10-Q 1 swn10q6302001.txt ================================================================================ 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 June 30, 2001 ------------- or [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from _______ to _______ Commission file number 1-8246 SOUTHWESTERN ENERGY COMPANY (Exact name of registrant as specified in its charter) Arkansas 71-0205415 (State of incorporation (I.R.S. Employer or organization) Identification No.) 2350 N. Sam Houston Pkwy. E., Suite 300, Houston, Texas 77032 (Address of principal executive offices, including zip code) (281) 618-4700 (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 August 7, 2001 ---------------------------- ----------------------------- Common Stock, Par Value $.10 25,189,255 ================================================================================ - 1 - PART I FINANCIAL INFORMATION - 2 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited) ASSETS
June 30, December 31, 2001 2000 ------------- ------------ ($ in thousands) Current Assets Cash $ 1,492 $ 2,386 Accounts receivable 37,942 77,041 Inventories, at average cost 24,127 17,000 Under-recovered purchased gas costs 4,631 12,942 Hedging asset - SFAS No.133 6,504 - Other 2,712 3,486 --------- --------- Total current assets 77,408 112,855 --------- --------- Investments 16,233 15,574 --------- --------- Property, Plant and Equipment, at cost Gas and oil properties, using the full cost method 917,487 872,023 Gas distribution systems 190,965 190,893 Gas in underground storage 30,103 27,867 Other 28,338 27,940 --------- --------- 1,166,893 1,118,723 Less: Accumulated depreciation, depletion and amortization 578,142 554,616 --------- --------- 588,751 564,107 --------- --------- Other Assets 13,423 12,842 --------- --------- Total Assets $ 695,815 $ 705,378 ========= =========
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
June 30, December 31, 2001 2000 ------------- ------------ ($ in thousands) Current Liabilities Short-term debt $ - $ 171,000 Accounts payable 34,885 54,304 Taxes payable 2,920 4,346 Interest payable 2,632 2,806 Customer deposits 4,517 4,799 Deferred income tax payable 2,537 - Other 3,558 2,629 --------- --------- Total current liabilities 51,049 239,884 --------- --------- Long-Term Debt, less current portion above 357,000 225,000 --------- --------- Other Liabilities Deferred income taxes 112,457 97,431 Other 1,836 1,772 --------- --------- 114,293 99,203 --------- --------- Commitments and Contingencies Minority Interest in Partnership 4,284 - --------- --------- 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 20,210 20,220 Retained earnings 171,235 148,353 Accumulated other comprehensive income 4,601 - --------- --------- 198,820 171,347 Less: Common stock in treasury, at cost, 2,547,723 shares in 2001 and 2,556,908 shares in 2000 28,445 28,485 Unamortized cost of 227,226 restricted shares in 2001 and 241,452 restricted shares in 2000, issued under stock incentive plan 1,186 1,571 --------- --------- 169,189 141,291 --------- --------- Total Liabilities and Shareholders' Equity $ 695,815 $ 705,378 ========= =========
The accompanying notes are an integral part of the financial statements. - 4 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, ------------------------- ------------------------- 2001 2000 2001 2000 ---------- ---------- ---------- ---------- ($ in thousands, except per share amounts) Operating Revenues Gas sales $ 52,173 $ 37,686 $ 147,558 $ 97,978 Gas marketing 17,523 35,384 52,712 65,388 Oil sales 4,682 3,798 8,844 7,377 Gas transportation and other 1,645 1,615 4,038 4,653 ---------- ---------- ---------- ---------- 76,023 78,483 213,152 175,396 ---------- ---------- ---------- ---------- Operating Costs and Expenses Gas purchases - utility 9,370 7,963 50,498 27,226 Gas purchases - marketing 16,845 34,456 50,580 63,119 Operating expenses 9,215 8,476 19,678 17,342 General and administrative expenses 7,580 6,770 12,407 12,690 Unusual item - 109,288 - 109,288 Depreciation, depletion and amortization 12,637 11,251 24,274 22,342 Taxes, other than income taxes 2,361 2,128 5,101 4,182 ---------- ---------- ---------- ---------- 58,008 180,332 162,538 256,189 ---------- ---------- ---------- ---------- Operating Income (Loss) 18,015 (101,849) 50,614 (80,793) ---------- ---------- ---------- ---------- Interest Expense Interest on long-term debt 5,904 4,944 12,771 10,145 Other interest charges 538 913 829 1,105 Interest capitalized (424) (683) (860) (1,320) ---------- ---------- ---------- ---------- 6,018 5,174 12,740 9,930 ---------- ---------- ---------- ---------- Other Income (Expense) (358) 3,239 22 1,998 ---------- ---------- ---------- ---------- Income (Loss) Before Income Taxes & Minority Interest 11,639 (103,784) 37,896 (88,725) ---------- ---------- ---------- ---------- Minority Interest in Partnership (384) - (384) - ---------- ---------- ---------- ---------- Income (Loss) Before Income Taxes 11,255 (103,784) 37,512 (88,725) ---------- ---------- ---------- ---------- Income Tax Provision (Benefit) Current - (872) - - Deferred 4,386 (39,603) 14,630 (34,602) ---------- ---------- ---------- ---------- 4,386 (40,475) 14,630 (34,602) ---------- ---------- ---------- ---------- Income (Loss) Before Extraordinary Item 6,869 (63,309) 22,882 (54,123) Extraordinary Loss Due to Early Retirement of Debt (Net of $569 Tax Benefit) - (890) - (890) ---------- ---------- ---------- ---------- Net Income (Loss) $ 6,869 $ (64,199) $ 22,882 $ (55,013) ========== ========== ========== ========== Basic Earnings Per Share $0.27 ($2.57) $0.91 ($2.20) ========== ========== ========== ========== Basic Average Common Shares Outstanding 25,189,623 25,035,079 25,188,370 25,036,294 ========== ========== ========== ========== Diluted Earnings Per Share $0.27 ($2.57) $0.89 ($2.20) ========== ========== ========== ========== Diluted Average Common Shares Outstanding 25,657,842 25,035,079 25,576,721 25,036,294 ========== ========== ========== ========== Dividends Declared Per Share Payable 5/5/00 - - - $0.06 ========== ========== ========== ==========
The accompanying notes are an integral part of the financial statements. - 5 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Six Months Ended June 30, -------------------- 2001 2000 -------- -------- ($ in thousands) Cash Flows From Operating Activities Net income (loss) $ 22,882 $(55,013) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 25,017 23,049 Deferred income taxes 14,630 (34,602) Equity in loss of NOARK partnership 789 1,057 Gain on sale of Missouri utility assets - (3,209) Extraordinary loss due to early retirement of debt (net of tax) - 890 Minority interest in partnership 384 - Change in assets and liabilities: Accounts receivable 39,099 3,563 Inventories (7,127) 3,577 Under recovered purchased gas costs 8,311 (4,750) Accounts payable (19,419) 7,441 Accrual for Hales judgment - 109,288 Other current assets and liabilities (178) (690) -------- -------- Net cash provided by operating activities 84,388 50,601 -------- -------- Cash Flows From Investing Activities Capital expenditures (47,990) (43,404) Sale of Missouri utility assets - 32,000 Investment in NOARK partnership (1,449) (1,620) Change in gas stored underground (2,236) 944 Other items 1,493 (354) -------- -------- Net cash used in investing activities (50,182) (12,434) -------- -------- Cash Flows From Financing Activities Net change in revolving long-term debt (39,000) (27,700) Contributions from minority interest partner 3,900 - Payment on revolving short-term debt - (7,500) Cash dividends - (3,005) -------- -------- Net cash used in financing activities (35,100) (38,205) -------- -------- Decrease in cash (894) (38) Cash at beginning of year 2,386 1,240 -------- -------- Cash at end of period $ 1,492 $ 1,202 ======== ========
The accompanying notes are an integral part of the financial statements. - 6 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, -------------------- -------------------- 2001 2000 2001 2000 -------- -------- -------- -------- ($ in thousands) ($ in thousands) Net income (loss) $ 6,869 $(64,199) $ 22,882 $(55,013) Other comprehensive income: Unrealized gain on derivative instruments 14,942 - 19,186 - -------- -------- -------- -------- Comprehensive Income (Loss) $ 21,811 $(64,199) $ 42,068 $(55,013) ======== ======== ======== ======== Reconciliation of Accumulated Other Comprehensive Income (Loss): Balance, Beginning of Period $(12,173) $ - $ - $ - Cumulative effect of adoption of SFAS No. 133 - - (36,963) - Current period reclassification to earnings 1,832 - 22,378 - Current period change in derivative instruments 14,942 - 19,186 - -------- -------- -------- -------- Balance, End of Period $ 4,601 $ - 4,601 $ - ======== ======== ======== ========
The accompanying notes are an integral part of the financial statements. - 7 - SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 2001 1. BASIS OF PRESENTATION The financial statements included herein are unaudited; however, such financial statements reflect 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 2000 Annual Report on Form 10-K, Item 8, Notes to Consolidated Financial Statements. 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 896,015 shares of common stock with a weighted average exercise price of $14.08 per share at June 30, 2001, and options for 2,052,933 shares with an average exercise price of $10.51 per share at June 30, 2000, that were not included in the calculation of diluted shares because they would have had an antidilutive effect. 3. UNUSUAL ITEMS In the second quarter of 2000, the Company recorded an unusual charge of $109.3 million for the adverse Hales judgment. 4. DIVIDEND PAYABLE As a result of the financial impact of the Hales judgment in the second quarter of 2000, the Company has indefinitely suspended payment of quarterly dividends on its common stock. 5. DERIVATIVE AND HEDGING ACTIVITIES Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS No. 137 and SFAS No. 138, was adopted by the Company on January 1, 2001. SFAS No. 133 requires that each derivative be recognized in the balance sheet as either an asset or liability measured at its -8- fair value. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a transition obligation of $60.6 million related to cash flow hedges that are intended to reduce the volatility in commodity prices for the Company's forecasted oil and gas production. At June 30, 2001, the Company recorded assets of $7.5 million related to its commodity cash flow hedges. Additionally, at June 30, 2001, the Company recorded net of tax cumulative income to other comprehensive income (equity section of the balance sheet) of $4.6 million. The amount recorded in other comprehensive income will be taken to the income statement as the physical transactions being hedged occur. Additional volatility in earnings and other comprehensive income may occur in the future as a result of the adoption of SFAS No. 133. 6. SEGMENT INFORMATION The Company applies SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The Company's reportable business segments have been identified based on the differences in products or services provided. Revenues for the exploration and production segment are derived from the production and sale of natural gas and crude oil. Revenues for the gas distribution segment arise from the transportation and sale of natural gas at retail. The marketing segment generates revenue through the marketing of both Company and third party produced gas volumes. Summarized financial information for the Company's reportable segments 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 June 30, 2001: Revenues from external customers $ 38,914 $ 19,586 $ 17,523 $ -- $ 76,023 Intersegment revenues 1,797 20 37,105 112 39,034 Operating income (loss) 18,272 (768) 444 67 18,015 Depreciation, depletion and amortization expense 11,039 1,557 16 25 12,637 Interest expense(1) 5,255 380 128 255 6,018 Provision (benefit) for income taxes(1) 4,921 (403) 123 (255) 4,386 Assets 498,862 151,300 13,415 32,238(2) 695,815(2) Capital expenditures 31,334(4) 1,260 17 65 32,676(4) -9- Exploration and Gas Production Distribution Marketing Other Total ----------- ------------ --------- ------- -------- (in thousands) Three months ended June 30, 2000: Revenues from external customers $ 19,799 $ 23,300 $ 35,384 $ -- $ 78,483 Intersegment revenues 4,986 26 15,412 112 20,536 Unusual items (109,288)(3) -- -- -- (109,288)(3) Operating income (loss) (101,660)(3) (692) 572 (69) (101,849)(3) Depreciation, depletion and amortization expense 9,522 1,687 17 25 11,251 Interest expense(1) 3,628 1,274 -- 272 5,174 Provision (benefit) for income taxes(1) (41,093) 429 226 (37) (40,475) Assets 455,957 148,275 18,319 34,681(2) 657,232(2) Capital expenditures 27,406 1,372 4 65 28,847 Six months ended June 30, 2001: Revenues from external customers $ 59,491 $100,949 $ 52,712 $ -- $213,152 Intersegment revenues 21,960 149 72,948 224 95,281 Operating income 40,260 8,630 1,587 137 50,614 Depreciation, depletion and amortization expense 21,085 3,108 33 48 24,274 Interest expense(1) 10,577 1,471 162 530 12,740 Provision (benefit) for income taxes(1) 11,422 3,000 556 (348) 14,630 Assets 498,862 151,300 13,415 32,238(2) 695,815(2) Capital expenditures 45,633(4) 2,169 17 171 47,990(4) Six months ended June 30, 2000: Revenues from external customers $ 33,514 $ 76,494 $ 65,388 $ -- $175,396 Intersegment revenues 16,032 80 28,653 224 44,989 Unusual items (109,288)(3) -- -- -- (109,288)(3) Operating income (loss) (92,972)(3) 10,678 1,537 (36) (80,793)(3) Depreciation, depletion and amortization expense 18,762 3,497 35 48 22,342 Interest expense(1) 6,866 2,527 -- 537 9,930 Provision (benefit) for income taxes(1) (39,191) 4,359 605 (375) (34,602) Assets 455,957 148,275 18,319 34,681(2) 657,232(2) Capital expenditures 40,517 2,652 4 231 43,404
(1) Interest expense and the provision (benefit) for income taxes by segment reflect an allocation of corporate amounts as debt and the provision (benefit) for income taxes are incurred at the corporate level. (2) Other assets includes the Company's equity investment in the operations of the NOARK Pipeline System, Limited Partnership, corporate assets not allocated to segments, and assets for non-reportable segments. (3) Includes a charge of $109.3 million in 2000 for the Hales judgment. Excluding this item, operating income for the exploration and production segment would have been $7.6 million and $16.3 million for the three and six month periods ended June 30, 2000, respectively. (4) Capital expenditures for the exploration and production segment for the three and six month periods ended June 30, 2001, include $3.9 million of expenditures funded by a minority interest partner. -10- Intersegment sales by the exploration and production segment and marketing segment to the gas distribution segment are priced in accordance with terms of existing contracts and current market conditions. Parent company assets include furniture and fixtures, prepaid debt costs and prepaid pension costs. Parent company general and administrative costs, depreciation expense and taxes other than income are allocated to segments. The exploration and production segment includes the consolidated amounts for a limited partnership in which the Company is the controlling partner. All of the Company's operations are located within the United States. 7. INTEREST AND INCOME TAXES PAID The following table provides interest and income taxes paid during each period presented.
Three Months Six Months Ended June 30, Ended June 30, ----------------- ----------------- 2001 2000 2001 2000 ----------------- ----------------- (in thousands) Interest payments $9,617 $9,465 $16,847 $10,071 Income tax payments $ -- $ 270 $ -- $ 270
8. MINORITY INTEREST IN PARTNERSHIP In the second quarter of 2001, the Company formed a limited partnership with an investor to drill and complete the first 14 development wells in the Company's Overton Field located in Smith County, Texas. Because Southwestern is the sole general partner and controls the partnership, the operating and financial results are included in the Company's exploration and production results and the investor's share of the partnership activity is reported as a minority interest item in the Company's financial statements. The Company will contribute 50% of the capital required to drill the first 14 wells. Revenues and expenses are allocated 65% to the Company prior to payout of the initial investment and 85% to the Company thereafter. 9. CONTINGENCIES AND COMMITMENTS The Company recently settled litigation in a case filed in a state court in Franklin County, Arkansas in 1996 against the Company and two of its subsidiaries related to overriding royalty interests on certain Arkansas oil and gas properties. In a Form 8-K filed in July 1996, the Company disclosed the lawsuit and that the plaintiff was seeking several million dollars in damages for failure to attach overrides dating back to 1939 to certain gas producing properties. The plaintiff subsequently expanded its claim alleging the underpayment of overriding royalties arising from contractual arrangements for the purchase and sale of natural gas between subsidiaries of the Company dating back to 1978. -11- This matter went to a non-jury trial as to the issue of liability in January 2000. The court issued Findings of Fact and Conclusions of Law that found no fraud was committed and that any overriding royalty interests subject to the plaintiff's claim for additional overriding royalties accrued after March 1, 1990. All claims prior to March 1, 1990 were barred by the statute of limitations. The damages phase of the trial was scheduled for June 2001 and the Company recently settled all outstanding issues in the case through mediation. The Company recorded a $2.0 million charge in the second quarter of 2001 related to the settlement. Also, in connection with the settlement, the Company purchased the plaintiff's overriding royalty interest in a group of the Company's Arkansas gas producing properties. The Company and the other general partner of NOARK have severally guaranteed the principal and interest payments on NOARK's 7.15% Notes due 2018. At June 30, 2001 and December 31, 2000, the principal outstanding for these Notes was $74.0 million and $75.0 million, respectively. The Company's share of the several guarantee is 60%. The Notes were issued in June 1998 and require semi-annual principal payments of $1.0 million. Under the several guarantee, the Company is required to fund its proportionate share of NOARK's debt service obligations if such obligations cannot be funded by operations of the pipeline. As a result of the integration of NOARK Pipeline with the Ozark Gas Transmission System, management of the Company believes that it will realize its investment in NOARK over the life of the integrated pipeline system. Therefore, no provision for any loss relating to the NOARK investment has been made in the accompanying financial statements. Additionally, the Company's gas distribution subsidiary has transportation contracts for firm capacity of 66.9 MMcfd on NOARK's integrated pipeline system. These contracts expire in 2002 and 2003, and are renewable on an annual basis thereafter unless terminated after 180 days' prior notice. The Company is subject to laws and regulations relating to the protection of the environment. The Company's policy is to accrue environmental and cleanup related costs of a noncapital nature when it is both probable that a liability has been incurred and the amount of such liability can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or reported results of operations of the Company. The Company is subject to other litigation and claims that have arisen in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such litigation and claims will not have a material effect on the financial position or reported results of operations of the Company. -12- 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, 2000, and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2001, and the comparable periods of 2000. RESULTS OF OPERATIONS Net income for the three months ended June 30, 2001 was $6.9 million, or $.27 per share, compared to a net loss of $64.2 million, or $2.57 per share, in 2000. The Company's results for the three months ended June 30, 2000, included an unusual charge of $109.3 million for the adverse judgment in the Hales royalty lawsuit ($66.7 million after-tax), an extraordinary loss on the early retirement of debt, and a $3.2 million gain from the sale of the Company's Missouri utility properties. Excluding these unusual and extraordinary items, Southwestern would have reported net income of $1.4 million, or $.05 per share, for the second quarter of 2000. Net income for the six months ended June 30, 2001, was $22.9 million, or $.91 of basic earnings per share ($.89 per share on a fully diluted basis), compared to a net loss for the six months ended June 30, 2000, of $55.0 million, or $2.20 per share. Excluding the unusual and extraordinary items discussed above, net income for the first six months of 2000 would have been $10.6 million, or $.42 per share. The increases in quarterly and year-to-date net income were due to improved operating results experienced by the exploration and production segment. This segment benefited from both increased production and higher commodity prices. Exploration and Production Overview The Company's exploration and production segment's revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas and oil, which are dependent upon numerous factors beyond its control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. -13-
Three Months Six Months Ended June 30, Ended June 30, -------------------- ------------------- 2001 2000 2001 2000 -------------------- ------------------- Revenues (in thousands) $40,711 $ 24,785 $81,451 $ 49,546 Operating income (loss) (in thousands) $18,272 $(101,660)(1) $40,260 $(92,972)(1) Gas production (MMcf) 8,653 7,924 16,678 15,700 Oil production (MBbls) 191 169 352 324 Total production (MMcfe) 9,799 8,938 18,790 17,644 Average gas price per Mcf $4.16 $2.64 $4.31 $2.63 Average oil price per Bbl $24.59 $22.54 $25.15 $22.78 Operating expenses per Mcfe Production expenses $0.44 $0.35 $0.48 $0.37 Production taxes $0.18 $0.15 $0.20 $0.14 General & administrative expenses $0.54(2) $0.35 $0.39(2) $0.31 Full cost pool amortization $1.10 $1.03 $1.09 $1.03
(1) Includes a charge of $109.3 million for the Hales judgment. Excluding this item, operating income for the exploration and production segment would have been $7.6 million and $16.3 million for the three and six month periods ended June 30, 2000, respectively. (2) Includes $2.0 million, or $.20 per Mcfe for the three months ended June 30, 2001 and $.11 per Mcfe for the six months ended June 30, 2001, for settled litigation. Revenues and Operating Income Revenues for the exploration and production segment were up 64% for both the three and six month periods ended June 30, 2001, compared to the same periods in 2000. The increases were due to both higher gas and oil prices and increased gas and oil production. Operating income, excluding unusual items, for the exploration and production segment was up $10.6 million for the three months ended June 30, 2001, and up $23.9 million for the first six months of 2001, both as compared to the same periods in 2000. The improvements in operating income were due to the higher segment revenues. Production Gas and oil production during the second quarter of 2001 was 9.8 billion cubic feet (Bcf) equivalent, up 10% from 8.9 Bcf equivalent for the same period in 2000. The increase in production primarily resulted from new wells added in 2000 and 2001 in the Company's Arkoma Basin and Gulf Coast operating areas. Gas production was 8.7 Bcf for the second quarter of 2001, compared to 7.9 Bcf for the same period in 2000. For the six months ended June 30, 2001, gas and oil production was 18.8 Bcf equivalent compared to 17.6 Bcf equivalent for the same period in 2000. Gas production was 16.7 Bcf for the first six months of 2001 compared to 15.7 in 2000. The Company's sales to its gas distribution systems were 3.1 Bcf during the six months ended -14- June 30, 2001, compared to 4.8 Bcf for the same period in 2000. The Company's oil production was 352 thousand barrels (MBbls) during the first six months of 2001, up from 324 MBbls for the same period of 2000. Commodity Prices The Company realized an average price of $4.16 per thousand cubic feet (Mcf) for its natural gas production for the three months ended June 30, 2001, up from $2.64 per Mcf for the same period of 2000. The average realized price for the six months ended June 30, 2001 was $4.31 compared to $2.63 for the same period in 2000. The Company hedged 14.1 Bcf of gas production in the first six months of 2001 primarily through zero-cost collars, which had the effect of reducing the average gas price by $.49 per Mcf in the second quarter of 2001 and by $1.57 per Mcf in the first half of 2001. On a comparative basis, the average realized price during the second quarter of 2000 was reduced by $.75 per Mcf and was reduced by $.41 per Mcf in the first half of 2000, due to the effect of commodity price hedges. Additionally, the Company receives monthly demand charges related to the no-notice service it makes available to the utility segment which increase the Company's average gas price. For the remainder of 2001, the Company has 12.7 Bcf of gas production hedged with collars having an average NYMEX floor price of $3.85 per Mcf and an average NYMEX ceiling price of $4.73 per Mcf. The Company also has 1.1 Bcf of gas production for the remainder of 2001 hedged with fixed price swaps at an average NYMEX price of $3.55 per Mcf. For the years 2002 and 2003 combined, the Company has 7.2 Bcf hedged under zero-cost collars and fixed-price swaps. See Part I, Item 3 of this Form 10-Q for additional information regarding the Company's commodity price risk hedging activities. The Company received an average price of $24.59 per barrel for its oil production during the three months ended June 30, 2001, up from $22.54 per barrel for the same period of 2000. For the six months ended June 30, 2001, the Company received an average price of $25.15 per barrel for its oil production, up from $22.78 per barrel for the same period of 2000. For the remainder of 2001, the Company has a collar on 150,000 barrels with an average floor of $27.40 per barrel, and an average ceiling of $29.95 per barrel, and a hedge on 36,000 barrels at an average NYMEX price of $17.49 per barrel. Operating Costs and Expenses Operating costs and expenses for the exploration and production segment increased in the second quarter and first six months of 2001 due to higher production related expenses, increased depreciation, depletion and amortization expense, and a $2.0 million charge included in general and administrative expense related to the settlement of litigation. The increase in operating expenses was due to increased production volumes, a higher level of workover expenses and an industry-wide increase in costs related to normal production activities. Additionally, increased severance and ad valorem taxes resulted from both increased production volumes and higher commodity prices. The Company anticipates that the inflationary increases in exploration and production related costs that have resulted from an overall increase in the activity level of the domestic oil and gas industry will continue in the near future. The increases in depreciation, -15- depletion and amortization expense were due to the increase in production and an increase in the amortization rate per unit of production. The full cost pool amortization rate for this segment averaged $1.10 per Mcf equivalent for the second quarter of 2001 and $1.09 for the first six months of 2001, compared to $1.03 per Mcf equivalent for the comparable periods of 2000. 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 June 30, 2001, 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 other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings. In the second quarter of 2001, the Company formed a limited partnership with an investor to drill and complete the first 14 development wells in the Company's Overton Field located in Smith County, Texas. This partnership was created to provide the capital necessary to accelerate the field's development. The Overton properties were acquired by the Company in April 2000 and have multiple development locations through the downspacing of the existing units. Because Southwestern is the sole general partner and controls the partnership, operating and financial results for the partnership are consolidated with the other operations of the Company and the investor's share of the partnership activity is reported as a minority interest item in the financial statements. During the second quarter of 2000, the Company recorded an unusual charge of $109.3 million resulting from the adverse judgment in the Hales litigation. Gas Distribution Overview The operating results of the Company's gas distribution segment are highly seasonal. This segment typically realizes operating losses in the second and third quarters of the year and realizes operating income during the winter heating season in the first and fourth quarters. The extent and duration of heating weather also impacts the profitability of this segment, although the Company has a weather normalization clause in its filed rate tariffs that lessens the impact of revenue increases and decreases which might result from weather variations during the winter heating season. The gas distribution segment's profitability is also dependent upon the timing and amount of regulatory rate increases that are filed with and approved by the Arkansas Public Service Commission. For periods subsequent to allowed rate increases, the Company's profitability is impacted by its ability to manage and control this segment's operating costs and expenses. -16-
Three Months Six Months Ended June 30, Ended June 30, --------------------- -------------------- 2001 2000 2001 2000 --------------------- -------------------- ($ in thousands, except for per Mcf amounts) Revenues $ 19,606 $ 23,326 $101,098 $ 76,574 Gas purchases $ 11,148 $ 12,948 $ 72,437 $ 43,258 Operating costs and expenses $ 9,226 $ 11,070 $ 20,031 $ 22,638 Operating income (loss) $ (768) $ (692) $ 8,630 $ 10,678 Deliveries (Bcf) Sales and end-use transportation 3.6 5.2 14.1 17.3 Off-system transportation 1.0 .5 1.0 2.1 Average number of customers 133,733 164,197 135,177 173,122 Average sales rate per Mcf $9.39 $6.85 $9.33 $5.84 Heating weather - degree days 166 293 2,327 1,982 - percent of normal 55% 96% 95% 81%
Note: Amounts and statistics for the three and six month periods ended June 30, 2000, include the operations of the Company's Missouri properties that were sold in May 2000. On May 31, 2000, the Company completed the sale of its Missouri gas distribution assets for $32.0 million. The sale resulted in a pre-tax gain of approximately $3.2 million and proceeds from the sale were used to pay down debt. As a result of the adverse Hales judgment, the Company's Board of Directors had authorized management to pursue the sale of the Company's remaining gas distribution operations. The Company has suspended the sale process as it did not result in an acceptable bid. Although the Company may decide to sell its gas distribution segment in the future, it currently plans to operate these assets as a continuing part of its business. Revenues and Operating Income Revenues for the three and six month periods ended June 30, 2001 are up from the comparable periods of 2000 primarily due to the cost of gas supply which has more than doubled when compared to the prior year periods. The high cost of gas supply is reflected in the Company's average rate for its utility sales which increased during the first six months of 2001 to $9.33 per Mcf, up from $5.84 per Mcf for the same period in 2000. The average sales rate for the second quarter of 2001 was $9.39 compared to $6.85 for the same period of 2000. The higher prices paid for purchases of natural gas are passed through to customers under automatic adjustment clauses. Operating income of the gas distribution segment decreased 11% in the second quarter of 2001 and decreased 19% in the first six months of 2001, as compared to the same periods of 2000. The -17- decreases in operating income were due to the impact of the sale of the Company's Missouri gas distribution assets in May 2000. Excluding the effects of the Missouri operations from 2000, operating results for the first six months of 2001 were approximately even with 2000 despite weather which was 5% warmer than normal and 17% colder than in the same period of 2000. This was primarily due to the Company's weather normalization clause in its rate tariffs. The weather normalization clause lessens the impacts of revenue increases and decreases that might result from weather variations during the winter heating season. Deliveries The utility systems delivered 3.6 Bcf to sales and end-use transportation customers during the second quarter of 2001, down from 5.2 Bcf for the same period in 2000. For the six months ended June 30, 2001, the utility systems delivered 14.1 Bcf to sales and end-use transportation customers, compared to 17.3 Bcf for the same period in 2000. The decrease in deliveries in the second quarter was due to warmer weather and the sale of the Missouri operations in May 2000. The decrease in deliveries for the first six months of 2001 was due to the sale of the Missouri properties, offset by increased deliveries due to colder weather. Excluding the effect of the Missouri operations from the three and six month periods ended June 30, 2000, deliveries to sales and end-use transportation customers were 4.4 Bcf and 13.7 Bcf, respectively. Operating Costs and Expenses The changes in purchased gas costs for the gas distribution segment reflect volumes purchased, prices paid for supplies, the mix of purchases from intercompany versus third party sources and the sale of the Missouri assets as discussed above. Other operating costs and expenses of the gas distribution segment for the three and six month periods ended June 30, 2001 were lower than the comparable periods of the prior year due primarily to the sale of the Missouri assets. Marketing and Other
Three Months Six Months Ended June 30, Ended June 30, ------------------ ------------------- 2001 2000 2001 2000 ------------------ ------------------- Marketing revenues (in thousands) $54,628 $50,796 $125,660 $94,041 Marketing operating income (in thousands) $444 $572 $1,587 $1,537 Gas volumes marketed (Bcf) 12.4 15.7 23.4 33.9
Marketing The increases in gas marketing revenues for the three and six month periods ended June 30, 2001, relate to a substantial increase in natural gas commodity prices from the prior year, and was largely offset by a comparable increase in purchased gas costs. Operating income for the marketing segment was $.4 million for the second quarter of 2001 and $1.6 million for the first six months of 2001, compared to $.6 million and $1.5 million for the comparable periods in 2000. -18- The Company marketed 12.4 Bcf of gas in the second quarter of 2001 and 23.4 Bcf in the first six months of 2001, compared to 15.7 Bcf and 33.9 Bcf for the same periods in 2000. The decreases in volumes marketed resulted from a planned decrease in volumes marketed for unaffiliated third parties. NOARK Pipeline The Company's share of the NOARK pre-tax loss included in other income was $.8 million for the first six months of 2001, compared to $1.1 million for the same period in 2000. Interest Expense Interest expense increased 16% for the second quarter of 2001 and 28% for the first six months of 2001, both as compared to the same periods in 2000, due to higher average borrowings caused by the payment of the Hales judgment in July 2000, and a lower level of capitalized interest. Interest is capitalized in the exploration and production segment on costs that are unevaluated and excluded from amortization. Income Taxes The changes in the provisions for current and deferred income taxes recorded in the three and six month periods ended June 30, 2001, as compared to the same periods in 2000, resulted primarily from the increase in the level of taxable income in 2001. Also impacting deferred taxes is 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. CHANGES IN FINANCIAL CONDITION Changes in the Company's financial condition at June 30, 2001, as compared to December 31, 2000, primarily reflect the seasonal nature of the Company's gas distribution segment and the effects of the adoption of SFAS No. 133 (See Note 5 to Consolidated Financial Statements in this Form 10-Q). Routine capital expenditures and scheduled debt retirements have predominantly been funded through cash provided by operations. For the first six months of 2001 and 2000, cash provided by operating activities was $84.4 and $50.6 million, respectively, and exceeded the total of these routine requirements. Financing Requirements In July 2001, the Company arranged a new unsecured revolving credit facility with a group of banks to replace the existing short-term credit facility. The short-term facility was put in place in July 2000 to fund the Hales judgment of $109.3 million, pay off the existing revolver balance and retire $22.0 million of private placement debt. The new revolving credit facility has a capacity of $160 million and a three-year term. The interest rate on the new facility is 137.5 basis points over the current London Interbank Offered Rate (LIBOR), and was 5.2% at June 30, 2001. The -19- new credit facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 75% of its total capital, must maintain a certain level of shareholders' equity, and the Company must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to fixed charges of at least 3.75 or higher through March 30, 2002. These covenants change over the term of the credit facility and generally become more restrictive. At June 30, 2001, the Company's revolving credit facility had a balance of $132.0 million and was classified as long-term debt in the Company's balance sheet. During the first six months of 2001, the Company's total debt decreased by $39.0 million, as increased cash flow generated from operations exceeded the Company's capital requirements. Total debt at June 30, 2001, accounted for 68% of the Company's capitalization, down from 74% at December 31, 2000. Excluding the effects of SFAS No. 133, the percentage of debt to total capitalization would have been 69% at June 30, 2001. The Company's capital expenditures for the first six months of 2001 were $48.0 million, compared to $43.4 million for the same period in 2000. The Company's reported capital investments include the gross expenditures of the Overton partnership. The minority interest partner in Overton funded $3.9 million of the Company's reported expenditures during the period. Additionally, the Company's capital expenditures during the second quarter of 2001 included $5.8 million to purchase overriding royalty interests in a group of the Company's Arkoma Basin properties. This acquisition was made in connection with the settlement of litigation. Planned capital investments during calendar year 2001 are currently expected to be approximately $100 million, including approximately $12 million which will be funded by the minority interest partner in Overton. At June 30, 2001, NOARK had outstanding debt totaling $74.0 million. The Company and the other general partner of NOARK have severally guaranteed the principal and interest payments on the NOARK debt. The Company's share of the several guarantee is 60%. Working Capital Accounts receivable have declined since December 31, 2000, due to the seasonal nature of the Company's gas distribution segment and a decrease in the amounts owed to the Company's exploration and production segment for oil and gas production due to lower commodity prices. Under-recovered purchased gas costs for the Company's gas distribution segment were $4.6 million at June 30, 2001, compared to $12.9 million at December 31, 2000. Purchased gas costs are recovered from the Company's utility customers in subsequent months through automatic cost of gas adjustment clauses included in the utility's filed rate tariffs. Inventories have increased due to the injection of gas into the Company's gas storage facilities. At June 30, 2001, the Company recorded a current hedging asset of $6.5 million and a current deferred income tax payable of $2.5 million under the provisions of SFAS No. 133. Accounts payable has decreased since December 31, 2000, due primarily to decreases in gas purchase costs in the gas distribution and marketing segments and to the timing of expenditures. -20- Other changes in current assets and current liabilities between periods resulted primarily from the timing of expenditures and receipts, and the sale of the Company's Missouri gas distribution assets in 2000. FORWARD LOOKING INFORMATION All statements, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for gas and oil, the timing and extent of the Company's success in discovering, developing, producing, and estimating reserves, property acquisition or divestiture activities that may occur, the effects of weather and regulation on the Company's gas distribution segment, increased competition, legal and economic factors, governmental regulation, the financial impact of accounting regulations for derivative instruments, changing market conditions, the comparative cost of alternative fuels, conditions in capital markets and changes in interest rates, availability of oil field services, drilling rigs and other equipment, as well as various other factors beyond the Company's control. A discussion of these and other factors affecting the Company's performance is included in the Company's periodic reports filed with the Securities and Exchange Commission including its Annual Report on Form 10-K for the year ended December 31, 2000. -21- 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 and interest rate swaps to reduce the volatility of earnings, cash flow and the cost of purchased gas due to fluctuations in the prices of natural gas and oil and fluctuations in interest rates. The Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price 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 4% of accounts receivable. See the discussion of commodities risk below. Interest Rate Risk The Company's revolving 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 June 30, 2001. Subsequent to June 30, 2001, the Company entered into an interest rate swap for calendar year 2002 that allows the Company to pay a fixed interest rate of 5.7% on $50 million of its outstanding revolving debt. The Company's revolving debt was $171.0 million at December 31, 2000, and had an average interest rate of 7.8%. At June 30, 2001, the Company's revolving debt was $132.0 million with an average interest rate of 5.2%. Other than the Company's revolving debt, there have been no material changes in the interest rate risk information that was presented in the Company's 2000 Form 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, activity in its marketing segment, and gas purchases in the utility segment against the inherent price risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX (New York Mercantile Exchange) futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps), and (3) the purchase and sale of index-related puts and calls (collars) that provide a "floor" price below which -22- the counterparty pays (production hedge) or receives (gas purchase hedge) funds equal to the amount by which the price of the commodity is below the contracted floor, and a "ceiling" price above which the Company pays to (production hedge) or receives from (gas purchase hedge) the counterparty the amount by which the price of the commodity is above the contracted ceiling. The primary market 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 or purchase 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 credit quality of each counterparty and the level of financial exposure the Company has to each counterparty are periodically reviewed to ensure limited credit risk exposure. The following table provides information about the Company's financial instruments that are sensitive to changes in commodity prices. The table presents the notional amount in Bcf (billion cubic feet) and MBbls (thousand barrels), the weighted average contract prices, and the total dollar contract amount by expected maturity dates. The "Carrying Amount" 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 June 30, 2001. At June 30, 2001, the "Fair Value" exceeded the "Carrying Amount" of these financial instruments by $7.5 million.
Expected Maturity Date -------------------------------------------------------- 2001 2002 2003 ---------------- ---------------- ---------------- Carrying Fair Carrying Fair Carrying Fair Amount Value Amount Value Amount Value -------- ----- -------- ----- -------- ----- Production and Marketing Natural Gas: Swaps with a fixed price receipt Contract volume (Bcf) 1.0 1.0 .2 Weighted average price per Mcf $3.48 $2.65 $2.75 Contract amount (in millions) $3.4 $3.6 $2.6 $1.7 $.6 $.4 Swaps with a fixed price payment Contract volume (Bcf) .1 - - Weighted average price per Mcf $4.41 - - Contract amount (in millions) $.6 $.4 - - - - -23- Expected Maturity Date -------------------------------------------------------- 2001 2002 2003 ---------------- ---------------- ---------------- Carrying Fair Carrying Fair Carrying Fair Amount Value Amount Value Amount Value -------- ----- -------- ----- -------- ----- Price collar Contract volume (Bcf) 12.7 6.0 - Weighted average floor price per Mcf $3.85 $4.00 - Contract amount of floor (in millions) $48.9 $58.9 $24.0 $29.1 - - Weighted average ceiling price per Mcf $4.73 $4.72 - Contract amount of ceiling (in millions) $60.1 $58.2 $28.3 $26.6 - - Oil: Swaps with a fixed price receipt Contract volume (MBbls) 36 - - Weighted average price per Bbl $17.49 - - Contract amount (in millions) $.6 $.3 - - - - Price collar Contract volume (MBbls) 150 - - Weighted average floor price Per Bbl $27.40 - - Contract amount of floor (in millions) $4.1 $4.5 - - - - Weighted average ceiling price Per Bbl $29.95 - - Contract amount of ceiling (in millions) $4.5 $4.4 - - - - Natural Gas Purchases Swaps with a fixed price payment Contract volume (Bcf) 1.1 2.4 - Weighted average price per Mcf $4.43 $4.49 - Contract amount (in millions) $4.7 $3.8 $10.9 $8.9 - -
-24- PART II OTHER INFORMATION Item 1 The Company recently settled litigation in a case filed in a state court in Franklin County, Arkansas in 1996 against the Company and two of its subsidiaries related to overriding royalty interests on certain Arkansas oil and gas properties. In a Form 8-K filed in July 1996, the Company disclosed the lawsuit and that the plaintiff was seeking several million dollars in damages for failure to attach overrides dating back to 1939 to certain gas producing properties. The plaintiff subsequently expanded its claim alleging the underpayment of overriding royalties arising from contractual arrangements for the purchase and sale of natural gas between subsidiaries of the Company dating back to 1978. This matter went to a non-jury trial as to the issue of liability in January 2000. The court issued Findings of Fact and Conclusions of Law that found no fraud was committed and that any overriding royalty interests subject to the plaintiff's claim for additional overriding royalties accrued after March 1, 1990. All claims prior to March 1, 1990 were barred by the statute of limitations. The damages phase of the trial was scheduled for June 2001 and the Company recently settled all outstanding issues in the case through mediation. The Company recorded a $2.0 million charge in the second quarter of 2001 related to the settlement. Also, in connection with the settlement, the Company purchased the plaintiff's overriding royalty interest in a group of the Company's Arkansas gas producing properties. Items 2 - 6(a) No developments required to be reported under Items 2 - 6(a) occurred during the quarter ended June 30, 2001. Item 6(b) On July 5, 2001, the Company filed a Form 8-K discussing the settlement of litigation involving overriding royalty interests. All other filings on Form 8-K during the quarter ended June 30, 2001 have been previously disclosed in the Company's Form 10-Q for the first quarter of 2001. -25- 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: August 10, 2001 /s/ GREG D. KERLEY -------------------- ----------------------------- Greg D. Kerley Executive Vice President and Chief Financial Officer -26- Southwestern Energy Company P.O. Box 1408 Fayetteville, AR 72702-1408 August 10, 2001 Securities and Exchange Commission ATTN: Filing Desk, Stop 1-4 450 Fifth Street, N.W. Washington, DC 20549-1004 Gentlemen: Pursuant to regulations of the Securities and Exchange Commission, submitted herewith for filing on behalf of Southwestern Energy Company is the Quarterly Report on Form 10-Q for the quarter ended June 30, 2001. This filing is being effected by direct transmission to the Commission's EDGAR System. Very truly yours, Stan Wilson Controller