-----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, Bz8pzKdq3sLaTYiT+8VislX+Xv1gzIMSHqUDmzeaDxGxqrWVZWdOVRiItRQZ2HOk W3onw98etO3s0OLYJ4SiMg== 0000007332-99-000024.txt : 19991115 0000007332-99-000024.hdr.sgml : 19991115 ACCESSION NUMBER: 0000007332-99-000024 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991112 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHWESTERN ENERGY CO CENTRAL INDEX KEY: 0000007332 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION & DISTRIBUTION [4923] IRS NUMBER: 710205415 STATE OF INCORPORATION: AR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-08246 FILM NUMBER: 99750165 BUSINESS ADDRESS: STREET 1: 1083 SAIN ST STREET 2: P O BOX 1408 CITY: FAYETTEVILLE STATE: AR ZIP: 72702-1408 BUSINESS PHONE: 5015211141 FORMER COMPANY: FORMER CONFORMED NAME: ARKANSAS WESTERN GAS CO DATE OF NAME CHANGE: 19790917 10-Q 1 FORM 10-Q FOR THE PERIOD ENDED SEPTEMBER 30, 1999 =========================================================================== UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------------------- FORM 10-Q (Mark one) [X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended September 30, 1999 ------------------ 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 of incorporation (I.R.S. Employer or organization) Identification No.) 1083 Sain Street, P.O. Box 1408, Fayetteville, Arkansas 72702-1408 (Address of principal executive offices, including zip code) (501) 521-1141 (Registrant's telephone number, including area code) No Change (Former name, former address and former fiscal year; if changed since last report) 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 twelve 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 the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Class Outstanding at November 5, 1999 ---------------------------- ------------------------------- Common Stock, Par Value $.10 24,943,934 =========================================================================== - 1 - PART I FINANCIAL INFORMATION - 2 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited) ASSETS
September 30, December 31, 1999 1998 ------------- ------------ ($ in thousands) Current Assets Cash $ 1,560 $ 1,622 Accounts receivable 28,482 40,655 Income taxes receivable 5,500 2,008 Inventories, at average cost 27,109 22,812 Other 7,188 5,174 --------- --------- Total current assets 69,839 72,271 --------- --------- Investments 12,394 14,015 --------- --------- Property, Plant and Equipment, at cost Gas and oil properties, using the full cost method 801,723 758,863 Gas distribution systems 221,008 217,741 Gas in underground storage 23,658 24,279 Other 28,192 27,582 --------- --------- 1,074,581 1,028,465 Less: Accumulated depreciation, depletion and amortization 509,603 478,790 --------- --------- 564,978 549,675 --------- --------- Other Assets 11,128 11,659 --------- --------- Total Assets $ 658,339 $ 647,620 ========= =========
The accompanying notes are an integral part of the financial statements. - 3 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited) LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, December 31, 1999 1998 ------------- ------------ ($ in thousands) Current Liabilities Current portion of long-term debt $ 1,536 $ 1,536 Accounts payable 36,760 37,780 Taxes payable 2,829 3,408 Interest payable 7,017 2,471 Customer deposits 5,712 5,635 Other 2,626 3,956 --------- --------- Total current liabilities 56,480 54,786 --------- --------- Long-Term Debt, less current portion above 282,600 281,900 --------- --------- Other Liabilities Deferred income taxes 128,612 121,413 Other 3,355 3,665 --------- --------- 131,967 125,078 --------- --------- Commitments and Contingencies Shareholders' Equity Common stock, $.10 par value; authorized 75,000,000 shares, issued 27,738,084 shares 2,774 2,774 Additional paid-in capital 21,221 21,249 Retained earnings 195,107 194,102 Less: Common stock in treasury, at cost, 2,796,570 shares in 1999 and 2,803,527 shares in 1998 31,154 31,248 Unamortized cost of 99,233 restricted shares in 1999 and 133,172 restricted shares in 1998, issued under stock incentive plan 656 1,021 --------- --------- 187,292 185,856 --------- --------- Total Liabilities and Shareholders' Equity $ 658,339 $ 647,620 ========= =========
The accompanying notes are an integral part of the financial statements. - 4 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Quarter Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 ---------- ---------- ---------- ---------- ($ in thousands, except per share amounts) Operating Revenues Gas sales $ 28,238 $ 27,974 $ 119,892 $ 123,268 Gas marketing 27,915 21,851 62,720 56,556 Oil sales 2,556 2,138 6,529 7,482 Gas transportation and other 1,691 1,588 5,518 5,535 ---------- ---------- ---------- ---------- 60,400 53,551 194,659 192,841 ---------- ---------- ---------- ---------- Operating Costs and Expenses Gas purchases - utility 5,994 3,588 34,068 26,258 Gas purchases - marketing 27,079 21,199 59,752 54,525 Operating and general 13,854 13,865 42,096 45,606 Depreciation, depletion and amortization 10,133 10,356 30,826 35,794 Write-down of oil and gas properties - - - 66,383 Taxes, other than income taxes 1,676 1,629 4,783 5,273 ---------- ---------- ---------- ---------- 58,736 50,637 171,525 233,839 ---------- ---------- ---------- ---------- Operating Income (Loss) 1,664 2,914 23,134 (40,998) ---------- ---------- ---------- ---------- Interest Expense Interest on long-term debt 4,916 4,833 14,429 14,584 Other interest charges 252 387 793 1,155 Interest capitalized (814) (763) (2,480) (3,094) ---------- ---------- ---------- ---------- 4,354 4,457 12,742 12,645 ---------- ---------- ---------- ---------- Other Income (Expense) (482) (638) (1,387) (2,614) ---------- ---------- ---------- ---------- Income (Loss) Before Income Taxes (3,172) (2,181) 9,005 (56,257) ---------- ---------- ---------- ---------- Income Tax Provision (Benefit) Current (4,402) (4,705) (3,652) (817) Deferred 3,165 3,855 7,164 (21,123) ---------- ---------- ---------- ---------- (1,237) (850) 3,512 (21,940) ---------- ---------- ---------- ---------- Net Income (Loss) $ (1,935) $ (1,331) $ 5,493 $ (34,317) ========== ========== ========== ========== Basic Earnings (Loss) Per Share ($0.08) ($0.05) $0.22 ($1.38) ====== ====== ====== ====== Weighted Average Common Shares Outstanding 24,938,229 24,892,778 24,935,402 24,865,375 ========== ========== ========== ========== Diluted Earnings (Loss) Per Share ($0.08) ($0.05) $0.22 ($1.38) ====== ====== ====== ====== Diluted Weighted Average Common Shares Outstanding 24,938,229 24,892,778 24,935,402 24,865,375 ========== ========== ========== ========== Dividends Declared Per Share Payable 11/5/99 and 11/5/98 $ .06 $ .06 $ .06 $ .06 ===== ===== ===== =====
The accompanying notes are an integral part of the financial statements. - 5 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, 1999 1998 -------- -------- ($ in thousands) Cash Flows From Operating Activities Net income (loss) $ 5,493 $(34,317) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 31,850 36,790 Write-down of oil and gas properties - 66,383 Deferred income taxes 7,164 (21,123) Equity in loss of partnership 1,620 2,618 Change in assets and liabilities: Decrease in accounts receivable 12,173 23,884 Increase in income taxes receivable (3,492) (579) Increase in inventories (4,297) (3,329) Increase (decrease) in over-recovered purchased gas costs (3,704) 9,734 Decrease in accounts payable (1,020) (5,896) Increase in interest payable 4,546 4,511 Net change in other current assets and liabilities (141) 881 -------- -------- Net cash provided by operating activities 50,192 79,557 -------- -------- Cash Flows From Investing Activities Capital expenditures (49,482) (41,641) Investment in partnership - (7,955) (Increase) decrease in gas stored underground 621 (2,046) Other items 2,395 3,392 -------- -------- Net cash used in investing activities (46,466) (48,250) -------- -------- Cash Flows From Financing Activities Net change in revolving long-term debt 700 (29,100) Cash dividends (4,488) (5,970) -------- -------- Net cash used in financing activities (3,788) (35,070) -------- -------- Decrease in cash (62) (3,763) Cash at beginning of year 1,622 4,603 -------- -------- Cash at end of period $ 1,560 $ 840 ======== ========
The accompanying notes are an integral part of the financial statements. - 6 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 1999 1. BASIS OF PRESENTATION The financial statements included herein are unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the results for the interim periods. The Company's accounting policies are summarized in the 1998 Annual Report to Shareholders, Notes to Financial Statements. Certain reclassifications have been made to the September 30, 1998, financial statements in order to conform with the 1999 presentation. These reclassifications had no effect on previously reported net income. 2. EARNINGS PER SHARE 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 1,574,815 shares of common stock with a weighted average exercise price of $12.02 per share at September 30, 1999, and options to purchase 1,581,901 shares with a weighted average exercise price of $12.33 at September 30, 1998, that were not included in the calculation of diluted shares because they would have had an anti-dilutive effect. 3. DIVIDEND PAYABLE A dividend of $.06 per share was declared October 7, 1999, payable November 5, 1999. 4. SEGMENT INFORMATION The Company adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," in 1998 which changes the way the Company reports information about its operating segments. 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. The Company utilizes operating income to evaluate segment profit or loss. -7- Summarized financial information for the Company's reportable segments are 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 (in thousands) Three months ended September 30, 1999: Revenues from external customers $ 13,074 $ 19,411 $ 27,915 $ - $ 60,400 Intersegment revenues 3,782 59 11,423 112 15,376 Depreciation, depletion and amortization expense 8,344 1,749 18 22 10,133 Operating income 2,667 (1,542) 469 70 1,664 Assets 428,408 177,297 13,669 38,965 658,339 Capital expenditures 19,398 1,536 - 14 20,948 Three months ended September 30, 1998: Revenues from external customers $ 15,044 $ 16,623 $ 21,850 $ 34 $ 53,551 Intersegment revenues 3,931 54 5,304 96 9,385 Depreciation, depletion and amortization expense 8,468 1,849 7 32 10,356 Operating income 4,345 (1,839) 322 86 2,914 Assets 398,023 176,785 7,453 37,608 619,869 Capital expenditures 12,047 2,839 - 341 15,227 Nine months ended September 30, 1999: Revenues from external customers $ 37,937 $ 94,002 $ 62,720 $ - $ 194,659 Intersegment revenues 15,337 131 29,770 304 45,542 Depreciation, depletion and amortization expense 25,365 5,340 54 67 30,826 Operating income 10,260 10,785 1,924 165 23,134 Assets 428,408 177,297 13,669 38,965 658,339 Capital expenditures 44,615 4,721 8 138 49,482 Nine months ended September 30, 1998: Revenues from external customers $ 41,349 $ 94,700 $ 56,556 $ 236 $ 192,841 Intersegment revenues 23,033 327 14,288 288 37,936 Depreciation, depletion and amortization expense 30,014 5,632 23 125 35,794 Write-down of oil and gas properties 66,383 - - - 66,383 Operating income (52,417) 10,032 1,146 241 (40,998) Assets 398,023 176,785 7,453 37,608 619,869 Capital expenditures 33,705 7,272 8 656 41,641 Other assets includes the Company's equity investment in the operations of NOARK, corporate assets not allocated to segments, and assets for non-reportable segments. Includes a $66.4 million pre-tax write-down of oil and gas properties.
Intersegment sales 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. -8- 5. DERIVATIVE AND HEDGING ACTIVITIES In June 1999, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133" (SFAS No. 137). FASB Statement No. 133 (SFAS No. 133) establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 is effective for fiscal years beginning after June 15, 2000, as amended in SFAS 137, and cannot be applied retroactively. The Company has not yet quantified the impacts of adopting SFAS No. 133 on its financial statements, nor has it determined the timing of or method of adoption. However, it should be noted that SFAS No. 133 could increase volatility in future reported earnings and other comprehensive income. 6. INTEREST AND INCOME TAXES PAID The following table provides interest and income taxes paid during each period presented.
Three Months Nine Months Periods Ended September 30 1999 1998 1999 1998 (in thousands) Interest payments $322 $145 $9,746 $9,926 Income tax payments $ - $907 $641 $3,249
-9- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following updates information as to the Company's financial condition provided in the Company's Form 10-K for the year ended December 31, 1998, and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 1999, and the comparable periods of 1998. RESULTS OF OPERATIONS The Company reported a net loss of $1.9 million, or $.08 per share, for the third quarter of 1999, compared to a net loss of $1.3 million or $.05 per share, for the same period in 1998. Net income for the nine months ended September 30, 1999, was $5.5 million, or $.22 per share, compared to $6.2 million, or $.25 per share for the same period in 1998, excluding the impact of an after-tax, non-cash ceiling test write-down of the Company's oil and gas properties of $40.5 million, or $1.63 per share recorded in the second quarter of 1998. Results for the third quarter of 1999, compared to the same period in 1998, were unfavorably impacted by lower production volumes and lower average gas prices received. The following tables compare operating revenues and operating income (before the effects of the write-down of oil and gas properties in 1998) by business segment for the three and nine month periods ended September 30, 1999 and 1998:
Quarter Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) Revenues Exploration and production $ 16,856 $ 18,975 $ 53,274 $ 64,382 Gas distribution 19,470 16,677 94,133 95,027 Marketing and other 39,450 27,284 92,794 71,368 Eliminations (15,376) (9,385) (45,542) (37,936) -------- -------- -------- -------- $ 60,400 $ 53,551 $194,659 $192,841 ======== ======== ======== ======== Operating Income (Loss) Exploration and production $ 2,667 $ 4,345 $ 10,260 $ 13,966 Gas distribution (1,542) (1,839) 10,785 10,032 Marketing and other 539 408 2,089 1,387 -------- -------- -------- -------- $ 1,664 $ 2,914 $ 23,134 $ 25,385 ======== ======== ======== ========
-10- Exploration and Production Revenues of the exploration and production segment were down 11% for the three month period ended September 30, 1999, and down 17% for the nine month period ended September 30, 1999, both as compared to the same periods in 1998, primarily due to lower production volumes and lower gas prices received. Operating income of this segment, excluding the write-down in 1998, was down $1.7 million for the three months ended September 30, 1999, and was down $3.7 million for the nine months ended September 30, 1999, as compared to the same periods in 1998. Gas production for the three months ended September 30, 1999, was 7.2 Bcf, compared to 7.6 Bcf for the same period in 1998. For the nine months ended September 30, 1999, gas production was 22.1 Bcf, compared to 24.3 Bcf in 1998. The decrease in production resulted from the combined effects of lower production from the Company's non-operated properties caused primarily by the industry slowdown that began last year, reduced demand from the Company's utility systems due to warm weather, and higher declines than expected from some of the Company's Gulf Coast properties. The Company's sales to its utility distribution systems were 5.7 Bcf during the nine months ended September 30, 1999, compared to 8.5 Bcf for the same period in 1998. The decline in sales to the utility segment was primarily the result of weather that was 5% warmer than in 1998. Warmer weather impacts deliveries to customers and lowers the utility segment's requirements for gas to be injected into its storage facilities. Southwestern received an average price of $1.99 per Mcf for its gas production during the three months ended September 30, 1999, down from $2.22 per Mcf for the same period in 1998. The Company received an average price of $2.13 per Mcf for its gas production during the nine months ended September 30, 1999, down from $2.34 per Mcf for the same period in 1998. The Company's average price was reduced by $.48 cents per Mcf for the quarter and $.02 cents per Mcf for the first nine months of 1999 as a result of the Company's hedging activities. In the fourth quarter of 1999 the Company has hedged approximately 5.0 Bcf at an average NYMEX price of $2.33 per Mcf. For the year 2000, the Company has hedged 2.5 Bcf of its production in the first quarter at an average NYMEX price of $2.47, 4.0 Bcf in each of the second and third quarters at an average NYMEX price of $2.29, and 2.5 Bcf in the fourth quarter at an average NYMEX price of $2.35. The Company's oil production was 423 thousand barrels (MBbls) during the nine months ended September 30, 1999, down from 550 MBbls for the same period of 1998, primarily reflecting the decline in productive capability of existing properties. Southwestern received an average price of $15.44 per barrel for its oil production during the nine months ended September 30, 1999, compared to $13.60 per barrel for the same period of 1998. Gas Distribution Operating income of the gas distribution segment increased $.3 million for the third quarter of 1999 and $.8 million for the first nine months of 1999, as compared to the same periods in 1998, despite weather during the first nine months of 1999 that was 16% warmer than normal and 5% warmer than the same period of 1998. Customer growth and reduced operating costs and expenses more than offset the effect of warmer weather. The utility systems delivered 22.5 Bcf to sales and end-use transportation customers during the nine months ended September 30, 1999, up slightly from 22.4 Bcf for the same period in 1998. The Company's average rate for its utility sales increased to $5.77 -11- per Mcf during the first nine months of 1999, up from $5.62 per Mcf or the same period in 1998. The utility also realized 1% growth in the average number of customers. In October 1999, the Company signed a definitive agreement to sell its Missouri gas distribution assets for $32.0 million. The net book value of the assets being sold is approximately $28.0 million. Proceeds from the sale will be used to reduce the Company's long term debt. The sale requires regulatory approval and is expected to close in three to ten months following execution of the agreement. After closing, the Company's operating results for its gas distribution segment will be lower reflecting the asset divestiture and the loss of Missouri customers. However, the Company does not expect the sale to negatively impact earnings as the loss in operating income should be offset by a corresponding decrease in interest expense. The Company currently serves approximately 48,000 customers in Missouri. The Company will continue to operate its gas distribution systems in Arkansas where it currently serves approximately 131,000 customers. Marketing Operating income for the marketing segment was $.5 million on revenues of $39.3 million for the third quarter of 1999, compared to $.3 million on revenues of $27.2 million for the same period in 1998. For the nine months ended September 30, 1999, operating income for this segment was $1.9 million on revenues of $92.5 million, compared to $1.1 million on revenues of $70.8 million for the same period in 1998. The increase in operating income in the marketing segment was primarily due to increased volumes marketed. The Company marketed 44.6 Bcf of gas in the first nine months of 1999, compared to 36.4 Bcf for the same period in 1998. NOARK Pipeline The Company's share of NOARK's pre-tax loss included in other income was $.5 million for the third quarter of 1999 and $1.6 million for the first nine months of 1999, compared to $.9 million and $2.6 million, respectively, for the same periods in 1998. The improvement in NOARK's pre-tax loss primarily reflects the benefits of the integration of the NOARK Pipeline System with the Ozark Gas Transmission System. The integration of the two systems was completed in November 1998. The Company expects its losses associated with NOARK to continue to decline over time from historical levels. Regulatory Matters On May 19, 1999, the Staff of the Arkansas Public Service Commission (Staff) initiated a proceeding before the Arkansas Public Service Commission (APSC) in which it sought an annual reduction of approximately $2.3 million in the rates Arkansas Western Gas Company charges its ratepayers in northwest Arkansas (AWG division). The AWG division's last rate case was settled in 1996. 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. The Company has reached agreement with the Staff to resolve this issue and close several other dockets that had remained open. In the settlement agreement, the Company has 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 they had previously recommended the disallowance of approximately $3.1 million of gas supply costs. As part of the settlement, this -12- docket will be closed with no negative adjustment to the Company. The settlement agreement between Staff and the Company is subject to approval by the APSC. Operating Costs and Expenses The Company's operating costs and expenses, exclusive of gas purchases by the Company's utility and marketing segments and the non-cash write-down of oil and gas properties in the second quarter of 1998, were down slightly in the third quarter of 1999 and decreased 10% for the first nine months of 1999, both as compared to the comparable periods in 1998. The decrease in operating and general expenses for the first nine months of 1999 was due primarily to decreases in operating costs in both the exploration and production and gas distribution segments, and lower general and administrative costs due to severance and other costs incurred in connection with the closing of the Company's Oklahoma City exploration and production office in 1998. The decrease in depreciation, depletion and amortization expense for this same period was due to both lower production and a decrease in the average amortization rate per unit of production in the exploration and production segment that resulted primarily from the second quarter 1998 write-down of oil and gas properties. The Company's amortization rate was $1.00 per Mcf equivalent for the first nine months of 1999, compared to $1.06 for the same period in 1998. 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 plus the lower of cost or market value of unproved properties. At September 30, 1999, the Company's unamortized costs of oil and gas properties did not exceed this ceiling amount. The Company's full cost ceiling is evaluated at the end of each quarter. A decline in gas and oil prices from current levels, or other factors, without mitigating circumstances could cause a future write-down of capitalized costs and a non-cash charge against future earnings. Gas purchased for resale by the Company's marketing segment increased in the third quarter and the first nine months of 1999 due to increases in volumes marketed. The increases in purchased gas costs for the gas distribution segment for these same periods reflect prices paid for supplies and the mix of purchases from intercompany versus third party sources. The changes in the provisions for current and deferred income taxes recorded in the three and nine month periods ended September 30, 1999, as compared to the same periods in 1998, resulted primarily from the June 1998 write-down of the Company's oil and gas properties which resulted in a deferred tax benefit of $25.9 million. Other items impacting deferred taxes were the level of taxable income 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. -13- CHANGES IN FINANCIAL CONDITION Changes in the Company's financial condition at September 30, 1999, as compared to December 31, 1998, primarily reflect the seasonal nature of the gas distribution segment of the Company's business and the timing of cash receipts and payments. Routine capital expenditures, cash dividends and scheduled debt retirements are predominately funded through cash provided by operations. For the first nine months of 1999 and 1998, net cash provided by operating activities was $50.2 million and $79.6 million, respectively. Net cash provided by operating activities met 93% of routine cash requirements in the first nine months of 1999, and exceeded these routine requirements in 1998. The decrease in net cash provided by operating activities during the first nine months of 1999 was due in large part to the timing of cash receipts and payments for working capital items. Financing Requirements The Company has access to $80.0 million of medium to long-term capital at current market lending rates through two floating rate credit facilities. Of this amount, $35.6 million was outstanding at September 30, 1999, all of which was classified as long-term debt. Long-term debt accounted for 60% of the Company's capitalization, at both September 30, 1999 and December 31, 1998. The Company remains confident that it will prevail in its appeal of the royalty owners proceeding described in Part II, Item 1. However, the agreement under which unsecured letters of credit have been provided to collateralize the appeal bond would require the Company to reimburse its lenders for the full amount drawn under the letters of credit if it were to lose the appeal. Under these circumstances the Company's ability to borrow money would be restricted and existing financing agreements could be impacted through cross default provisions. The Company's capital expenditures for the first nine months of 1999 were $49.5 million, compared to $41.6 million for the same period in 1998. Capital expenditures in the third quarter of 1999 include an acquisition of approximately 12 Bcf equivalent of proved producing oil and gas properties for $9.3 million. Including the acquisition, planned capital investments during calendar year 1999 are currently expected to be approximately level with 1998. Working Capital Accounts receivable has declined since December 31, 1998, due primarily to seasonally lower deliveries of the gas distribution segment. Inventories have increased since December 31, 1998 due to injection of gas storage volumes in anticipation of the upcoming heating season. Accounts payable is down slightly since December 31, 1998, as liabilities for seasonally lower gas purchases for the gas distribution segment have been partially offset by a payable for the acquisition of oil and gas properties discussed above in Financing Requirements. The payment for this acquisition was funded by the Company's revolving long-term debt on October 1, 1999. Other changes in current assets and current liabilities between periods resulted primarily from the timing of expenditures and receipts. -14- YEAR 2000 The primary financial information systems of the Company that are supported by outside vendors are designed to accommodate the century date or have been upgraded and tested in 1998 to a year 2000 compliant version at no additional cost to the Company. Other information systems supported internally by the Company have been either scheduled for replacement at which time they will become year 2000 compliant, or have been modified to support year 2000 processing. Scheduled implementation and final testing of these systems was originally scheduled to be completed no later than mid-year 1999. Due to delays by a third party vendor, one of the information systems that was an upgrade to existing software will not be completely installed and tested by December 31, 1999. Due to this delay, the Company has modified its existing processes to accommodate the year 2000 date. The Company is continuing with the installation of the software upgrade that will be completed in the year 2000. For additional information regarding the Company's state of readiness for the year 2000, refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's 1998 Form 10-K. FORWARD LOOKING INFORMATION All statements, other than historical financial information, included in this discussion and analysis of financial condition and results of operations 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, the effects of weather and regulation on the Company's gas distribution segment, increased competition, legal and economic factors, 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. -15- PART I Item 3. Quantitative and Qualitative Disclosures About Market Risk Market risks relating to the Company's operations result primarily from changes in commodity prices and interest rates, as well as credit risk concentrations. The Company uses natural gas and crude oil swap agreements and options to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil. The Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risks. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with acceptable 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 8% of accounts receivable. See the discussion of credit risk associated with commodities trading below. Interest Rate Risk The Company's long-term debt obligations are sensitive to changes in interest rates. 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. There were no interest rate swaps outstanding at September 30, 1999. There have been no material changes in the interest rate risk information that was presented in the Company's 1998 10-K. Commodities Risk The Company uses over-the-counter natural gas and crude oil swap agreements and options to hedge sales of Company production and marketing activity 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 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), and (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps). The primary market risk related to these derivative contracts is the volatility in market prices for natural gas and crude oil. However, this market risk is offset by the gain or loss recognized upon the related sale of the natural gas or 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 -16- 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 designated as hedges that are sensitive to changes in commodity prices. The table presents the notional amount in Bcf (billion cubic feet), the weighted average contract prices, and the total dollar contract amount by expected maturity dates. The "Carrying Amount" for the contract amounts are calculated as the contractual payments for the quantity of gas or oil to be exchanged under futures contracts and do not represent amounts recorded in the Company's financial statements. The "Fair Value" represents values for the same contracts using comparable market prices at September 30, 1999. At September 30, 1999, the "Carrying Amount" exceeds the "Fair Value" by $7.7 million.
Expected Maturity Date 1999 2000 2001 2002 Carrying Fair Carrying Fair Carrying Fair Carrying Fair Amount Value Amount Value Amount Value Amount Value Natural Gas: Swaps with a fixed price receipt Contract volume (Bcf) 5.4 15.5 .7 .5 Weighted average price per Mcf $2.36 $2.33 $2.57 $2.57 Contract amount (in millions) $12.7 $10.5 $36.1 $31.0 $1.7 $1.7 $1.2 $1.2 Swaps with a fixed price payment Contract volume (Bcf) .2 - - - Weighted average price per Mcf $2.47 - - - Contract amount (in millions) $.4 $.4 - - - - - - Oil: Price floor Contract volume (MBbls) 94 350 325 - Weighted average price per Bbl $18.00 $18.00 $18.00 - Contract amount (in millions) $1.7 $1.7 $6.3 $6.3 $5.9 $5.9 - - Swaps with a fixed price receipt Contract volume (MBbls) 21 96 72 - Weighted average price per Bbl $20.80 $18.87 $17.49 - Contract amount (in millions) $.4 $.3 $1.8 $1.6 $1.3 $1.2 - -
-17- PART II OTHER INFORMATION Item 1 In May 1996, a class action suit was filed against the Company in the Circuit Court of Sebastian County, Arkansas on behalf of royalty owners alleging improprieties in the disbursements of royalty proceeds. A trial was held on the class action suit beginning in late September 1998 that resulted in a verdict against the Company and two of its wholly-owned subsidiaries, SEECO, Inc. and Arkansas Western Gas Company, in the amount of $62.1 million. The trial judge subsequently awarded pre-judgment interest in an amount of $31.1 million, and post-judgment interest accrued from the date of the judgment at the rate of 10% per annum simple interest. The Company had been required by the state court to post a judgment bond in the amount of $102.5 million (verdict amount plus pre-judgment interest and one year of post-judgment interest) in order to stay the jury's verdict and proceed with an appeal process. The bond was placed by a surety company and was collateralized by unsecured letters of credit. The amount of this bond has been increased to $109.3 million in November 1999 to include additional interest costs through June 2000. The verdict was returned following a trial on the issues of the class action lawsuit brought by certain royalty owners of SEECO, Inc., who contend that since 1979 the defendants breached implied covenants in certain oil and gas leases, misrepresented or failed to disclose material facts to royalty owners concerning gas purchase contracts between the Company's subsidiaries, and failed to fulfill other alleged common law duties to the members of the royalty owner plaintiff class. The litigation was commenced in May 1996 and was disclosed by the Company at that time. The Company believes that the jury's verdict was wrong as a matter of law and fact and that incorrect rulings by the trial judge (including evidentiary rulings and prejudicial jury instructions) provide substantial grounds for a successful appeal. The Company has obtained a temporary stay of the judgment on the jury's verdict and has filed and will vigorously prosecute an appeal in the Arkansas Supreme Court. All appeal briefs are expected to be filed by the end of November. Oral argument is likely to occur in the first quarter of 2000, and a decision from the Court is likely by July 2000. If the Company is not successful in its appeal from the jury verdict, the Company's financial condition and results of operations would be materially and adversely affected. In its Form 8-K filed July 2, 1996, the Company disclosed that a lawsuit relating to overriding royalty interests in certain Arkansas oil and gas properties had been filed against it and two of its wholly-owned subsidiaries. The lawsuit, which was brought by a party who was originally included in (but opted out of) the class action litigation described above, involves claims similar to those upon which judgment was rendered against the Company and its subsidiaries. This case has been set for trial in January 2000. In September 1998, another party who opted out of the class threatened the Company with similar litigation. While the amounts of these pending and threatened claims could be material, management believes, based on its investigations, that the Company's ultimate liability, if any, will not be material to its consolidated financial position or results of operations. -18- The United States Minerals Management Service (MMS), a federal agency responsible for the administration of federal oil and gas leases, is investigating the Company and its subsidiaries in respect of claims similar to those in the class action litigation. MMS was included in the class action litigation against its objections. MMS has withdrawn its cross appeal on this issue and has not pursued further action to remove itself from the class. If MMS does remove itself from the class, its claims may be brought separately under federal statutes that provide for treble damages and civil penalties. In such event, the Company believes it would have defenses that were not available in the class action litigation. While the aggregate amount of MMS's claims could be material, management believes, based on its investigations, that the Company's ultimate liability, if any, will not be material to its consolidated financial position or results of operations. Items 2 - 6(a) No developments required to be reported under Items 1 - 6(a) occurred during the quarter ended September 30, 1999 that have not been previously reported. Item 6(b) On October 20, 1999, the Company filed a current report on Form 8-K dated October 19, 1999, announcing the sale of its Missouri gas distribution assets to Atmos Energy Corporation for $32.0 million. Signatures Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SOUTHWESTERN ENERGY COMPANY --------------------------- Registrant DATE: November 12, 1999 /s/ GREGORY D. KERLEY --------------------- --------------------------- Gregory D. Kerley Senior Vice President and Chief Financial Officer -19- EX-27 2 FINANCIAL DATA SCHEDULE FOR 3RD QTR - 1999
5 1,000 9-MOS DEC-31-1999 SEP-30-1999 1,560 0 28,482 0 27,109 69,839 1,074,581 (509,603) 658,339 56,480 282,600 0 0 2,774 184,518 658,339 189,141 194,659 0 171,525 0 0 12,742 9,005 3,512 5,493 0 0 0 5,493 0.22 0.22 The information has been prepared in accordance with SFAS No. 128. Basic and diluted EPS have been entered in place of primary and fully diluted, respectively.
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