borrower in the form of Exhibit G (i) setting forth in reasonable detail the calculations required to establish whether the Borrower was in compliance with the requirements of Section 6.4 on the date of such financial statements, (ii) stating whether there exists on the date of such certificate any Default and or Unmatured Default and, if any Default or Unmatured Default then exists setting forth the details thereof and the action which the Borrower is taking or proposes to take with respect -34- thereto, and (iii) stating that such financial statements fairly reflect in all material respects the financial conditions and results of operations of the Borrower and its Subsidiaries as of the date of the delivery of such financial statements and for the period covered thereby. (d) As soon as possible and in any event within 10 Business Days after the Borrower has Knowledge that any of the events or conditions specified below has occurred or exists with respect to any Plan or Multiemployer Plan, a statement, signed by the chief financial officer or chief accounting officer of the Borrower, describing said event or condition and the action which the Borrower or applicable member of the Controlled Group proposes to take with respect thereto (and a copy of any report or notice required to be filed with or given to the PBGC by the Borrower or applicable member of the Controlled Group with respect to such event or condition): (i) the occurrence of any Reportable Event with respect to any Plan, or any waiver shall be requested under Section 412(d) of the Code for any Plan, (ii) the distribution under Section 4041(c) of ERISA of a notice of intent to terminate any Plan, or any action taken by the Borrower or any member of the Controlled Group to terminate any Plan under Section 4041(c) of ERISA, (iii) the institution by PBGC of proceedings under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan, or the receipt by the Borrower or any member of the Controlled Group of a notice from any Multiemployer Plan that such action has been taken by PBGC with respect to such Multiemployer Plan, (iv) the complete or partial withdrawal from a Multiemployer Plan by the Borrower or any member of the Controlled Group that could reasonably be expected to result in liability of the Borrower or such member under Section 4201 or 4204 of ERISA (including the obligation to satisfy secondary liability as a result of a purchaser default) having a Material Adverse Effect, or the receipt by the Borrower or any member of the Controlled Group of notice from a Multiemployer Plan that it is in reorganization or insolvency pursuant to Section 4241 or 4245 of ERISA or that it intends to terminate or has terminated under Section 4041A of ERISA, (v) the institution of a proceeding by a fiduciary of any Multiemployer Plan against the Borrower or any member of the Controlled Group to enforce Section 515 of ERISA, which proceeding is not dismissed within 30 days, or (vi) the adoption of an amendment to any Plan that, pursuant to Section 401(a)(29) of the Code or Section 307 of ERISA, would result in the loss of tax-exempt status of the trust of which such Plan is a part if the Borrower or any -35- member of the Controlled Group fails to timely provide security to the Plan in accordance with the provisions of said Sections. (e) Promptly upon the filing thereof, copies of al registration statements and annual, quarterly, monthly or other regular reports which the Borrower or any of its Subsidiaries files with the Securities and Exchange Commission. (f) Promptly upon the furnishing thereof to all shareholders of the Borrower generally, copies of all financial statements, reports and proxy statements so furnished. (g) Promptly upon receipt thereof, one copy of each written audit report submitted to the Borrower or any Subsidiary by independent accountants resulting from (i) any annual or interim audit submitted after the occurrence and during the continuance of a Default or Unmatured Default and (ii) any special audit submitted at any time, in each case, made by them of the books of the Borrower or any Subsidiary. (h) As soon as available and in any event not later than April 30 of each calendar year, an engineering and economic analysis of the producing properties of the Borrower and its Subsidiaries prepared by an independent firm of consulting petroleum engineers and in form, substance and detail consistent with past practice. (i) Promptly and in any event within five Business Days after an Authorized Officer obtains knowledge thereof, notice of the occurrence of a Default or Unmatured Default, together with the details of such event and the actions, if any, the Borrower has taken or intends to take with respect thereto. (j) Such other information (including nonfinancial information) as the Administrative Agent or any Lender may from time t time reasonably request. 6.2 Affirmative Covenants. The Borrower will, and will cause each Subsidiary, to: 6.2.1 Reports and Inspection. Keep proper books and records in good order in accordance with sound business practice and prepare its financial statements in accordance with Agreement Accounting Principles and permit the Administrative Agent or any Lender, at its own expense, by its representatives and agents, to inspect any of the properties, books and financial records of the Borrower and each Subsidiary, to examine and make copies of the books of accounts and other financial records of the Borrower and each Subsidiary, and to discuss the affairs, finances and accounts of the Borrower and each Subsidiary with, and to be advised as to the same by, their respective officers at such reasonable times and intervals during regular business hours as the Administrative Agent or such Lender may designate, provided that such inquiry shall be limited to the purpose of evaluating the Borrower's financial condition or compliance with this Agreement. -36- 6.2.2 Conduct of Business. Carry on and conduct its principal business of exploration for, and production, transportation, distribution, refinement, processing, storage, marketing and gathering of oil and other hydrocarbons and petroleum, and natural, synthetic or other gas in substantially the same manner and in substantially the same fields of enterprise as it is presently conducted; and do all things necessary to remain duly organized, validly existing and in good standing as a domestic corporation or limited liability company in its jurisdiction of organization (unless the existence or ownership by the Borrower of any Subsidiary shall be discontinued as a result of a merger, consolidation or sale of assets as permitted by Section 6.3.2) and maintain all requisite authority to conduct its business in each jurisdiction in which the failure to have such authority could reasonably be expected to have a Material Adverse Effect. 6.2.3 Insurance. Maintain insurance with reputable insurance companies or associations in such forms and amounts and covering such risks as are customary for companies of established reputation and similar size engaged in similar businesses and owning and operating similar properties; provided that it is agreed that, as of the date of this Agreement, the insurance coverage of the Borrower and its Subsidiaries set forth on Schedule 6.2 hereto satisfies the requirements of this Section 6.2.3. 6.2.4 Taxes. Promptly pay and discharge all material taxes, assessments and governmental charges or levies imposed upon the Borrower or any Subsidiary (but in the case of a Subsidiary, only to the extent that such Subsidiary's assets shall be sufficient for the purpose), respectively, or upon or in respect of all or any part of the property and business of the Borrower or any Subsidiary, and all due and payable claims for work, labor or materials, which if unpaid might become a Lien upon any property of the Borrower or any Subsidiary (other than claims against any such Subsidiary in a proceeding under any bankruptcy or similar law), provided that the Borrower or such Subsidiary shall not be required to pay any such tax, assessment, charge, levy or claim if the validity thereof shall concurrently be contested in good faith by appropriate proceedings and if the Borrower or such Subsidiary shall set aside on its or their books reserves deemed by it or them to be required with respect thereto in accordance with generally accepted accounting principles. 6.2.5 Compliance with Laws. Maintain all franchises, licenses and permits necessary for the conduct of its businesses, and comply with all laws, rules, regulations, orders, writs, judgments, injunctions, decrees or awards to which it may be subject, including, without limitation, (i) all provisions of ERISA, which, if violated, might result in a Lien or charge upon any property of the Borrower or any Subsidiary, and (ii) all material provisions of the Occupational Safety and Health Act of 1970 and the rules and regulations thereunder and applicable statutes, regulations, orders and restrictions relating to environmental standards or controls, except to the extent that failure to maintain or comply with any of the foregoing, singly and in the aggregate, could not reasonably be expected to have a Material Adverse Effect. 6.2.6 Maintenance of Properties. Do all things necessary to maintain, preserve, protect and keep its material properties (whether owned in fee or a leasehold interest) in good repair, working order and condition, and make all proper repairs, renewals and replacements so that its -37- business carried on in connection therewith may be properly conducted at all times; provided that, subject to Section 6.3.2 and all other terms of this Agreement, nothing in this Section 6.2.6 shall prevent the Borrower or any of its Subsidiaries from discontinuing the operation and maintenance of any of its properties (x) if such discontinuance is, in the judgment of the Borrower or such Subsidiary, desirable in the conduct of its business or (y) if such discontinuance or disposal could not reasonably be expected to have a Material Adverse Effect. 6.2.7 Additional Guarantors. On the date on which any Subsidiary which is not an original signatory to the Subsidiary Guaranty delivers to the Administrative Agent a counterpart of the Subsidiary Guaranty, cause such Subsidiary to deliver such supporting documents (including documents of the types described in clauses (i), (ii), (iii) and (vi) of Section 4.1(b)) as the Administrative Agent or any Lender may reasonably request in support thereof. 6.3 Negative Covenants. The Borrower will not, nor (where applicable) will it permit any Subsidiary to: 6.3.1 Restricted Payments. Declare or pay any dividends on its capital stock (other than dividends payable in its own capital stock) or redeem, repurchase or otherwise acquire or retire any of its capital stock at any time outstanding or any warrants, rights or options to purchase or acquire any shares of its capital stock or permit any Subsidiary to purchase any shares of stock of the Borrower, except that any Subsidiary may declare and pay dividends to the Borrower or another Wholly-Owned Subsidiary. 6.3.2 Merger and Sale of Assets. Merge or consolidate with or into any other Person or lease, sell or otherwise dispose of all, or substantially all, of its property, assets (other than inventory, physical assets sold in the ordinary course of business or obsolete, worn out or excess property) or business to any other Person except that: (1) the Borrower may merge or consolidate with or sell all of its assets to any other solvent corporation, provided that (i) the surviving, continuing or resulting corporation (if not the Borrower) shall (x) expressly assume by a written instrument reasonably satisfactory to the Administrative Agent and the Lenders (which shall be provided with an opportunity to review and comment upon it prior to the consummation of any transaction) the due and punctual payment of the principal of all Obligations and the due performance and observance of all covenants, conditions and agreements on the part of the Borrower under this Agreement, (y) deliver to the Administrative Agent and the Lenders an opinion of counsel, in form and substance reasonably satisfactory to the Administrative Agent and the Lenders, to the effect that such written instrument has been duly authorized, executed and delivered by such surviving, continuing or resulting corporation and constitutes a legal, valid and binding instrument enforceable against such surviving, continuing or resulting corporation in accordance with its terms, and to such further effects as the Administrative Agent and the Lenders may reasonably request, and (z) have an investment grade rating from Moody's Investors Service, Inc. and Standard & Poor's Rating Group, (ii) the surviving, continuing or resulting corporation shall be a corporation organized and existing under the laws of the United States of America or any State -38- thereof or the District of Columbia, and (iii) immediately after such merger, consolidation or sale, no Default or Unmatured Default would exist; (2) any Subsidiary may merge into the Borrower or another Subsidiary which is a Wholly-Owned Subsidiary, and may sell, lease or otherwise dispose of any of its assets to the Borrower or another Subsidiary which is a Wholly-Owned Subsidiary; (3) any Subsidiary may merge or consolidate with any entity other than the Borrower or another Subsidiary, provided that (i) the surviving, continuing or resulting entity shall be a Subsidiary, and (ii) immediately after such merger or consolidation, no Default or Unmatured Default would exist; and (4) the Borrower may sell, lease or otherwise dispose of all or any part of its assets to any Person, and any Subsidiary may sell, lease or otherwise dispose of all or any part of its assets to any Person other than the Borrower or another Subsidiary, in each case for a consideration which represents the fair value at the time of such sale or other disposition, provided that (x) immediately after such sale, lease or other disposition (and the application of the proceeds thereof as provided in clause (y)) no Default or Unmatured Default would exist and (y) to the extent applicable, the Net Cash Proceeds of such sale, lease or other disposition are applied as required by Sections 2.8 and 2.9; and provided, further, that neither the Borrower nor any Subsidiary shall sell, lease or otherwise dispose of any asset if, after giving effect to such transaction, the aggregate fair market value of all assets sold, leased or otherwise disposed of by the Borrower and its Subsidiaries in any fiscal year of the Borrower (minus all Net Cash Proceeds thereof applied t reduce the Aggregate Commitment pursuant to Section 2.8(b)) would exceed 7.5% of the Borrower's consolidated assets as of the beginning of such fiscal year. Without imiting clause (4) above, the Borrower will not permit Arkansas Western Gas Company to (x) cease to be a Subsidiary of the Borrower; and (y) sell all or any Substantial Portion (as defined below) of its assets. For purposes of the foregoing, "Substantial Portion" means, with respect to Arkansas Western Gas Company, assets which (i) represent more than 20% of the consolidated tangible assets of Arkansas Western Gas Company and its Subsidiaries as at the beginning of the fiscal year in which any determination is to be made or (ii) are responsible for more than 20% of the consolidated net earnings of Arkansas Western Gas Company and its Subsidiaries for the fiscal year preceding the fiscal year in which any determination is to be made. 6.3.3 Liens. Create, incur, assume or suffer to exist any Lien on (a) any Productive Property, (b) any Principal Transmission Facility or (c) any shares of stock of any Subsidiary, except: (i) Liens for taxes, assessments or governmenta charges or levies on its property if the same shall not at the time be delinquent or thereafter can be paid without penalty or, provided the Borrower or any Subsidiary knew or should have known of such Liens, are being actively contested in good faith and by -39- appropriate proceedings and for which adequate reserves shall have been set aside on its books in accordance with Agreement Accounting Principles, (ii) Liens imposed by law, such as carriers', warehousemen's, operators', royalty, surface damages and mechanics' liens and other similar liens arising in the ordinary course of business which secure payment of obligations not more than 60 days past due or which are being contested in good faith by appropriate proceedings and for which adequate reserves shall have been set aside on its books in accordance with Agreement Accounting Principles, (iii) Liens incurred in the ordinary course of business (a) arising out of pledges or deposits under workmen's compensation laws, unemployment insurance, old age pensions, or other social security or retirement benefits, or similar legislation, (b) to secure the performance of letters of credit, bids, tenders, sales contracts, leases (including rent security deposits), statutory obligations, surety, appeal and performance bonds, joint operating agreements or other similar agreements and other similar obligations not incurred in connection with the borrowing of money, the obtaining of advances or the payment of the deferred purchase price of property or (c) consisting of deposits which secure public or statutory obligations of the Borrower or any Subsidiary, or surety, custom or appeal bonds to which the Borrower or any Subsidiary is a party, or the payment of contested taxes or import duties of the Borrower or any Subsidiary, (iv) utility easements, building restrictions and such other encumbrances or charges against real property as are of a nature generally existing with respect to properties of a similar character and which do not in any material way affect the marketability of the same or interfere with the use thereof in the business of the Borrower or the Subsidiaries, (v) Liens on drilling equipment and facilities in order to secure the financing for the construction of such equipment and facilities not constructed as of the date hereof, provided that such financing is permitted pursuant to Section 6.4, (vi) attachment, judgment and other similar Liens arising in connection with court proceedings; provided the execution or other enforcement of such Liens is effectively stayed or the claims secured thereby are being actively contested in good faith and by appropriate proceedings; and provided, further, the Borrower or any Subsidiary knew or should have known of such Liens, (vii) Liens on property of a Subsidiary, provided such Liens secure only obligations owing to the Borrower or a Wholly-Owned Subsidiary, -40- (viii) purchase money mortgages or other mortgages or other Liens on assets of the Borrower or any Subsidiary securing Indebtedness hereafter incurred by the Borrower or such Subsidiary for the acquisition of such assets, provided no such mortgage or other Lien shall extend to any other property (unless such mortgage or Lien is permitted under another clause of this Section 6.3.3) and the amount thereby secured shall not exceed the purchase price of such asset plus interest, if any, accrued thereon and shall be permitted pursuant to Section 6.4, (ix) Liens on property hereafter acquired (including shares of stock hereafter acquired of any Person (including any Person in which the Borrower or any Subsidiary already owns an interest)) existing at the time of acquisition and liens assumed by the Borrower or a Subsidiary as a result of a merger of another entity into the Borrower or a Subsidiary or the acquisition by the Borrower or a Subsidiary of the assets and liabilities of another entity, provided that in each case such Liens shall not have been created in anticipation of such transaction, (x) any right which any municipal or governmental body or agency may have by virtue of any franchise, license, contract or statute to purchase, or designate a purchaser of or order the sale of, any property of the Borrower or any Subsidiary upon payment of reasonable compensation therefor or to terminate any franchise, license or other rights or to regulate the property and business of the Borrower or any Subsidiary, (xi) easements or reservations in respect of any property of the Borrower or any Subsidiary for the purpose of rights-of-way and similar purposes, reservations, restrictions, covenants, party wall agreements, conditions of record and other encumbrances (other than to secure the payment of money) and minor irregularities or deficiencies in the record and evidence of title, which in the reasonable opinion of the Borrower (at the time of the acquisition of the property affected or subsequently) will not interfere in any material way with the proper operation and development of the property affected thereby, (xii) Liens existing on the date hereof and set forth on Schedule 5.19 hereto, (xiii) Liens on property to secure all or any part of the cost of construction, alteration or repair of any building, equipment or other improvement on all or any part of such property, including any pipeline, or to secure any Indebtedness incurred prior to, at the time of, or within 360 days after, the completion of such construction, alteration or repair to provide funds for the payment of all or any part of such cost, (xiv) rights of lessors under oil, gas or mineral leases arising in the ordinary course of business, -41- (xv) any extension, renewal or replacement (or successive extensions, renewals or replacements), in whole or in part, of any Lien referred to in the foregoing clauses; provided that the principal amount of Indebtedness secured thereby shall not exceed the principal amount of Indebtedness so secured at the time of such extension, renewal or replacement and such extension, renewal or replacement Lien shall be limited to all or a part of the property which secured the Lien so extended, renewed or replaced (plus improvements on such property), (xvi) Liens which may hereafter be attached to undeveloped real estate not containing oil or gas reserves presently owned by the Borrower in the ordinary course of the Borrower's real estate sales, development and rental activities, (xvii) Liens not otherwise permitted by the foregoing clauses of this Section 6.3.3 securing Indebtedness in an aggregate principal amount which, at the time of incurrence, does not exceed 5% of Stockholders' Equity as of the end of the most recently completed fiscal quarter of the Borrower as shown on the consolidated balance sheet related thereto, and (xviii) Liens not otherwise permitted by the foregoing clauses of this Section 6.3.3 in an aggregate principal amount in excess of 5% of Stockholders' Equity; provided that at the time such Lien is created, the Obligations will be secured pari passu with the obligations such Lien is securing pursuant to documentation in form and substance satisfactory to the Administrative Agent and the Lenders (drafts of which documentation shall be furnished to the Administrative Agent and the Lenders sufficiently in advance to provide the Administrative Agent and the Lenders with an opportunity to review and comment upon it prior to the granting of any such Lien). 6.3.4 Subsidiary Guarantors. Permit more than 10% of the consolidated assets of the Borrower and its Subsidiaries (excluding Arkansas Western Gas Company) to be owned by, or more than 10% of the consolidated earnings of the Borrower and its Subsidiaries (excluding Arkansas Western Gas Company) for the most recent period of four consecutive fiscal quarters (beginning with the period ending June 30, 2001) to be earned by, Subsidiaries (other than Arkansas Western Gas Company) which are not Guarantors. For the avoidance of doubt, Arkansas Western Gas Company shall not be required to be a Guarantor. 6.3.5 Investments. Make, incur, assume or suffer to exist any Investment in any other Person, except (without duplication) the following: (a) Cash Equivalent Investments; (b) Investments existing on the date of this Agreement; -42- (c) in the ordinary course of business, Investments by the Company in any Subsidiary or by any Subsidiary in the Company or any other Subsidiary; (d) bank deposits in the ordinary course of business; (e) Investments in Persons involved in oil and gas exploration and production and related businesses in the ordinary course of business consistent with past practice; and (f) other Investments in an aggregate amount not at any time exceeding $5,000,000. 6.3.6 Indebtedness of Arkansas Western Gas Company. Permit the aggregate outstanding principal amount of all Indebtedness of Arkansas Western Gas Company and its Subsidiaries (excluding (i) Indebtedness outstanding on the date hereof and renewals, extensions and refinancings thereof so long as the principal amount thereof is not increased and (ii) Indebtedness to the Borrower or another Wholly-Owned Subsidiary) to exceed $20,000,000. 6.4 Financial Covenants. The Borrower will not: 6.4.1 Debt to Capitalization Ratio. Permit the Debt to Capitalization Ratio at any time during any period set forth below to exceed the applicable ratio set forth below:
Period Maximum Debt to Capitalization Ratio =============================== ==================================== The date hereof through 3/30/02 0.75 to 1.0 3/31/02 through 3/30/03 0.70 to 1.0 3/31/03 through 3/30/04 0.65 to 1.0 Thereafter 0.60 to 1.0;
provided that if on any date prior to March 30, 2003 the Borrower is not required to reduce the Aggregate Commitment upon receipt of proceeds of any Equity Issuance pursuant to clause (iii) of the proviso to Section 2.8(b), the maximum Debt to Capitalization Ratio shall be reduced to 0.65 to 1.0 during the period from such date through March 30, 2003. 6.4.2 Interest Coverage Ratio. Permit the Interest Coverage Ratio as of the last day of any fiscal quarter of the Borrower to be less than the applicable ratio set forth below:
Fiscal Quarter Ending Minimum Interest Coverage Ratio =============================== ==================================== 6/30/01 through 12/31/02 3.75 to 1.0 3/31/03 through 12/31/03 4.00 to 1.0 Thereafter 5.00 to 1.0.
6.4.3 Net Worth. Permit Stockholder's Equity at any time to be less than the sum of (a) $135,000,000 plus (b) 50% of consolidated net income of the Borrower and its Subsidiaries for -43- each fiscal year of the Borrower (and, if applicable, the completed portion of the then-current fiscal year for which the Borrower has delivered financial statements pursuant to Section 6.1(b)) ending after the date of this Agreement, without giving effect to any loss in any such fiscal year (or, if applicable, the completed portion of the then-current fiscal year), excluding, in the case of the Borrower's 2001 fiscal year, the first fiscal quarter of such year, plus (c) 75% of the net proceeds of any Equity Issuance after the date of this Agreement. ARTICLE VII DEFAULTS 7.1 Events of Default. The occurrence and continuance of any one or more of the following events shall constitute a Default: 7.1.1 Representations and Warranties. Any representation or warranty made or deemed made by or on behalf of the Borrower to the Administrative Agent or any Lender in this Agreement or in any certificate or instrument delivered in connection herewith shall be materially false as of the date on which made. 7.1.2 Payment Default. Nonpayment of any principal, interest, fee or other obligation hereunder within ten days after the same becomes due. 7.1.3 Breach of Certain Covenants. The breach by the Borrower of (i) any of the terms or provisions of Section 6.1(i), 6.3.1, 6.3.2 or 6.4 or (ii) any of the terms or provisions of Section 6.3.3 which is not remedied within ten days after written notice from the Administrative Agent. 7.1.4 Other Breach of this Agreement. The breach by the Borrower (other than a breach which constitutes a Default under Section 7.1.1, 7.1.2 or 7.1.3) of any term or provision of this Agreement which is not remedied within 30 days after written notice from the Administrative Agent. 7.1.5 ERISA. An event or condition specified in Section 6.1(d) shall occur or exist with respect to any Plan or any Multiemployer Plan and, as a result or such event or condition, together with all other such events or conditions then outstanding, the Borrower or any member or the Controlled Group shall incur, or shall be reasonably likely to incur, a liability to any Plan, any Multiemployer Plan or the PBGC (or any combination of the foregoing) that would have a Material Adverse Effect. 7.1.6 Cross-Default. Failure of the Borrower or any Significant Subsidiary to pay any Indebtedness when due (after giving effect to any period of grace set forth in any agreement under which such Indebtedness was created or is governed); or the default by the Borrower or any Significant Subsidiary in the performance of any other term, provision or condition contained in any agreement under which any of their respective Indebtedness was created or is governed, the effect of which is to cause, or to permit the holder or holders of such Indebtedness -44- to cause, such Indebtedness to become due prior to its stated maturity; or any Indebtedness of the Borrower or any Significant Subsidiary shall become due and payable or be required to be prepaid (other than by a regularly scheduled payment) prior to the stated maturity thereof; provided that, in each case, the principal amount of Indebtedness as to which such a payment default shall occur and be continuing, or such a failure to perform or other event causing or permitting acceleration shall occur and be continuing, exceeds $5,000,000. 7.1.7 Voluntary Bankruptcy, etc. The Borrower, or any Significant Subsidiary or a Material Group of Subsidiaries shall (i) not pay, or admit in writing its inability to pay, its debts generally as they become due, (ii) make an assignment for the benefit of creditors, (iii) apply for, seek, consent to, or acquiesce in, the appointment of a receiver, custodian, trustee, examiner, liquidator or similar official for the Borrower, such Significant Subsidiary or such Material Group of Subsidiaries, (iv) institute any proceeding seeking an order for relief under the Federal bankruptcy laws as now or hereafter in effect or seeking to adjudicate it a bankrupt or insolvent, or seeking dissolution, winding up, liquidation, reorganization, arrangement, adjustment or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors or (v) take any action to authorize or effect any of the foregoing actions set forth in this Section 7.1.7. 7.1.8 Involuntary Bankruptcy, etc. Without the application, approval or consent of the Borrower, the applicable Significant Subsidiary or the applicable Material Group of Subsidiaries, a receiver, trustee, examiner, liquidator or similar official shall be appointed for the Borrower, any Significant Subsidiary or such Material Group of Subsidiaries, or a proceeding described in Section 7.1.7(iv) shall be instituted against the Borrower, any Significant Subsidiary or such Material Group of Subsidiaries and such appointment continues undischarged or such proceeding continues undismissed or unstayed for a period of 60 consecutive days. 7.1.9 Judgments. The Borrower or any Significant Subsidiary shall fail within 30 days to pay, bond or otherwise discharge any final judgment or order for the payment of money in excess of $2,500,000, which is not stayed on appeal or otherwise being appropriately contested in good faith. 7.1.10 Environmental Matters. The Borrower, any Significant Subsidiary or any Material Group of Subsidiaries shall suffer any adverse determination pertaining to the release by the Borrower, any Significant Subsidiary or any other Person of any toxic or hazardous waste or substance into the environment, or any violation of any federal, state or local environmental, health or safety law or regulation, which, in either case, could reasonably be expected to have a Material Adverse Effect. 7.1.11 Subsidiary Guaranty. The Subsidiary Guaranty shall fail to remain in full force or effect or any action shall be taken to discontinue or to assert the invalidity or unenforceability of the Subsidiary Guaranty, or any Guarantor shall deny that it has any further liability under the Subsidiary Guaranty or shall give notice to such effect (excluding any Guarantor which ceases to be a Subsidiary as a result of a transaction permitted by this Agreement). -45- ARTICLE VIII ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES; RELEASES OF GUARANTORS 8.1 Acceleration. If any Default described in Section 7.1.6 or 7.1.7 occurs with respect to the Borrower, the obligations of the Lenders to make Loans hereunder shall automatically terminate and the Obligations shall immediately become due and payable without any election or action on the part of the Administrative Agent or any Lender. If any other Default occurs, the Required Lenders (or the Administrative Agent with the consent of the Required Lenders) may terminate or suspend the obligations of the Lenders to make Loans hereunder, or declare the Obligations to be due and payable, or both, whereupon the Obligations shall become immediately due and payable, without presentment, demand, protest or notice of any kind, all of which the Borrower hereby expressly waives. If, within 30 days after acceleration of the maturity of the Obligations or termination of the obligations of the Lenders to make Loans hereunder as a result of any Default (other than any Default as described in Section 7.1.6 or 7.1.7 with respect to the Borrower) and before any judgment or decree for the payment of the Obligations due shall have been obtained or entered, the Required Lenders (in their sole discretion) shall so direct, the Administrative Agent shall, by notice to the Borrower, rescind and annul such acceleration and/or termination. 8.2 Amendments. Subject to the provisions of this Article VIII, the Required Lenders (or the Administrative Agent with the consent in writing of the Required Lenders) and the Borrower may enter into agreements supplemental hereto for the purpose of adding to or modifying any provision in any Loan Document or changing in any manner the rights of the Lenders or the Borrower hereunder or waiving any Default hereunder; provided that no such supplemental agreement shall, without the consent of all of the Lenders: (i) Extend the final maturity of any Loan or forgive all or any portion of the principal amount thereof, or reduce the rate or extend the time of payment of interest or fees thereon. (ii) Reduce the percentage specified in the definition of Required Lenders. (iii) Extend the Termination Date, or reduce the amount or extend the payment date for, the mandatory payments required under Section 2.12, or increase the amount of the Aggregate Commitment or of the Commitment of any Lender hereunder, or permit the Borrower to assign its rights under this Agreement. (iv) Amend the last paragraph of Section 6.3.2 or this Section 8.2. -46- (v) Release any Guarantor from its obligations under the Subsidiary Guaranty (except as provided in Section 8.4). No amendment of any provision of this Agreement relating to the Administrative Agent shall be effective without the written consent of the Administrative Agent. No amendment of any provision of this Agreement relating to the Swing Line Lender or any Swing Line Loan shall be effective without the written consent of the Swing Line Lender. The Administrative Agent may waive payment of the fee required under Section 12.3.2 without obtaining the consent of any other party to this Agreement. 8.3 Preservation of Rights. No delay or omission of the Lenders or the Administrative Agent to exercise any right under the Loan Documents shall impair such right or be construed to be a waiver of any Default or an acquiescence therein, and the making of a Loan notwithstanding the existence of a Default or the inability of the Borrower to satisfy the conditions precedent to such Loan shall not constitute any waiver or acquiescence. Any single or partial exercise of any such right shall not preclude other or further exercise thereof or the exercise of any other right, and no waiver, amendment or other variation of the terms, conditions or provisions of the Loan Documents whatsoever shall be valid unless in writing signed by the Lenders required pursuant to Section 8.2, and then only to the extent in such writing specifically set forth. All remedies contained in the Loan Documents or by law afforded shall be cumulative and all shall be available to the Administrative Agent and the Lenders until the Obligations have been paid in full. 8.4 Releases of Guarantors. The Lenders hereby authorize the Administrative Agent to, and the Administrative Agent agrees that it will, release any Guarantor from its obligations under the Subsidiary Guaranty so long as (a) no Default or Unmatured Default exists or will result therefrom and (b) either (i) such Guarantor ceases to be a Subsidiary as a result of a transaction permitted hereunder or (ii) the Borrower requests such release in writing and, after giving effect thereto, the Borrower will be in compliance with Section 6.3.4. In determining whether any such release is permitted, the Administrative Agent may rely on a certificate from the Borrower. The Administrative Agent shall promptly notify the Lenders of any such release. ARTICLE IX GENERAL PROVISIONS 9.1 Survival of Representations. All representations and warranties of the Borrower contained in this Agreement shall survive the making of the Loans herein contemplated. 9.2 Governmental Regulation. Anything contained in this Agreement to the contrary notwithstanding, no Lender shall be obligated to extend credit to the Borrower in violation of any limitation or prohibition provided by any applicable statute or regulation. -47- 9.3 Headings. Section headings in the Loan Documents are for convenience of reference only, and shall not govern the interpretation of any of the provisions of the Loan Documents. 9.4 Entire Agreement. The Loan Documents embody the entire agreement and understanding among the Borrower, the Administrative Agent and the Lenders and supersede all prior agreements and understandings among the Borrower, the Administrative Agent and the Lenders relating to the subject matter thereof. 9.5 Several Obligations; Benefits of this Agreement. The respective obligations of the Lenders hereunder are several and not joint and no Lender shall be the partner or agent of any other (except to the extent to which the Administrative Agent is authorized to act as such). The failure of any Lender to perform any of its obligations hereunder shall not relieve any other Lender from any of its obligations hereunder. This Agreement shall not be construed so as to confer any right or benefit upon any Person other than the parties to this Agreement and their respective successors and assigns, provided that the parties hereto expressly agree that the Arranger shall enjoy the benefits of the provisions of Sections 9.6, 9.10 and 10.11 to the extent specifically set forth therein and shall have the right to enforce such provisions on its own behalf and in its own name to the same extent as if it were a party to this Agreement. 9.6 Expenses; Indemnification. (i) The Borrower shall reimburse the Administrative Agent and the Arranger for all reasonable costs, internal charges and out-of-pocket expenses (including, subject to any limit on fees which is separately agreed to, reasonable attorneys' fees and reasonable time charges of attorneys for the Administrative Agent, which attorneys may be employees of the Administrative Agent) paid or incurred by the Administrative Agent or the Arranger in connection with the preparation, negotiation, execution, delivery, syndication, review, amendment, modification, and administration of the Loan Documents. The Borrower also agrees to reimburse the Administrative Agent, the Arranger and the Lenders for all reasonable costs, internal charges and out-of-pocket expenses (including reasonable attorneys' fees and reasonable time charges of attorneys for the Administrative Agent, the Arranger and the Lenders, which attorneys may be employees of the Administrative Agent, the Arranger or any Lender) paid or incurred by the Administrative Agent, the Arranger or any Lender in connection with the collection and enforcement of the Loan Documents. (ii) The Borrower hereby further agrees to indemnify the Administrative Agent, the Arranger, each Lender, their respective affiliates, and each of their directors, officers and employees against all losses, claims, damages, penalties, judgments, liabilities and reasonable expenses (including, without limitation, all reasonable expenses of litigation or preparation therefor whether or not the Administrative Agent, the Arranger, any Lender or any affiliate is a party thereto) which any of them may pay or incur arising out of or relating to this Agreement, the other Loan Documents, the transactions contemplated hereby or the direct or indirect application or proposed application of the proceeds of any Loan hereunder except to the extent that they are determined in a final non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the party seeking -48- indemnification. The obligations of the Borrower under this Section 9.6 shall survive the termination of this Agreement. 9.7 Numbers of Documents. All statements, notices, closing documents, and requests hereunder shall be furnished to the Administrative Agent with sufficient counterparts so that the Administrative Agent may furnish one to each of the Lenders. 9.8 Accounting. Except as provided to the contrary herein, all accounting terms used herein shall be interpreted and all accounting determinations hereunder shall be made in accordance with Agreement Accounting Principles. 9.9 Severability of Provisions. Any provision in any Loan Document that is held to be inoperative, unenforceable, or invalid in any jurisdiction shall, as to that jurisdiction, be inoperative, unenforceable, or invalid without affecting the remaining provisions in that jurisdiction or the operation, enforceability, or validity of that provision in any other jurisdiction, and to this end the provisions of all Loan Documents are declared to be severable. 9.10 Nonliability of Lenders. The relationship between the Borrower on the one hand and the Lenders and the Administrative Agent on the other hand shall be solely that of borrower and lender. None of the Administrative Agent, the Arranger or any Lender shall have any fiduciary responsibilities to the Borrower. None of the Administrative Agent, the Arranger or any Lender undertakes any responsibility to the Borrower to review or inform the Borrower of any matter in connection with any phase of the Borrower's business or operations. The Borrower agrees that none of the Administrative Agent, the Arranger or any Lender shall have liability to the Borrower (whether sounding in tort, contract or otherwise) for losses suffered by the Borrower in connection with, arising out of, or in any way related to, the transactions contemplated and the relationship established by the Loan Documents, or any act, omission or event occurring in connection therewith, unless it is determined in a final non-appealable judgment by a court of competent jurisdiction that such losses resulted from the gross negligence or willful misconduct of the party from which recovery is sought. None of the Administrative Agent, the Arranger or any Lender shall have any liability with respect to, and the Borrower hereby waives, releases and agrees not to sue for, any special, indirect or consequential damages suffered by the Borrower in connection with, arising out of, or in any way related to the Loan Documents or the transactions contemplated thereby. 9.11 Confidentiality. Each Lender agrees to hold any confidential information which it may receive from the Borrower pursuant to this Agreement in confidence, except for disclosure (i) to the extent permitted by law or regulation, to its Affiliates and to other Lenders and their respective Affiliates, (ii) to legal counsel, accountants, and other professional advisors to such Lender or to a Transferee, (iii) to regulatory officials, (iv) to any Person as required by law, regulation, or legal process, (v) to any Person in connection with any legal proceeding to which such Lender is a party to the extent required by law, regulation or legal process, (vi) permitted by Section 12.4, (vii) to rating agencies if required by such agencies in connection with a rating relating to the Advances hereunder, and (viii) to the extent required in connection with the -49- exercise of any remedy or any enforcement of this Agreement by such Lender or the Administrative Agent. 9.12 Nonreliance. Each Lender hereby represents that it is not relying on or looking to any margin stock (as defined in Regulation U of the Board of Governors of the Federal Reserve System) for the repayment of the Loans provided for herein. 9.13 Disclosure. The Borrower and each Lender hereby (i) acknowledge and agree that Bank One and/or its Affiliates from time to time may hold investments in, make other loans to or have other relationships with the Borrower and its Affiliates, and (ii) waive any liability of Bank One or such Affiliate of Bank One to the Borrower or any Lender, respectively, arising out of or resulting from such investments, loans or relationships other than liabilities arising out of the gross negligence or willful misconduct of Bank One or its Affiliates. ARTICLE X THE ADMINISTRATIVE AGENT 10.1 Appointment; Nature of Relationship. Bank One is hereby appointed by each of the Lenders as the Administrative Agent hereunder and under each other Loan Document, and each of the Lenders irrevocably authorizes the Administrative Agent to act as the contractual representative of such Lender with the rights and duties expressly set forth herein and in the other Loan Documents. The Administrative Agent agrees to act as Administrative Agent upon the express conditions contained in this Article X. Notwithstanding the use of the defined term "Administrative Agent," it is expressly understood and agreed that the Administrative Agent shall not have any fiduciary responsibilities to any Lender by reason of this Agreement or any other Loan Document and that Administrative Agent is merely acting as the contractual representative of the Lenders with only those duties as are expressly set forth in this Agreement and the other Loan Documents. In its capacity as the Administrative Agent, (i) the Administrative Agent does not assume any fiduciary duties to any of the Lenders, (ii) the Administrative Agent is a "representative" of the Lenders within the meaning of Section 9-105 of the Uniform Commercial Code and (iii) the Administrative Agent is acting as an independent contractor, the rights and duties of which are limited to those expressly set forth in this Agreement and the other Loan Documents. Each of the Lenders hereby agrees to assert no claim against the Administrative Agent on any agency theory or any other theory of liability for breach of fiduciary duty, all of which claims each Lender hereby waives. 10.2 Powers. The Administrative Agent shall have and may exercise such powers under the Loan Documents as are specifically delegated to the Administrative Agent by the terms of each thereof, together with such powers as are reasonably incidental thereto. The Administrative Agent shall not have any implied duties to the Lenders, or any obligation to the Lenders to take any action thereunder except any action specifically provided by the Loan Documents to be taken by the Administrative Agent. -50- 10.3 General Immunity. Neither the Administrative Agent nor any of the Administrative Agent's directors, officers, agents or employees shall be liable to the Borrower, the Lenders or any Lender for any action taken or omitted to be taken by it or them hereunder or under any other Loan Document or in connection herewith or therewith except to the extent such action or inaction is determined in a final non-appealable judgment by a court of competent jurisdiction to have arisen from the gross negligence or willful misconduct of such Person. 10.4 No Responsibility for Loans, Recitals, etc. Neither the Administrative Agent nor any of the Administrative Agent's directors, officers, agents or employees shall be responsible for or have any duty to ascertain, inquire into, or verify (a) any statement, warranty or representation made in connection with any Loan Document or any borrowing hereunder; (b) the performance or observance of any of the covenants or agreements of any obligor under any Loan Document, including, without limitation, any agreement by an obligor to furnish information directly to each Lender; (c) the satisfaction of any condition specified in Article IV, except for the receipt of items required to be delivered solely to Administrative Agent; (d) the existence or possible existence of any Default or Unmatured Default; (e) the validity, enforceability, effectiveness, sufficiency or genuineness of any Loan Document or any other instrument or writing furnished in connection therewith; or (f) the financial condition of the Borrower or of any of the Borrower's Subsidiaries. The Administrative Agent shall not have any duty to disclose to the Lenders information that is not required to be furnished by the Borrower to the Administrative Agent at such time, but is voluntarily furnished by the Borrower to the Administrative Agent (either in its capacity as the Administrative Agent or in its individual capacity). 10.5 Action on Instructions of Lenders. The Administrative Agent shall in all cases be fully protected in acting, or in refraining from acting, hereunder and under any other Loan Document in accordance with written instructions signed by the Required Lenders (or, when expressly required hereunder, all of the Lenders), and such instructions and any action taken or failure to act pursuant thereto shall be binding on all of the Lenders. The Lenders hereby acknowledge that the Administrative Agent shall not be under any duty to take any discretionary action permitted to be taken by it pursuant to the provisions of this Agreement or any other Loan Document unless it shall be requested in writing to do so by the Required Lenders. Each Administrative Agent shall be fully justified in failing or refusing to take any action hereunder and under any other Loan Document unless it shall first be indemnified to its satisfaction by the Lenders (ratably in accordance with their respective Pro Rata Shares) against any and all liability, cost and expense that it may incur by reason of taking or continuing to take any such action. The Administrative Agent agrees, upon the request of any Lender at any time an Unmatured Default exists, to give a written notice to the Borrower of the type described in Section 7.1.3 or 7.1.4. 10.6 Employment of Agents and Counsel. The Administrative Agent may execute any of its duties as Administrative Agent hereunder and under any other Loan Document by or through employees, agents, and attorneys-in-fact and shall not be answerable to the Lenders, except as to money or securities received by it or its authorized agents, for the default or -51- misconduct of any such agents or attorneys-in-fact selected by it with reasonable care. The Administrative Agent shall be entitled to advice of counsel concerning the contractual arrangement between the Administrative Agent and the Lenders and all matters pertaining to the Administrative Agent's duties hereunder and under any other Loan Document. 10.7 Reliance on Documents; Counsel. The Administrative Agent shall be entitled to rely upon any Note, notice, consent, certificate, affidavit, letter, telegram, statement, paper or document believed by it to be genuine and correct and to have been signed or sent by the proper person or persons, and, in respect to legal matters, upon the opinion of counsel selected by the Administrative Agent, which counsel may be employees of the Administrative Agent. 10.8 Administrative Agent's Reimbursement and Indemnification. The Lenders agree to reimburse and indemnify the Administrative Agent, ratably in accordance with their respective Pro Rata Shares, (i) for any amounts not reimbursed by the Borrower for which the Administrative Agent is entitled to reimbursement by the Borrower under the Loan Documents, (ii) for any other expenses incurred by the Administrative Agent on behalf of the Lenders, in connection with the preparation, execution, delivery, administration and enforcement of the Loan Documents (including, without limitation, for any expenses incurred by the Administrative Agent in connection with any dispute between the Administrative Agent and any Lender or between two or more of the Lenders) and (iii) for any liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind and nature whatsoever which may be imposed on, incurred by or asserted against the Administrative Agent in any way relating to or arising out of the Loan Documents or any other document delivered in connection therewith or the transactions contemplated thereby (including, without limitation, for any such amounts incurred by or asserted against the Administrative Agent in connection with any dispute between the Administrative Agent and any Lender or between two or more of the Lenders), or the enforcement of any of the terms of the Loan Documents or of any such other documents, provided that (i) no Lender shall be liable to the Administrative Agent for any of the foregoing to the extent any of the foregoing is found in a final non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the Administrative Agent and (ii) any indemnification required pursuant to Section 3.5(vii) shall, notwithstanding the provisions of this Section 10.8, be paid by the relevant Lender in accordance with the provisions thereof. The obligations of the Lenders under this Section 10.8 shall survive payment of the Obligations and termination of this Agreement. 10.9 Notice of Default. The Administrative Agent shall be deemed to have knowledge or notice of the occurrence of any Default or Unmatured Default hereunder unless the Administrative Agent has received written notice from a Lender or the Borrower referring to this Agreement describing such Default or Unmatured Default and stating that such notice is a "notice of default". In the event that the Administrative Agent receives such a notice, the Administrative Agent shall give prompt notice thereof to the Lenders. 10.10 Rights as a Lender. In the event the Administrative Agent is a Lender, the Administrative Agent shall have the same rights and powers hereunder and under any other Loan -52- Document with respect to its Commitment and its Loans as any Lender and may exercise the same as though it were not the Administrative Agent, and the term "Lender" or "Lenders" shall, at any time when the Administrative Agent is a Lender, unless the context otherwise indicates, include the Administrative Agent in its individual capacity. The Administrative Agent and its Affiliates may accept deposits from, lend money to, and generally engage in any kind of trust, debt, equity or other transaction, in addition to those contemplated by this Agreement or any other Loan Document, with the Borrower or any of its Subsidiaries in which the Borrower or such Subsidiary is not restricted hereby from engaging with any other Person. The Agent, in its individual capacity, is not obligated to remain a Lender. 10.11 Lender Credit Decision. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, the Arranger or any other Lender and based on the financial statements prepared by the Borrower and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and the other Loan Documents. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, the Arranger or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement and the other Loan Documents. 10.12 Successor Administrative Agent. The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower, such resignation to be effective upon the appointment of a successor Administrative Agent, or, if no successor Administrative Agent has been appointed, forty-five days after the retiring Administrative Agent gives notice of its intention to resign. The Administrative Agent may be removed at any time with or without cause by written notice received by the Administrative Agent from the Required Lenders, such removal to be effective on the date specified by the Required Lenders. Upon any resignation or removal of the Administrative Agent, the Required Lenders shall have the right (with, so long as no Default or Unmatured Default exists, the consent of the Borrower, which shall not be unreasonably withheld) to appoint, on behalf of the Borrower and the Lenders, a successor Administrative Agent. If no successor Administrative Agent shall have been so appointed by the Required Lenders within thirty days after the resigning Administrative Agent's giving notice of its intention to resign, then the resigning Administrative Agent may appoint, on behalf of the Borrower and the Lenders, a successor Administrative Agent. Notwithstanding the previous sentence, the Administrative Agent may at any time without the consent of any Lender and with the consent of the Borrower, not to be unreasonably withheld or delayed, appoint any of its Affiliates which is a commercial bank as a successor Administrative Agent hereunder. If the Administrative Agent has resigned or been removed and no successor Administrative Agent has been appointed, the Lenders may perform all the duties of the Administrative Agent hereunder and the Borrower shall make all payments in respect of the Obligations to the applicable Lender and for all other purposes shall deal directly with the Lenders. No successor Administrative Agent shall be deemed to be appointed hereunder until such Administrative Agent has accepted the appointment. Any such successor Administrative Agent shall be a commercial bank having capital and retained earnings of at least $100,000,000. Upon the acceptance of any appointment -53- as Administrative Agent hereunder by a successor Administrative Agent, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the resigning or removed Administrative Agent. Upon the effectiveness of the resignation or removal of the Administrative Agent, the resigning or removed Administrative Agent shall be discharged from its duties and obligations hereunder and under the Loan Documents. After the effectiveness of the resignation or removal of the Administrative Agent, the provisions of this Article X shall continue in effect for the benefit of the such Person in respect of any actions taken or omitted to be taken by such Person while such Person was acting as Administrative Agent hereunder and under the other Loan Documents. In the event that there is a successor to the Administrative Agent by merger, or the Administrative Agent assigns its duties and obligations to an Affiliate pursuant to this Section 10.12, then the term "Prime Rate" as used in this Agreement shall mean the prime rate, base rate or other analogous rate of the new Administrative Agent. 10.13 Delegation to Affiliates. The Borrower and the Lenders agree that the Administrative Agent may delegate any of its duties under this Agreement to any of its respective Affiliates. Any such Affiliate (and such Affiliate's directors, officers, agents and employees) which performs duties in connection with this Agreement shall be entitled to the same benefits of the indemnification, waiver and other protective provisions to which the Administrative Agent is entitled under Articles IX and X. 10.14 Other Agents. No Lender identified on the cover page or the signature pages of this Agreement or otherwise herein, or in any amendment hereof or other document related hereto, as being the "Syndication Agent" shall have any right, power, obligation, liability, responsibility or duty under this Agreement in such capacity other than those applicable to all Lenders. Each Lender acknowledges that it has not relied, and will not rely, on any Person so identified in deciding to enter into this Agreement or in taking or refraining from taking any action hereunder or pursuant hereto. ARTICLE XI SETOFF; RATABLE PAYMENTS 11.1 Setoff. In addition to, and without limitation of, any rights of the Lenders under applicable law, if the Borrower becomes insolvent, however evidenced, or any Default occurs, any and all deposits (including all account balances, whether provisional or final and whether or not collected or available) and any other Indebtedness at any time held or owing by any Lender or any Affiliate of any Lender to or for the credit or account of the Borrower may be offset and applied toward the payment of the Obligations owing to such Lender, whether or not the Obligations, or any part thereof, shall then be due. 11.2 Ratable Payments. If any Lender, whether by setoff or otherwise, has payment made to it upon its Ratable Loans or its participation in Swing Line Loans (other than payments -54- received pursuant to Section 3.1, 3.2, 3.4 or 3.5) in a greater proportion than that received by any other Lender, such Lender agrees, promptly upon demand, to purchase a portion of the Loans (or participations in Swing Line Loans) held by the other Lenders so that after such purchase each Lender will hold its Pro Rata Share of all Ratable Loans (and participations in Swing Line Loans). If any Lender, whether in connection with setoff or amounts which might be subject to setoff or otherwise, receives collateral or other protection for its Obligations or such amounts which may be subject to setoff, such Lender agrees, promptly upon demand, to take such action necessary such that all Lenders share in the benefits of such collateral ratably in proportion to their respective Pro Rata Shares. In case any such payment is disturbed by legal process, or otherwise, appropriate further adjustments shall be made. ARTICLE XII BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS 12.1 Successors and Assigns. The terms and provisions of the Loan Documents shall be binding upon and inure to the benefit of the Borrower and the Lenders and their respective successors and assigns, except that (i) the Borrower shall not have the right to assign its rights or obligations under the Loan Documents and (ii) any assignment by any Lender must be made in compliance with Section 12.3. The parties to this Agreement acknowledge that clause (ii) of the foregoing sentence relates only to absolute assignments and does not prohibit assignments creating security interests, including, without limitation, any pledge or assignment by any Lender of all or any portion of its rights under this Agreement and any Note to a Federal Reserve Bank; provided that no such pledge or assignment creating a security interest shall release the transferor Lender from its obligations hereunder unless and until the parties thereto have complied with the provisions of Section 12.3. The Administrative Agent may treat the Person which made any Loan or which holds any Note as the owner thereof for all purposes hereof unless and until such Person complies with Section 12.3; provided that the Administrative Agent may in its discretion (but shall not be required to) follow instructions from the Person which made any Loan or which holds any Note to direct payments relating to such Loan or Note to another Person. Any assignee of the rights to any Loan or any Note agrees by acceptance of such assignment to be bound by all the terms and provisions of the Loan Documents. Any request, authority or consent of any Person, who at the time of making such request or giving such authority or consent is the owner of the rights to any Loan (whether or not a Note has been issued in evidence thereof), shall be conclusive and binding on any subsequent holder or assignee of the rights to such Loan. 12.2 Participations. 12.2.1 Permitted Participants; Effect. Any Lender may, in the ordinary course of its business and in accordance with applicable law, at any time sell to one or more banks or other entities ("Participants") participating interests in any Loan owing to such Lender, any Note held by such Lender, any Commitment of such Lender or any other interest of such Lender under the -55- Loan Documents. In the event of any such sale by a Lender of participating interests to a Participant, such Lender's obligations under the Loan Documents shall remain unchanged, such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, such Lender shall remain the owner of its Loans and the holder of any Note issued to it in evidence thereof for all purposes under the Loan Documents, all amounts payable by the Borrower under this Agreement (including under Article III) shall be determined as if such Lender had not sold such participating interests, and the Borrower and the Administrative Agent shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under the Loan Documents. 12.2.2 Voting Rights. Each Lender shall retain the sole right to approve, without the consent of any Participant, any amendment, modification or waiver of any provision of the Loan Documents other than any amendment, modification or waiver with respect to any Loan or Commitment in which such Participant has an interest which forgives principal, interest or fees or reduces the interest rate or fees payable with respect to any such Loan or Commitment, extends the Termination Date, postpones any date fixed for any regularly scheduled payment of principal of, or interest or fees on, any such Loan or Commitment or releases any Guarantor from its obligations under the Subsidiary Guaranty (except as provided in Section 8.4). 12.3 Assignments. 12.3.1 Permitted Assignments. Any Lender may, in the ordinary course of its business and in accordance with applicable law, at any time assign to one or more banks or other entities ("Purchasers") all or any part of its rights and obligations under the Loan Documents. Such assignment shall be substantially in the form of Exhibit C or in such other form as may be agreed to by the parties thereto. The consents of the Borrower and the Administrative Agent (which consents shall not be unreasonably withheld or delayed by any such party) shall be required prior to an assignment becoming effective with respect to a Purchaser which is not a Lender or an Affiliate thereof; provided that if a Default has occurred and is continuing, the consent of the Borrower shall not be required; provided, further, that no assignment shall be permitted if, as of the date thereof, any event or circumstance exists which would result in the Borrower being obligated to pay any greater amount hereunder to the Purchaser than the Borrower is obligated to pay to the assigning Lender. Each such assignment with respect to a Purchaser which is not a Lender or an Affiliate thereof shall (unless each of the Borrower and the Administrative Agent otherwise consents) be in an amount not less than the lesser of (i) $5,000,000 or (ii) the remaining amount of the assigning Lender's Commitment (calculated as at the date of such assignment) or outstanding Ratable Loans and participations in Swing Line Loans (if the Commitments has been terminated). 12.3.2 Effect; Effective Date. Upon (i) delivery to the Administrative Agent of an assignment, together with any consents required by Section 12.3.1, and (ii) payment of a $4,000 fee to the Administrative Agent for processing such assignment (unless such fee is waived by the Administrative Agent), such assignment shall become effective on the effective date specified in such assignment. The assignment shall contain a representation by the Purchaser to the effect -56- that none of the consideration used to make the purchase of the Commitment and Loans under the applicable assignment agreement constitutes "plan assets" as defined under ERISA and that the rights and interests of the Purchaser in and under the Loan Documents will not be "plan assets" under ERISA. On and after the effective date of such assignment, such Purchaser shall for all purposes be a Lender party to this Agreement and any other Loan Document executed by or on behalf of the Lenders and shall have all the rights and obligations of a Lender under the Loan Documents, to the same extent as if it were an original party hereto, and no further consent or action by the Borrower, the Lenders or the Administrative Agent shall be required to release the transferor Lender with respect to the percentage of the Aggregate Commitment and Loans assigned to such Purchaser. Upon the consummation of any assignment to a Purchaser pursuant to this Section 12.3.2, the transferor Lender, the Administrative Agent and the Borrower shall, if the transferor Lender or the Purchaser desires that its Loans be evidenced by Notes, make appropriate arrangements so that new Notes or, as appropriate, replacement Notes are issued to such transferor Lender and new Notes or, as appropriate, replacement Notes, are issued to such Purchaser, in each case in principal amounts reflecting their respective Commitments, as adjusted pursuant to such assignment. 12.4 Dissemination of Information. The Borrower authorizes each Lender to disclose to any Participant or Purchaser or any other Person acquiring an interest in the Loan Documents by operation of law (each a "Transferee") and any prospective Transferee any and all information in such Lender's possession concerning the creditworthiness of the Borrower and its Subsidiaries, including without limitation any information contained in any Reports; provided that each Transferee and prospective Transferee agrees to be bound by Section 9.11 of this Agreement. 12.5 Tax Treatment. If any interest in any Loan Document is transferred to any Transferee which is organized under the laws of any jurisdiction other than the United States or any State thereof, the transferor Lender shall cause such Transferee, concurrently with the effectiveness of such transfer, to comply with the provisions of Section 3.5(iv) and the Borrower shall not be required to indemnify such Transferee pursuant to Section 3.5 hereof for any Taxes withheld as a result of the failure of the Transferee to so comply. ARTICLE XIII NOTICES 13.1 Notices. Except as otherwise permitted by Section 2.15 with respect to borrowing notices, all notices, requests and other communications to any party hereunder shall be in writing (including electronic transmission, facsimile transmission or similar writing) and shall be given to such party: (x) in the case of the Borrower or the Administrative Agent, at its address or facsimile number set forth on the signature pages hereof, (y) in the case of any Lender, at its address or facsimile number set forth in its administrative questionnaire or (z) in the case of any party, at such other address or facsimile number as such party may hereafter specify for the -57- purpose by notice to the Administrative Agent and the Borrower in accordance with the provisions of this Section 13.1. Each such notice, request or other communication shall be effective (i) if given by facsimile transmission, when transmitted to the facsimile number specified in this Section 13.1 and confirmation of receipt is received, or (ii) if given by any other means, when delivered (or, in the case of electronic transmission, received) at the address specified in this Section 13.1; provided that notices to the Administrative Agent under Article II shall not be effective until received. 13.2 Change of Address. The Borrower, the Administrative Agent and any Lender may each change the address for service of notice upon it by a notice in writing to the other parties hereto. ARTICLE XIV COUNTERPARTS This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Agreement by signing any such counterpart. This Agreement shall be effective when it has been executed by the Borrower, the Administrative Agent and the Lenders and each party has notified the Administrative Agent by facsimile transmission or telephone that it has taken such action. ARTICLE XV CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL; MAXIMUM INTEREST RATE 15.1 CHOICE OF LAW. THE LOAN DOCUMENTS (OTHER THAN THOSE CONTAINING A CONTRARY EXPRESS CHOICE OF LAW PROVISION) SHALL BE CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS (INCLUDING, WITHOUT LIMITATION, 735 ILCS SECTION 105/5-1 ET SEQ, BUT OTHERWISE WITHOUT REGARD TO THE CONFLICT OF LAWS PROVISIONS) OF THE STATE OF ILLINOIS, BUT GIVING EFFECT TO FEDERAL LAWS APPLICABLE TO NATIONAL BANKS. 15.2 CONSENT TO JURISDICTION. THE BORROWER HEREBY IRREVOCABLY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR ILLINOIS STATE COURT SITTING IN CHICAGO, ILLINOIS IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO ANY LOAN DOCUMENTS AND THE BORROWER HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH COURT AND IRREVOCABLY -58- WAIVES ANY OBJECTION IT MAY NOW OR HEREAFTER HAVE AS TO THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN SUCH A COURT OR THAT SUCH COURT IS AN INCONVENIENT FORUM. NOTHING HEREIN SHALL LIMIT THE RIGHT OF THE ADMINISTRATIVE AGENT OR ANY LENDER TO BRING PROCEEDINGS AGAINST THE BORROWER IN THE COURTS OF ANY OTHER JURISDICTION. ANY JUDICIAL PROCEEDING BY THE BORROWER AGAINST THE ADMINISTRATIVE AGENT OR ANY LENDER OR ANY AFFILIATE OF THE ADMINISTRATIVE AGENT OR ANY LENDER INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT SHALL BE BROUGHT ONLY IN A COURT IN CHICAGO, ILLINOIS. 15.3 WAIVER OF JURY TRIAL. THE BORROWER, THE ADMINISTRATIVE AGENT AND EACH LENDER HEREBY WAIVE TRIAL BY JURY IN ANY JUDICIAL PROCEEDING INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER (WHETHER SOUNDING IN TORT, CONTRACT OR OTHERWISE) IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT OR THE RELATIONSHIP ESTABLISHED THEREUNDER. 15.4 Maximum Interest Rate. No provision of the Loan Documents shall require the payment or permit the collection of interest in excess of the maximum permitted by applicable law ("Maximum Rate"). If any interest in excess of the Maximum Rate is provided for or shall be adjudicated to be provided for in the Notes or otherwise in connection with this Agreement, the provisions of this Section 15.4 shall govern and prevail and neither the Borrower nor the sureties, guarantors, successors or assigns of the Borrower shall be obligated to pay the excess amount of the interest or any other excess sum paid for the use, forbearance, or detention of sums loaned. In the event the Administrative Agent or any Lender ever receives, collects or applies as interest any amount in excess of the Maximum Rate, the amount by which such amount exceeds the Maximum Rate shall be applied as a payment and reduction of the principal of indebtedness evidenced by the Loans, and, if the principal amount of the Loans has been paid in full, any remaining excess shall forthwith be paid to the Borrower. -59- IN WITNESS WHEREOF, the Borrower, the Lenders, the Administrative Agent and the Syndication Agent have executed this Agreement as of the date first above written. SOUTHWESTERN ENERGY COMPANY By:_____________________________________ Executive Vice President and Chief Financial Officer 2350 N. Sam Houston Parkway East Suite 300 Houston, Texas 77032 Attention: Greg Kerley Fax: 281-618-4757 S-1 BANK ONE, NA, Individually and as Administrative Agent By:_____________________________________ Title:_______________________________ 1 Bank One Plaza Chicago, Illinois 60670 Attention: Madeleine Pember Fax: 312-732-9727 S-2 ROYAL BANK OF CANADA, Individually and as Syndication Agent By:_____________________________________ Title:_______________________________ Royal Bank of Canada 2800 Post Oak Boulevard Suite 5700 Houston, Texas 77056 Attention: Jason York Fax: 713-403-5624 S-3 FLEET NATIONAL BANK By:_____________________________________ Title:_______________________________ Mail Stop: MA DE 10008D 100 Federal Street Boston, MA 02110 Attention: Stephen Hoffman Fax: 617-434-3652 S-4 WELLS FARGO BANK TEXAS, N.A. By:_____________________________________ Title:_______________________________ Wells Fargo Bank Texas, N.A. 1000 Louisiana St. 3rd Floor Houston, TX 77002 Attention: Alan Smith Fax: 713-739-1087 S-5 COMPASS BANK By:_____________________________________ Title:_______________________________ Compass Bank 24 Greenway Plaza Suite 1400A Houston, TX 77046 Attention: Dorothy Marchand Fax: 713-968-8292 S-6 HIBERNIA NATIONAL BANK By:_____________________________________ Title:_______________________________ Hibernia National Bank 213 W. Vermilion St. 2nd Floor Lafayette, Louisiana 70501 Attention: David R. Reid Fax: 337-268-4566 S-7
Lender Amount of Commitment ============================ ===================== Bank One, NA $ 55,000,000 Royal Bank of Canada $ 40,000,000 Fleet National Bank $ 25,000,000 Wells Fargo Bank Texas, N.A. $ 15,000,000 Compass Bank $ 15,000,000 Hibernia National Bank $ 10,000,000 Aggregate Commitment $160,000,000
SCHEDULE 1B PRICING SCHEDULE
LEVEL I LEVEL II LEVEL III LEVEL IV LEVEL V STATUS STATUS STATUS STATUS STATUS ------- -------- --------- -------- ------- Commitment Fee Rate 17.5 20.0 25.0 30.0 30.0 (basis points) Applicable Margin 87.5 137.5 150.0 175.0 250.0 for Eurodollar Rate (basis points) Applicable Margin 0.0 0.0 0.0 25.0 100.0 for Floating Rate (basis points)
For the purposes of this Schedule, the following terms have the following meanings, subject to the final paragraph of this Schedule: "Level I Status" exists at any date if, on such date, the Borrower's Moody's Rating is Baa1 or better or the Borrower's S&P Rating is BBB+ or better. "Level II Status" exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status and (ii) the Borrower's Moody's Rating is Baa2 or better or the Borrower's S&P Rating is BBB or better. "Level III Status" exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status or Level II Status and (ii) the Borrower's Moody's Rating is Baa3 or better or the Borrower's S&P Rating is BBB- or better. "Level IV Status" exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status , Level II Status or Level III Status and (ii) the Borrower's Moody's Rating is Ba1 or better or the Borrower's S&P Rating is BB+ or better. "Level V Status" exists at any date if, on such date, the Borrower has not qualified for Level I Status, Level II Status, Level III Status , or Level IV Status. "Moody's Rating" means, at any time, the rating issued by Moody's Investors Service, Inc. and then in effect with respect to the Borrower's senior unsecured long-term public debt securities without third-party credit enhancement. "S&P Rating" means, at any time, the rating issued by Standard and Poor's Rating Services, a division of The McGraw Hill Companies, Inc., and then in effect with respect to the Borrower's senior unsecured long-term public debt securities without third-party credit enhancement. "Status" means Level I Status, Level II Status, Level III Status, Level IV Status or Level V Status. The Applicable Margin and Commitment Fee Rate shall be determined in accordance with the foregoing table based on the Borrower's Status as determined from its then-current Moody's and S&P Ratings. The credit rating in effect on any date for the purposes of this Schedule is that in effect at the close of business on such date. If at any time the Borrower has no Moody's Rating or no S&P Rating, Level V Status shall exist. If the Borrower is split-rated and the ratings differential is one level, the higher rating will apply. If the Borrower is split-rated and the ratings differential is two levels or more, the intermediate rating at the midpoint will apply. If there is no midpoint, the higher of the two intermediate ratings will apply. SCHEDULE 2.8(a) EXCLUDED ASSET SALES A.W. Realty Sale An undivided 2/3 interest in Lot1-B of Vantage Square, a Joint Venture, or a portion of Lot 1-B yet to be determined. Lot 1-B containing 5.86 acres is located in the northeast quarter of the northeast quarter of Section 26, Township 17 north, range 30 west of Washington County, Arkansas. Anticipated sales proceeds of approximately $1.2 million. SCHEDULE 2.8(b) ASSETS TO BE SWAPPED Southwestern Energy Production Company's working interest in approximately 250 oil and gas producing properties in the Anadarko Basin of Oklahoma. Properties would be anticipated to be sold at a price ranging from $20 million to $30 million. SCHEDULE 5.4 SUBSIDIARIES Arkansas Western Gas Company Southwestern Energy Production Company Southwestern Energy Pipeline Company SEECO, Inc. A.W. Realty Company Southwestern Energy Services Company Diamond M Production Company All of the above are 100% wholly-owned by the Company and are Arkansas corporations. Arkansas Gas Gathering Company, an Arkansas corporation, is 100% wholly-owned by SEECO, Inc. Overton Partners, LLC, an Arkansas limited liability company, is 100% wholly-owned by Southwestern Energy Production Company. SCHEDULE 5.13 LITIGATION On August 25, 2000, a class action suit was filed against the Borrower and its subsidiaries in Sebastian County, Arkansas, on behalf of all mineral owners who own or owned a royalty and/or overriding royalty interest in oil and gas leases or other agreements in certain sections of Franklin County, Arkansas. The Borrower was granted authority in 1968 by the Arkansas Oil and Gas Commission to operate a gas storage facility in one section of Franklin County. Based upon subsequently developed geological data, the Borrower sought authority to expand this area and was granted authority by the Arkansas Oil and Gas Commission to operate gas storage in additional sections. Plaintiffs are challenging the storage agreements that the Borrower obtained from the mineral interest owners in 1968, 1999 and 2000 to operate the gas storage facility known as "Stockton." Plaintiffs allege various wrongful, intentional and fraudulent acts relating to the operation of the storage pool beginning in 1968 and continuing to the present and allege that the above-referenced agreements from the mineral owners were obtained through misrepresentation and fraud. The Borrower has owned and operated the Stockton storage unit through its Arkansas Western Gas Company subsidiary until 1994, at which time it was transferred to its subsidiary, SEECO, Inc. Plaintiffs claim ownership rights in the gas that the Borrower has stored in the storage pool in an amount in excess of $5 million in actual damages, interest, attorney's fees and punitive damages. The Borrower and its outside counsel believe that this action is without merit and does not meet the requirements for a class action. The Borrower believes that plaintiffs claim to the storage gas, which the Borrower has injected into the storage facility, has no merit and is not supported by the Arkansas gas storage statute under which the Borrower operates this facility. While the amount of this claim could be significant, management believes, based upon its investigation, that this claim is without merit and that the Borrower's ultimate liability, if any, will not be material to its consolidated financial position, but in any one period it could be significant to its results of operations. SCHEDULE 5.19 NEGATIVE PLEDGES Listed below are all of the documents evidencing Indebtedness of Southwestern Energy Company and its Subsidiaries which contain limitations on the creation, incurrence, or assumption of Liens on any of their properties. Indenture dated as of December 1, 1995, between the Borrower and Bank One, NA (then known as The First National Bank of Chicago), as Trustee. SCHEDULE 6.2 INSURANCE 1. Property "all risk" insurance including earthquake coverage for buildings, personal property, equipment and inventory. Minimum limit of $15,000,000. 2. Workers' Compensation with Statutory Limits and Employer's Liability with $1,000,000 per accident or occupational disease covering all employees in compliance with the laws of the States of Arkansas, Oklahoma, New Mexico and Texas. Such policy is endorsed to provide United States Longshoremen's & Harbor Workers' Compensation Act and Maritime Coverages. 3. Comprehensive General Liability Insurance with bodily injury and death limits of $1,000,000 for injury to or death of one person and $2,000,000 for the death or injury of more than one person in one occurrence and property damage limits of $1,000,000 for each occurrence. 4. Automobile Public Liability Insurance covering bodily injury or death and property damage of at least $1,000,000 per occurrence, combined single limit. 5. Control of Well Coverage with $10,000,000 combined single limit for operator's extra expense/care, custody and control; redrilling/recompletion; and seepage, pollution and containment. 6. Umbrella Liability Insurance with minimum limits of at least $30,000,000 to apply in excess of the primary limits of the above stated policies. EXHIBIT A FORM OF BORROWING NOTICE Reference is made to the Credit Agreement dated as of July 12, 2001 (as from time to time amended, the "Agreement") among Southwestern Energy Company, an Arkansas corporation (the "Borrower"), various financial institutions, and Bank One, NA, as Administrative Agent (the "Administrative Agent"). Capitalized terms used but not defined herein have the respective meanings given to such terms in the Agreement. Pursuant to the Agreement, the Borrower hereby requests that an Advance in the amount of $_________ to be made on ____________, ____. The Borrower requests that the Advance to be made hereunder shall be [a Floating Rate Advance] [a Eurodollar Advance] [and shall have an Interest Period of _______________.] The Borrower certifies that: (a) The representations and warranties of the Borrower set forth in Article V of the Agreement are true and correct on and as of the date hereof, with the same effect as though such representations and warranties had been made on and as of the date hereof or, if such representations and warranties are expressly limited to particular dates, as of such particular dates. (b) No Default or Unmatured Default exists or will result from the Borrower's receipt and application of the proceeds of the Advance requested hereby. IN WITNESS WHEREOF, this instrument is executed as of _________, ____. SOUTHWESTERN ENERGY COMPANY By:________________________________ Name:______________________________ Title:_____________________________ EXHIBIT B FORM OF OPINION July 12, 2001 The Administrative Agent and the Lenders who are parties to the Credit Agreement described below. Gentlemen/Ladies: I am counsel for Southwestern Energy Company (the "Borrower"), and have represented the Borrower and the Subsidiaries of the Borrower listed on Schedule 1 (the "Guarantors") in connection with its execution and delivery of a Credit Agreement dated as of July 12, 2001 (the "Agreement") among the Borrower, the Lenders named therein, and Bank One, NA, as Administrative Agent, and providing for Advances in an aggregate principal amount not exceeding $160,000,000 at any one time outstanding. All capitalized terms used in this opinion and not otherwise defined herein shall have the meanings attributed to them in the Agreement. I have examined the Borrower's and each Guarantor's **[describe constitutive documents of Borrower and Guarantors and appropriate evidence of authority to enter into the transaction]**, the Loan Documents and such other matters of fact and law which we deem necessary in order to render this opinion. Based upon the foregoing, it is our opinion that: l. Each of the Borrower and its Subsidiaries is a corporation, partnership or limited liability company duly and properly incorporated or organized, as the case may be, validly existing and (to the extent such concept applies to such entity) in good standing under the laws of its jurisdiction of incorporation or organization and has all requisite authority to conduct its business in each jurisdiction in which its business is conducted. 2. The execution and delivery by the Borrower and each Guarantor of the Loan Documents to which it is a party and the performance by the Borrower and each Guarantor of its obligations thereunder have been duly authorized by proper corporate or limited liability company proceedings on the part of the Borrower and each Guarantor and will not: (a) require any consent of the Borrower's or any Guarantor's shareholders or members (other than any such consent as has already been given and remains in full force and effect); (b) violate (i) any law, rule, regulation, order, writ, judgment, injunction, decree or award binding on the Borrower or any of its Subsidiaries or (ii) the Borrower's or any Subsidiary's articles or certificate of incorporation, articles or certificate of organization, bylaws, or operating or other management agreement, as the case may be, or (iii) the provisions of any indenture, instrument or agreement to which the Borrower or any of its Subsidiaries is a party or is subject, or by which it, or its Property, is bound, or conflict with or constitute a default thereunder; or (c) result in, or require, the creation or imposition of any Lien in, of or on the Property of the Borrower or a Subsidiary pursuant to the terms of any indenture, instrument or agreement binding upon the Borrower or any of its Subsidiaries. 3. The Loan Documents to which the Borrower or any Guarantor is a party have been duly executed and delivered by the Borrower or such Guarantor, as the case may be, and constitute legal, valid and binding obligations of the Borrower enforceable against the Borrower or such Guarantor, as the case may be, in accordance with their terms except to the extent the enforcement thereof may be limited by bankruptcy, insolvency or similar laws affecting the enforcement of creditors' rights generally and subject also to the availability of equitable remedies if equitable remedies are sought. 4. Except for the litigation disclosed in Borrower's Form 10-K for the year ended December 31, 2000 and updated in the Borrower's most recent Form 10-Q, there is no litigation, arbitration, governmental investigation, proceeding or inquiry pending or, to the best of our knowledge after due inquiry, threatened against the Borrower or any of its Subsidiaries which, if adversely determined, could reasonably be expected to have a Material Adverse Effect. 5. No order, consent, adjudication, approval, license, authorization, or validation of, or filing, recording or registration with, or exemption by, or other action in respect of any governmental or public body or authority, or any subdivision thereof, which has not been obtained by the Borrower or any of its Subsidiaries, is required to be obtained by the Borrower or any of its Subsidiaries in connection with the execution and delivery of the Loan Documents, the borrowings under the Agreement, the payment and performance by the Borrower of the Obligations, or the legality, validity, binding effect or enforceability of any of the Loan Documents. This opinion may be relied upon by the Administrative Agent, the Lenders and their participants, assignees and other transferees. Very truly yours, EXHIBIT C ASSIGNMENT AGREEMENT This Assignment Agreement (this "Assignment Agreement") between (the "Assignor") and (the "Assignee") is dated as of , 20___. The parties hereto agree as follows: 1. PRELIMINARY STATEMENT. The Assignor is a party to a Credit Agreement (which, as it may be amended, modified, renewed or extended from time to time is herein called the "Credit Agreement") described in Item 1 of Schedule 1 attached hereto ("Schedule 1"). Capitalized terms used herein and not otherwise defined herein shall have the meanings attributed to them in the Credit Agreement. 2. ASSIGNMENT AND ASSUMPTION. The Assignor hereby sells and assigns to the Assignee, and the Assignee hereby purchases and assumes from the Assignor, an interest in and to the Assignor's rights and obligations under the Credit Agreement and the other Loan Documents, such that after giving effect to such assignment the Assignee shall have purchased pursuant to this Assignment Agreement the percentage interest specified in Item 3 of Schedule 1 of all outstanding rights and obligations under the Credit Agreement and the other Loan Documents relating to the facilities listed in Item 3 of Schedule 1. The aggregate Commitment (or Loans, if the Commitments have been terminated) purchased by the Assignee hereunder is set forth in Item 4 of Schedule 1. 3. EFFECTIVE DATE. The effective date of this Assignment Agreement (the "Effective Date") shall be the later of the date specified in Item 5 of Schedule 1 or two Business Days (or such shorter period agreed to by the Administrative Agent) after this Assignment Agreement, together with any consents required under the Credit Agreement, are delivered to the Administrative Agent. In no event will the Effective Date occur if the payments required to be made by the Assignee to the Assignor on the Effective Date are not made on the proposed Effective Date. 4. PAYMENT OBLIGATIONS. In consideration for the sale and assignment of Loans hereunder, the Assignee shall pay the Assignor, on the Effective Date, the amount agreed to by the Assignor and the Assignee. On and after the Effective Date, the Assignee shall be entitled to receive from the Administrative Agent all payments of principal, interest and fees with respect to the interest assigned hereby. The Assignee will promptly remit to the Assignor any interest on Loans and fees received from the Administrative Agent which relate to the portion of the Commitment or Loans assigned to the Assignee hereunder for periods prior to the Effective Date and not previously paid by the Assignee to the Assignor. In the event that either party hereto receives any payment to which the other party hereto is entitled under this Assignment Agreement, then the party receiving such amount shall promptly remit it to the other party hereto. 5. RECORDATION FEE. The Assignor and Assignee each agree to pay one-half of the recordation fee required to be paid to the Administrative Agent in connection with this Assignment Agreement unless otherwise specified in Item 6 of Schedule 1. 6. REPRESENTATIONS OF THE ASSIGNOR; LIMITATIONS ON THE ASSIGNOR'S LIABILITY. The Assignor represents and warrants that (i) it is the legal and beneficial owner of the interest being assigned by it hereunder, (ii) such interest is free and clear of any adverse claim created by the Assignor and (iii) the execution and delivery of this Assignment Agreement by the Assignor is duly authorized. It is understood and agreed that the assignment and assumption hereunder are made without recourse to the Assignor and that the Assignor makes no other representation or warranty of any kind to the Assignee. Neither the Assignor nor any of its officers, directors, employees, agents or attorneys shall be responsible for (i) the due execution, legality, validity, enforceability, genuineness, sufficiency or collectability of any Loan Document, including without limitation, documents granting the Assignor and the other Lenders a security interest in assets of the Borrower or any guarantor, (ii) any representation, warranty or statement made in or in connection with any of the Loan Documents, (iii) the financial condition or creditworthiness of the Borrower or any guarantor, (iv) the performance of or compliance with any of the terms or provisions of any of the Loan Documents, (v) inspecting any of the property, books or records of the Borrower, (vi) the validity, enforceability, perfection, priority, condition, value or sufficiency of any collateral securing or purporting to secure the Loans or (vii) any mistake, error of judgment, or action taken or omitted to be taken in connection with the Loans or the Loan Documents. 7. REPRESENTATIONS AND UNDERTAKINGS OF THE ASSIGNEE. The Assignee (i) confirms that it has received a copy of the Credit Agreement, together with copies of the financial statements requested by the Assignee and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment Agreement, (ii) agrees that it will, independently and without reliance upon the Administrative Agent, the Assignor or any other Lender and based on such documents and information at it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, (iii) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under the Loan Documents as are delegated to the Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto, (iv) confirms that the execution and delivery of this Assignment Agreement by the Assignee is duly authorized, (v) agrees that it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender, (vi) agrees that its payment instructions and notice instructions are as set forth in the attachment to Schedule 1, (vii) confirms that none of the funds, monies, assets or other consideration being used to make the purchase and assumption hereunder are "plan assets" as defined under ERISA and that its rights, benefits and interests in and under the Loan Documents will not be "plan assets" under ERISA, (viii) agrees to indemnify and hold the Assignor harmless against all losses, costs and expenses (including, without limitation, reasonable attorneys' fees) and liabilities incurred by the Assignor in connection with or arising in any manner from the Assignee's nonperformance of the 2 obligations assumed under this Assignment Agreement, and (ix) if applicable, attaches the forms prescribed by the Internal Revenue Service of the United States certifying that the Assignee is entitled to receive payments under the Loan Documents without deduction or withholding of any United States federal income taxes. 8. GOVERNING LAW. This Assignment Agreement shall be governed by the internal law, and not the law of conflicts, of the State of Illinois. 9. NOTICES. Notices shall be given under this Assignment Agreement in the manner set forth in the Credit Agreement. For the purpose hereof, the addresses of the parties hereto (until notice of a change is delivered) shall be the address set forth in the attachment to Schedule 1. 10. COUNTERPARTS; DELIVERY BY FACSIMILE. This Assignment Agreement may be executed in counterparts. Transmission by facsimile of an executed counterpart of this Assignment Agreement shall be deemed to constitute due and sufficient delivery of such counterpart and such facsimile shall be deemed to be an original counterpart of this Assignment Agreement. IN WITNESS WHEREOF, the duly authorized officers of the parties hereto have executed this Assignment Agreement by executing Schedule 1 hereto as of the date first above written. 3 SCHEDULE 1 to Assignment Agreement 1. Description and Date of Credit Agreement: Credit Agreement dated as of July 12, 2001 among Southwestern Energy Company, the lenders named therein including the Assignor, and Bank One, NA individually and as Administrative Agent for such lender, as it may be amended from time to time. 2. Date of Assignment Agreement: __________, 20__ 3. Amounts (As of Date of Item 2 above): a. Assignee's percentage of Aggregate Commitment (Advances) purchased under the Assignment Agreement** ____% b. Amount of Assignor's Commitment purchased under the Assignment Agreement** $____ 4. Assignee's Commitment (or Loans with respect to terminated Commitments) purchased hereunder: $___________________ 5. Proposed Effective Date: ____________________ 6. Non-standard Recordation Fee Arrangement N/A*** [Assignor/Assignee to pay 100% of fee] [Fee waived by Administrative Agent] Accepted and Agreed: [NAME OF ASSIGNOR] [NAME OF ASSIGNEE] By:______________________ By:______________________ Title____________________ Title:___________________ 4 ACCEPTED AND CONSENTED TO**** SOUTHWESTERN ENERGY COMPANY By:__________________________ Title:_______________________ ** Percentage taken to 10 decimal places *** If fee is split 50-50, pick N/A as option **** Delete if not required by Credit Agreement ACCEPTED AND CONSENTED TO BY BANK ONE, NA, as Administrative Agent By:__________________________ Title:_______________________ 5 Attachment to SCHEDULE 1 to ASSIGNMENT AGREEMENT ADMINISTRATIVE INFORMATION SHEET Attach Assignor's Administrative Information Sheet, which must include notice addresses for the Assignor and the Assignee (Sample form shown below) ASSIGNOR INFORMATION Contact: Name:__________________ Telephone No.:__________________________ Fax No.:________________ Telex No.:______________________________ Answerback:_____________________________ Payment Information: Name & ABA # of Destination Bank: ___________________________________ Account Name & Number for Wire Transfer:_____________________________ _____________________________________________________________________ Other Instructions:__________________________________________________ Address for Notices for Assignor:____________________________________ ASSIGNEE INFORMATION Credit Contact: Name:____________________ Telephone No.:__________________________ Fax No.:__________________ Telex No.:______________________________ Answerback:_____________________________ Key Operations Contacts: Booking Installation: Booking Installation: Name: Name: Telephone No.: Telephone No.: Fax No.: Fax No.: Telex No.: Telex No.: Answerback: Answerback: 6 Payment Information: Name & ABA # of Destination Bank: Account Name & Number for Wire Transfer:_____________________________ Other Instructions: Address for Notices for Assignee: 7 BANK ONE INFORMATION Assignee will be called promptly upon receipt of the signed agreement. Initial Funding Contact: Subsequent Operations Contact: Name: Name: Telephone No.: (312) Telephone No.: (312) Fax No.: (312) Fax No.: (312) Bank One Telex No.: 190201 (Answerback: FNBC UT) Initial Funding Standards: Libor Fund 2 days after rates are set. Bank One Wire Instructions: Bank One, NA, ABA # 071000013 LS2 Incoming Account # 481152860000 Ref:________________ Address for Notices for Bank One: 1 Bank One Plaza, Chicago, IL 60670 Attn: Agency Compliance Division, Suite IL1-0353 Fax No. (312) 7322038 or (312) 7324339 8 EXHIBIT D LOAN/CREDIT RELATED MONEY TRANSFER INSTRUCTION To Bank One, NA, as Administrative Agent (the "Administrative Agent") under the Credit Agreement Described Below. Re: Credit Agreement, dated as of July 12, 2001 (as the same may be amended or modified, the "Credit Agreement"), among Southwestern Energy Company (the "Borrower"), the Lenders named therein and the Administrative Agent. Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned thereto in the Credit Agreement. The Administrative Agent is specifically authorized and directed to act upon the following standing money transfer instructions with respect to the proceeds of Advances or other extensions of credit from time to time until receipt by the Administrative Agent of a specific written revocation of such instructions by the Borrower, provided that the Administrative Agent may otherwise transfer funds as hereafter directed in writing by the Borrower in accordance with Section 13.1 of the Credit Agreement or based on any telephonic notice made in accordance with Section 2.15 of the Credit Agreement. Facility Identification Number(s)_____________________________________ Customer/Account Name: [Borrower] Transfer Funds To_____________________________________________________ _____________________________________________________ For Account No._______________________________________________________ Reference/Attention To________________________________________________ Authorized Officer (Customer Representative) Date____________ ______________________________________________ ____________________ (Please Print) Signature Bank Officer Name Date____________ ______________________________________________ ____________________ (Please Print) Signature (Deliver Completed Form to Credit Support Staff For Immediate Processing) EXHIBIT E NOTE [Date] Southwestern Energy Company, an Arkansas corporation (the "Borrower"), promises to pay to the order of ____________________________________ (the "Lender") the aggregate unpaid principal amount of all Loans made by the Lender to the Borrower pursuant to Article II of the Agreement (as hereinafter defined), in immediately available funds at the main office of Bank One, NA in Chicago, Illinois, as Administrative Agent, together with interest on the unpaid principal amount hereof at the rates and on the dates set forth in the Agreement. The Borrower shall pay the principal of and accrued and unpaid interest on the Loans in full on the Termination Date. The Lender shall, and is hereby authorized to, record on the schedule attached hereto, or to otherwise record in accordance with its usual practice, the date and amount of each Loan and the date and amount of each principal payment hereunder. This Note is one of the Notes issued pursuant to, and is entitled to the benefits of, the Credit Agreement dated as of July 12, 2001 (which, as it may be amended or modified and in effect from time to time, is herein called the "Agreement"), among the Borrower, the lenders party thereto, including the Lender, and Bank One, NA, as Administrative Agent, to which Agreement reference is hereby made for a statement of the terms and conditions governing this Note, including the terms and conditions under which this Note may be prepaid or its maturity date accelerated. This Note is guaranteed pursuant to the Subsidiary Guaranty, as more specifically described in the Agreement. Capitalized terms used herein and not otherwise defined herein are used with the meanings attributed to them in the Agreement. Notwithstanding anything to the contrary in this Note, no provision of this Note shall require the payment or permit the collection of interest in excess of the maximum permitted by applicable law ("Maximum Rate"). If any interest in excess of the Maximum Rate is provided for or shall be adjudicated to be so provided, in this Note or otherwise in connection with the loan transaction, the provisions of this paragraph shall govern and prevail, and neither the Borrower nor the sureties, guarantors, successors or assigns of the Borrower shall be obligated to pay the excess of the interest or any other excess sum paid for the use, forbearance, or detention of sums loaned. If for any reason interest in excess of the Maximum Rate shall be deemed charged, required or permitted by any court of competent jurisdiction, the excess shall be applied as payment and reduction of the principal of indebtedness evidenced by this Note, and, if the principal amount has been paid in full, any remaining excess shall forthwith be paid to the Borrower. This Note shall be construed in accordance with the internal laws (and not the law of conflicts) of the State of Illinois, but giving effect to Federal laws applicable to national banks. SOUTHWESTERN ENERGY COMPANY By:________________________________ Print Name:________________________ Title:_____________________________ 2
SCHEDULE OF LOANS AND PAYMENTS OF PRINCIPAL TO NOTE DATED___________, 2001 ---------------------------------------------------------------------------- : : Principal : Maturity : Principal : : : Date : Amount of Loan : of Interest Period : Amount Paid : Unpaid Balance: ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ---------------------------------------------------------------------------- : : : : : : ----------------------------------------------------------------------------
i EXHIBIT G FORM OF COMPLIANCE CERTIFICATE The undersigned, the _________________ of Southwestern Energy Company (the "Borrower") hereby (a) delivers this Certificate pursuant to Section 6.1(c) of the Credit Agreement dated as of July 12, 2001 (the "Agreement"; capitalized terms used but not defined herein have the respective meanings given thereto in the Agreement) among the Borrower, various financial institutions and Bank One, NA, as Administrative Agent, and (b) certifies to each Lender as follows: 1. Attached as Schedule I are the financial statements of the Borrower as of and for the Fiscal Year Quarter (check one) ended ________________, ______. 2. Such financial statements have been prepared in accordance with Agreement Accounting Principles and fairly present in all material respects the financial condition of the Borrower as of the date indicated therein and the results of operations for the respective periods covered thereby. 3. Attached as Schedule II are detailed calculations used by the Borrower to establish whether the Borrower was in compliance with the requirements of Section 6.4 of the Agreement on the date of the financial statements attached as Schedule I. 4. Unless otherwise disclosed on Schedule III, neither a Default nor an Unmatured Default has occurred which is in existence on the date hereof or, if any Default or Unmatured Default is disclosed on Schedule III, the Borrower has taken or proposes to take the action to cure such Default or Unmatured Default set forth on Schedule III. 5. Except as described on Schedule IV, the representations and warranties of the Borrower set forth in the Agreement are true and correct on and as of the date hereof, with the same effect as though such representations and warranties had been made on and as of the date hereof or, if such representations and warranties are expressly limited to particular dates, as of such particular dates. IN WITNESS WHEREOF, the undersigned has duly executed this Certificate as of ________________, _______. SOUTHWESTERN ENERGY COMPANY By:________________________________ Name:______________________________ Title:_____________________________ Schedule I Financial Statements (to be attached) Schedule II Compliance Calculations (to be attached) Schedule III Defaults/Remedial Action (to be attached) Schedule IV Qualifications to Representations and Warranties
TABLE OF CONTENTS ARTICLE I DEFINITIONS....................................................................1 ARTICLE II THE CREDITS...................................................................14 2.1 Commitments.....................................................14 2.2 Types of Advances...............................................14 2.3 Minimum Amount of Each Advance..................................14 2.4 Method of Selecting Types and Interest Periods for New Advances....................................................15 2.5 Conversion and Continuation of Outstanding Advances.............15 2.6 Swing Line Loans................................................16 2.6.1 Amount of Swing Line Loans..........................16 2.6.2 Method of Borrowing.................................16 2.6.3 Making of Swing Line Loans..........................16 2.6.4 Repayment of Swing Line Loans.......................16 2.7 Commitment Fee; Voluntary Reductions in Aggregate Commitment....17 2.8 Mandatory Reductions in Aggregate Commitment....................18 2.9 Prepayments.....................................................18 2.10 Interest Rates, etc.............................................19 2.11 Rates Applicable After Default..................................19 2.12 Maturity........................................................20 2.13 Method of Payment...............................................20 2.14 Noteless Agreement; Evidence of Indebtedness....................20 2.15 Telephonic Notices..............................................21 2.16 Interest Payment Dates; Interest and Fee Basis..................21 2.17 Notification of Advances, Interest Rates, Prepayments and Commitment Reductions...........................................22 2.18 Lending Installations...........................................22 2.19 Non-Receipt of Funds by the Administrative Agent................22 2.20 Replacement of Lender...........................................22 ARTICLE III YIELD PROTECTION; TAXES.......................................................23 3.1 Yield Protection................................................23 3.2 Changes in Capital Adequacy Regulations.........................24 3.3 Availability of Types of Advances...............................25 3.4 Funding Indemnification.........................................25 3.5 Taxes...........................................................25 3.6 Lender Statements; Survival of Indemnity........................27 i ARTICLE IV CONDITIONS PRECEDENT..........................................................27 4.1 Initial Loan....................................................27 4.2 Each Loan.......................................................29 ARTICLE V REPRESENTATIONS AND WARRANTIES................................................29 5.1 Organization....................................................29 5.2 Authorization and Validity......................................29 5.3 Financial Statements............................................29 5.4 Subsidiaries....................................................30 5.5 ERISA...........................................................30 5.6 Defaults........................................................30 5.7 Accuracy of Information.........................................30 5.8 Regulation U....................................................30 5.9 No Adverse Change...............................................30 5.10 Taxes...........................................................30 5.11 Liens...........................................................31 5.12 Compliance with Orders..........................................31 5.13 Litigation......................................................31 5.14 Burdensome Agreements...........................................31 5.15 No Conflict.....................................................31 5.16 Title to Properties.............................................31 5.17 Public Utility Holding Company Act..............................32 5.18 Regulatory Approval.............................................32 5.19 Negative Pledge.................................................32 5.20 Investment Company Act..........................................32 5.21 Compliance with Laws............................................32 ARTICLE VI COVENANTS.....................................................................32 6.1 Information.....................................................32 6.2 Affirmative Covenants...........................................35 6.2.1 Reports and Inspection..............................35 6.2.2 Conduct of Business.................................35 6.2.3 Insurance...........................................36 6.2.4 Taxes...............................................36 6.2.5 Compliance with Laws................................36 6.2.6 Maintenance of Properties...........................36 6.2.7 Additional Guarantors...............................37 6.3 Negative Covenants..............................................37 6.3.1 Restricted Payments.................................37 6.3.2 Merger and Sale of Assets...........................37 ii 6.3.3 Liens...............................................38 6.3.4 Subsidiary Guarantors...............................41 6.3.5 Investments.........................................41 6.3.6 Indebtedness of Arkansas Western Gas Company........42 6.4 Financial Covenants.............................................42 6.4.1 Debt to Capitalization Ratio........................42 6.4.2 Interest Coverage Ratio.............................42 6.4.3 Net Worth...........................................42 ARTICLE VII DEFAULTS......................................................................43 7.1 Events of Default...............................................43 7.1.1 Representations and Warranties.....................43 7.1.2 Payment Default.....................................43 7.1.3 Breach of Certain Covenants.........................43 7.1.4 Other Breach of this Agreement......................43 7.1.5 ERISA...............................................43 7.1.6 Cross-Default.......................................43 7.1.7 Voluntary Bankruptcy, etc...........................44 7.1.8 Involuntary Bankruptcy, etc.........................44 7.1.9 Judgments...........................................44 7.1.10 Environmental Matters...............................44 7.1.11 Subsidiary Guaranty.................................44 ARTICLE VIII ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES; RELEASES OF GUARANTORS........45 8.1 Acceleration....................................................45 8.2 Amendments......................................................45 8.3 Preservation of Rights..........................................46 8.4 Releases of Guarantors..........................................46 ARTICLE IX GENERAL PROVISIONS............................................................46 9.1 Survival of Representations.....................................46 9.2 Governmental Regulation.........................................46 9.3 Headings........................................................46 9.4 Entire Agreement................................................47 9.5 Several Obligations; Benefits of this Agreement.................47 9.6 Expenses; Indemnification.......................................47 9.7 Numbers of Documents............................................48 9.8 Accounting......................................................48 9.9 Severability of Provisions......................................48 iii 9.10 Nonliability of Lenders.........................................48 9.11 Confidentiality.................................................48 9.12 Nonreliance.....................................................49 9.13 Disclosure......................................................49 ARTICLE X THE ADMINISTRATIVE AGENT......................................................49 10.1 Appointment; Nature of Relationship.............................49 10.2 Powers..........................................................49 10.3 General Immunity................................................49 10.4 No Responsibility for Loans, Recitals, etc......................50 10.5 Action on Instructions of Lenders...............................50 10.6 Employment of Agents and Counsel................................50 10.7 Reliance on Documents; Counsel..................................51 10.8 Administrative Agent's Reimbursement and Indemnification........51 10.9 Notice of Default...............................................51 10.10 Rights as a Lender..............................................51 10.11 Lender Credit Decision..........................................52 10.12 Successor Administrative Agent..................................52 10.13 Delegation to Affiliates........................................53 10.14 Other Agents....................................................53 ARTICLE XI SETOFF; RATABLE PAYMENTS......................................................53 11.1 Setoff..........................................................53 11.2 Ratable Payments................................................53 ARTICLE XII BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS.............................54 12.1 Successors and Assigns..........................................54 12.2 Participations..................................................54 12.2.1 Permitted Participants: Effect......................54 12.2.2 Voting Rights.......................................55 12.3 Assignments.....................................................55 12.3.1 Permitted Assignments...............................55 12.3.2 Effect; Effective Date..............................55 12.4 Dissemination of Information....................................56 12.5 Tax Treatment...................................................56 iv ARTICLE XIII NOTICES.......................................................................56 13.1 Notices.........................................................56 13.2 Change of Address...............................................57 ARTICLE XIV COUNTERPARTS..................................................................57 ARTICLE XV CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL; MAXIMUM INTEREST RATE.........................................................57 15.1 CHOICE OF LAW...................................................57 15.2 CONSENT TO JURISDICTION.........................................57 15.3 WAIVER OF JURY TRIAL............................................58 15.4 Maximum Interest Rate...........................................58
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SCHEDULES Schedule 1A Commitments Schedule 1B Pricing Schedule Schedule 2.8(a) Excluded Asset Sales Schedule 2.8(b) Assets to be Swapped Schedule 5.4 Subsidiaries Schedule 5.13 Litigation Schedule 5.19 Negative Pledges Schedule 6.2 Insurance EXHIBITS Exhibit A Form of Borrowing Notice Exhibit B Form of Opinion of Counsel to Borrower Exhibit C Form of Assignment Agreement Exhibit D Form of Money Transfer Instructions Exhibit E Form of Note Exhibit F Form of Subsidiary Guaranty Exhibit G Form of Compliance Certificate
vi EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT ------------------------------
State of Incorporation or Subsidiary Name Organization --------------- ---------------- Arkansas Western Gas Company Arkansas Seeco, Inc. Arkansas Southwestern Energy Production Company Arknasas Diamond "M" Production Company Delaware Southwestern Energy Services Company Arkansas Southwestern Energy Pipeline Company Arkansas Arkansas Western Pipeline Company Arkansas A.W. Realty Company Arkansas Overton Partners, L.P. Texas
EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 4, 2002, included in this Form 10-K, into the Company's previously filed Registration Statements on Form S-8 (File Nos. 333-03787, 333-03789, 333-64961, 333-96161, 333-42484 and 333-69720). Arthur Andersen LLP Tulsa, Oklahoma March 29, 2002 Exhibit 99.1 SOUTHWESTERN ENERGY COMPANY 2350 N. Sam Houston Parkway East Suite 300 Houston, Texas 77032 LETTER TO COMMISSION PURSUANT TO TEMPORARY NOTE 3T March 29, 2002 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 Ladies and Gentlemen: Pursuant to Temporary Note 3T to Article 3 of Regulation S-X, Southwestern Energy Company has obtained a letter of representation from Arthur Andersen LLP stating that the December 31, 2001 audit was subject to their quality control system for the U.S. accounting and auditing practice to provide reasonable assurance that the engagement was conducted in compliance with professional standards, that there was appropriate continuity of Arthur Andersen LLP personnel working on the audit and availability of national office consultation. Availability of personnel at foreign affiliates of Arthur Andersen LLP is not relevant to this audit. Very truly yours, Southwestern Energy Company Greg D. Kerley Executive Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----