-----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, Rp1lPJOpJVJNItspIxfVyp8FEC/5WNQD19sJZnwoiabq4J7kxDOe9WuSM7pEPtJY GqkGBGKwOUz0ch+FHADd6A== 0000007332-98-000025.txt : 19981118 0000007332-98-000025.hdr.sgml : 19981118 ACCESSION NUMBER: 0000007332-98-000025 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19980930 FILED AS OF DATE: 19981116 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: 98751913 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, 1998 =========================================================================== 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, 1998 ------------------ 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, 1998 ---------------------------- ------------------------------- Common Stock, Par Value $.10 24,931,337 =========================================================================== - 1 - PART I FINANCIAL INFORMATION - 2 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited) ASSETS
September 30, December 31, 1998 1997 ------------ --------- ($ in thousands) Current Assets Cash $ 840 $ 4,603 Accounts receivable 21,868 45,752 Income taxes receivable 3,653 3,074 Inventories, at average cost 23,794 20,465 Under-recovered purchased gas costs, net - 9,428 Other 4,219 4,633 --------- --------- Total current assets 54,374 87,955 --------- --------- Investments 12,377 7,039 --------- --------- Property, Plant and Equipment, at cost Gas and oil properties, using the full cost method 741,332 708,094 Gas distribution systems 216,053 212,779 Gas in underground storage 25,794 23,748 Other 26,206 25,319 --------- --------- 1,009,385 969,940 Less: Accumulated depreciation, depletion and amortization 468,254 366,638 --------- --------- 541,131 603,302 --------- --------- Other Assets 11,987 12,570 --------- --------- Total Assets $ 619,869 $ 710,866 ========= =========
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, 1998 1997 ------------- --------- ($ in thousands) Current Liabilities Current portion of long-term debt $ 3,071 $ 3,071 Accounts payable 24,007 29,903 Taxes payable 3,282 3,893 Interest payable 7,080 2,569 Customer deposits 5,233 5,307 Other 5,704 4,246 --------- --------- Total current liabilities 48,377 48,989 --------- --------- Long-Term Debt, less current portion above 267,371 296,472 --------- --------- Other Liabilities Deferred income taxes 118,279 139,256 Other 3,874 4,584 --------- --------- 122,153 143,840 --------- --------- 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 21,252 21,475 Retained earnings 190,382 230,669 Less: Common stock in treasury, at cost 2,804,259 shares in 1998 and 2,904,519 shares in 1997 31,253 32,357 Unamortized cost of 137,588 restricted shares in 1998 and 90,375 restricted shares in 1997, issued under stock incentive plan 1,187 996 --------- --------- 181,968 221,565 --------- --------- Total Liabilities and Shareholders' Equity $ 619,869 $ 710,866 ========= =========
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, 1998 1997 1998 1997 ---------- ---------- ---------- ---------- ($ in thousands, except per share amounts) Operating Revenues Gas sales $ 27,974 $ 27,876 $ 123,268 $ 129,318 Gas marketing 21,851 16,264 56,556 44,287 Oil sales 2,138 3,295 7,482 10,978 Gas transportation and other 1,588 1,209 5,535 4,224 ---------- ---------- ---------- --------- 53,551 48,644 192,841 188,807 ---------- ---------- ---------- --------- Operating Costs and Expenses Gas purchases - utility 3,588 2,773 26,258 30,049 Gas purchases - marketing 21,199 15,877 54,525 42,591 Operating and general 13,865 14,019 45,606 42,755 Depreciation, depletion and amortization 10,356 11,123 35,794 34,952 Write-down of oil and gas properties - - 66,383 - Taxes, other than income taxes 1,629 1,731 5,273 5,156 ---------- ---------- ---------- --------- 50,637 45,523 233,839 155,503 ---------- ---------- ---------- --------- Operating Income (Loss) 2,914 3,121 (40,998) 33,304 ---------- ---------- ---------- --------- Interest Expense 4,457 4,114 12,645 11,845 ---------- ---------- ---------- --------- Other Income (Expense) (638) (1,068) (2,614) (3,441) ---------- ---------- ---------- --------- Income (Loss) Before Provision for Income Taxes (2,181) (2,061) (56,257) 18,018 ---------- ---------- ---------- --------- Income Tax Provision (Benefit) Current (4,705) (4,801) (817) 1,497 Deferred 3,855 4,007 (21,123) 5,440 ---------- ---------- ---------- --------- (850) (794) (21,940) 6,937 ---------- ---------- ---------- --------- Net Income (Loss) $ (1,331) $ (1,267) $(34,317) $ 11,081 ========== ========== ========== ========== Basic Earnings (Loss) Per Share ($0.05) ($0.05) ($1.38) $ .45 ====== ====== ====== ===== Weighted Average Common Shares Outstanding 24,892,778 24,742,129 24,865,375 24,732,972 ========== ========== ========== ========== Diluted Earnings (Loss) Per Share $(0.05) ($0.05) $(1.38) $ .45 ====== ====== ====== ===== Diluted Weighted Average Common Shares Outstanding 24,892,778 24,742,129 24,865,375 24,846,650 ========== ========== ========== ========== Dividends Declared Per Share Payable 11/5/98 and 11/5/97 $ .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, 1998 1997 -------- -------- ($ in thousands) Cash Flows From Operating Activities Net income (loss) $(34,317) $ 11,081 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 36,790 35,732 Write-down of oil and gas properties 66,383 - Deferred income taxes (21,123) 5,440 Equity in loss of partnership 2,618 3,169 Change in assets and liabilities: Decrease in accounts receivable 23,884 11,589 (Increase) decrease in income taxes receivable (579) 4,235 Increase in inventories (3,329) (4,382) (Increase) decrease in under-recovered purchased gas costs 9,734 (7,612) Increase (decrease) in accounts payable (5,896) 3,683 Increase in interest payable 4,511 4,898 Net change in other current assets and liabilities 881 (2,546) -------- -------- Net cash provided by operating activities 79,557 65,287 -------- -------- Cash Flows From Investing Activities Capital expenditures (41,641) (64,751) Investment in partnership (7,955) (3,726) Increase in gas stored underground (2,046) (1,112) Other items 3,392 (117) -------- -------- Net cash used in investing activities (48,250) (69,706) -------- -------- Cash Flows From Financing Activities Decrease in revolving long-term debt (29,100) (66,700) Issuance of long-term debt - 75,000 Cash dividends (5,970) (4,451) -------- -------- Net cash provided (used) in financing activities (35,070) 3,849 -------- -------- Decrease in cash (3,763) (570) Cash at beginning of year 4,603 2,297 -------- -------- Cash at end of period $ 840 $ 1,727 ======== ========
The accompanying notes are an integral part of the financial statements. - 6 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1998 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 1997 Annual Report to Shareholders, Notes to Financial Statements. Certain reclassifications have been made to the September 30, 1997, financial statements in order to conform with the 1998 presentation. These reclassifications had no effect on previously reported net income. 2. CONTINGENCIES AND COMMITMENTS The Company announced on October 16, 1998, that a state court jury in Fort Smith, Arkansas, by a vote of nine to three, returned 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 has 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. Subject to court approval, the bond will be placed by a surety company and will be collateralized by unsecured letters of credit. The verdict was returned following a trial on the issues of a 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 asked the trial judge to recuse himself due to his apparent bias toward the plaintiffs and has also filed a motion with the trial court for judgement notwithstanding the verdict or, in the alternative, for a new trial. The Company has obtained a temporary stay of the judgment on the jury's verdict and intends to file and vigorously prosecute an appeal in the Arkansas - 7 - Supreme Court if its post trial motions are denied. The Company expects that an indefinite stay pending appeal will be approved by the state court trial judge upon approval of the bond. If the Company is not successful in post trial motions and its appeal from the jury verdict, the Company's financial condition and results of operations would be materially and adversely affected. 3. OIL AND GAS PROPERTIES 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. Such capitalized costs do not include costs related to unevaluated properties. At September 30, 1998, the Company's unamortized costs of oil and gas properties exceeded this ceiling amount by approximately $40.1 million (net of taxes) due primarily to low oil and gas prices. However, the ceiling limitation was recalculated using October, 1998 prices, as prescribed by SEC guidelines, and, as a result, the Company's unamortized costs of oil and gas properties did not exceed this recomputed ceiling amount. 4. EARNINGS PER SHARE The Company has adopted Financial Accounting Standards Board Statement No. 128, "Earnings Per Share" (SFAS No. 128). 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 impact of the adoption of SFAS No. 128 had no effect on reported earnings per share for the three month and nine month periods ended September 30, 1998 and 1997. 5. COMPREHENSIVE INCOME In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" (SFAS No. 130), establishing standards for reporting and display of comprehensive income and its components in financial statements. SFAS No. 130 defines comprehensive income as the total of net income and all other nonowner changes in equity. The Company had no nonowner changes in equity other than net income during the nine months ended September 30, 1998 and 1997. - 8 - 6. DERIVATIVE AND HEDGING ACTIVITIES In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 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, 1999. A company may also implement the statement as of the beginning of any fiscal quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 (and, at the company's election, before January 1, 1998). 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. 7. DIVIDEND PAYABLE A dividend of $.06 per share was declared September 11, 1998, payable November 5, 1998. 8. 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 1998 1997 1998 1997 - --------------------------------------------------------------------------------------- (in thousands) Interest payments $145 $431 $9,926 $9,276 Income tax payments $907 $3,025 $3,249 $3,409
- 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, 1997, and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 1998, and the comparable periods of 1997. RESULTS OF OPERATIONS The Company reported a net loss of $1.3 million, or $.05 per share, for the third quarter of 1998, even with the same period in 1997. The loss reflects the seasonal nature of both natural gas prices and consumption by the Company's utility customers. The Company reported a net loss of $34.3 million, or $1.38 per share, for the nine months ended September 30, 1998. The loss for the nine months reflects 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. Excluding the non-cash charge, the Company would have recognized net income for the nine months ended September 30, 1998, of $6.2 million, or $.25 per share, down from net income of $11.1 million, or $.45 per share, for the same period in 1997. The decrease in earnings (excluding the non-cash charge) was primarily due to lower wellhead prices for both oil and gas. 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. Such capitalized costs do not include costs related to unevaluated properties. At September 30, 1998, the Company's unamortized costs of oil and gas properties exceeded this ceiling amount by approximately $40.1 million (net of taxes) due primarily to low oil and gas prices. However, the ceiling limitation was recalculated using October, 1998 prices, as prescribed by SEC guidelines, and, as a result, the Company's unamortized costs of oil and gas properties did not exceed this recomputed 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 other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings. The following tables compare operating revenues and operating income (before the effects of the second quarter write-down of oil and gas properties) by business segment for the three and nine month periods ended September 30, 1998 and 1997: - 10 -
Quarter Ended Nine Months Ended September 30, September 30, --------------------- -------------------- 1998 1997 1998 1997 ---- ---- ---- ---- (in thousands) Revenues Exploration and production $18,975 $20,324 $64,382 $70,239 Gas distribution 16,711 18,791 95,263 103,970 Energy services and other 27,250 20,779 71,132 56,315 Eliminations (9,385) (11,250) (37,936) (41,717) ------- ------- -------- -------- $53,551 $48,644 $192,841 $188,807 ======= ======= ======== ======== Operating Income Exploration and production $ 4,345 $ 4,942 $ 13,966 $ 22,044 Gas distribution (1,818) (2,021) 10,173 10,173 Energy services and other 387 200 1,246 1,087 ------- ------- -------- -------- $ 2,914 $ 3,121 $ 25,385 $ 33,304 ======= ======= ======== ========
Exploration and Production Revenues of the exploration and production segment were down 7% for the three month period ended September 30, 1998, and were down 8% for the nine month period ended September 30, 1998, both as compared to the same periods in 1997. Operating income of this segment was down $.6 million for the three months ended September 30, 1998, and excluding the write-down of oil and gas properties, was down $8.1 million for the nine months ended September 30, 1998, both as compared to the same periods in 1997. Gas production for the three months ended September 30, 1998, was 7.6 Bcf, even with the same period in 1997. For the nine months ended September 30, 1998, gas production was 24.3 Bcf, compared to 24.2 Bcf in 1997. The Company's sales to its utility distribution systems were 8.5 Bcf during the nine months ended September 30, 1998, compared to 10.1 Bcf for the same period in 1997. The decline in sales to the utility segment was primarily the result of weather that was 11% warmer than in 1997. Southwestern received an average price of $2.22 per Mcf for its gas production during the three months ended September 30, 1998, down from $2.25 per Mcf for the same period in 1997. The Company received an average price of $2.34 per Mcf for its gas production during the nine months ended September 30, 1998, down from $2.45 per Mcf for the same period in 1997. The Company's average price was enhanced by 30 cents per Mcf for the quarter and 22 cents per Mcf for the first nine months of 1998 as a result of the Company's hedging activities. The Company hedged approximately 80% of its floating price gas production through September, 1998. For the period of October, 1998 through March, 1999, the Company has hedged approximately 1.4 Bcf per month at an average NYMEX price of $2.51 per Mcf. Most of the intersegment gas sales to Arkansas Western Gas Company (AWG), the utility subsidiary that operates the Company's northwest Arkansas utility system, are pursuant to a long-term contract entered into in 1978 which was amended and restated in 1994. SEECO, one of the Company's exploration and production subsidiaries, sold 5.6 Bcf under this contract at an average - 11 - price of $2.92 per Mcf in the first nine months of 1998, compared to 5.9 Bcf at an average price of $3.42 per Mcf for the same period in 1997. This contract expired July 24, 1998, but is being continued on a month-to-month basis through November, 1998. In March, 1997, AWG filed a gas supply plan with the Arkansas Public Service Commission (APSC) which projects system load growth patterns and long range gas supply needs for the utility's northwest Arkansas system. The gas supply plan also addressed replacement supplies for AWG's long-term contract with SEECO. After discussions with the APSC it was determined that the majority of the utility's future gas supply needs should be provided through a competitive bidding process. On October 1, 1998, AWG sent requests for proposal to various suppliers requesting bids on seven different packages of gas supply to be effective December 1, 1998. These bid requests included replacement of the gas supply and no-notice service previously provided by the long-term gas supply contract between AWG and SEECO. Eleven potential suppliers returned bids in late October. SEECO along with the Company's energy services subsidiary successfully bid on five of the seven packages with prices based on the NorAm East Index plus a demand charge. The volumes of gas projected to be sold under these contracts in their first year are approximately equal to the historical annual volumes sold under the expired long-term contract. However, the volumes to be sold under these contracts are not fixed as they were under the expired contract. The total premium over the NorAm East Index under these contracts is estimated to be approximately $1.0 million lower (after tax) than the annual premium earned under the expired long-term contract. The majority of the premium will be received through monthly demand charges ranging from approximately $1.0 million in December through February to approximately $225,000 per month for the remainder of the year. These demand charges will be received regardless of volumes actually delivered. Other sales to AWG are made under long-term contracts with flexible pricing provisions. The Company's oil production was 550 thousand barrels (MBbls) during the nine months ended September 30, 1998, compared to 576 MBbls for the same period of 1997. Southwestern received an average price of $13.60 per barrel for its oil production during the nine months ended September 30, 1998, down from $19.07 per barrel for the same period of 1997. The decrease in average price reflects the general decline in the market price for oil during the first nine months of 1998. Gas Distribution Operating income in the third quarter for the gas distribution segment improved by $.2 million from the level in 1997. Operating income for the first nine months of 1998 remained even with 1997 results, despite weather that was 12% warmer than normal and 11% warmer than last year. The utility systems delivered 22.4 Bcf to sales and end-use transportation customers during the nine months ended September 30, 1998, down from 23.0 Bcf for the same period in 1997. Rate increases and tariff changes totaling $3.0 million annually implemented in late 1997 helped offset the effect of decreased deliveries due to warmer weather. The utility also realized 2% growth in the average number of customers. The Company's average rate for its utility sales increased to $5.62 per Mcf during the first nine months of 1998, up from $5.39 per Mcf for the same period in 1997. The increase was the result - 12 - of the rate increases discussed above and the effects of weather normalization clauses included in the rate tariffs of Arkansas customers. Energy Services Operating income for the energy services segment was $.3 million on revenues of $27.1 million for the third quarter of 1998, compared to $.2 million on revenues of $20.7 million for the same period in 1997. For the nine months ended September 30, 1998, operating income for this segment was $1.1 million on revenues of $70.8 million, compared to $1.1 million on revenues of $56.1 million for the same period in 1997. The Company marketed 36.4 Bcf of gas in the first nine months of 1998, compared to 26.1 Bcf for the same period in 1997. The higher margins in relation to revenue levels realized during 1997 primarily relate to income realized from the Company's unregulated storage facilities which were utilized to take advantage of the higher gas prices available at that time. A portion of the activity of the energy services segment involves the NOARK Pipeline System (NOARK). The Company's share of NOARK's pre-tax loss included in other income was $.9 million for the third quarter of 1998 and $2.6 million for the first nine months of 1998, compared to $1.2 million and $3.2 million, respectively, for the same periods in 1997. The improvement in NOARK's pre-tax loss for the first nine months of 1998 primarily reflects a lower interest rate on NOARK's debt which resulted from a refinancing discussed below in "Changes in Financial Condition". 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 is a 437-mile interstate pipeline system which begins in eastern Oklahoma and terminates in eastern Arkansas. On July 1, 1998, the Federal Energy Regulatory Commission (FERC) authorized the operation and integration of the Ozark pipeline and the NOARK pipeline as a single, integrated pipeline. The FERC order also authorized the purchase of Ozark by a subsidiary of Enogex and the construction of integration facilities. Effective August 1, 1998, Enogex acquired Ozark and contributed the pipeline system to the NOARK partnership. Enogex has also acquired the NOARK partnership interests not held by Southwestern. In addition to its purchase of Ozark, Enogex funded the integration project and an expansion of the combined system. Enogex spent approximately $70 million to acquire Ozark and integrate it with NOARK. The integrated system became operational November 1, 1998, and includes 749 miles of pipeline with a total throughput capacity of 330 MMcfd. Effective November 1, 1998, the Company's interest in the expanded project decreased to 25% with Enogex owning a 75% interest. After its start-up period, the Company expects the improved project to significantly reduce the losses it has been experiencing on its NOARK investment. Operating Costs and Expenses Operating costs and expenses increased 11% in the third quarter of 1998 and increased 8% for the first nine months of 1998 (excluding the impact of the write-down of oil and gas properties), both as compared to the comparable periods in 1997. The increase in the third quarter was - 13 - primarily caused by increased gas purchases by the gas distribution and energy services segments, partially offset by lower depreciation, depletion and amortization expense. The increase in the year-to-date expense was primarily due to increased gas purchases in the energy services segment, increased operating and general expenses and higher depreciation, depletion and amortization expense, offset by lower purchased gas costs of the gas distribution segment. The increase in operating and general expenses for the first nine months of 1998 was due primarily to increased payroll and benefit costs, and for employee termination benefits and other costs incurred in connection with the closing of the Company's Oklahoma City exploration and production office. The activities of this office were consolidated into the Company's Houston office. The increase in depreciation, depletion and amortization expense was due to an increase in the amortization rate per unit of production in the exploration and production segment for the nine month period ended September 30, 1998. The Company's amortization rate, excluding the impact of the write-down of oil and gas properties, was $1.07 per Mcf equivalent for the first nine months of 1998, compared to $1.05 for the same period in 1997. Due primarily to the write-down of its property costs in the second quarter of 1998, the Company's amortization rate for the third quarter of 1998 was $.96 per Mcf equivalent compared to $1.06 for the same period in 1997. The future amortization rate will be impacted by the level of reserve additions and costs added to the full cost pool. Interest expense, net of capitalization, for the nine months ended September 30, 1998, was up 7% compared to the same period in 1997, due to slightly higher average borrowings. Interest is capitalized in the exploration and production segment on costs that are unevaluated and excluded from amortization. The Company's capitalized interest for this segment was down $.4 million, or 36%, in the third quarter of 1998 as compared to the prior year. This decrease was due to the transfer of approximately $27.2 million of previously unevaluated costs to the amortizable full cost pool in the second quarter of 1998. The previously discussed second quarter write-down of the Company's oil and gas properties resulted in a deferred tax benefit of $25.9 million. Excluding the impact of this change in deferred income taxes, the changes in the provisions for current and deferred income taxes recorded in the three and nine month periods ended September 30, 1998, as compared to the same periods in 1997, resulted primarily from the level of taxable income and from 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. Year 2000 The year 2000 problem impacts most companies as many informational and operational systems that currently exist will be unable to continue processing in the year 2000 due to the improper recognition of calendar dates. The Company began an initial review in late 1996 of its processing systems and the ability of those systems to process year 2000 data. The primary financial information systems of the Company that are supported by outside vendors are designed to accommodate the century date or are scheduled for an upgrade in 1998 to a year 2000 compliant version at no additional cost to the Company. The Company is currently testing these upgrades - 14 - and expects these systems to be year 2000 compliant by the end of 1998. Other information systems supported internally by the Company are either scheduled for replacement at which time they will become year 2000 compliant or they will be subject to modification to support year 2000 processing during 1998. Implementation and final testing of these systems is expected to be completed no later than mid-year 1999. The total costs associated with the modification of these systems are expected to be approximately $.8 million. Of this amount, approximately $.5 million relates to planned improvements that were not directly related to the year 2000 problem. The Company has also identified internal processes and areas of non-information technology (e.g. equipment with embedded chips) that require modification to process year 2000 data or that require further assessment. The Company is replacing the operating system of its personal computers to the NT version of Windows, which will also result in the replacement of noncompliant personal computers and the related software that is not already year 2000 compliant. This rollout of NT was a scheduled replacement not directly related to the year 2000 problem. It is expected to be completed by the end of 1998 at an estimated cost of $.6 million. An assessment is underway in other non-information technology areas related to electronic meter reading and field measurement. Currently, replacement of electronic meter reading equipment is estimated to cost approximately $.3 million and is expected to be completed by the end of 1998. The Company has not completed its estimate of the timing and costs related to its field measurement equipment, but it is not expected to have a material impact on the Company's financial condition or its results of operations. The highest risk area for the Company related to the year 2000 issues is noncompliance by third parties. At this time, the most reasonably likely worst case scenario would be year 2000 noncompliance by third parties that comprised a significant level of business conducted with the Company. Depending upon the level of noncompliance, the Company could be adversely impacted by such things as late or incorrect revenue receipts or expense disbursements, communication problems, or scheduling or delivery problems related to the transportation and distribution of natural gas. The Company is addressing this risk through communication with industry partners, suppliers, financial institutions and others. The major risk areas associated with third party noncompliance have been identified, and the third parties within these areas have been further risk-weighted based upon the Company's level of business reliance. These third parties are being contacted and the Company is in the process of evaluating responses and corresponding with those parties that have not responded or that have responded inadequately. As this process continues, the Company will develop contingency plans that it deems necessary based on its evaluations of third party readiness. The Company expects to have this process completed with any necessary contingency plans in place by mid-year 1999. No such contingency plans have been developed to date. Based upon its assessment of third party assurances at this time, the Company does not anticipate any material disruptions in its business activities as a result of third party year 2000 noncompliance, although it cannot be certain that such disruptions will not occur. If such disruptions do occur, the materiality of their impact on the Company's financial condition and results of operations will depend on the extent and duration of the disruptions and the nature of any legal proceedings resulting from the disruptions. - 15 - CHANGES IN FINANCIAL CONDITION Changes in the Company's financial condition at September 30, 1998, as compared to December 31, 1997, primarily reflect the seasonal nature of the gas distribution segment of the Company's business. Routine capital expenditures, cash dividends and scheduled debt retirements are predominately funded through cash provided by operations. For the first nine months of 1998 and 1997, net cash provided by operating activities was $79.6 million and $65.3 million, respectively, and exceeded the total of these routine requirements. The increase in net cash provided by operating activities during the first nine months of 1998 was largely due to the utility segment's collection of $9.7 million of gas costs incurred during 1997, but deferred for collection until 1998 pursuant to the utility's purchased gas adjustment clauses in its filed rate tariffs. The Company had net over-recovered purchased gas costs of $.3 million at September 30, 1998, recorded in other current liabilities. At December 31, 1997, the Company had net under-recovered purchased gas costs of $9.4 million. This amount was classified as a current asset. 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, $17.3 million was outstanding at September 30, 1998, all of which was classified as long-term debt. During the first nine months of 1998, the Company's revolving long-term debt decreased by $29.1 million primarily due to cash flow generated by seasonally high utility revenues and the collection of deferred gas costs discussed above. Due primarily to the second quarter write-down of the Company's oil and gas properties, shareholders' equity decreased by $39.6 million, as compared to December 31, 1997. As a result, long-term debt at September 30, 1998, accounted for 59.5% of the Company's capitalization, up from 57.2% at December 31, 1997. The Company's capital expenditures for the first nine months of 1998 were $41.6 million, down from $64.8 million for the same period in 1997. The decrease primarily relates to reduced capital expenditures by the Company's exploration and production segment. Planned capital spending during 1998 is expected to be approximately $20.0 million lower than actual 1997 spending. In connection with the Enogex transaction discussed above, the Company and a previous general partner converted certain of their loans to the NOARK partnership, plus accrued interest, into equity, and contributed approximately $10.7 million to the partnership to fund costs incurred in connection with the prepayment of NOARK's 9.74% Senior Secured Notes. The Company's share of the contribution was $6.5 million and is the primary reason for the increase in investments during the first nine months of 1998. The notes were temporarily refinanced with Senior Secured Notes payable to the other current general partner of NOARK. In June, 1998, the NOARK partnership issued $80.0 million of 7.15% Notes due 2018. Proceeds from the issue of the notes were used to repay the Senior Secured Notes and amounts borrowed under the partnership's bank revolving line of credit. The notes require semi-annual principal payments of $1.0 million beginning in December, 1998. The Company and the other general partner of - 16 - NOARK have severally guaranteed the principal and interest payments on the NOARK debt. The Company's share of the several guarantee is 60%. Working Capital Accounts receivable has declined since December 31, 1997, due primarily to seasonally lower deliveries of the gas distribution segment. Accounts payable has decreased since December 31, 1997 due to the seasonally lower gas purchases for the gas distribution segment and due to the timing of expenditures. Other changes in current assets and current liabilities between periods resulted primarily from the timing of expenditures and receipts. 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 and Section 21E of the Securities Exchange Act of 1934. These statements reflect the Company's current views with respect to future events and performance. The Company believes that its expectations are based on reasonable assumptions. No assurances, however can be given that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include (1) the timing and extent of changes in commodity prices for gas and oil and interest rates, (2) the timing and extent of the Company's success in discovering, developing, producing, and estimating reserves, (3) the effects of weather and regulation on the Company's gas distribution segment, and (4) conditions in capital markets, availability of oil field services, drilling rigs, and other equipment, as well as other competitive factors during the periods covered by the forward-looking statements. - 17 - PART II OTHER INFORMATION Item 1 - Legal Proceedings As previously disclosed in its Form 8-K filed October 16, 1998, a state court jury in Fort Smith, Arkansas, by a vote of nine to three, returned 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 has 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. Subject to court approval, the bond will be placed by a surety company and will be collateralized by unsecured letters of credit. The verdict was returned following a trial on the issues of a 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 asked the trial judge to recuse due to his apparent bias toward the plaintiffs and has also filed a motion with the trial court for judgement notwithstanding the verdict or, in the alternative, for a new trial. The Company has obtained a temporary stay of the judgment on the jury's verdict and intends to file and vigorously prosecute an appeal in the Arkansas Supreme Court if its post trial motions are denied. The Company expects that an indefinite stay pending appeal will be approved by the state court trial judge upon approval of the bond. If the Company is not successful in post trial motions and 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. 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, - 18 - 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. 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, but 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 2 - 6(a) occurred during the quarter ended September 30, 1998. Item 6(b) On October 16, 1998, the Company filed a current report on Form 8-K dated October 15, 1998, announcing the verdict of a state court jury in a class action royalty lawsuit against Southwestern Energy Company and two of its subsidiaries. The verdict is discussed above in Item 1 of Part II. On October 30, 1998, the Company filed a current report on Form 8-K dated October 29, 1998, announcing the appointment by the Company's Board of Directors of Harold Korell to replace Charles E. Scharlau as Chief Executive Officer of the Company effective January 1, 1999. Mr. Korell was also elected to the Company's Board of Directors effective immediately. 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 16, 1998 /s/ GREGORY D. KERLEY ------------------------------- Gregory D. Kerley Senior Vice President - Finance and Chief Financial Officer - 19 - EX-27 2 FINANCIAL DATA SCHEDULE FOR 3RD QTR - 1998
5 1,000 9-MOS DEC-31-1998 SEP-30-1998 840 0 21,868 0 23,794 54,374 1,009,385 (468,254) 619,869 48,377 267,371 0 0 2,774 179,194 619,869 187,306 192,841 0 233,839 0 0 12,645 (56,257) (21,940) (34,317) 0 0 0 (34,317) (1.38) (1.38) The information has been prepared in accordance with SFAS No. 128. Basic and dilted EPS have been entered in place of primary and fully diluted, respectively.
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