10-Q 1 march10qfy03.txt MARCH 31, 2003 FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q For the quarterly period ended March 31, 2003 Commission File No. 1-6407 SOUTHERN UNION COMPANY (Exact name of registrant as specified in its charter) Delaware 75-0571592 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) One PEI Center, Second Floor 18711 Wilkes-Barre, Pennsylvania (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: (570) 820-2400 Securities Registered Pursuant to Section 12(b) of the Act: Title of each class Name of each exchange in which registered ------------------- ----------------------------------------- Common Stock, par value $1 per share New York Stock Exchange Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No ----- --------- The number of shares of the registrant's Common Stock outstanding on May 9, 2003 was 55,621,093. -------------------------------------------------------------------------------- SOUTHERN UNION COMPANY AND SUBSIDIARIES FORM 10-Q March 31, 2003 Index
PART I. FINANCIAL INFORMATION Page(s) ------- Item 1. Financial Statements: Consolidated statements of operations - three, nine and twelve months ended March 31, 2003 and 2002 2-4 Consolidated balance sheet - March 31, 2003 and 2002 and June 30, 2002 5-6 Consolidated statement of stockholders' equity - nine months ended March 31, 2003 and twelve months ended June 30, 2002 7 Consolidated statements of cash flows - three, nine and twelve months ended March 31, 2003 and 2002 8-10 Notes to consolidated financial statements 11-22 Item 2. Management's Discussion and Analysis of Financial Condition and Results 23-33 of Operations Item 3. Quantitative and Qualitative Disclosures about Market Risk 32 Item 4. Controls and Procedures 33 PART II. OTHER INFORMATION Item 1. Legal Proceedings (See "COMMITMENTS AND CONTINGENCIES" in Notes to Consolidated Financial Statements) 19-22 Item 6. Exhibits and Reports on Form 8-K 34
SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS
Three Months Ended March 31, 2003 2002 ------------- ------------ (thousands of dollars, except shares and per share amounts) Operating revenues ........................................... $ 535,663 $ 419,599 Cost of gas and other energy ................................. (356,393) (260,853) Revenue-related taxes ........................................ (17,870) (15,116) ------------ ------------ Operating margin ........................................ 161,400 143,630 Operating expenses: Operating, maintenance and general ...................... 48,203 43,152 Depreciation and amortization ........................... 14,621 14,061 Taxes, other than on income and revenues ................ 6,434 5,560 ------------ ------------ Total operating expenses ............................ 69,258 62,773 ------------ ------------ Net operating revenues .............................. 92,142 80,857 ------------ ------------ Other income (expense): Interest ................................................ (19,840) (21,723) Dividends on preferred securities of subsidiary trust ... (2,370) (2,370) Other, net .............................................. 5,223 3,713 ------------ ------------ Total other expenses, net ........................... (16,987) (20,380) ------------ ------------ Earnings from continuing operations before income taxes ...... 75,155 60,477 Federal and state income taxes ............................... 28,921 21,578 ------------ ------------ Net earnings from continuing operations ...................... 46,234 38,899 ------------ ------------ Discontinued operations: Earnings from discontinued operations before income taxes 62,992 14,620 Federal and state income taxes .......................... 45,327 9,731 ------------ ------------ Net earnings from discontinued operations .................... 17,665 4,889 ------------ ------------ Net earnings available for common stock ...................... $ 63,899 $ 43,788 ============ ============ Net earnings from continuing operations per share: Basic ................................................... $ .85 $ .73 ============ ============ Diluted ................................................. $ .83 $ .69 ============ ============ Net earnings available for common stock per share: Basic ................................................... $ 1.18 $ .82 ============ ============ Diluted ................................................. $ 1.14 $ .78 ============ ============ Weighted average shares outstanding: Basic ................................................... 54,344,794 53,447,791 ============ ============ Diluted ................................................. 56,041,342 56,263,243 ============ ============
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS
Nine Months Ended March 31, 2003 2002 ------------- ------------ (thousands of dollars, except shares and per share amounts) Operating revenues ........................................... $ 981,477 $ 826,897 Cost of gas and other energy ................................. (613,958) (494,587) Revenue-related taxes ........................................ (33,624) (28,649) ------------ ------------ Operating margin ........................................ 333,895 303,661 Operating expenses: Operating, maintenance and general ...................... 131,823 127,488 Business restructuring charges .......................... -- 30,553 Depreciation and amortization ........................... 43,072 44,120 Taxes, other than on income and revenues ................ 19,145 18,691 ------------ ------------ Total operating expenses ............................ 194,040 220,852 ------------ ------------ Net operating revenues .............................. 139,855 82,809 ------------ ------------ Other income (expense): Interest ................................................ (61,583) (70,444) Dividends on preferred securities of subsidiary trust ... (7,110) (7,110) Other, net .............................................. 18,949 26,354 ------------ ------------ Total other expenses, net ........................... (49,744) (51,200) ------------ ------------ Earnings from continuing operations before income taxes ...... 90,111 31,609 Federal and state income taxes ............................... 34,544 15,062 ------------ ------------ Net earnings from continuing operations ...................... 55,567 16,547 ------------ ------------ Discontinued operations: Earnings from discontinued operations before income taxes 84,773 28,364 Federal and state income taxes .......................... 53,517 11,776 ------------ ------------ Net earnings from discontinued operations .................... 31,256 16,588 ------------ ------------ Net earnings available for common stock ...................... $ 86,823 $ 33,135 ============ ============ Net earnings from continuing operations per share: Basic ................................................... $ 1.03 $ .31 ============ ============ Diluted ................................................. $ .99 $ .29 ============ ============ Net earnings available for common stock per share: Basic ................................................... $ 1.60 $ .61 ============ ============ Diluted ................................................. $ 1.55 $ .58 ============ ============ Weighted average shares outstanding: Basic ................................................... 54,120,204 53,944,420 ============ ============ Diluted ................................................. 55,903,939 57,002,247 ============ ============
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS
Twelve Months Ended March 31, 2003 2002 ------------- ------------ (thousands of dollars, except shares and per share amounts) Operating revenues ........................................... $ 1,135,194 $ 1,026,451 Cost of gas and other energy ................................. (692,448) (621,126) Revenue-related taxes ........................................ (38,384) (33,336) ------------ ------------ Operating margin ........................................ 404,362 371,989 Operating expenses: Operating, maintenance and general ...................... 175,482 182,085 Business restructuring charges .......................... (1,394) 30,553 Depreciation and amortization ........................... 57,941 62,310 Taxes, other than on income and revenues ................ 24,162 25,621 ------------ ------------ Total operating expenses ............................ 256,191 300,569 ------------ ------------ Net operating revenues .............................. 148,171 71,420 ------------ ------------ Other income (expense): Interest ................................................ (82,131) (98,020) Dividends on preferred securities of subsidiary trust ... (9,480) (9,480) Other, net .............................................. 6,873 79,391 ------------ ------------ Total other expenses, net ........................... (84,738) (28,109) ------------ ------------ Earnings from continuing operations before income taxes ...... 63,433 43,311 Federal and state income taxes ............................... 22,893 19,159 ------------ ------------ Net earnings from continuing operations ...................... 40,540 24,152 ------------ ------------ Discontinued operations: Earnings from discontinued operations before income taxes 86,210 29,008 Federal and state income taxes .......................... 53,438 8,890 ------------ ------------ Net earnings from discontinued operations .................... 32,772 20,118 ------------ ------------ Net earnings available for common stock ...................... $ 73,312 $ 44,270 ============ ============ Net earnings from continuing operations per share: Basic ................................................... $ .75 $ .45 ============ ============ Diluted ................................................. $ .72 $ .42 ============ ============ Net earnings available for common stock per share: Basic ................................................... $ 1.36 $ .82 ============ ============ Diluted ................................................. $ 1.31 $ .77 ============ ============ Weighted average shares outstanding: Basic ................................................... 54,018,957 54,220,213 ============ ============ Diluted ................................................. 55,933,809 57,276,163 ============ ============
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET ASSETS
March 31, June 30, 2003 2002 2002 ----------- ----------- ----------- (thousands of dollars) Property, plant and equipment: Plant in service ............................. $ 1,787,434 $ 1,744,482 $ 1,767,349 Construction work in progress ................ 20,702 19,418 6,535 ----------- ----------- ----------- 1,808,136 1,763,900 1,773,884 Less accumulated depreciation and amortization (630,654) (598,824) (604,114) ----------- ----------- ----------- Net property, plant and equipment ....... 1,177,482 1,165,076 1,169,770 ----------- ----------- ----------- Current assets: Cash and cash equivalents .................... 408,772 9,844 -- Accounts receivable, billed and unbilled, net 302,764 202,886 95,036 Inventories, principally at average cost ..... 24,936 80,677 101,076 Deferred gas purchase costs .................. 16,041 3,727 3,597 Investment securities available for sale ..... 505 4,339 1,163 Prepayments and other ........................ 8,809 11,203 13,527 Assets held for sale ......................... -- 418,418 395,446 ----------- ----------- ----------- Total current assets .................... 761,827 731,094 609,845 ----------- ----------- ----------- Goodwill, net ..................................... 642,921 642,921 642,921 Deferred charges .................................. 200,078 220,634 206,130 Investment securities, at cost .................... 9,786 19,227 9,786 Other ............................................. 44,009 44,092 41,612 ----------- ----------- ----------- Total assets ................................. $ 2,836,103 $ 2,823,044 $ 2,680,064 =========== =========== ===========
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Continued) STOCKHOLDERS' EQUITY AND LIABILITIES
March 31, June 30, 2003 2002 2002 ------------ ------------ ----------- (thousands of dollars) Common stockholders' equity: Common stock, $1 par value; authorized 200,000,000 shares; issued 58,681,205 shares ........................ $ 58,681 $ 54,844 $ 58,055 Premium on capital stock .................................... 710,645 679,347 707,912 Less treasury stock, 3,125,993 shares at cost ............... (57,186) (50,752) (57,673) Less common stock held in trust ............................. (17,623) (19,878) (17,821) Deferred compensation plans ................................. 9,591 9,201 9,373 Accumulated other comprehensive income (loss) ............... (12,564) (2,042) (14,500) Retained earnings ........................................... 86,823 38,238 -- ----------- ----------- ----------- Total common stockholders' equity ........................... 778,367 708,958 685,346 Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely subordinated notes of Southern Union ..................................... 100,000 100,000 100,000 Long-term debt and capital lease obligation ...................... 1,006,366 799,717 1,082,210 ----------- ----------- ----------- Total capitalization .................................... 1,884,733 1,608,675 1,867,556 Current liabilities: Long-term debt and capital lease obligation due within one year ................................................ 75,851 451,852 108,203 Notes payable ............................................... 209,800 132,300 131,800 Accounts payable ............................................ 132,739 97,254 71,343 Federal, state and local taxes .............................. 32,506 60,829 9,212 Accrued interest ............................................ 16,033 17,676 17,019 Accrued dividends on preferred securities of subsidiary trust -- 2,370 2,370 Customer deposits ........................................... 6,804 7,773 7,572 Other ....................................................... 60,941 48,506 38,686 Liabilities related to assets held for sale ................. -- 74,003 67,718 ----------- ----------- ----------- Total current liabilities ............................... 534,674 892,563 453,923 ----------- ----------- ----------- Deferred credits and other ....................................... 133,990 124,964 141,933 Accumulated deferred income taxes ................................ 282,706 196,842 216,652 ----------- ----------- ----------- Total stockholders' equity and liabilities .................. $ 2,836,103 $ 2,823,044 $ 2,680,064 =========== =========== ===========
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Common Accumulated Common Premium Treasury Stock Other Stock,$1 on Capital Stock, at Held in Comprehen- Retained Par Value Stock Cost Trust sive Income Earnings Total ---------- ----------- --------- -------- ----------- ---------- --------- (thousands of dollars) Balance July 1, 2001................... $ 54,553 $ 676,324 $ (15,869) $ (11,697) $ 13,443 $ 5,103 $ 721,857 Comprehensive income: Net earnings...................... -- -- -- -- -- 19,624 19,624 Unrealized loss in investment securities, net of tax benefit.. -- -- -- -- (18,249) -- (18,249) Minimum pension liability adjustment, net of tax benefit.. -- -- -- -- (10,498) -- (10,498) Unrealized gain on hedging activities, net of tax.......... -- -- -- -- 804 -- 804 --------- Comprehensive income (loss)....... (8,319) --------- Payment on note receivable.......... -- 202 -- -- -- -- 202 Purchase of treasury stock.......... -- -- (41,632) -- -- -- (41,632) 5% stock dividend................... 2,618 22,091 -- -- -- (24,727) (18) Stock compensation plan............. -- 1,248 -- 1,257 -- -- 2,505 Sale of common stock held in trust.......................... -- 26 -- 1,945 -- -- 1,971 Exercise of stock options........... 884 8,021 (172) 47 -- -- 8,780 ---------- ----------- ---------- ---------- ---------- ---------- ------------ Balance June 30, 2002.................. 58,055 707,912 (57,673) (8,448) (14,500) -- 685,346 Comprehensive income: Net earnings...................... -- -- -- -- -- 86,823 86,823 Unrealized loss in investment securities, net of tax benefit.. -- -- -- -- (428) -- (428) Net unrealized loss on hedging activities, net of tax benefit.. -- -- -- -- (1,814) -- (1,814) Minimum pension liability adjustment, net of tax.......... -- -- -- -- 4,178 -- 4,178 --------- Comprehensive income.............. 88,759 --------- Stock compensation plan............. -- 480 -- 737 -- -- 1,217 Exercise of stock options........... 626 2,253 487 (321) -- -- 3,045 ---------- ---------- ----------- ---------- ---------- ---------- ----------- Balance March 31, 2003................. $ 58,681 $ 710,645 $ (57,186) $(8,032) $(12,564) $ 86,823 $ 778,367 ========== ========== =========== ========== ========== ========== =========== -------------------------------
The Company's common stock is $1 par value. Therefore, the change in Common Stock, $1 Par Value is equivalent to the change in the number of shares of common stock outstanding. See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS
Three Months Ended March 31, 2003 2002 ---------- ----------- (thousands of dollars) Cash flows from (used in) operating activities: Net earnings .............................................................. $ 63,899 $ 43,788 Adjustments to reconcile net earnings to net cash flows from (used in) operating activities: Depreciation and amortization ......................................... 14,621 14,061 Deferred income taxes ................................................. 68,521 4,202 Provision for bad debts ............................................... 2,634 5,259 Gain on sale of subsidiaries .......................................... (62,992) -- Financial derivative trading gains .................................... (151) (3,776) Net cash provided by assets held for sale ............................. -- 42,716 Other ................................................................. 993 1,128 Changes in operating assets and liabilities, net of dispositions: Accounts receivable, billed and unbilled .......................... (61,861) (45,458) Accounts payable .................................................. 3,760 3,933 Customer deposits ................................................. (90) 175 Deferred gas purchase costs ....................................... (3,257) 22,996 Inventories ....................................................... 82,403 75,204 Deferred charges and credits ...................................... (15,621) (6,728) Prepaids and other current assets ................................. (1,544) (717) Taxes and other current liabilities ............................... 14,995 33,798 --------- --------- Net cash flows from operating activities ................................ 106,310 190,581 --------- --------- Cash flows from (used in) investing activities: Additions to property, plant and equipment ................................ (11,512) (11,272) Changes in assets and liabilities held for sale ........................... -- (8,635) Proceeds from sale of subsidiaries ........................................ 420,000 -- Customer advances ......................................................... 59 (1,227) Other ..................................................................... -- (384) --------- --------- Net cash flows from (used in) investing activities ...................... 408,547 (21,518) --------- --------- Cash flows from (used in) financing activities: Issuance cost of debt ..................................................... (260) (98) Repayment of debt and capital lease obligation ............................ (26,229) (78,169) Net payments under revolving credit facilities ............................ (80,200) (82,650) Proceeds from exercise of stock options ................................... 604 1,698 --------- --------- Net cash flows used in financing activities ............................. (106,085) (159,219) --------- --------- Change in cash and cash equivalents .......................................... 408,772 9,844 Cash and cash equivalents at beginning of period ............................. -- -- --------- --------- Cash and cash equivalents at end of period ................................... $ 408,772 $ 9,844 ========= ========= Supplemental disclosures of cash flow information: Cash paid during the period for: Interest ................................................................ $ 21,940 $ 19,459 ========= ========= Income taxes ............................................................ $ 2,126 $ 90 ========= =========
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS
Nine Months Ended March 31, 2003 2002 ------------ ----------- (thousands of dollars) Cash flows from (used in) operating activities: Net earnings ................................................................ $ 86,823 $ 33,135 Adjustments to reconcile net earnings (loss) to net cash flows from (used in) operating activities: Depreciation and amortization ........................................... 43,072 44,120 Deferred income taxes ................................................... 67,401 7,224 Provision for bad debts ................................................. 9,031 10,738 Business restructuring charges .......................................... -- 27,247 Gain on settlement of interest rate swaps ............................... -- (17,166) Gain on sale of subsidiaries and other assets ........................... (62,992) (5,214) Loss on sale of subsidiaries ............................................ -- 1,500 Financial derivative trading gains ...................................... (454) (6,109) Net cash provided by (used in) assets held for sale ..................... (23,698) 31,468 Other ................................................................... 3,117 1,899 Changes in operating assets and liabilities, net of dispositions: Accounts receivable, billed and unbilled ............................ (190,027) (37,148) Accounts payable .................................................... 61,207 12,629 Customer deposits ................................................... (768) 142 Deferred gas purchase costs ......................................... (12,444) 53,306 Inventories ......................................................... 76,140 21,443 Deferred charges and credits ........................................ (11,422) (1,815) Prepaids and other current assets ................................... 2,640 (327) Taxes and other liabilities ......................................... 40,688 30,467 --------- --------- Net cash flows from operating activities .................................. 88,314 207,539 --------- --------- Cash flows from (used in) investing activities: Additions to property, plant and equipment .................................. (49,618) (57,558) Changes in assets and liabilities held for sale ............................. (13,410) (19,578) Notes receivable ............................................................... (6,750) -- Proceeds from sale of subsidiaries and other assets ......................... 420,000 38,635 Customer advances ........................................................... 677 (1,510) Proceeds from settlement of interest rate swaps ............................. -- 17,166 Other ....................................................................... (1,664) (691) --------- --------- Net cash flows from (used in) investing activities ........................ 349,235 (23,536) --------- --------- Cash flows from (used in) financing activities: Issuance of long-term debt .................................................. 311,087 -- Issuance cost of debt ....................................................... (1,627) (617) Repayment of debt and capital lease obligation .............................. (419,283) (83,974) Net (payments) borrowings under revolving credit facilities ................. 78,000 (58,300) Purchase of treasury stock .................................................. -- (34,711) Proceeds from exercise of stock options ..................................... 3,046 2,224 --------- --------- Net cash flows used in financing activities ................................. (28,777) (175,378) --------- --------- Change in cash and cash equivalents ............................................ 408,772 8,625 Cash and cash equivalents at beginning of period ............................... -- 1,219 --------- --------- Cash and cash equivalents at end of period ..................................... $ 408,772 $ 9,844 ========= ========= Supplemental disclosures of cash flow information: Cash paid during the period for: Interest .................................................................. $ 70,101 $ 75,789 ========= ========= Income taxes .............................................................. $ 2,003 $ 90 ========= =========
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS
Twelve Months Ended March 31, 2003 2002 ---------- --------- (thousands of dollars) Cash flows from (used in) operating activities: Net earnings .............................................................. $ 73,312 $ 44,270 Adjustments to reconcile net earnings to net cash flows from (used in) operating activities: Depreciation and amortization ......................................... 57,941 62,310 Deferred income taxes ................................................. 88,574 36,564 Provision for bad debts ............................................... 10,552 24,103 Provision for investment impairment ................................... 10,380 -- Business restructuring charges ........................................ (2,807) 27,247 Gain on settlement of interest rate swaps ............................. -- (17,166) Gain on sale of subsidiaries and other assets ......................... (64,192) (5,921) Loss on sale of subsidiaries .......................................... -- 1,500 Financial derivative trading gains .................................... (548) (2,749) Gain on sale of investment securities ................................. (1,004) (53,219) Net cash provided by (used in) assets held for sale ................... (6,548) 46,986 Other ................................................................. 5,512 2,866 Changes in operating assets and liabilities, net of dispositions: Accounts receivable, billed and unbilled .......................... (80,946) 154,440 Accounts payable .................................................. 36,613 (96,800) Customer deposits ................................................. (963) (355) Deferred gas purchase costs ....................................... (12,314) 89,143 Inventories ....................................................... 55,741 (44,820) Deferred charges and credits ...................................... 7,197 (3,134) Prepaids and other current assets ................................. (768) (1,416) Taxes and other liabilities ....................................... (21,341) (21,765) --------- --------- Net cash flows from operating activities ................................ 154,391 242,084 --------- --------- Cash flows from (used in) investing activities: Additions to property, plant and equipment ................................ (62,758) (91,443) Changes in assets and liabilities held for sale ........................... (17,047) (22,013) Acquisition of operations, net of cash received ........................... -- (7,720) Purchase of investment securities ......................................... (938) (135) Notes receivable .......................................................... (9,500) -- Proceeds from sale of subsidiaries and other assets ....................... 422,300 41,935 Proceeds from sale of investment securities ............................... 1,213 59,180 Customer advances ......................................................... 1,784 (1,018) Proceeds from settlement of interest rate swaps ........................... -- 17,166 Other ..................................................................... (1,509) (236) --------- --------- Net cash flows from (used in) investing activities ...................... 333,545 (4,284) --------- --------- Cash flows from (used in) financing activities: Issuance of long-term debt ................................................ 311,087 -- Issuance cost of debt ..................................................... (1,931) (1,553) Repayment of debt and capital lease obligation ............................ (480,440) (122,466) Net (payments) borrowings under revolving credit facilities ............... 77,500 (79,300) Purchase of treasury stock ................................................ (6,434) (34,711) Proceeds from exercise of stock options ................................... 8,884 -- Other ..................................................................... 2,326 1,908 --------- --------- Net cash flows used in financing activities ............................. (89,008) (236,122) --------- --------- Change in cash and cash equivalents .......................................... 398,928 1,678 Cash and cash equivalents at beginning of period ............................. 9,844 8,166 --------- --------- Cash and cash equivalents at end of period ................................... $ 408,772 $ 9,844 ========= ========= Supplemental disclosures of cash flow information: Cash paid (refunded) during the period for: Interest ................................................................ $ 93,481 $ 103,062 ========= ========= Income taxes ............................................................ $ (2,301) $ 16,948 ========= =========
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FINANCIAL STATEMENTS These interim financial statements should be read in conjunction with the financial statements and notes thereto contained in Southern Union Company's (Southern Union and, together with its wholly-owned subsidiaries, the Company) Annual Report on Form 10-K for the fiscal year ended June 30, 2002, as updated by the Company's Current Report on Form 8-K dated March 10, 2003 to reflect discontinued operations due to the sale of the Southern Union Gas Company (Southern Union Gas) natural gas operating division and related assets (as described below). All dollar amounts in the tables herein, except per share amounts, are stated in thousands unless otherwise indicated. Certain prior period amounts have been reclassified to conform with the current period presentation. These interim financial statements are unaudited but, in the opinion of management, reflect all adjustments (including both normal recurring as well as any non-recurring) necessary for a fair presentation of the results of operations for such periods. As further described below, the Company completed the sale of its Southern Union Gas division and related assets effective January 1, 2003. In accordance with the Financial Accounting Standards Board (FASB) standard, Accounting for the Impairment or Disposal of Long-Lived Assets, the assets and liabilities sold have been segregated and reported as "held for sale" in the Consolidated Balance Sheet as of March 31, 2002 and June 30, 2002, and the related results of operations and gain on sale have been segregated and reported as "discontinued operations" in the Consolidated Statement of Operations and the Consolidated Statement of Cash Flows for all periods presented in this Quarterly Report on Form 10-Q. Because of the seasonal nature of the Company's operations, the results of operations and cash flows for any interim period are not necessarily indicative of results for the full year. SIGNIFICANT ACCOUNTING POLICIES Effective July 1, 2002, the Company adopted the FASB standard, Accounting for Asset Retirement Obligations, which requires the fair value of a liability for an asset retirement legal obligation to be recognized in the period in which it is incurred and when the amount of the liability can be reasonably estimated. When the liability is initially recorded, associated costs are capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. In certain rate jurisdictions, the Company is permitted to include annual charges for cost of removal in its regulated cost of service rates charged to customers. The adoption of the Statement did not have a material impact on the Company's financial position, results of operations or cash flows for all periods presented. Also effective July 1, 2002, the Company adopted the FASB standard, Accounting for the Impairment or Disposal of Long-Lived Assets. The Statement provides new guidance on the recognition of impairment losses on long-lived assets to be held and used or to be disposed of and also broadens the definition of what constitutes a discontinued operation and how the results of a discontinued operation are to be measured and presented. Under the Statement, assets held for sale that are a component of an entity will be included in discontinued operations if the operations and cash flows will be or have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the operations prospectively. The Statement is not expected to materially change the methods the Company uses to measure impairment losses on long-lived assets, but will result in additional future dispositions being reported as discontinued operations than was previously permitted. In December 2002, the FASB issued Accounting for Stock-Based Compensation - Transition and Disclosure. The Statement amends the previous standard, Accounting for Stock-Based Compensation, to provide alternative methods of transition for an entity that voluntarily changes to a fair value based method of accounting for stock-based employee compensation and amends disclosure provisions of that standard to require prominent disclosure about the effects on reported net income of an entity's accounting policy decisions with respect to such compensation. The Company expects to continue to account for stock-based compensation in accordance with Accounting Principles Board opinion, Accounting for Stock Issued to Employees, and will provide the prominent disclosures required in its annual and future interim financial statements. In April 2003, the FASB issued Amendment of Statement 133 on Derivative Instruments and Hedging Activities. The Statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under the FASB standard Accounting for Derivative Instruments and Hedging Activities. The Statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Statement is not expected to materially change the methods the Company uses to account for and report its derivatives and hedging activities. In November 2002, the FASB issued Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Guarantees of Indebtedness of Others. The Interpretation expands the existing disclosure requirements for guarantees and requires that companies recognize, at the inception of a guarantee, a liability for the fair value of the obligations undertaken when issuing the guarantee. The initial recognition and initial measurement provisions of the Interpretation are effective for guarantees issued or modified after December 31, 2002. The Interpretation is not expected to have a material impact on the Company's financial position, results of operations or cash flows. PENDING ACQUISITIONS On December 21, 2002, the Company and AIG Highstar Capital, L.P. (AIG Highstar), a private equity fund sponsored by American International Group, Inc., reached a definitive agreement (the Stock Purchase Agreement) with CMS Gas Transmission Company, a subsidiary of CMS Energy Corporation (CMS), to acquire Panhandle Eastern Pipe Line Company and its subsidiaries (Panhandle). On May 12, 2003, the Company, CMS and AIG Highstar agreed to: (1) terminate AIG Highstar's participation in the acquisition of Panhandle, (2) amend the Stock Purchase Agreement so that AIG Highstar is no longer a party, and (3) enter into a mutual release with respect to obligations relating to the Stock Purchase Agreement. Accordingly, on the same day, the Company and CMS amended the Stock Purchase Agreement to reduce the purchase price by $37.5 million to approximately $1.79 billion. Under the amended agreement, Southern Union, as the sole purchaser of Panhandle, will pay approximately $584.3 million in cash plus three million shares of Southern Union common stock, and will assume approximately $1.166 billion of Panhandle debt. The amended transaction has been approved by the boards of directors of both parties and will close following clearance by the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvement Act. This acquisition will be funded in part by proceeds received from the Company's January 2003 sale of Southern Union Gas and related assets discussed below. The Panhandle entities include CMS Panhandle Eastern Pipe Line Company, CMS Trunkline Gas Company, CMS Trunkline LNG Company and CMS Sea Robin Pipeline Company. The Panhandle entities operate approximately 11,000 miles of mainline natural gas pipeline extending from the Gulf of Mexico to the Midwest and Canada. These pipelines access the major natural gas supply regions of the Louisiana and Texas Gulf Coasts as well as the Midcontinent and Rocky Mountains. The pipelines have a combined peak day delivery capacity of 5.4 billion cubic feet per day, 88 billion cubic feet of underground storage capacity and 6.3 billion cubic feet of above ground LNG storage facilities. CMS Trunkline LNG Company operates an LNG terminal complex at Lake Charles, La. DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE Effective January 1, 2003, the Company completed the sale of its Southern Union Gas natural gas operating division and related assets to ONEOK, Inc. ("ONEOK") for approximately $420,000,000 in cash, subject to working capital adjustment, resulting in a pre-tax gain of $62,992,000 that is included in earnings from discontinued operations in the Consolidated Statement of Operations for the three-, nine- and twelve-month periods ended March 31, 2003. In addition to Southern Union Gas, the sale involved the disposition of Mercado Gas Services, Inc. (Mercado), SUPro Energy Company (SUPro), Southern Transmission Company (STC), Southern Union Energy International, Inc. (SUEI), Southern Union International Investments, Inc. (Investments) and Norteno Pipeline Company (Norteno) (collectively, the Texas Operations). Southern Union Gas distributes natural gas as a public utility to approximately 535,000 customers throughout Texas, including the cities of Austin, El Paso, Brownsville, Galveston and Port Arthur. Mercado markets natural gas to commercial and industrial customers. SUPro provides propane gas services to approximately 4,000 customers located principally in Austin, El Paso and Alpine, Texas as well as Las Cruces, New Mexico and surrounding communities. STC owns and operates 118.8 miles of intrastate pipeline that serves commercial, industrial and utility customers in central, southern and coastal Texas. SUEI and Investments participate in energy-related projects internationally. Energia Estrella del Sur, S. A. de C. V., a wholly-owned Mexican subsidiary of SUEI and Investments, has a 43% equity ownership in a natural gas distribution company, along with other related operations, which currently serves 23,000 customers in Piedras Negras, Mexico, across the border from Southern Union Gas' Eagle Pass, Texas service area. Norteno owns and operates interstate pipelines that serve the gas distribution properties of Southern Union Gas and the Public Service Company of New Mexico. Norteno also transports gas through its interstate network to the country of Mexico for Pemex Gas y Petroquimica Basica. The Company plans to re-deploy substantially all the sales proceeds towards its pending acquisition of Panhandle. The Company anticipates that the sale and reinvestment will qualify as part of a like-kind exchange of property covered by Section 1031 of the Internal Revenue Code thereby enabling the Company to achieve certain tax deferrals. Accordingly, as of March 31, 2003, approximately $406,000,000 of the sales proceeds has been temporarily invested through a Qualified Intermediary, as defined by Section 1031, pending the completion of the acquisition and like-kind exchange, and approximately $92,500,000 of related income taxes has been reflected as accumulated deferred income taxes on the Condensed Consolidated Balance Sheet. The following table summarizes the Texas Operations' assets and liabilities sold, effective January 1, 2003, and reported as "held for sale" in the Company's Consolidated Balance Sheet as of March 31, 2002 and June 30, 2002:
January 1, March 31, June 30, ASSETS: 2003 2002 2002 ----------- ---------- ---------- Property, plant and equipment: Utility plant, at cost .................. $ 516,203 $ 499,867 $ 504,015 Accumulated depreciation and amortization (221,573) (213,534) (217,425) --------- --------- --------- Net property, plant and equipment .... 294,630 286,333 286,590 Current assets .............................. 71,623 52,175 29,677 Goodwill, net ............................... 70,469 70,469 70,469 Deferred charges and other assets ........... 12,037 9,441 8,710 --------- --------- --------- Total assets ...................... $ 448,759 $ 418,418 $ 395,446 ========= ========= ========= LIABILITIES: Current liabilities ......................... $ 57,340 $ 51,435 $ 43,762 Deferred credits and other liabilities ...... 18,940 22,568 23,956 --------- --------- --------- Total liabilities ................. $ 76,280 $ 74,003 $ 67,718 ========= ========= =========
The following table summarizes the Texas Operations' results of operations that have been segregated and reported as "discontinued operations" in the Company's Consolidated Statement of Operations:
Three Months Ended Nine Months Ended Twelve Months Ended March 31, March 31, March 31, -------------------- ------------------- ------------------- 2003 2002 2003 2002 2003 2002 --------- -------- -------- -------- -------- -------- Operating revenues .......................... $ -- $108,699 $144,490 $251,811 $202,615 $320,609 ========= ======== ======== ======== ======== ======== Net operating margin (a) .................... $ -- $ 32,417 $ 51,480 $ 83,276 $ 73,934 $106,208 ========= ======== ======== ======== ======== ======== Net earnings from discontinued operations (b) $ 17,665 $ 4,889 $ 31,256 $ 16,588 $ 32,772 $ 20,118 ========= ======== ======== ======== ======== ========
--------------------------------- (a) Net operating margin consists of operating revenues less gas purchase costs and revenue-related taxes. (b) Net earnings from discontinued operations include the $62,992,000 pre-tax gain on sale recorded during the quarter ended March 31, 2003. Net earnings from discontinued operations do not include any allocation of interest expense or other corporate costs, in accordance with generally accepted accounting principles. All outstanding debt of Southern Union Company and subsidiaries is maintained at the corporate level, and no debt was assumed by ONEOK, Inc. in the sale of the Texas Operations. DIVESTITURES In April 2002, PG Energy Services Inc. ("Energy Services"), a wholly-owned subsidiary of Southern Union, sold its propane operations for $2,300,000, resulting in a pre-tax gain of $1,200,000. In December 2001, Southern Transmission Company, a wholly-owned subsidiary of the Company, sold its 43-mile Carrizo Springs Pipeline for $1,000,000, resulting in a pre-tax gain of $561,000. Also in December 2001, the Company sold South Florida Natural Gas, a natural gas division of Southern Union, and Atlantic Gas Corporation, a Florida propane subsidiary of the Company (collectively, the Florida Operations), for $10,000,000, resulting in a pre-tax loss of $1,500,000. In October 2001, Morris Merchants, a wholly-owned subsidiary of Southern Union which served as a manufacturers' representative agency for franchised plumbing and heating contract supplies throughout New England, was sold for $1,586,000. In September 2001, Valley Propane, a wholly-owned subsidiary of the Company which sold liquid propane to residential, commercial and industrial customers, was sold for $5,301,000. In August 2001, ProvEnergy Oil, a wholly-owned subsidiary of Southern Union which operated a fuel oil distribution business through its subsidiary, ProvEnergy Fuels, Inc. for residential and commercial customers, was sold for $15,776,000. No financial gain or loss was recognized on any of these sales transactions. In July 2001, Energy Services sold its commercial and industrial natural gas marketing contracts for $4,972,000, resulting in a pre-tax gain of $4,653,000. In June 2001, Keystone Pipeline Services, Inc., a wholly-owned subsidiary of Energy Services which engaged in the construction, maintenance, and rehabilitation of natural gas distribution pipelines, was sold for $3,300,000, resulting in a pre-tax gain of $707,000. EARNINGS PER SHARE The following table summarizes the Company's basic and diluted earnings per share calculations for the three-, nine- and twelve-month periods ending March 31:
Three Months Ended Nine Months Ended Twelve Months Ended March 31, March 31, March 31, ----------------------- ----------------------- ----------------------- 2003 2002 2003 2002 2003 2002 ---------- ----------- ----------- ----------- ----------- ---------- Net earnings from continuing operations ........ $ 46,234 $ 38,899 $ 55,567 $ 16,547 $ 40,540 $ 24,152 Net earnings from discontinued operations....... 17,665 4,889 31,256 16,588 32,772 20,118 ---------- ----------- ----------- ----------- ----------- ---------- Net earnings available for common stock......... $ 63,899 $ 43,788 $ 86,823 $ 33,135 $ 73,312 $ 44,270 ========== =========== =========== =========== =========== ========== Weighted average shares outstanding - basic..... 54,344,794 53,447,791 54,120,204 53,944,420 54,018,957 54,220,213 =========== =========== =========== =========== =========== ========== Weighted average shares outstanding - diluted... 56,041,342 56,263,243 55,903,939 57,002,247 55,933,809 57,276,163 =========== =========== =========== =========== =========== ========== Basic earnings per share: Net earnings from continuing operations...... $ 0.85 $ 0.73 $ 1.03 $ 0.31 $ 0.75 $ 0.45 Net earnings from discontinued operations.... 0.33 0.09 0.57 0.30 0.61 0.37 ---------- ---------- ----------- ----------- ----------- ---------- Net earnings available for common stock...... $ 1.18 $ 0.82 $ 1.60 $ 0.61 $ 1.36 $ 0.82 ========== ========== =========== =========== =========== ========== Diluted earnings per share: Net earnings from continuing operations...... $ 0.83 $ 0.69 $ 0.99 $ 0.29 $ 0.72 $ 0.42 Net earnings from discontinued operations.... 0.31 0.09 0.56 0.29 0.59 0.35 ---------- ---------- ----------- ----------- ----------- ---------- Net earnings available for common stock...... $ 1.14 $ 0.78 $ 1.55 $ 0.58 $ 1.31 $ 0.77 ========== ========== =========== =========== =========== ==========
Diluted earnings per share include average shares outstanding as well as common stock equivalents from stock options and warrants. Common stock equivalents were 538,371 and 1,561,343 for the three-month period ended March 31, 2003 and 2002, respectively; 606,694 and 1,818,640 for the nine-month period ended March 31, 2003 and 2002, respectively; and 738,980 and 1,833,728 for the twelve-month period ended March 31, 2003 and 2002, respectively. Stock options to purchase 2,150,459, 2,150,459 and 2,140,880 shares of common stock were outstanding during the three-, nine- and twelve-month periods ended March 31, 2003, respectively, but were not included in the computation of diluted earnings per share because the options' exercise price was greater than the average market price of the common shares during the respective period. There were no "antidilutive" options outstanding for the same periods in 2002. At March 31, 2003, 1,117,119 shares of common stock were held by various rabbi trusts for certain of the Company's benefit plans and 24,456 shares were held in a rabbi trust for certain employees who deferred receipt of Company shares for stock options exercised. From time to time, the Company's benefit plans may purchase shares of Southern Union common stock subject to regular restrictions. GOODWILL Effective July 1, 2001, the Company adopted Goodwill and Other Intangible Assets. In accordance with this Statement, the Company has ceased amortization of goodwill. Goodwill, which was previously amortized on a straight-line basis over forty years, is now subject to at least an annual assessment for impairment by applying a fair-value based test. In connection with the Company's Cash Flow Improvement Plan announced in July 2001, the Company began the divestiture of certain non-core assets. As a result of prices of comparable businesses for various non-core properties, a goodwill impairment loss of $1,417,000 was recognized in depreciation and amortization from continuing operations and an impairment loss of $1,941,000 was recognized in discontinued operations on the Consolidated Statement of Operations for the quarter ended September 30, 2001. As a result of the sale of the Carrizo Springs Pipeline and the Florida Operations, goodwill of $7,872,000 was eliminated during the quarter ended December 31, 2001. As a result of the sale of the Texas Operations, goodwill of $70,469,000 was eliminated during the quarter ended March 31, 2003. DEFERRED CHARGES AND CREDITS March 31, June 30, 2003 2002 -------- -------- Deferred Charges Pensions ................................ $ 52,347 $ 52,481 Income taxes ............................ 24,661 24,000 Unamortized debt expense ................ 33,429 33,897 Retirement costs other than pensions..... 31,116 33,032 Service Line Replacement Program......... 19,534 21,360 Environmental............................ 14,083 16,646 Other ................................... 24,908 24,714 -------- -------- Total Deferred Charges ............ $200,078 $206,130 ======== ======== As of March 31, 2003 and June 30, 2002, the Company's deferred charges include regulatory assets in the aggregate amount of $85,594,000 and $91,116,000, respectively, of which $51,986,000 and $66,301,000, respectively, is being recovered through current rates. As of March 31, 2003 and June 30, 2002, the remaining recovery period associated with these assets ranges from 1 to 220 months and from 7 months to 230 months, respectively. None of these regulatory assets, which primarily relate to pensions, retirement costs other than pensions, income taxes, Year 2000 costs, Missouri Gas Energy's Service Line Replacement program and environmental remediation costs, are included in rate base. The Company records regulatory assets in accordance with the FASB standard, Accounting for the Effects of Certain Types of Regulation. March 31, June 30, 2003 2002 -------- -------- Deferred Credits Pensions ........................... $ 35,564 $ 45,645 Retirement costs other than pensions 33,058 37,669 Customer advances for construction . 11,796 11,119 Environmental ...................... 16,527 7,206 Investment tax credit .............. 5,767 6,212 Self-insurance ..................... 6,882 6,208 Other .............................. 24,396 27,874 -------- -------- Total Deferred Credits ....... $133,990 $141,933 ======== ======== The Company's deferred credits include regulatory liabilities in the aggregate amount of $10,241,000 and $6,389,000, respectively, at March 31, 2003, and June 30, 2002. These regulatory liabilities primarily relate to retirement benefits other than pensions, environmental insurance recoveries and income taxes. The Company records regulatory liabilities in accordance with the FASB standard, Accounting for the Effects of Certain Types of Regulation. INVESTMENT SECURITIES At March 31, 2003, the Company held securities of Capstone Turbine Corporation (Capstone). This investment is classified as "available for sale" under the FASB standard Accounting for Certain Investments in Debt and Equity Securities. As of March 31, 2003, the Company's investment in Capstone had a fair value of $505,000 and unrealized gains, net of tax, related to this investment were $175,000. The Company has classified this investment as current, as it plans to monetize its investment in the near future and use the proceeds to reduce outstanding debt. All other securities owned by the Company are accounted for under the cost method. The Company's other investments in securities consist of common and preferred stock in non-public companies whose value is not readily determinable. Various Southern Union executive management personnel, Board of Directors and employees also have an equity ownership in certain of these investments. The Company reviews its portfolio of investment securities on a quarterly basis to determine whether a decline in value is other than temporary. Factors that are considered in assessing whether a decline in value is other than temporary include, but are not limited to: earnings trends and asset quality; near term prospects and financial condition of the issuer, including the availability and terms of any additional financing requirements; financial condition and prospects of the issuer's region and industry, customers and markets and Southern Union's intent and ability to retain the investment. If Southern Union determines that the decline in value of an investment security is other than temporary, the Company will record a charge on its Consolidated Statement of Operations to reduce the carrying value of the security to its estimated fair value. OTHER INCOME On August 6, 2002, Southwest Gas Corporation ("Southwest") agreed to pay Southern Union $17,500,000 to settle the Company's claims of fraud and bad faith breach of contract related to Southern Union's attempts to purchase Southwest. The settlement resulted in a pre-tax gain and cash flow of $17,500,000 for the quarter ended September 30, 2002. Effective January 1, 2003, ONEOK agreed to pay Southern Union $5,000,000 to settle the Company's claims related to ONEOK's blocked acquisition of Southwest. The settlement resulted in a pre-tax gain and cash flow of $5,000,000 for the quarter ended March 31, 2003. During the quarter ended September 30, 2001, the Company settled three interest rate swaps that were not designated as hedges and did not meet the criteria for hedge accounting, resulting in a pre-tax gain and cash flow of $17,166,000. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Derivative Instruments and Hedging Activities The Company utilizes derivative instruments on a limited basis to manage certain business risks. Interest rate swaps are employed to hedge the effect of changes in interest rates related to certain debt instruments. Cash Flow Hedges The Company is party to an interest rate swap created to manage its exposure against volatility in interest payments on variable rate debt and which qualifies for hedge accounting. As of March 31, 2003, the derivative liability related to this designated cash flow hedge had a fair value of $200,000 and is classified under other current liabilities in the Consolidated Balance Sheet. For the nine-month period ended March 31, 2003, the Company recorded net settlement payments of $443,000 on this swap through interest expense, and unrealized gains of $208,000, net of taxes, through accumulated other comprehensive income. Hedge ineffectiveness, which is recorded in interest expense, was immaterial. No component of the swaps' gain or loss was excluded from the assessment of hedge effectiveness. As of March 31, 2003, the Company expects to reclassify as interest expense $121,000 in derivative losses, net of taxes, from accumulated other comprehensive income as the settlement of swap payments occur over the next eight months. The maximum length of time over which the Company is hedging its exposure to the payment of variable interest rates is 8 months. In March 2003, the Company entered into a series of Treasury Rate Locks to manage its exposure against changes in future interest payments attributable to changes in the benchmark interest rate prior to the anticipated issuance of fixed-rate debt. These agreements have computational periods of five and ten years and qualify for hedge accounting. As of March 31, 2003, the derivative liability related to these designated cash flow hedges had a fair value of $3,250,000 and is classified under other current liabilities in the Consolidated Balance Sheet. As of March 31, 2003, the Company expects to reclassify as interest expense $464,000 in derivative losses, net of taxes, from accumulated other comprehensive income upon the issuance of the debt and as interest payments occur over the next twelve months. The maximum length of time over which the Company is hedging its exposure to changes in the benchmark interest rate on future debt issuances is 3 months. Trading and Non-Hedging Activities In March 2001, the Company discovered unauthorized financial derivative energy trading activity by a non-regulated, wholly-owned subsidiary. All unauthorized trading activity was subsequently closed in March and April of 2001 resulting in a cumulative cash expense of $191,000, net of taxes. For the nine-month period ended March 31, 2003, the Company recorded $454,000 through other income relating to the expiration of contracts resulting from this trading activity. The majority of the remaining deferred liability of $1,263,000 at March 31, 2003 related to these derivative instruments will be recognized as income in the Consolidated Statement of Operations over the next 27 months based on the related contracts. PREFERRED SECURITIES OF SUBSIDIARY TRUST On May 17, 1995, Southern Union Financing I (Subsidiary Trust), a consolidated wholly-owned subsidiary of Southern Union, issued $100,000,000 of 9.48% Trust Originated Preferred Securities (Preferred Securities). In connection with the Subsidiary Trust's issuance of the Preferred Securities and the related purchase by Southern Union of all of the Subsidiary Trust's common securities (Common Securities), Southern Union issued to the Subsidiary Trust $103,092,800 principal amount of its 9.48% Subordinated Deferrable Interest Notes, due 2025 (Subordinated Notes). The sole assets of the Subsidiary Trust are the Subordinated Notes. The interest and other payment dates on the Subordinated Notes correspond to the distribution and other payment dates on the Preferred Securities and the Common Securities. Under certain circumstances, the Subordinated Notes may be distributed to holders of the Preferred Securities and holders of the Common Securities in liquidation of the Subsidiary Trust. Since May 17, 2000, the Subordinated Notes have been redeemable at the option of the Company, at a redemption price of $25 per Subordinated Note plus accrued and unpaid interest. The Preferred Securities and the Common Securities will be redeemed on a pro rata basis to the same extent as the Subordinated Notes are repaid, at $25 per Preferred Security and Common Security plus accumulated and unpaid distributions. Southern Union's obligations under the Subordinated Notes and related agreements, taken together, constitute a full and unconditional guarantee by Southern Union of payments due on the Preferred Securities. As of March 31, 2003 and 2002, 4,000,000 shares of Preferred Securities were outstanding. DEBT AND CAPITAL LEASE March 31, June 30, 2003 2002 ---------- ---------- 7.60% Senior Notes, due 2024 ......................... $ 359,765 $ 362,515 8.25% Senior Notes, due 2029 ......................... 300,000 300,000 Term Note, due 2002 .................................. -- 350,000 Term Note, due 2005 .................................. 286,087 -- 5.62% to 10.25% First Mortgage Bonds, due 2003 to 2029 115,884 147,888 7.70% Debentures, due 2027 ........................... 6,756 6,776 Capital lease and other .............................. 13,725 23,234 ---------- ---------- Total debt and capital lease ......................... 1,082,217 1,190,413 Less current portion ............................. 75,851 108,203 ---------- ---------- Total long-term debt and capital lease ............... $1,006,366 $1,082,210 ========== ========== Capital Lease The Company completed the installation of an Automated Meter Reading (AMR) system at Missouri Gas Energy during the first quarter of fiscal year 1999. The installation of the AMR system involved an investment of approximately $30,000,000 which is accounted for as a capital lease obligation. As of March 31, 2003, the capital lease obligation outstanding was $13,313,000 with a fixed rate of 5.79%. Credit Facilities On June 10, 2002, the Company entered into an amended short-term credit facility in the amount of $150,000,000 (the "Short-Term Facility"), that matures on June 9, 2003. Also on June 10, 2002, the Company amended the terms and conditions of its $225,000,000 long-term credit facility (the "Long-Term Facility"), which expires on May 29, 2004. The Company has additional availability under uncommitted line of credit facilities (Uncommitted Facilities) with various banks. Borrowings under the facilities are available for Southern Union's working capital, letter of credit requirements and other general corporate purposes. The Short-Term Facility and the Long-Term Facility (together, the "Facilities") are subject to a commitment fee based on the rating of the Senior Notes. As of March 31, 2003, the commitment fees were an annualized 0.14% on the Facilities. The interest rate on borrowings on the Facilities is calculated based upon a formula using the LIBOR or prime interest rates. A balance of $209,800,000 was outstanding under the Facilities at March 31, 2003. Term Note On August 28, 2000 the Company entered into the Term Note to fund (i) the cash portion of the consideration to be paid to the Fall River Gas' stockholders; (ii) the all cash consideration to be paid to the ProvEnergy and Valley Resources stockholders, (iii) repayment of approximately $50,000,000 of long- and short-term debt assumed in the mergers, and (iv) all related acquisition costs. On July 16, 2002, the Company repaid the Term Note with the proceeds from the issuance of a $311,087,000 Term Note dated July 15, 2002 (the "2002 Term Note") and borrowings under the Company's lines of credit. The 2002 Term Note is held by a syndicate of sixteen banks, led by JPMorgan Chase Bank, as Agent. Twelve of the sixteen banks were also among the lenders of the Term Note, and they are also lenders under at least one of the Facilities. The 2002 Term Note carries a variable interest rate that is tied to either the LIBOR or prime interest rates at the Company's option. The interest rate spread over the LIBOR rate varies with the credit rating of the Senior Notes by S&P and Moody's, and is currently LIBOR plus 105 basis points. The 2002 Term requires semi-annual principal repayments on February 15th and August 15th of each year, with payments of $25,000,000 each due February 15, 2003, August 15, 2003, February 15, 2004, and August 15, 2004 and payments of $35,000,000 each being due February 15, 2005 and August 15, 2005. The remaining principal amount of $141,087,000 is due August 26, 2005. A balance of $286,087,000 was outstanding under the 2002 Term Note at March 31, 2003. No additional draws can be made on the 2002 Term Note. UTILITY REGULATION AND RATES Missouri On July 5, 2001, the Missouri Public Service Commission (MPSC) issued an order approving a unanimous settlement of Missouri Gas Energy's rate request. The settlement provides for an annual $9,892,000 base rate increase, as well as $1,081,000 in added revenue from new and revised service charges. The majority of the rate increase will be recovered through increased monthly fixed charges to gas sales service customers. New rates became effective August 6, 2001, two months before the statutory deadline for resolving the case. The approved settlement resulted in the dismissal of all pending judicial reviews of prior rate cases. The settlement also provides for the development of a two-year experimental low-income program that will help certain customers in the Joplin area pay their natural gas bills. Rhode Island On May 24, 2002, the Rhode Island Public Utilities Commission (RIPUC) approved a settlement agreement between the New England Gas Company and the RIPUC. The settlement agreement resulted in a $3,900,000 decrease in base revenues effective July 1, 2002 for New England Gas Company's Rhode Island operations, a unified rate structure ("One State; One Rate") and an integration/merger savings mechanism. The settlement agreement also allows New England Gas Company to retain $2,049,000 of merger savings and to share incremental earnings with customers when the division's Rhode Island operations return on equity exceeds 11.25%. Included in the settlement agreement was a conversion to therm billing and the approval of a reconciling Distribution Adjustment Clause (DAC). The DAC allows New England Gas Company to continue its low income assistance and weatherization programs, to recover environmental response costs over a 10-year period, puts into place a new weather normalization clause and allows for the sharing of nonfirm margins (non-firm margin is margin earned from interruptible customers with the ability to switch to alternative fuels). The weather normalization clause is designed to mitigate the impact of weather volatility on customer billings, which will assist customers in paying bills and stabilize the revenue stream. New England Gas Company will defer the margin impact of weather that is greater than 2% colder-than-normal and will recover the margin impact of weather that is greater than 2% warmer-than-normal. The non-firm margin incentive mechanism allows New England Gas Company to retain 25% of all non-firm margins earned in excess of $1,600,000. On February 4, 2003, New England Gas Company filed with RIPUC a settlement agreement entered into with the Division of Public Utilities and Carriers related to the final calculation of earnings sharing for the 21-month period covered by the Energize Rhode Island Extension settlement agreement. This calculation generated excess revenues of $2.5 million. On February 6, 2003, the Commission rejected the settlement agreement and additional hearings were held. The Company expects a decision on this matter in May 2003. COMMITMENTS AND CONTINGENCIES Environmental The Company is subject to federal, state and local laws and regulations relating to the protection of the environment. These evolving laws and regulations may require expenditures over a long period of time to control environmental impacts. The Company has established procedures for the on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. The Company is investigating the possibility that the Company or predecessor companies may have been associated with Manufactured Gas Plant (MGP) sites in its former service territories, principally in Texas, Arizona and New Mexico, and present service territories in Missouri, Pennsylvania, Massachusetts and Rhode Island. At the present time, the Company is aware of certain MGP sites in these areas and is investigating those and certain other locations. While the Company's evaluation of these Texas, Missouri, Arizona, New Mexico, Pennsylvania, Massachusetts and Rhode Island MGP sites is in its preliminary stages, it is likely that some compliance costs may be identified and become subject to reasonable quantification. Within the Company's service territories certain MGP sites are currently the subject of governmental actions. These sites are as follows: Kansas City, Missouri MGP Sites In a letter dated May 10, 1999, the Missouri Department of Natural Resources ("MDNR") sent notice of a planned Site Inspection/Removal Site Evaluation of the Kansas City Coal Gas Former Manufactured Gas Plant ("MGP") site. This site (comprised of two adjacent MGP operations previously owned by two separate companies and hereafter referred to as Station A and Station B) is located at East 1st Street and Campbell in Kansas City, Missouri and is owned by Missouri Gas Energy ("MGE"). During July 1999, the Company sent applications to MDNR submitting the two sites to the agency's Voluntary Cleanup Program ("VCP"). The sites were accepted into the VCP, and MGE subsequently performed environmental assessments of Stations A and B and submitted the results of these assessments to MDNR. On September 6, 2002, MGE submitted a work plan for the remediation of Station A to MDNR. Following MDNR's approval of the Station A work plan, the Company selected a qualified remediation contractor in a competitive bidding process. The Company began remediation of Station A during the quarter ended March 31, 2003. In August 2001, MGE received a demand from the Port Authority for MGE to assume responsibility for remediation of soil and groundwater at property owned by the Port Authority adjacent to MGE's Stations A and B. The Port Authority intends to develop its property adjacent to MGE as a commercial and residential area (the "Riverfront Redevelopment Site"), and sought to have MGE and other parties who may be responsible remediate contamination on the Port Authority property allegedly resulting from the historic manufactured gas plant operations. Honeywell International Inc. has also been identified as a potentially responsible party, as the alleged successor to a tar manufacturing operation formerly located on a portion of the Port Authority property known as the Riverfront Development. MGE and other parties owning property in the area performed assessments in 2001 and early 2002 of their own and of the alleged contaminated portions of the Port Authority property. In a letter dated July 24, 2002, the Port Authority demanded that the Company assume full financial responsibility for the design and implementation of a remedial action plan on the Riverfront Redevelopment Site allowing the Port Authority to obtain an "unrestricted" clearance for redevelopment of the site. On April 17, 2003, a settlement agreement was announced among the Port Authority, the City of Kansas City, MDNR and MGE, whereby the claims related to the Riverfront Redevelopment Site were resolved, and MGE obtained a release therefrom, on the basis of payment by MGE of $3.5 million. Providence, Rhode Island Sites During 1995, Providence Gas began an environmental evaluation at its primary gas distribution facility located at 642 Allens Avenue in Providence, Rhode Island. Environmental studies and a subsequent remediation work plan were completed at an approximate cost of $4.5 million. Providence Gas also began a soil remediation project on a portion of the site in July 1999. As of June 30, 2001, approximately $8.9 million had been expended on soil remediation under the remediation work plan. Based on the results of the environmental investigation and the site information gained during the performance of work under the remediation work plan, on January 15, 2002, the Company requested and subsequently received authorization from the Rhode Island Department of Environmental Management ("RIDEM") to make certain specific modifications to the 1999 Remedial Action Work Plan. On April 17, 2002, RIDEM issued a Temporary Remedial Action Permit for Phase 1 remediation at the site. A contractor was selected by the Company in a competitive bidding process. Work on Phase 1 of the site remediation was initiated on April 17, 2002, and was completed on October 10, 2002. The approximate cost of the environmental work conducted since April 17, 2002 is $4 million. Remediation of the remaining 37.5 acres of the site (known as the "Phase 2" remediation project) is not scheduled at this time. In November 1998, Providence Gas received a letter of responsibility from the RIDEM relating to possible contamination on previously owned property at 170 Allens Avenue in Providence. The operator of the property at that time, Cargill, Inc., also received a letter of responsibility. A work plan had been created and approved by RIDEM. An investigation was then begun to determine the extent of contamination, as well as the extent of the Company's responsibility. Providence Gas entered into a cost-sharing agreement with the current operator of the property, under which Providence Gas was responsible for approximately twenty percent (20%) of the costs related to the investigation. Costs of testing at this site as of March 31, 2003 were approximately $300,000. Until RIDEM provides its final response to the investigation, and the Company knows it's ultimate responsibility respective to other potentially responsible parties with respect to the site, the Company cannot offer any conclusions as to its ultimate financial responsibility with respect to the site. Tiverton, Rhode Island Sites Fall River Gas Company was a defendant in a civil action seeking to recover anticipated remediation costs associated with contamination found at property owned by the plaintiffs. This claim was based on alleged dumping of material by Fall River Gas Company trucks at the site in the 1930s and 1940s. In a settlement agreement effective December 3, 2001, the Company agreed to perform all assessment, remediation and monitoring activities at the site sufficient to obtain a final letter of compliance from the Rhode Island Department of Environmental Management. In a letter dated March 17, 2003, RIDEM sent the New England Gas Company division of Southern Union Company ("NEGC") a letter of responsibility pertaining to alleged historical manufactured gas plant impacted soils along Bay Street, Judson Street, Canonicus Street, Hooper Street, Hilton Street, Chase Street and Foote Street (collectively the "Bay Street Area") in Tiverton, Rhode Island. The letter requested that NEGC prepare a draft Site Investigation Work Plan for submittal to RIDEM by April 10, 2003 and subsequently perform a Site Investigation of the Bay Street Area. Without admitting responsibility or accepting liability, NEGC responded to RIDEM in a letter dated March 19, 2003 and agreed to perform the activities requested by the State within the period proposed by RIDEM. Valley Gas Company Sites Valley Gas Company is a party to an action in which Blackstone Valley Electric Company ("Blackstone") brought suit for contribution to its expenses of cleanup of a site on Mendon Road in Attleboro, Massachusetts, to which coal manufacturing waste was transported from a former MGP site in Pawtucket, Rhode Island (the "Blackstone Litigation"). Blackstone Valley Electric Company v. Stone & Webster, Inc., Stone & Webster Engineering Corporation, Stone & Webster Management Consultants, Inc. and Valley Gas Company, C. A. No. 94-10178JLT, United States District Court, District of Massachusetts. Valley Gas Company takes the position in that litigation that it is indemnified for any cleanup expenses by Blackstone pursuant to a 1961 agreement signed at the time of Valley Gas Company's creation. This suit was stayed in 1995 pending the issuance of rulemaking at the United States EPA (Commonwealth of Massachusetts v. Blackstone Valley Electric Company, 67 F.3d 981 (1995)). In January 2001, the EPA issued a Preliminary Administrative Decision on this issue and announced that it was soliciting comments on the Decision. While the public comment period has now closed, the EPA has yet to reissue its decision. While this suit has been stayed, Valley Gas Company and Blackstone (merged with Narragansett Electric Company in May 2000) have received letters of responsibility from the RIDEM with respect to releases from two MGP sites in Rhode Island. RIDEM issued letters of responsibility to Valley Gas Company and Blackstone in September 1995 for the Tidewater MGP in Pawtucket, Rhode Island, and in February 1997 for the Hamlet Avenue MGP in Woonsocket, Rhode Island. Valley Gas Company entered into an agreement with Blackstone (now Narragansett) in which Valley Gas Company and Blackstone agreed to share equally the expenses for the costs associated with the Tidewater site subject to reallocation upon final determination of the legal issues that exist between the companies with respect to responsibility for expenses for the Tidewater site and otherwise. No such agreement has been reached with respect to the Hamlet site. Massachusetts Sites In a letter dated March 11, 2003, The Commonwealth of Massachusetts Department of Environmental Protection provided New England Gas Company a Notice of Responsibility for 60 and 82 Hartwell Street in Fall River, Massachusetts. This Notice of Responsibility requested that site assessment activities be conducted with respect to the listed properties and with respect to the adjacent former manufactured gas plant property owned by NEGC at 66 5th Street, Fall River. Pennsylvania Sites PG Energy recently received inquiries from the Pennsylvania Department of Environmental Protection ("PADEP") pertaining to three former manufactured gas plant sites. PG Energy has participated in another Pennsylvania Utility's assessment of one site for the purpose of evaluating any environmental threat from the former gas manufacture operations at this site. In addition, PG Energy has met with PADEP representatives concerning two other sites and is currently performing environmental assessment work at one of the sites. Other Environmental To the extent that potential costs associated with former MGPs are quantified, the Company expects to provide any appropriate accruals and seek recovery for such remediation costs through all appropriate means, including in rates charged to customers, insurance and regulatory relief. At the time of the closing of the acquisition of the Company's Missouri service territories, the Company entered into an Environmental Liability Agreement that provides that Western Resources retains financial responsibility for certain liabilities under environmental laws that may exist or arise with respect to Missouri Gas Energy. In addition, the New England Division has reached agreement with its Rhode Island rate regulators on a regulatory plan that creates a mechanism for the recovery of environmental costs over a 10-year period. This plan, effective July 1, 2002, establishes an environmental fund for the recovery of evaluation, remedial and clean-up costs arising out of the Company's MGPs and sites associated with the operation and disposal activities from MGPs. In certain of the Company's jurisdictions the Company is allowed to recover environmental remediation expenditures through rates. Although significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms, management does not believe that environmental expenditures for MGP sites will have a material adverse effect on the Company's financial position, results of operations or cash flows. The Company follows the provisions of an American Institute of Certified Public Accountants Statement of Position, Environmental Remediation Liabilities, for recognition, measurement, display and disclosure of environmental remediation liabilities. Regulatory In August 1998, the City of Edinburg obtained a jury verdict totaling approximately $13,000,000 jointly and severally against PG&E Gas Transmission-Texas Corporation (formerly Valero Energy Corporation (Valero)), and a number of its subsidiaries, as well as former Valero subsidiary Rio Grande Valley Gas Company (RGV) and RGV's successor company, Southern Union Company for the alleged underpayment of franchise fees. (Southern Union purchased RGV from Valero in 1993.) The trial court reduced the jury award to approximately $8,500,000. Subsequently, the Texas (13th District) Court of Appeals further reduced the award to $4,085,000. The Court of Appeals also remanded a portion of the case to the trial court with instructions to retry certain issues; these issues were settled in December 2002 for a non-material amount. In August 2002, the Supreme Court of Texas granted the Company's petition for review. Oral arguments were made to the Court on November 20, 2002. Effective January 1, 2003, all potential remaining liability for this case was assigned to ONEOK as part of the sale of the Company's Texas Operations to ONEOK. On May 31, 2002, the staff of the MPSC recommended that the Commission disallow approximately $15 million in gas costs incurred during the period July 1, 2000 through June 30, 2001. Missouri Gas Energy filed its response in opposition to the Staff's recommendation on July 11, 2002, vigorously disputing the Commission staff's assertions. Missouri Gas Energy intends to vigorously defend itself in this proceeding. On November 4, 2002, the Commission adopted a procedural schedule setting the matter for hearing in May of 2003. On November 27, 2001, August 1, 2000 and August 12, 1999, the staff of the MPSC recommended that the Commission disallow approximately $5.9 million, $5.9 million and $4.3 million, respectively, in gas costs incurred during the period July 1, 1999 through June 30, 2000, July 1, 1998 through June 30, 1999, and July 1, 1997 through June 30, 1998, respectively. The basis of these proposed disallowances appears to be the same as was rejected by the Commission through an order dated March 12, 2002, applicable to the period July 1, 1996 through June 30, 1997. MGE intends to vigorously defend itself in these proceedings. On November 4, 2002, the Commission adopted a procedural schedule calling for a hearing in this matter some time after May of 2003. Southwest Gas Litigation Several actions were commenced by persons involved in competing efforts to acquire Southwest Gas Corporation (Southwest) during 1999. All of these actions eventually were transferred to the District of Arizona (the Court), consolidated and lodged with Judge Roslyn Silver. As a result of summary judgments granted, there are no claims remaining against Southern Union. Southern Union's claims against Southwest were settled on August 6, 2002, by Southwest's payment to Southern Union of $17,500,000. Southern Union's claims against ONEOK, Inc. and the individual defendants associated with ONEOK were settled on January 3, 2003, following the closing of Southern Union's sale of the Texas assets to ONEOK, by ONEOK's payment to Southern Union of $5,000,000. Southern Union's claims against Jack Rose, former aide to Arizona Corporation Commissioner James Irvin, were settled by Mr. Rose's payment to Southern Union of $75,000, which the Company donated to charity. The trial of Southern Union's claims against the sole-remaining defendant, Arizona Corporation Commissioner James Irvin, was concluded on December 18, 2002, with a jury award to Southern Union of nearly $400,000 in actual damages and $60,000,000 in punitive damages against Commissioner Irvin. The Court is currently in the process of considering Commissioner Irvin's post-trial motions for relief. With the exception of ongoing legal fees associated with the aforementioned litigation, the Company believes that the results of the above-noted Southwest litigation and any related appeals will not have a materially adverse effect on the Company's financial condition, results of operations or cash flows. Other Legal Southern Union and its subsidiaries are parties to other legal proceedings that management considers to be normal actions to which an enterprise of its size and nature might be subject, Management does not consider these actions to be material to Southern Union's overall business or financial condition, results of operations or cash flows. SOUTHERN UNION COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview Currently, the Company's core business is the distribution of natural gas as a public utility through its Missouri Gas Energy, PG Energy, and New England Gas Company divisions. Upon the completion of the acquisition of Panhandle Eastern Pipe Line Company and its subsidiaries (Panhandle), Southern Union will have a wholly-owned interest in various natural gas transportation pipelines and liquefied natural gas (LNG) facilities. This acquisition will be funded in part by proceeds received from the January 2003 sale of Southern Union Gas and related assets as discussed below. Several of these business activities are subject to regulation by federal, state or local authorities where the Company operates. Thus, the Company's financial condition and results of operations have been and will continue to be dependent upon the receipt of adequate and timely adjustments in rates. In addition, the Company's business is affected by seasonal weather impacts, competitive factors within the energy industry and economic development and residential growth in its service areas. Discontinued Operations and Assets Held For Sale Effective January 1, 2003, the Company completed the sale of its Southern Union Gas natural gas operating division and related assets to ONEOK, Inc. ("ONEOK") for approximately $420,000,000 in cash, subject to working capital adjustment, resulting in a pre-tax gain of $62,992,000 that is included in earnings from discontinued operations in the Consolidated Statement of Operations for the three-, nine- and twelve-month periods ended March 31, 2003. In addition to Southern Union Gas, the sale involved the disposition of Mercado Gas Services, Inc. (Mercado), SUPro Energy Company (SUPro), Southern Transmission Company (STC), Southern Union Energy International, Inc. (SUEI), Southern Union International Investments, Inc. (Investments) and Norteno Pipeline Company (Norteno) (collectively, the Texas Operations). Southern Union Gas distributes natural gas as a public utility to approximately 535,000 customers throughout Texas, including the cities of Austin, El Paso, Brownsville, Galveston and Port Arthur. Mercado markets natural gas to commercial and industrial customers. SUPro provides propane gas services to approximately 4,000 customers located principally in Austin, El Paso and Alpine, Texas as well as Las Cruces, New Mexico and surrounding communities. STC owns and operates 118.8 miles of intrastate pipeline that serves commercial, industrial and utility customers in central, south and coastal Texas. SUEI and Investments participate in energy-related projects internationally. Energia Estrella del Sur, S. A. de C. V., a wholly-owned Mexican subsidiary of SUEI and Investments, has a 43% equity ownership in a natural gas distribution company, along with other related operations, which currently serves 23,000 customers in Piedras Negras, Mexico, across the border from Southern Union Gas' Eagle Pass, Texas service area. Norteno owns and operates interstate pipelines that serve the gas distribution properties of Southern Union Gas and the Public Service Company of New Mexico. Norteno also transports gas through its interstate network to the country of Mexico for Pemex Gas y Petroquimica Basica. The Company plans to re-deploy substantially all the sales proceeds towards its pending acquisition of Panhandle. The Company anticipates that the sale and reinvestment will qualify as part of a like-kind exchange of property covered by Section 1031 of the Internal Revenue Code thereby enabling the Company to achieve certain tax deferrals. Accordingly, as of March 31, 2003, approximately $406,000,000 of the sales proceeds has been temporarily invested through a Qualified Intermediary, as defined by Section 1031, pending the completion of the acquisition and like-kind exchange. Divestitures In April 2002, PG Energy Services Inc. ("Energy Services"), a wholly-owned subsidiary of Southern Union, sold its propane operations for $2,300,000, resulting in a pre-tax gain of $1,200,000. In December 2001, Southern Transmission Company, a wholly-owned subsidiary of the Company, sold its 43-mile Carrizo Springs Pipeline for $1,000,000, resulting in a pre-tax gain of $561,000. Also in December 2001, the Company sold South Florida Natural Gas, a natural gas division of Southern Union, and Atlantic Gas Corporation, a Florida propane subsidiary of the Company (collectively, the Florida Operations), for $10,000,000, resulting in a pre-tax loss of $1,500,000. In October 2001, Morris Merchants, a wholly-owned subsidiary of Southern Union which served as a manufacturers' representative agency for franchised plumbing and heating contract supplies throughout New England, was sold for $1,586,000. In September 2001, Valley Propane, a wholly-owned subsidiary of the Company which sold liquid propane to residential, commercial and industrial customers, was sold for $5,301,000. In August 2001, ProvEnergy Oil, a wholly-owned subsidiary of Southern Union which operated a fuel oil distribution business through its subsidiary, ProvEnergy Fuels, Inc. for residential and commercial customers, was sold for $15,776,000. No financial gain or loss was recognized on any of these sales transactions. In July 2001, Energy Services sold its commercial and industrial natural gas marketing contracts for $4,972,000, resulting in a pre-tax gain of $4,653,000. In June 2001, Keystone Pipeline Services, Inc., a wholly-owned subsidiary of Energy Services which engaged in the construction, maintenance, and rehabilitation of natural gas distribution pipelines, was sold for $3,300,000, resulting in a pre-tax gain of $707,000. As a result of the divestiture of non-core business assets and the seasonal nature of gas utility operations, the results of operations for the three-, nine- and twelve-month periods ended March 31, 2003 are not indicative of results that would necessarily be achieved for a full year. The majority of the Company's operating margin is earned during the winter heating season. RESULTS OF OPERATIONS Three Months Ended March 31, 2003 and 2002 The Company recorded net earnings available for common stock of $63,899,000 for the three-month period ended March 31, 2003 compared with net earnings of $43,788,000 for the same period in 2002. Earnings per diluted share were $1.14 in 2003 compared with $.78 in 2002. Continuing Operations Net earnings from continuing operations were $46,234,000 for the three-month period ended March 31, 2003 compared with $38,899,000 for the same period in 2002. Earnings from continuing operations per diluted share were $.83 in 2003 compared with $.69 in 2002. Operating revenues were $535,663,000 for the three-month period ended March 31, 2003, compared with $419,599,000 in 2002. Gas purchase and other energy costs for the three-month period ended March 31, 2003 were $356,393,000, compared with $260,853,000 in 2002. The Company's operating revenues are affected by the level of sales volumes and by the pass-through of increases or decreases in the Company's gas purchase costs through its purchased gas adjustment clauses. Additionally, revenues are affected by increases or decreases in gross receipts taxes (revenue-related taxes) which are levied on sales revenue as collected from customers and remitted to the various taxing authorities. The increase in both operating revenues and gas purchase costs between periods was primarily due to a 22% increase in gas sales volumes to 59,095 MMcf in 2003 from 48,282 MMcf in 2002, and by a 12% increase in the average cost of gas from $5.39 per Mcf in 2002 to $6.03 per Mcf in 2003. The increase in gas sales volumes is primarily due to colder weather in 2003 as compared with 2002 in all of the Company's service territories. The increase in the average cost of gas is due to increases in the average spot market prices throughout the Company's distribution system as a result of seasonal impacts on demands for natural gas as well as the current competitive pricing occurring within the energy industry. Weather in Missouri Gas Energy's service territories was 100% of a 30-year measure for the three-month period ended March 31, 2003, compared with 90% in 2002. PG Energy's service territories experienced weather that was 108% of a 30-year measure in 2003, compared with 84% in 2002. Weather for the New England Gas Company service territories was 108% of a 30-year measure for the three-month period ended March 31, 2003, compared with 85% in 2002. Operating margin (operating revenues less gas purchase and other energy costs and revenue-related taxes) increased $17,770,000 for the three-month period ended March 31, 2003 compared with the same period in 2002. Operating margin increased principally as a result of colder weather in 2003 as compared with 2002, previously discussed. Operating expenses were $69,258,000 for the three-month period ended March 31, 2003, an increase of $6,485,000, compared with $62,773,000 in 2002. Operating expenses for the quarter ended March 31, 2003 were impacted by increased pension and other postretirement benefits costs primarily due to volatility in the stock markets, increased employee payroll and other operating costs as a result of the colder weather in 2003 as compared with 2002 and increased insurance expense. These increased costs were partially offset by a reduction in bad debt expense due to a reduction in delinquent customer receivables. Interest expense was $19,840,000 for the three-month period ended March 31, 2003, compared with $21,723,000 in 2002. Interest expense primarily decreased due to a $169,352,000 reduction in long-term debt principal since March 31, 2002 which was partially offset by a $77,500,000 increase in notes payable outstanding since March 31, 2002. Principal was primarily reduced on the bank note (the Term Note) entered into by the Company on August 28, 2000 for the acquisition of the New England Operations. The Company entered into the Term Note to (i) fund the cash consideration paid to stockholders of Fall River Gas, ProvEnergy and Valley Resources, (ii) refinance and repay long- and short-term debt assumed in the New England Operations, and (iii) fund the acquisition costs of the New England Operations. A portion of the Term Note was refinanced on July 16, 2002. See Debt and Capital Lease in the Notes to the Consolidated Financial Statements included herein. The Company's average effective interest rate was 5.9% for the three-month periods ended March 31, 2003 and 2002. Other income for the three-month period ended March 31, 2003 was $5,223,000 compared with $3,713,000 in 2002. Other income for the three-month period ended March 31, 2003 includes a gain of $5,000,000 on the settlement of the Company's claims against ONEOK related to its blocked acquisition of Southwest Gas Corporation ("Southwest") and income of $569,000 generated from the sale and/or rental of gas-fired equipment and appliances by various operating subsidiaries. These items were partially offset by $504,000 of legal costs related to the Southwest litigation. Other income for the three-month period ended March 31, 2002 includes the recognition of $3,776,000 of previously recorded deferred income related to financial derivative energy trading activity of a wholly-owned subsidiary and $370,000 of income generated from the sale and/or rental of gas-fired equipment and appliances. These items were partially offset by $1,200,000 of Southwest litigation costs. The consolidated federal and state effective income tax rate was 38% and 36% for the three-month periods ended March 31, 2003 and 2002, respectively. The increase in the effective income tax rate is primarily due to an increase in state income tax expense as a result of the sale of the Texas Operations which operated in a state with no state income tax. Discontinued Operations Net earnings from discontinued operations were $17,665,000 for the three-month period ended March 31, 2003 compared with $4,889,000 for the same period in 2002. Earnings from discontinued operations per diluted share were $.31 in 2003 compared with $.09 in 2002. Effective January 1, 2003, the Company completed the sale of its Texas Operations resulting in an after-tax gain on sale of $17,665,000 that is reported in earnings from discontinued operations for the three-month period ended March 31, 2003, in accordance with the FASB standard, Accounting for the Impairment or Disposal of Long-Lived Assets. The after-tax gain on the sale of the Texas Operations was impacted by the elimination of $70,469,000 of goodwill related to these operations which was primarily non-tax deductible. Nine Months Ended March 31, 2003 and 2002 The Company recorded net earnings available for common stock of $86,823,000 for the nine-month period ended March 31, 2003 compared with net earnings of $33,135,000 in 2002. Net earnings per diluted share were $1.55 in 2003 compared with $.58 in 2002. Continuing Operations Net earnings from continuing operations were $55,567,000 for the nine-month period ended March 31, 2003 compared with $16,547,000 for the same period in 2002. Earnings from continuing operations per diluted share were $.99 in 2003 compared with $.29 in 2002. Operating revenues were $981,477,000 for the nine-month period ended March 31, 2003, compared with $826,897,000 in 2002. Gas purchase and other energy costs for the nine-month period ended March 31, 2003 were $613,958,000, compared with $494,587,000 in 2002. The increase in both operating revenues and gas purchase costs between periods was primarily due to a 21% increase in sales volume from 86,494 MMcf in 2002 to 104,619 MMcf in 2003, and by a 3% increase in the average cost of gas from $5.68 per Mcf in 2002 to $5.86 per Mcf in 2003. The increase in gas sales volumes is primarily due to colder weather in 2003 as compared with 2002 in all of the Company's service territories. The increase in the average cost of gas is due to increases in the average spot market prices throughout the Company's distribution system as a result of seasonal impacts on demands for natural gas as well as the current competitive pricing occurring within the energy industry. Weather in Missouri Gas Energy's service territories was 100% of a 30-year measure for the nine-month period ended March 31, 2003, compared with 84% in 2002. PG Energy's service territories experienced weather that was 106% of a 30-year measure in 2003, compared with 84% in 2002. Weather for the New England Gas Company service territories was 104% of a 30-year measure for the nine-month period ended March 31, 2003, compared with 86% in 2002. Operating margin increased $30,234,000 for the nine-month period ended March 31, 2003 compared with the same period in 2002. Operating margin increased principally as a result of colder weather in 2003 as compared with 2002, previously discussed. Operating expenses were $194,040,000 for the nine-month period ended March 31, 2003, a decrease of $26,812,000, compared with operating expenses of $220,852,000 in 2002. Operating expenses for the nine-month period ended March 31, 2002 were impacted by a $30,553,000 business restructuring charge discussed below. Operating expenses for the nine-month period ended March 31, 2003 were impacted by the previously discussed increases in pension and other postretirement benefits costs, employee payroll and other operating costs due to the colder weather and insurance expense. These increased costs were partially offset by an increase in environmental insurance recoveries of $997,000 in 2003 as compared with 2002. Additionally, in connection with the Company's Cash Flow Improvement Plan announced in July 2001 and discussed below, the Company offered Early Retirement Programs ("ERPs") in certain of its operating divisions and a limited reduction in force ("RIF") within its corporate offices and began the divesture of certain non-core assets which contributed savings of $3,212,000 in operating expenses during the nine-month period ended March 31, 2003 as compared with 2002. The Company also recognized a goodwill impairment loss of $1,417,000 in depreciation and amortization expense in 2002, based on prices of comparable businesses for various non-core properties. In August 2001, the Company implemented a corporate reorganization and restructuring which was initially announced in July 2001 as part of a Cash Flow Improvement Plan designed to increase annualized pre-tax cash flow from operations by at least $50 million by the end of fiscal year 2002. Actions taken included (i) the offering of voluntary ERPs in certain of its operating divisions and (ii) a limited RIF within its corporate offices. ERPs, providing for increased benefits for those electing retirement, were offered to approximately 325 eligible employees across the Company's operating divisions, with approximately 59% of such eligible employees accepting. The RIF was limited solely to certain corporate employees in the Company's Austin and Kansas City offices where forty-eight employees were offered severance packages. In connection with the corporate reorganization and restructuring efforts, the Company recorded a charge of $30,553,000 during the quarter ended September 30, 2001. This charge was reduced by $1,394,000 during the quarter ended June 30, 2002, as a result of the Company's ability to negotiate more favorable terms on certain of its restructuring liabilities. The charge included: $16.4 million of voluntary and accepted ERP's, primarily through enhanced benefit plan obligations, and other employee benefit plan obligations; $6.8 million of RIF within the corporate offices and related employee separation benefits; and $6.0 million connected with various business realignment and restructuring initiatives. All restructuring actions were completed as of June 30, 2002. Interest expense was $61,583,000 for the nine-month period ended March 31, 2003 compared with $70,444,000 in 2002. Interest expense decreased primarily due to the reduction in the principal on the previously mentioned Term Note. See Debt and Capital Lease in the Notes to the Consolidated Financial Statements included herein. Other income for the nine-month period ended March 31, 2003 was $18,949,000 compared with $26,354,000 in 2002. Other income for the nine-month period ended March 31, 2003 includes a gain of $22,500,000 on the settlement of the Company's claims against ONEOK and Southwest Gas Corporation related to the Southwest litigation, and income of $1,718,000 generated from the sale and/or rental of gas-fired equipment and appliances by various operating subsidiaries. These items were partially offset by $5,473,000 of legal costs related to the Southwest litigation and $1,298,000 of selling costs related to the Texas Operations' disposition. Other income for the nine-month period ended March 31, 2002 includes gains of $17,166,000 generated through the settlement of several interest rate swaps, the recognition of $6,109,000 in previously recorded deferred income related to financial derivative energy trading activity, a gain of $4,653,000 realized through the sale of marketing contracts held by PG Energy Services Inc., income of $1,735,000 generated from the sale and/or rental of gas-fired equipment and appliances, power generation and sales income of $1,228,000 from PEI Power Corporation and a $561,000 gain on the sale of a 43-mile pipeline by a subsidiary of the Company. These items were partially offset by $6,106,000 of Southwest litigation costs and a $1,500,000 loss on the sale of South Florida Natural Gas, a natural gas division of Southern Union, and Atlantic Gas Corporation, a Florida propane subsidiary of the Company. The consolidated federal and state effective income tax rate was 38% and 48% for the nine-month period ended March 31, 2003 and 2002, respectively. The decline in the effective income tax rate is a result of non-tax deductible write-off of goodwill, along with the level of pre-tax earnings, which was partially offset by an increase in state income tax due to the sale of the Texas Operations as previously discussed. Discontinued Operations Net earnings from discontinued operations were $31,256,000 for the nine-month period ended March 31, 2003 compared with $16,588,000 for the same period in 2002. Earnings from discontinued operations per diluted share were $.56 in 2003 compared with $.29 in 2002. Earnings from discontinued operations for the nine-month period ended March 31, 2003 were impacted by the $17,665,000 after-tax gain on the sale of the Texas Operations, previously discussed. The timing of the Texas Operations' disposition, completed effective January 1, 2003, resulted in a $14,620,000 decrease in pre-tax earnings from discontinued operations for the nine-month period ended March 31, 2003 as compared with 2002. This decrease in earnings was partially offset by a $3,579,000 pre-tax reduction in depreciation expense, recorded during the quarter ended December 31, 2002. In accordance with the FASB standard, Accounting for the Impairment or Disposal of Long-Lived Assets, once the assets of the Texas Operations were deemed to be "held for sale" in October 2002, depreciation of such assets ceased. Additionally, during the quarter ended September 30, 2001, the Texas Operations recorded a charge of $2,153,000 in connection with the previously discussed reorganization and restructuring efforts under the Cash Flow Improvement Plan and recognized a goodwill impairment loss of $1,941,000 based on prices of comparable businesses for certain non-core properties. Twelve Months Ended March 31, 2003 and 2002 The Company recorded net earnings available for common stock of $73,312,000 for the twelve-month period ended March 31, 2003 compared with net earnings of $44,270,000 in 2002. Earnings per diluted share were $1.31 in 2003 compared with $.77 in 2002. Continuing Operations Net earnings from continuing operations were $40,540,000 for the twelve-month period ended March 31, 2003 compared with $24,152,000 for the same period in 2002. Earnings from continuing operations per diluted share were $.72 in 2003 compared with $.42 in 2002. Operating revenues were $1,135,194,000 for the twelve-month period ended March 31, 2003, compared with $1,026,451,000 in 2002. Gas purchase and other energy costs for the twelve-month period ended March 31, 2003 were $692,448,000, compared with $621,126,000 in 2002. The increase in both operating revenues and gas purchase costs between periods was primarily due to a 19% increase in sales volume from 101,025 MMcf in 2002 to 120,184 MMcf in 2003, which was partially offset by an 1% decrease in the average cost of gas from $5.80 per Mcf in 2002 to $5.75 per Mcf in 2003. The increase in gas sales volumes is primarily due to colder weather in 2003 as compared with 2002 in all of the Company's service territories. The decrease in the average cost of gas was due to the ability to inject lower cost gas into storage during the summer of 2002 thereby lowering the overall cost of gas used during the winter. Current average spot market prices throughout the Company's distribution system have increased from 2002 to 2003. Weather in Missouri Gas Energy's service territories was 99% of a 30-year measure for the twelve-month period ended March 31, 2003, compared with 82% in 2002. PG Energy's service territories experienced weather that was 105% of a 30-year measure in 2003, compared with 86% in 2002. Weather for the New England Gas Company service territories was 104% of a 30-year measure for the twelve-month period ended March 31, 2003, compared with 86% in 2002. Operating margin increased $32,373,000 for the twelve-month period ended March 31, 2003 compared with the same period in 2002. Operating margin increased principally as a result of colder weather in 2003 as compared with 2002, previously discussed, and the timing of a $10,973,000 annual revenue increase granted to Missouri Gas Energy effective August 6, 2001. The increase in operating margin was partially offset by a $4,770,000 decrease in operating margin between periods due to the sale of the Florida Operations and various non-core subsidiaries in New England. Operating expenses were $256,191,000 for the twelve-month period ended March 31, 2003, a decrease of $44,378,000, compared with operating expenses of $300,569,000 in 2002. Operating expenses for the twelve-month period ended March 31, 2003 were positively impacted by the timing of the previously discussed business restructuring charge, a reduction in bad debt expense of $13,551,000 due to a decrease in delinquent customer receivables, realized savings of approximately $9,600,000 in operating expenses from the Cash Flow Improvement Plan, the recognition of the previously discussed goodwill impairment of $1,417,000 for the twelve-month period ended March 31, 2002, an increase in environmental insurance recoveries of $997,000 in 2003, and the elimination of goodwill amortization resulting from the Company's adoption of Goodwill and Other Intangible Assets effective July 1, 2001. In accordance with this Statement, the Company has ceased the amortization of goodwill, which generated $4,293,000 of expense during the twelve-months ended March 31, 2002, and currently accounts for goodwill on an impairment-only basis. See Goodwill in the Notes to the Consolidated Financial Statements included herein. These items were partially offset by the previously discussed increases in pension and other postretirement benefit cost, employee payroll and other operating costs due to the colder weather and insurance expense during the twelve-month period ended March 31, 2003. Interest expense was $82,131,000 for the twelve-month period ended March 31, 2003 compared with $98,020,000 in 2002. Interest expense decreased primarily due to the reduction in the principal on the previously mentioned Term Note. See Debt and Capital Lease in the Notes to the Consolidated Financial Statements included herein. Other income for the twelve-month period ended March 31, 2003 was $6,873,000 compared with $79,391,000 in 2002. Other income for the twelve-month period ended March 31, 2003 includes a gain of $22,500,000 on the settlement of the Company's claims against ONEOK and Southwest Gas Corporation, previously discussed, income of $2,262,000 generated from the sale and/or rental of gas-fired equipment and appliances by various operating subsidiaries and realized gains of $1,004,000 on the sale of investment securities. These items were partially offset by a non-cash charge of $10,380,000 to reserve for the impairment of the Company's investment in a technology company and $8,467,000 of legal costs related to the Southwest litigation. Other income for the twelve-month period ended March 31, 2002, includes realized gains on the sale of investment securities of $53,219,000, gains of $17,166,000 generated through the settlement of several interest rate swaps, the recognition of $6,109,000 of previously recorded deferred income related to financial derivative energy trading activity, a gain of $4,653,000 realized through the sale of marketing contracts held by PG Energy Services Inc., and income of $2,508,000 generated from the sale and/or rental of gas-fired equipment and appliances. These items were partially offset by $10,495,000 of Southwest litigation costs and a $1,500,000 loss on the sale of the Florida Operations. The consolidated federal and state effective income tax rate was 36% and 44% for the twelve-month period ended March 31, 2003 and 2002, respectively. The decline in the effective tax rate is a result of non-tax deductible amortization and write-off of goodwill, along with the level of pre-tax earnings. Discontinued Operations Net earnings from discontinued operations were $32,772,000 for the twelve-month period ended March 31, 2003 compared with $20,118,000 for the same period in 2002. Earnings from discontinued operations per diluted share were $.59 in 2003 compared with $.35 in 2002. Earnings from discontinued operations for the twelve-month period ended March 31, 2003 were impacted by the $17,665,000 after-tax gain on the sale of the Texas Operations, previously discussed. The timing of the Texas Operations' disposition, effective January 1, 2003, resulted in a $14,620,000 decrease in pre-tax earnings from discontinued operations for the twelve-month period ended March 31, 2003 as compared with 2002. This decrease in earnings was partially offset by a $3,579,000 pre-tax reduction in depreciation expense, also previously discussed, recorded by the Texas Operations during the quarter ended December 31, 2002. Additionally, during the quarter ended September 30, 2001, the Texas Operations were impacted by a charge of $2,153,000 recorded in connection with the reorganization and restructuring efforts under the Cash Flow Improvement Plan and a goodwill impairment loss of $1,941,000, both previously discussed. The Texas Operations were also impacted by the elimination of $618,000 in goodwill amortization resulting from the Company's adoption of the FASB standard, Goodwill and Other Intangible Assets, effective July 1, 2001. The following table sets forth certain information regarding the Company's gas utility operations for the three- and twelve-month periods ended March 31, 2003 and 2002:
Three Months Twelve Months Ended March 31, Ended March 31, 2003 2002 2003 2002 ----------- ----------- ------------ ----------- Average number of gas sales customers served: Residential ...................................... 849,011 844,607 840,051 836,298 Commercial ....................................... 104,546 97,862 99,500 94,882 Industrial and irrigation ........................ 774 3,930 1,603 3,963 Public authorities and other ..................... 520 459 483 444 ----------- ----------- ----------- ----------- Total average customers served .............. 954,851 946,858 941,637 935,587 =========== =========== =========== =========== Gas sales in millions of cubic feet (MMcf) Residential ...................................... 43,696 35,899 83,310 69,465 Commercial ....................................... 17,521 13,884 33,336 27,227 Industrial and irrigation ........................ 778 963 3,216 2,994 Public authorities and other ..................... 172 225 335 1,258 ----------- ----------- ----------- ----------- Gas sales billed ............................ 62,167 50,971 120,197 100,944 Net change in unbilled gas sales ................. (3,072) (2,689) (13) 81 ----------- ----------- ----------- ----------- Total gas sales ............................. 59,095 48,282 120,184 101,025 =========== =========== =========== =========== Gas sales revenues (thousands of dollars): Residential ...................................... $ 384,227 $ 307,944 $ 773,980 $ 705,936 Commercial ....................................... 145,174 110,195 277,992 248,290 Industrial and irrigation ........................ 8,029 8,856 24,950 28,736 Public authorities and other ..................... 1,703 1,126 2,861 6,357 ----------- ----------- ----------- ----------- Gas revenues billed ......................... 539,133 428,121 1,079,783 989,319 Net change in unbilled gas sales revenues ........ (20,163) (17,567) 10,895 (34,637) ----------- ----------- ----------- ----------- Total gas sales revenues .................... $ 518,970 $ 410,554 $ 1,090,678 $ 954,682 =========== =========== =========== =========== Gas sales revenue per thousand cubic feet (Mcf) billed: Residential ...................................... $ 8.79 $ 8.58 $ 9.29 $ 10.16 Commercial ....................................... 8.29 7.94 8.34 9.12 Industrial and irrigation ........................ 10.32 9.20 7.76 9.60 Public authorities and other ..................... 9.90 5.00 8.54 5.05 Weather: Degree days: Missouri Gas Energy service territories ..... 2,723 2,439 5,145 4,266 PG Energy service territories ............... 3,360 2,592 6,571 5,320 New England Gas Company service territories . 3,131 2,547 5,958 5,087 Percent of normal based on 30-year measure: Missouri Gas Energy service territories ..... 100% 90% 99% 82% PG Energy service territories ............... 108% 84% 105% 86% New England Gas Company service territories . 108% 85% 104% 86% Gas transported in millions of cubic feet (MMcf) ...... 20,855 19,645 66,892 63,640 Gas transportation revenues (thousands of dollars) .... $ 13,690 $ 12,784 $ 38,654 $ 35,588 ----------------------------------------------
The above information does not include the Company's Texas Operations, which were sold effective January 1, 2003 and are reported as discontinued operations in the Consolidated Statement of Operations for all periods ended March 31, 2003 and 2002. The 30-year measure of weather is used above for consistent external reporting purposes. Measures of normal weather used by the Company's regulatory authorities to set rates vary by jurisdiction. Periods used to measure normal weather for regulatory purposes range from 10 years to 30 years. SOUTHERN UNION COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FINANCIAL CONDITION The Company's gas utility operations are seasonal in nature with a significant percentage of the annual revenues and earnings occurring in the traditional heating-load months. This seasonality results in a high level of cash flow needs immediately preceding the peak winter heating season months, due to the required payments to natural gas suppliers in advance of the receipt of cash payments from the Company's customers. The Company has historically used internally generated funds and its credit facilities to provide funding for its seasonal working capital, continuing construction and maintenance programs and operational requirements. On June 10, 2002, the Company entered into an amended short-term credit facility in the amount of $150,000,000 (the "Short-Term Facility"), that matures on June 9, 2003. Also on June 10, 2002, the Company amended the terms and conditions of its $225,000,000 long-term credit facility (the "Long-Term Facility"), which expires on May 29, 2004. On April 3, 2003, the Company entered into a short-term credit facility in the amount of $140,000,000 that matures on April 1, 2004 (the "2003 Short-Term Facility"), and cancelled the Short-Term Facility. The Company has additional availability under uncommitted line of credit facilities (Uncommitted Facilities) with various banks. Borrowings under the facilities are available for Southern Union's working capital, letter of credit requirements and other general corporate purposes. The 2003 Short-Term Facility and the Long-Term Facility (together, the "2003 Facilities") are subject to a commitment fee based on the rating of the Senior Notes. As of May 9, 2003, the commitment fees were an annualized 0.15% on the 2003 Facilities. The interest rate on borrowings on the 2003 Facilities is calculated based upon a formula using the LIBOR or prime interest rates. A balance of $215,000,000 was outstanding under the 2003 Facilities at May 9, 2003. On August 28, 2000 the Company entered into the Term Note to fund (i) the cash portion of the consideration to be paid to the Fall River Gas' stockholders; (ii) the all cash consideration to be paid to the ProvEnergy and Valley Resources stockholders, (iii) repayment of approximately $50,000,000 of long- and short-term debt assumed in the mergers, and (iv) all related acquisition costs. On July 16, 2002, the Company repaid the Term Note with the proceeds from the issuance of a $311,087,000 Term Note dated July 15, 2002 (the "2002 Term Note") and borrowings under the Company's lines of credit. A balance of $286,087,000 was outstanding under the 2002 Term Note at March 31, 2003. No additional draws can be made on the 2002 Term Note. The principal sources of funds during the three-month period ended March 31, 2003 were $420,000,000 from the sale of the Texas Operations and $106,310,000 in cash flow from operations. This provided funds of $80,200,000 for the repayment of borrowings under revolving credit facilities, $26,229,000 for the repayment of debt and capital lease obligations and $11,512,000 for on-going property, plant and equipment additions. The principal sources of funds during the nine-month period ended March 31, 2003 were $420,000,000 from the sale of the Texas Operations, $311,087,000 from the issuance of long-term debt, $88,314,000 in cash flow from operations and $78,000,000 in net borrowings under revolving credit facilities. This provided funds of $419,283,000 for the repayment of debt and capital lease obligations and $49,618,000 for on-going property, plant and equipment additions. The effective interest rate under the Company's current debt structure is 6.69% (including interest and the amortization of debt issuance costs and redemption premiums on refinanced debt). The Company retains its borrowing availability under the Facilities, as discussed above. Borrowings under these credit facilities will continue to be used, as needed, to provide funding for the seasonal working capital needs of the Company. Internally-generated funds from operations will be used principally for the Company's ongoing construction and maintenance programs and operational needs and may also be used periodically to reduce outstanding debt. On April 1, 2003, the Company filed a shelf registration for $800,000,000 of debt securities, common stock, and preferred stock. Southern Union may sell such securities up to such amounts from time to time, at prices determined at the time of any such offering. The Company currently has regulatory approval to issue up to $300,000,000 of these securities for certain uses. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK There are no material changes in market risks faced by the Company from those reported in the Company's Annual Report on Form 10-K for the year ended June 30, 2002. The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended June 30, 2002 (as updated by the Company's Current Report on Form 8-K dated March 10, 2003), in addition to the interim consolidated financial statements, accompanying notes, and Management's Discussion and Analysis of Financial Condition and Results of Operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. OTHER MATTERS Pending Acquisitions On December 21, 2002, the Company and AIG Highstar Capital, L.P. (AIG Highstar), a private equity fund sponsored by American International Group, Inc., reached a definitive agreement (the Stock Purchase Agreement) with CMS Gas Transmission Company, a subsidiary of CMS Energy Corporation (CMS), to acquire Panhandle Eastern Pipe Line Company and its subsidiaries (Panhandle). On May 12, 2003, the Company, CMS and AIG Highstar agreed to: (1) terminate AIG Highstar's participation in the acquisition of Panhandle, (2) amend the Stock Purchase Agreement so that AIG Highstar is no longer a party, and (3) enter into a mutual release with respect to obligations relating to the Stock Purchase Agreement. Accordingly, on the same day, the Company and CMS amended the Stock Purchase Agreement to reduce the purchase price by $37.5 million to approximately $1.79 billion. Under the amended agreement, Southern Union, as the sole purchaser of Panhandle, will pay approximately $584.3 million in cash plus three million shares of Southern Union common stock, and will assume approximately $1.166 billion of Panhandle debt. The Company expects that the amended transaction will expedite regulatory approval of the transaction and anticipates closing by June 30, 2003. The amended transaction has been approved by the boards of directors of both parties and will close following clearance by the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvement Act. This acquisition will be funded in part by proceeds received from the Company's January 2003 sale of Southern Union Gas and related assets, previously discussed. The Panhandle entities include CMS Panhandle Eastern Pipe Line Company, CMS Trunkline Gas Company, CMS Trunkline LNG Company and CMS Sea Robin Pipeline Company. The Panhandle entities operate approximately 11,000 miles of mainline natural gas pipeline extending from the Gulf of Mexico to the Midwest and Canada. These pipelines access the major natural gas supply regions of the Louisiana and Texas Gulf Coasts as well as the Midcontinent and Rocky Mountains. The pipelines have a combined peak day delivery capacity of 5.4 billion cubic feet per day, 88 billion cubic feet of underground storage capacity and 6.3 billion cubic feet of above ground LNG storage facilities. CMS Trunkline LNG Company operates an LNG terminal complex at Lake Charles, La. Management Agreement On November 20, 2002, EnergyWorx, Inc., a wholly-owned subsidiary of the Company, entered into a management services agreement with Southern Star Central Corporation (Southern Star), a wholly-owned subsidiary of AIG Highstar. EnergyWorx, Inc. managed the Southern Star Central Gas Pipeline which Southern Star purchased from Williams Gas Pipeline Company, LLC on November 15, 2002. These assets include an interstate natural gas pipeline with a transport capacity of 2.3 Bcf per day which traverses seven states and storage fields providing a seasonal storage capacity of 43 Bcf. On May 12, 2003, Southern Union and AIG Highstar terminated immediately the management services agreement in order to expedite regulatory approval of the Panhandle acquisition. As a condition to the Missouri Public Service Commission's approval of the Panhandle acquisition, the Company also had agreed generally to divest EnergyWorx, Inc. not later than June 30, 2003. The termination of the management services agreement and divestiture will not have a material impact on Southern Union's financial position, results of operations or cash flows. Investment Securities The Company reviews its portfolio of investment securities on a quarterly basis to determine whether a decline in value is other than temporary. Factors that are considered in assessing whether a decline in value is other than temporary include, but are not limited to: earnings trends and asset quality; near term prospects and financial condition of the issuer, including the availability and terms of any additional financing requirements; financial condition and prospects of the issuer's region and industry, customers and markets and Southern Union's intent and ability to retain the investment. If Southern Union determines that the decline in value of an investment security is other than temporary, the Company will record a charge on its Consolidated Statement of Operations to reduce the carrying value of the security to its estimated fair value. CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This Management's Discussion and Analysis of Results of Operations and Financial Condition and other sections of this Form 10-Q may contain forward-looking statements that are based on current expectations, estimates and projections about the industry in which the Company operates, management's beliefs and assumptions made by management. Words such as "expects," "anticipates," "intends," "plans," "believes," "seeks," "estimates," variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions, which are difficult to predict and many of which are outside the Company's control. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned not to put undue reliance on such forward-looking statements. Stockholders may review the Company's reports filed in the future with the Securities and Exchange Commission for more current descriptions of developments that could cause actual results to differ materially from such forward-looking statements. Factors that could cause or contribute to actual results differing materially from such forward-looking statements include the following: cost of gas; gas sales volumes; weather conditions in the Company's service territories; the achievement of operating efficiencies and the purchases and implementation of new technologies for attaining such efficiencies; impact of relations with labor unions of bargaining-unit employees; the receipt of timely and adequate rate relief; the outcome of pending and future litigation; governmental regulations and proceedings affecting or involving the Company; the risk that certain tax positions may be disallowed by the Internal Revenue Service; unanticipated environmental liabilities; changes in business strategy; the risk that the businesses acquired and any other businesses or investments that Southern Union has acquired or may acquire may not be successfully integrated with the businesses of Southern Union; the impairment or sale of investment securities; ability to access capital markets on reasonable terms; the possibility of war or terrorism attacks; and the nature and impact of any extraordinary transactions such as any acquisition or divestiture of a business unit or any assets. These are representative of the factors that could affect the outcome of the forward-looking statements. In addition, such statements could be affected by general industry and market conditions, and general economic conditions, including interest rate fluctuations, federal, state and local laws and regulations affecting the retail gas industry or the energy industry generally, and other factors. CONTROLS AND PROCEDURES We performed an evaluation within the 90-day period prior to the filing of this quarterly report under the supervision and with the participation of our management, including our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), and with the participation of personnel from our Legal, Internal Audit, Risk Management and Financial Reporting Departments, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2003 and have communicated that determination to the Audit Committee of our Board of Directors. There have been no significant changes in our internal controls or other factors that could significantly affect internal controls subsequent to March 31, 2003. SOUTHERN UNION COMPANY AND SUBSIDIARIES EXHIBITS AND REPORTS ON FORM 8-K Exhibits: The following exhibits are filed as part of this Quarterly Report on Form 10-Q: 99.1 Certificate of the Chief Executive Officer pursuant to 18 U.S.C. ss.1350 (Section 906 of the Sarbanes-Oxley Act of 2002) 99.2 Certificate of the Chief Financial Officer pursuant to 18 U.S.C. ss.1350 (Section 906 of the Sarbanes-Oxley Act of 2002) Reports on Form 8-K: The Company filed the following Current Reports on Form 8-K during the quarter ended March 31, 2003: Date Filed Description of Filing ---------- --------------------------------------------------------------------- 1/02/03 Announcement that Southern Union Company and AIG Highstar Capital, L.P. entered into a definitive agreement with CMS Energy Corporation to acquire the Panhandle Eastern Pipe Line Company and filing, under Item 7, the Stock Purchase Agreement dated as of December 21, 2002. 1/16/03 Announcement that Southern Union Company completed the sale of its Southern Union Gas Company Texas division and related assets ("Texas Operations") to ONEOK, Inc., effective January 1, 2003 and filing, under Item 7, pro forma financial information for the quarter ended September 30, 2002 and 2001 (unaudited) and for the years ended June 30, 2002, 2001 and 2000 (unaudited). 1/30/03 Announcement of Southern Union Company's operating performance for the quarter ended December 31, 2002 and 2001 and filing, under Item 9, summary statements of income for the quarter ended December 31, 2002 and 2001 (unaudited) and notes thereto. 3/10/03 Announcement that Southern Union Company is re-issuing updated audited historical financial statements for the years ended June 30, 2002, 2001 and 2000 in connection with its filing of a Registration Statement on Form S-3 and filing, under Item 7, the audited financial statements, accompanying notes and management's discussion and analysis, updated to reflect the Company's discontinued Texas Operations, for the years ended June 30, 2002, 2001 and 2000. 3/14/03 Announcement that the closing of Southern Union Company's acquisition of Panhandle Eastern Pipe Line Company may be delayed beyond March 31, 2003, due to the receipt of requests for additional information from the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvements Act. SOUTHERN UNION COMPANY AND SUBSIDIARIES 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. SOUTHERN UNION COMPANY --------------------------- (Registrant) Date May 15, 2003 By DAVID J. KVAPIL -------------------- ----------------------------- David J. Kvapil Executive Vice President and Chief Financial Officer CERTIFICATION I, George L. Lindemann, certify that: (1) I have reviewed this quarterly report on Form 10-Q of Southern Union Company; (2) Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; (3) Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; (4) The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and (c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; (5) The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the Audit Committee of the Company's Board of Directors: (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and (6) The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. GEORGE L. LINDEMANN ---------------------------------------------------------- George L. Lindemann Chairman of the Board and Chief Executive Officer May 14, 2003 CERTIFICATION I, David J. Kvapil, certify that: (1) I have reviewed this quarterly report on Form 10-Q of Southern Union Company; (2) Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; (3) Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; (4) The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and (c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; (5) The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the Audit Committee of the Company's Board of Directors: (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and (6) The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. DAVID J. KVAPIL ---------------------------------------------------------- David J. Kvapil Executive Vice President and Chief Financial Officer May 14, 2003 Exhibit 99.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Form 10-Q of Southern Union Company (the "Company") for the quarter ended March 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, George L. Lindemann, Chairman of the Board and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. GEORGE L. LINDEMANN ---------------------------------------------------------- George L. Lindemann Chairman of the Board and Chief Executive Officer May 14, 2003 Exhibit 99.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Form 10-Q of Southern Union Company (the "Company") for the quarter ended March 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, David J. Kvapil, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. DAVID J. KVAPIL ---------------------------------------------------------- David J. Kvapil Executive Vice President and Chief Financial Officer May 14, 2003