-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, A5gpKxFZIuSzHz/oSFiuHT+DYlpM/ITHAZ2mYW3O5DtSgatj0sV4mb25b4/NvDlv 6sawUWiffs/TIlA8F+Lg0w== 0000203248-04-000217.txt : 20040507 0000203248-04-000217.hdr.sgml : 20040507 20040507164258 ACCESSION NUMBER: 0000203248-04-000217 CONFORMED SUBMISSION TYPE: 10-Q/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20030930 FILED AS OF DATE: 20040507 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHERN UNION CO CENTRAL INDEX KEY: 0000203248 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 750571592 STATE OF INCORPORATION: DE FISCAL YEAR END: 0630 FILING VALUES: FORM TYPE: 10-Q/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-06407 FILM NUMBER: 04789674 BUSINESS ADDRESS: STREET 1: ONE PEI CENTER CITY: WILKES-BARRE STATE: PA ZIP: 18711 BUSINESS PHONE: (570) 820-2400 10-Q/A 1 form10qa93003.txt FORM 10-Q/A 9/30/03 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q/A (Amendment No. 1) For the quarterly period ended September 30, 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 ----- --------- Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes |X| No ----- --- The number of shares of the registrant's Common Stock outstanding on November 7, 2003 was 72,945,392. Explanatory Note This Amendment No. 1 to the Registrant's Quarterly Report on Form 10-Q for the period ended September 30, 2003 is being filed solely to correct the certifications required by Rule 13a-14(a) set forth on Exhibits 31.1 and 31.2. No revisions have been made to the Registrant's financial statements or any other disclosure contained in such Quarterly Report. SOUTHERN UNION COMPANY AND SUBSIDIARIES FORM 10-Q September 30, 2003 Index PART I. FINANCIAL INFORMATION Page(s) Item 1. Financial Statements: Consolidated statements of operations - three and twelve months ended September 30, 2003 and 2002 2-3 Consolidated balance sheet - September 30, 2003 and 2002 and 4-5 June 30, 2003 Consolidated statement of stockholders' equity - three months ended September 30, 2003 and twelve months ended June 30, 2003 6 Consolidated statements of cash flows - three and twelve months endedSeptember 30, 2003 and 2002 7-8 Notes to consolidated financial statements 9-25 Item 2. Management's Discussion and Analysis of Financial Condition 26-37 and Resultsof Operations Item 3. Quantitative and Qualitative Disclosures about Market Risk 35 Item 4. Controls and Procedures 37 PART II. OTHER INFORMATION Item 1. Legal Proceedings (See "COMMITMENTS AND CONTINGENCIES" in Notes to Consolidated Financial Statements) 18-23 Item 6. Exhibits and Reports on Form 8-K 38 SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS
Three Months Ended September 30, 2003 2002 --------------- -------------- (thousands of dollars, except shares and per share amounts) Operating revenues.................................................................. $ 231,394 $ 99,710 Cost of gas and other energy........................................................ (57,760) (42,060) Revenue-related taxes............................................................... (4,325) (3,186) --------------- -------------- Operating margin............................................................... 169,309 54,464 Operating expenses: Operating, maintenance and general............................................. 101,080 41,371 Depreciation and amortization.................................................. 31,334 14,384 Taxes, other than on income and revenues....................................... 12,916 6,498 --------------- -------------- Total operating expenses................................................... 145,330 62,253 --------------- -------------- Net operating revenues (loss).............................................. 23,979 (7,789) --------------- -------------- Other income (expense): Interest ...................................................................... (33,964) (21,001) Dividends on preferred securities of subsidiary trust.......................... -- (2,370) Other, net..................................................................... 3,807 16,439 --------------- -------------- Total other expenses, net.................................................. (30,157) (6,932) --------------- -------------- Loss from continuing operations before income tax benefit........................... (6,178) (14,721) Federal and state income tax benefit................................................ (2,471) (5,535) --------------- -------------- Net loss from continuing operations................................................. (3,707) (9,186) --------------- -------------- Discontinued operations: Earnings from discontinued operations before income taxes...................... -- 4,313 Federal and state income taxes................................................. -- 1,622 --------------- -------------- Net earnings from discontinued operations........................................... -- 2,691 --------------- -------------- Net loss attributable to common stock .............................................. $ (3,707) $ (6,495) =============== ============== Net loss from continuing operations per share: Basic.......................................................................... $ (.05) $ (.16) ============== ============== Diluted ........................................................................... $ (.05) $ (.16) ============== ============== Net loss attributable to common stock per share: Basic.......................................................................... $ (.05) $ (.11) ============== ============== Diluted........................................................................ $ (.05) $ (.11) ============== ============== Weighted average shares outstanding: Basic.......................................................................... 71,737,091 56,507,411 =============== ============== Diluted........................................................................ 71,737,091 56,507,411 =============== ==============
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS
Twelve Months Ended September 30, 2003 2002 --------------- -------------- (thousands of dollars, except shares and per share amounts) Operating revenues.................................................................. $ 1,320,191 $ 959,648 Cost of gas and other energy........................................................ (740,311) (553,943) Revenue-related taxes............................................................... (41,624) (32,689) --------------- -------------- Operating margin............................................................... 538,256 373,016 Operating expenses: Operating, maintenance and general............................................. 253,454 170,155 Business restructuring charges................................................. -- (1,394) Depreciation and amortization.................................................. 77,592 57,360 Taxes, other than on income and revenues....................................... 33,071 23,523 --------------- -------------- Total operating expenses................................................... 364,117 249,644 --------------- -------------- Net operating revenues..................................................... 174,139 123,372 --------------- -------------- Other income (expense): Interest ...................................................................... (96,306) (85,008) Dividends on preferred securities of subsidiary trust.......................... (7,110) (9,480) Other, net..................................................................... 5,762 7,238 --------------- -------------- Total other expenses, net.................................................. (97,654) (87,250) --------------- -------------- Earnings from continuing operations before income taxes............................. 76,485 36,122 Federal and state income taxes...................................................... 27,337 13,882 --------------- -------------- Net earnings from continuing operations............................................. 49,148 22,240 --------------- -------------- Discontinued operations: Earnings from discontinued operations before income taxes...................... 80,460 35,181 Federal and state income taxes................................................. 50,631 13,889 --------------- -------------- Net earnings from discontinued operations........................................... 29,829 21,292 --------------- -------------- Net earnings available for common stock ............................................ $ 78,977 $ 43,532 =============== ============== Net earnings from continuing operations per share: Basic.......................................................................... $ .80 $ .40 =============== ============== Diluted........................................................................ $ .78 $ .38 =============== ============== Net earnings available for common stock per share: Basic.......................................................................... $ 1.28 $ .77 =============== ============== Diluted......................................................................... $ 1.25 $ .74 =============== ============== Weighted average shares outstanding: Basic.......................................................................... 61,535,727 56,257,836 =============== ============== Diluted........................................................................ 63,306,641 58,909,395 =============== ==============
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET ASSETS
September 30, June 30, 2003 2002 2003 ------------- ------------- ------------ (thousands of dollars) Property, plant and equipment: Plant in service.................................................. $ 3,731,164 $ 1,778,769 $ 3,710,541 Construction work in progress..................................... 87,888 13,355 75,484 ------------- ------------- ------------- 3,819,052 1,792,124 3,786,025 Less accumulated depreciation and amortization.................... (668,525) (617,311) (641,225) ------------- ------------- ------------- Net property, plant and equipment............................ 3,150,527 1,174,813 3,144,800 ------------- ------------- ------------- Current assets: Cash and cash equivalents......................................... 14,730 985 86,997 Accounts receivable, billed and unbilled, net..................... 152,358 72,540 192,402 Federal and state taxes receivable................................ 25,145 -- 6,787 Inventories....................................................... 245,248 132,033 173,757 Deferred gas purchase costs....................................... 43,064 24,429 24,603 Gas imbalances - receivable....................................... 18,567 -- 34,911 Prepayments and other............................................. 23,308 11,777 18,971 Assets held for sale.............................................. -- 396,271 -- ------------- ------------- ------------- Total current assets......................................... 522,420 638,035 538,428 ------------- ------------- ------------- Goodwill, net ......................................................... 642,921 642,921 642,921 Deferred charges....................................................... 189,349 212,928 188,261 Investment securities, at cost......................................... 8,038 9,786 9,641 Other.................................................................. 69,587 41,560 73,674 ------------- ------------- ------------- Total assets...................................................... $ 4,582,842 $ 2,720,043 $ 4,597,725 ============= ============= ==============
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Continued) STOCKHOLDERS' EQUITY AND LIABILITIES
September 30, June 30, 2003 2002 2003 ------------- ------------- ------------ (thousands of dollars) Common stockholders' equity: Common stock, $1 par value; authorized 200,000,000 shares; issued 73,161,844 shares.............................. $ 73,162 $ 58,362 $ 73,074 Premium on capital stock.......................................... 902,479 708,757 901,701 Less treasury stock, 282,333 shares at cost....................... (10,467) (57,673) (10,467) Less common stock held in trust................................... (16,320) (18,250) (15,617) Deferred compensation plans....................................... 10,663 10,159 9,960 Accumulated other comprehensive income (loss)..................... (61,715) (14,943) (62,579) Retained earnings (deficit)....................................... 20,639 (6,495) 24,346 ------------- -------------- ------------- Total common stockholders' equity................................. 918,441 679,917 920,418 Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely subordinated notes of Southern Union.................................................... -- 100,000 100,000 Long-term debt and capital lease obligation............................ 2,041,455 1,049,079 1,611,653 ------------- ------------- ------------- Total capitalization.......................................... 2,959,896 1,828,996 2,632,071 Current liabilities: Long-term debt and capital lease obligation due within one year...................................................... 366,409 98,316 734,752 Notes payable..................................................... 323,800 230,700 251,500 Accounts payable.................................................. 82,247 49,623 112,840 Federal, state and local taxes.................................... 19,935 4,297 13,530 Accrued interest.................................................. 25,223 16,492 40,871 Customer deposits................................................. 11,985 6,896 12,585 Gas imbalances - payable.......................................... 56,384 -- 64,519 Other............................................................. 133,219 51,208 130,196 Liabilities related to assets held for sale....................... -- 62,910 -- ------------- ------------- ------------- Total current liabilities..................................... 1,019,202 520,442 1,360,793 ------------- ------------- ------------- Deferred credits and other ............................................ 306,790 156,560 322,154 Accumulated deferred income taxes...................................... 296,954 214,045 282,707 ------------- ------------- ------------- Total stockholders' equity and liabilities........................ $ 4,582,842 $ 2,720,043 $ 4,597,725 ============ ============= =============
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, 2002................... $ 58,055 $ 707,912 $ (57,673) $ (8,448) $ (14,500) $ -- $685,346 Comprehensive income (loss): Net earnings...................... -- -- -- -- -- 76,189 76,189 Unrealized loss in investment securities, net of tax benefit.. -- -- -- -- (581) -- (581) Minimum pension liability adjustment, net of tax benefit.. -- -- -- -- (41,930) -- (41,930) Unrealized loss on hedging activities, net of tax benefit.. -- -- -- -- (5,568) -- (5,568) --------- Comprehensive income.............. 28,110 --------- Payment on note receivable.......... -- 305 -- -- -- -- 305 Purchase of treasury stock.......... -- -- (2,181) -- -- -- (2,181) 5% stock dividend................... 3,468 48,342 -- -- -- (51,843) (33) Stock compensation plan............. -- 480 -- 737 -- -- 1,217 Issuance of stock for acquisition... -- -- 48,900 -- -- -- 48,900 Issuance of common stock............ 10,925 157,757 -- -- -- -- 168,682 Issuance costs of equity units...... -- (3,443) -- -- -- -- (3,443) Contract adjustment payment......... -- (11,713) -- -- -- -- (11,713) Sale of common stock held in trust.. -- (243) -- 2,424 -- -- 2,181 Exercise of stock options........... 626 2,304 487 (370) -- -- 3,047 ---------- ----------- ---------- ---------- ---------- ---------- --------- Balance June 30, 2003.................. 73,074 901,701 (10,467) (5,657) (62,579) 24,346 920,418 Comprehensive income (loss): Net loss.......................... -- -- -- -- -- (3,707) (3,707) Unrealized loss in investment securities, net of tax benefit.. -- -- -- -- (21) -- (21) Unrealized gain on hedging activities, net of tax.......... -- -- -- -- 885 -- 885 --------- Comprehensive loss................ (2,843) --------- Exercise of stock options........... 88 778 -- -- -- -- 866 ---------- ----------- ---------- ---------- ----------- ---------- --------- Balance September 30, 2003............. $ 73,162 $ 902,479 $ (10,467) $ (5,657) $ (61,715) $ 20,639 $ 918,441 ========== =========== ========== ========== ========== ========== =========
- ------------------------------- 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 September 30, 2003 2002 --------------- -------------- (thousands of dollars) Cash flows from (used in) operating activities: Net loss ........................................................................ $ (3,707) $ (6,495) Adjustments to reconcile net earnings to net cash flows from (used in) operating activities: Depreciation and amortization................................................ 31,334 14,384 Amortization of debt premium................................................. (4,501) -- Deferred income taxes........................................................ 13,560 (2,369) Provision for bad debts...................................................... 5,178 3,469 Provision for impairment of other assets..................................... 2,753 -- Gain on extinguishment of debt............................................... (6,123) -- Net cash provided by assets held for sale.................................... -- 1,804 Other........................................................................ 239 959 Changes in operating assets and liabilities, net of acquisitions and dispositions: Accounts receivable, billed and unbilled................................. 34,866 21,027 Gas imbalance receivable................................................. 16,344 -- Accounts payable......................................................... (30,593) (21,909) Gas imbalance payable................................................... (8,135) -- Customer deposits........................................................ (600) (676) Deferred gas purchase costs.............................................. (18,461) (20,832) Inventories.............................................................. (71,491) (30,957) Deferred charges and credits............................................. (7,598) 5,787 Prepaids and other current assets........................................ (1,453) 2,284 Taxes and other current liabilities...................................... (23,827) 5,719 --------------- -------------- Net cash flows used in operating activities.................................... (72,215) (27,805) --------------- -------------- Cash flows from (used in) investing activities: Additions to property, plant and equipment....................................... (40,252) (19,900) Changes in assets and liabilities held for sale.................................. -- (5,639) Notes receivable................................................................. -- (2,000) Customer advances................................................................ (3,676) 227 Other............................................................................ 2,623 322 --------------- -------------- Net cash flows used in investing activities.................................... (41,305) (26,990) --------------- -------------- Cash flows from (used in) financing activities: Issuance of long-term debt....................................................... 550,000 311,087 Issuance cost of debt............................................................ (3,996) (1,054) Repayment of debt and capital lease obligation................................... (577,917) (354,105) Net borrowings under revolving credit facilities................................. 72,300 98,900 Proceeds from exercise of stock options.......................................... 866 952 --------------- -------------- Net cash flows from financing activities....................................... 41,253 55,780 --------------- -------------- Change in cash and cash equivalents................................................. (72,267) 985 Cash and cash equivalents at beginning of period.................................... 86,997 -- --------------- -------------- Cash and cash equivalents at end of period.......................................... $ 14,730 $ 985 =============== ============== Supplemental disclosures of cash flow information: Cash paid during the period for: Interest....................................................................... $ 50,237 $ 25,824 =============== =============== Income taxes .................................................................. $ 112 $ 134 =============== ===============
See accompanying notes. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS
Twelve Months Ended September 30, 2003 2002 --------------- --------------- (thousands of dollars) Cash flows from (used in) operating activities: Net earnings..................................................................... $ 78,977 $ 43,532 Adjustments to reconcile net earnings to net cash flows from (used in) operating activities: Depreciation and amortization................................................ 77,592 57,360 Amortization of debt premium................................................. (5,807) -- Deferred income taxes........................................................ 94,676 24,552 Provision for bad debts...................................................... 17,912 14,350 Provision for impairment of other assets..................................... 2,753 10,380 Business restructuring charges............................................... -- (1,394) Gain on extinguishment of debt............................................... (6,123) -- Gain on sale of other assets................................................. (62,992) (1,761) Loss on sale of subsidiaries................................................. -- 1,500 Financial derivative trading gains........................................... (605) (5,997) Gain on sale of investment securities........................................ (599) (1,004) Net cash provided by (used in) assets held for sale.......................... (25,502) 44,649 Other........................................................................ 784 5,558 Changes in operating assets and liabilities, net of acquisitions and dispositions: Accounts receivable, billed and unbilled................................. (33,011) 23,816 Gas imbalance receivable................................................. 22,674 -- Accounts payable......................................................... 14,044 (19,786) Gas imbalance payable.................................................... (3,284) -- Customer deposits........................................................ 5,089 (535) Deferred gas purchase costs.............................................. (18,635) 35,056 Inventories.............................................................. (75,117) 26,326 Deferred charges and credits............................................. (25,946) 17,961 Prepaids and other current assets........................................ (1,196) (3,148) Taxes and other liabilities.............................................. (45,704) (7,569) --------------- -------------- Net cash flows from operating activities....................................... 9,980 263,846 --------------- -------------- Cash flows from (used in) investing activities: Additions to property, plant and equipment....................................... (100,082) (70,995) Changes in assets and liabilities held for sale.................................. (7,771) (24,093) Acquisition of operations, net of cash received.................................. (522,316) -- Purchase of investment securities................................................ -- (803) Notes receivable................................................................. (4,750) (4,750) Proceeds from sale of subsidiaries and other assets.............................. 437,000 14,886 Proceeds from sale of investment securities...................................... 835 1,213 Customer advances................................................................ (13,522) 431 Other............................................................................ 4,931 (213) ----------------- ---------------- Net cash flows used in investing activities.................................... (205,675) (84,324) --------------- ---------------- Cash flows from (used in) financing activities: Issuance of long-term debt....................................................... 550,000 311,087 Issuance of common stock......................................................... 168,682 -- Issuance of equity units......................................................... 125,000 -- Issuance cost of debt............................................................ (3,996) (1,684) Issuance costs of equity units................................................... (3,443) -- Repayment of debt and capital lease obligation................................... (721,900) (497,028) Net borrowings under revolving credit facilities................................. 93,100 37,700 Purchase of treasury stock....................................................... (2,181) (39,934) Proceeds from exercise of stock options.......................................... 2,961 9,299 Other............................................................................ 1,217 2,023 --------------- -------------- Net cash flows from (used in) financing activities............................. 209,440 (178,537) --------------- --------------- Change in cash and cash equivalents................................................. 13,745 985 Cash and cash equivalents at beginning of period.................................... 985 -- --------------- -------------- Cash and cash equivalents at end of period.......................................... $ 14,730 $ 985 =============== ============== Supplemental disclosures of cash flow information: Cash paid (refunded) during the period for: Interest....................................................................... $ 115,116 $ 97,121 =============== ============== Income taxes................................................................... $ 2,329 $ (4,080) =============== ==============
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 subsidiaries, the Company) Annual Report on Form 10-K for the fiscal year ended June 30, 2003. 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. Because of the seasonal nature of the Company's operations, as well as the timing of significant acquisitions and sales of operations (see Acquisitions and Sales, below), 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 Financial Accounting Standards Board (FASB) standard, Accounting for Asset Retirement Obligations (ARO). The Statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, costs should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the 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 long-lived 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. Panhandle Eastern Pipe Line Company, LLC (Panhandle Eastern Pipe Line and together with its subsidiaries, Panhandle Energy) has an ARO liability relating to the retirement of certain of its offshore lateral lines with an aggregate carrying amount of approximately $6.8 million and $7.3 million as of June 30, 2003 and September 30, 2003, respectively. During the quarter ended September 30, 2003, changes in the carrying amount of the ARO liability were attributable to $0.3 million of additional liabilities incurred and $0.2 million of accretion expense. Liabilities settled and cash flow revisions were nil for the current period. In April 2003, the FASB issued Amendment of Statement 133 on 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 (i) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (ii) clarifies when a derivative contains a financing component, (iii) amends the definition of an underlying to conform it to language used in FASB Interpretation Guarantor's Accounting and Disclosure Requirement for Guarantees, Including Indirect Guarantees of Indebtedness of Others, and (iv) amends certain other existing pronouncements. The Statement is not expected to materially change the methods the Company uses to account for and report its derivatives and hedging activities. Effective July 1, 2003, the Company adopted the FASB standard, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. The Statement establishes guidelines on how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Statement further defines and requires that certain instruments within its scope be classified as liabilities on the financial statements. The adoption of the Statement resulted in the reclassification of $100,000,000 of 9.48% Trust Originated Preferred Securities as debt on the Consolidated Balance Sheet at September 30, 2003 (see Preferred Securities). The dividends on these preferred securities for periods subsequent to July 1, 2003 are reported as interest expense on the Consolidated Statement of Operations. ACQUISITIONS AND SALES On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy Corporation for approximately $582 million in cash and three million shares of Southern Union common stock (before adjustment for subsequent stock dividends) valued at approximately $49 million based on market prices at closing and in connection therewith incurred transaction costs estimated at approximately $30 million. Southern Union also incurred additional deferred state income tax liabilities estimated at $18 million as a result of the transaction. At the time of the acquisition, Panhandle Energy had approximately $1.159 billion of debt outstanding that it retained. The Company funded the cash portion of the acquisition with approximately $437 million in cash proceeds it received for the January 1, 2003 sale of its Texas operations, approximately $121 million of the net proceeds it received from concurrent common stock and equity units offerings and with working capital available to the Company. The Company structured the Panhandle Energy acquisition and the sale of its Texas operations to qualify as a like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended. The acquisition was accounted for using the purchase method of accounting in accordance with accounting principles generally accepted in the United States of America with the purchase price paid by the Company being allocated to Panhandle Energy's net assets as of the acquisition date based on preliminary estimates. The Panhandle Energy assets acquired and liabilities assumed have been recorded at their estimated fair value as of the acquisition date and are subject to further assessment and adjustment pending the results of outside appraisals. The outside appraisals are expected to be completed prior to December 31, 2003. Panhandle Energy's results of operations have been included in the Consolidated Statement of Operations since June 11, 2003. Thus, the Consolidated Statement of Operations for the periods subsequent to the acquisition is not comparable to the same periods in prior years. Panhandle Energy is primarily engaged in the interstate transportation and storage of natural gas and also provides liquefied natural gas (LNG) terminalling and regasification services and is subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). The Panhandle Energy entities include Panhandle Eastern Pipe Line Company, LLC (Panhandle Eastern Pipe Line), Trunkline Gas Company, LLC (Trunkline), a wholly-owned subsidiary of Panhandle Eastern Pipe Line, Sea Robin Pipeline Company (Sea Robin), a Louisiana joint venture and indirect wholly-owned subsidiary of Panhandle Eastern Pipe Line, Trunkline LNG Company, LLC (Trunkline LNG), a wholly-owned subsidiary of Trunkline LNG Holdings, LLC (LNG Holdings) and Southwest Gas Storage, LLC (Southwest Gas Storage), a wholly-owned subsidiary of Panhandle Eastern Pipe Line. Collectively, the pipeline assets include more than 10,000 miles of interstate pipelines that transport natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes region. The pipelines have a combined peak day delivery capacity of 5.4 billion cubic feet per day and 72 billion cubic feet of owned underground storage capacity. Trunkline LNG, located on Louisiana's Gulf Coast, operates one of the largest LNG import terminals in North America and has 6.3 billion cubic feet of above ground LNG storage facilities. The following table summarizes the estimated fair values of the Panhandle Energy assets acquired and liabilities assumed at the date of acquisition.
At June 11, 2003 Property, plant and equipment (excluding intangibles) ................. $ 1,905,000 Intangibles............................................................ 20,000 Current assets (1)..................................................... 206,000 Other non-current assets............................................... 30,000 ---------------- Total assets acquired............................................. 2,161,000 ---------------- Long-term debt......................................................... (1,219,000) Current liabilities.................................................... (152,000) Other non-current liabilities.......................................... (111,000) ---------------- Total liabilities assumed......................................... (1,482,000) ---------------- Net assets acquired........................................... $ 679,000 ================
(1) Includes cash and cash equivalents of approximately $59 million. 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 $437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In accordance with accounting principles generally accepted in the United States of America, the assets and liabilities sold have been segregated and reported as "held for sale" in the Consolidated Balance Sheet as of September 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 Consolidated Statement of Cash Flows for all periods presented. 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. No financial gain or loss was recognized on this sales transaction. Pro Forma Financial Information The following unaudited pro forma financial information for the three-month period ended September 30, 2002 is presented as though the following events had occurred at the beginning of the period presented: (i) acquisition of Panhandle Energy; and (ii) the issuance of the common stock and equity units in June 2003. The pro forma financial information is not necessarily indicative of the results which would have actually been obtained had the acquisition of Panhandle Energy or the issuance of the common stock and equity units been completed as of the assumed date for the period presented or which may be obtained in the future.
Three Months Ended September 30, 2002 Operating revenues................................................................................. $ 209,505 Net earnings from continuing operations............................................................ 3,058 Net earnings per share from continuing operations: Basic......................................................................................... .04 Diluted....................................................................................... .04
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. EARNINGS PER SHARE The following table summarizes the Company's basic and diluted earnings per share calculations for the three- and twelve-month periods ending September 30:
Three Months Ended Twelve Months Ended September 30, September 30, ----------------------- ------------------------ 2003 2002 2003 2002 ----------- ----------- ----------- ----------- Net earnings (loss) from continuing operations ...................... $ (3,707) $ (9,186) $ 49,148 $ 22,240 Net earnings from discontinued operations............................ -- 2,691 29,829 21,292 ----------- ----------- ----------- ---------- Net earnings (loss) available for (attributable to) common stock..... $ (3,707) $ (6,495) $ 78,977 $ 43,532 =========== =========== =========== ========== Weighted average shares outstanding - basic.......................... 71,737,091 56,507,411 61,535,727 56,257,836 =========== =========== =========== ========== Weighted average shares outstanding - diluted........................ 71,737,091 56,507,411 63,306,641 58,909,395 =========== =========== =========== ========== Basic earnings per share: Net earnings (loss) from continuing operations.................... $ (0.05) $ (0.16) $ 0.80 $ 0.40 Net earnings from discontinued operations......................... -- 0.05 0.48 0.37 ---------- ----------- ----------- ----------- Net earnings (loss) available for (attributable to) common stock.. $ (0.05) $ (0.11) $ 1.28 $ 0.77 ========== =========== =========== =========== Diluted earnings per share: Net earnings (loss) from continuing operations.................... $ (0.05) $ (0.16) $ 0.78 $ 0.38 Net earnings from discontinued operations......................... -- 0.05 0.47 0.36 ---------- ----------- ----------- ----------- Net earnings (loss) available for (attributable to) common stock.. $ (0.05) $ (0.11) $ 1.25 $ 0.74 ========== =========== =========== ===========
Diluted earnings per share include average shares outstanding as well as common stock equivalents from stock options and warrants. Common stock equivalents were 826,286 and 874,742 for the three-month period ended September 30, 2003 and 2002, respectively, and 598,457 and 1,379,788 for the twelve-month period ended September 30, 2003 and 2002, respectively. Stock options to purchase 695,094 and 1,578,016 shares of common stock were outstanding during the three- and twelve-month period ended September 30, 2003, respectively, and stock options to purchase 2,367,105 and 803,375 shares of common stock were outstanding during the three- and twelve-month period ended September 30, 2002, 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. At September 30, 2003, 1,103,813 shares of common stock were held by various rabbi trusts for certain of the Company's benefit plans and 105,710 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 AND INTANGIBLES 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. As a result of the sale of the Florida Operations, goodwill of $7,710,000 was eliminated during the quarter ended December 31, 2001. As a result of the sale of the Texas Operations, goodwill of $70,469,000 (which was classified as Assets Held for Sale in the Consolidated Balance Sheet) was eliminated during the quarter ended March 31, 2003. As of September 30, 2003, the Distribution segment has goodwill of $642,921,000. On June 11, 2003, the Company completed its acquisition of Panhandle Energy. Based on the preliminary purchase price allocations, which rely on estimates and are subject to change based on final outside appraisal, the acquisition resulted in no recognition of goodwill as of the acquisition date. The final appraisal may result in some of the purchase price being allocated to goodwill. In addition, based on the preliminary purchase price allocations which are subject to change, the acquisition resulted in the recognition of intangible assets relating to customer relationships of approximately $20 million as of the acquisition date. These intangibles are currently being amortized over a period of five years, pending final determination of estimated remaining useful life. As of September 30, 2003, the carrying amount of these intangibles was approximately $18.8 million, net of $1.2 million of accumulated amortization, and is included in Property, Plant and Equipment on the Consolidated Balance Sheet. Amortization for the three-month period ended September 30, 2003 was approximately $1 million. Estimated annual amortization is expected to be approximately $4 million for each fiscal year through June 30, 2008. DEFERRED CHARGES AND CREDITS
September 30, June 30, 2003 2003 ------------- --------------- Deferred Charges Pensions......................................................................... $ 39,003 $ 39,088 Unamortized debt expense......................................................... 38,424 34,209 Income taxes..................................................................... 31,441 30,514 Retirement costs other than pensions............................................. 28,297 29,028 Service Line Replacement program................................................. 18,445 18,974 Environmental.................................................................... 14,357 14,304 Other............................................................................ 19,382 22,144 ------------- -------------- Total Deferred Charges........................................................ $ 189,349 $ 188,261 ============= ==============
As of September 30, 2003 and June 30, 2003, the Company's deferred charges include regulatory assets relating to Distribution segment operations in the aggregate amount of $82,683,000 and $84,023,000, respectively, of which $47,344,000 and $50,244,000, respectively, is being recovered through current rates. As of September 30, 2003 and June 30, 2003, the remaining recovery period associated with these assets ranges from 3 to 144 months and from 6 months to 147 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.
September 30, June 30, 2003 2003 ------------- --------------- Deferred Credits Pensions........................................................................ $ 89,894 $ 88,016 Retirement costs other than pensions............................................ 64,083 65,144 Environmental................................................................... 26,535 32,322 Cost of Removal................................................................. 27,282 27,286 Derivative liability............................................................ 19,665 26,151 Customer advances for construction.............................................. 11,967 12,008 Self-insurance.................................................................. 10,876 12,000 Investment tax credit........................................................... 5,557 5,791 Other........................................................................... 50,931 53,436 ------------- -------------- Total Deferred Credits........................................................ $ 306,790 $ 322,154 ============= ==============
The Company's deferred credits include regulatory liabilities relating to Distribution segment operations in the aggregate amount of $10,082,000 and $10,084,000, respectively, at September 30, 2003, and June 30, 2003. 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 As of September 30, 2003, all securities owned by Southern Union are accounted for under the cost method. The Company's 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. In June 2002, Southern Union determined that the decline in value of its investment in PointServe was other than temporary. Accordingly, the Company recorded a non-cash charge of $10,380,000 to reduce the carrying value of this investment to its estimated fair value. In September 2003, Southern Union recorded a similar non-cash charge of $1,603,000. The Company recognized these valuation adjustments to reflect lower private equity valuation metrics and changes in the business outlook of PointServe. PointServe is a closely held, privately owned company and, as such, has no published market value. The Company's remaining investment of $2,603,000 at September 30, 2003 is carried at its estimated fair value and may be subject to future market value risk. The Company will continue to monitor the value of its investment and periodically assess the impact, if any, on reported earnings in future periods. STOCKHOLDERS' EQUITY The Company accounts for its incentive plans under the Accounting Principles Board Opinion, Accounting for Stock Issued to Employees and related authoritative interpretations. The Company recorded no compensation expense for the three-month period ended September 30, 2003 and 2002. During 1997, the Company adopted the FASB Standard, Accounting for Stock-Based Compensation, for footnote disclosure purposes only. Had compensation cost for these incentive plans been determined consistent with this Statement, the Company's net loss from continuing operations and diluted loss per share would have been $4,027,000 and $.06, respectively, for the three-month period ended September 30, 2003 and $9,519,000 and $.17, respectively, for the same period in 2002. Had compensation cost for these incentive plans been determined consistent with this Statement, the Company's net loss attributable to common stock and diluted loss per share would have been $4,027,000 and $.06, respectively, for the three-month period ended September 30, 2003 and $6,828,000 and $.12, respectively, for the same period in 2002. Because this Statement has not been applied to options granted prior to July 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. COMPREHENSIVE INCOME The table below gives an overview of comprehensive income for the periods indicated. Three Months Ended
September 30, 2003 2002 ------------- ------------- Net loss ....................................................................... $ (3,707) $ (6,495) Other comprehensive income (loss): Unrealized loss in investment securities, net of tax benefit................. (21) (487) Unrealized gain on hedging activities, net of tax............................ 885 44 ------------- ------------- Other comprehensive income (loss).......................................... 864 (443) ------------- ------------- Comprehensive loss.............................................................. $ (2,843) $ (6,938) ============= =============
Accumulated other comprehensive income reflected in the Consolidated Balance Sheet at September 30, 2003, includes unrealized gains and losses on hedging activities and minimum pension liability adjustments. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company utilizes derivative instruments on a limited basis to manage certain business risks. Interest rate swaps and treasury rate locks are employed to manage the Company's exposure to interest rate risk. Cash Flow Hedges. As a result of the acquisition of Panhandle Energy, the Company is party to interest rate swap agreements with an aggregate notional amount of $204,365,000 as of September 30, 2003 that fix the interest rate applicable to floating rate long-term debt and which qualify for hedge accounting. As of September 30, 2003, the ineffectiveness of the interest rate swap agreements is not significant. As of September 30, 2003, floating rate London InterBank Offered Rate (LIBOR) based interest payments were exchanged for weighted fixed rate interest payments of 5.08%. As such, payments or receipts on interest rate swap agreements are recognized as adjustments to interest expense. As of September 30, 2003 and June 30, 2003, the fair value liability position of the swaps was $22,314,000 and $26,058,000, respectively. As of September 30, 2003 and since the acquisition date, an unrealized gain of $1,795,000, net of tax, was included in accumulated other comprehensive income related to these swaps, of which approximately $219,000, net of tax, is expected to be reclassified to interest expense during the next twelve months as the hedged interest payments occur. The Company is also party to an interest rate swap agreement with a notional amount of $3,604,000 and $8,199,000 as of September 30, 2003 and June 30, 2003, respectively, that fixes the interest rate applicable to floating rate long-term debt and which qualifies for hedge accounting. As of September 30, 2003, floating rate LIBOR-based interest payments were exchanged for fixed rate interest payments of 5.79%. The fair value liability position of the swap was $25,000 and $93,000 as of September 30, 2003 and June 30, 2003, respectively. In October 2003, the swap expired and $15,000 of unrealized after-tax losses included in accumulated other comprehensive income related to this swap will be reclassified to interest expense during the quarter ending December 31, 2003. In March and April 2003, the Company entered into a series of treasury rate locks with an aggregate notional amount of $250,000,000 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 treasury rate locks expired on June 30, 2003, resulting in a $6,862,000 after-tax loss that was recorded in accumulated other comprehensive income and will be amortized into interest expense over the lives of the associated debt instruments. As of September 30, 2003, approximately $846,000 of net after-tax losses in accumulated other comprehensive income will be amortized into interest expense during the next twelve months. The notional amounts of the interest rate swaps are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates. PREFERRED SECURITIES 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. Pursuant to the requirements of FASB Standard Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which was adopted by the Company on July 1, 2003, the Preferred Securities have been reclassified as debt on the Consolidated Balance Sheet at September 30, 2003 (see Debt and Capital Lease below). As of September 30, 2003 and 2002, 4,000,000 shares of Preferred Securities were outstanding. On October 1, 2003, the Company called the Subordinated Notes for redemption, and the Subordinated Notes and the Preferred Securities were redeemed on October 31, 2003. The Company financed the redemption with borrowings under its revolving credit facilities, which were paid down with the net proceeds of a $230 million offering of preferred stock by the Company on October 8, 2003, as further described below. On October 8, 2003, the Company issued 800,000 shares of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) to the public through the issuance of 8,000,000 Depositary Shares, each representing a one-tenth interest in a 7.55% Noncumulative Preferred Stock, Series A share (the Depositary Shares) at public offering price of $25.00 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $195.2 million in the aggregate. The Company granted the underwriters a 30-day over-allotment option to purchase up to an additional 1,200,000 Depositary Shares under the same terms and conditions, which was exercised on October 8, 2003, resulting in additional net proceeds to the Company of $29.0 million. The total net proceeds were used to repay debt under the Company's revolving credit facilities. DEBT AND CAPITAL LEASE
September 30, June 30, 2003 2003 ----------------- -------------- Southern Union Company 7.60% Senior Notes, due 2024.......................................................... $ 359,765 $ 359,765 8.25% Senior Notes, due 2029.......................................................... 300,000 300,000 2.75% Senior Notes, due 2006.......................................................... 125,000 125,000 9.48% Preferred Securities, due 2025.................................................. 100,000 -- Term Note, due 2005................................................................... 186,087 211,087 5.62% to 10.25% First Mortgage Bonds, due 2003 to 2029................................ 114,986 115,884 7.70% Debentures, due 2027............................................................ 6,756 6,756 Capital lease and other due 2003 to 2007.............................................. 4,411 9,179 ----------------- ------------- 1,197,005 1,127,671 Panhandle Energy 4.80% Senior Notes due 2008........................................................... 300,000 -- 6.05% Senior Notes due 2013........................................................... 250,000 -- 6.125% Senior Notes due 2004.......................................................... 146,080 292,500 7.875% Senior Notes due 2004.......................................................... 52,455 100,000 6.50% Senior Notes due 2009........................................................... 60,623 158,980 8.25% Senior Notes due 2010........................................................... 40,500 60,000 7.00% Senior Notes due 2029........................................................... 66,305 135,890 Term Loan due 2007.................................................................... 272,484 275,358 7.95% Debentures due 2023............................................................. -- 76,500 7.20% Debentures due 2024............................................................. -- 58,000 Net premiums on long-term debt........................................................ 22,412 61,506 --------------- ------------- 1,210,859 1,218,734 Total consolidated debt and capital lease............................................. 2,407,864 2,346,405 Less current portion.............................................................. 366,409 734,752 --------------- ------------- Total consolidated long-term debt and capital lease................................... $ 2,041,455 $ 1,611,653 =============== =============
Each note, debenture or bond is an obligation of Southern Union Company or a unit of Panhandle Energy, as noted above. The Panhandle Energy Term Loan due 2007 is debt related to Panhandle's Trunkline LNG Holdings subsidiary, and is non-recourse to other units of Panhandle Energy or Southern Union Company. The remainder of Panhandle Energy's debt is non-recourse to Southern Union. All debts that are listed as debt of Southern Union Company are direct obligations of Southern Union Company, and no debt is cross-collateralized. The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating. Certain covenants exist in certain of the Company's debt agreements that require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios, and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by the Company to satisfy any such covenant would be considered an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants. 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 September 30, 2003, the capital lease obligation outstanding was $4,050,000 with a fixed rate of 5.79%. The final lease payment was made on October 1, 2003, and the Company has no further obligations with respect to the capital lease. Credit Facilities. On April 3, 2003, the Company entered into a short-term credit facility in the amount of $140,000,000 (the Short Term Facility), that matures April 1, 2004. The Short-Term Facility was increased to $150,000,000 as of September 25, 2003. Also on April 3, 2003, 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 September 30, 2003, the commitment fees were an annualized 0.15% 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 $323,800,000 was outstanding under the Facilities at September 30, 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. The Term Note, which initially expired on August 27, 2001, was extended through August 26, 2002. 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. Eleven 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. As of September 30, 2003, a balance of $186,087,000 was outstanding under this 2002 Term Note. The 2002 Term Note requires semi-annual principal repayments on February 15th and August 15th of each year, with payments of $25,000,000 each being due 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 $66,087,000 is due August 26, 2005. No additional draws can be made on the 2002 Term Note. Panhandle Refinancing. In July 2003, Panhandle Energy announced a tender offer for any and all of the $747 million outstanding principal amount of five of its series of senior notes outstanding at that point in time (the Panhandle Tender Offer) and also called for redemption all of the outstanding $135 million principal amount of its two series of debentures that were outstanding (the Panhandle Calls). Panhandle Energy repurchased approximately $378 million of the principal amount of its outstanding debt through the Panhandle Tender Offer for total consideration of approximately $396 million plus accrued interest through the purchase date. Panhandle Energy also redeemed approximately $135 million of debentures through the Panhandle Calls for total consideration of $139 million, plus accrued interest through the redemption dates. As a result of the Panhandle Tender Offer, the Company has recorded a pre-tax gain on the extinguishment of debt of approximately $6.1 million in August 2003, which has been classified as other income, net, in the Consolidated Statement of Operations. In August 2003, Panhandle Energy issued $300 million of its 4.80% Senior Notes due 2008 and $250 million of its 6.05% Senior Notes due 2013 principally to refinance the repurchased notes and redeemed debentures. Also in August and September 2003, Panhandle Energy repurchased $3.2 million principal amount of its senior notes on the open market through two transactions for total consideration of $3.4 million, plus accrued interest through the repurchase date. UTILITY REGULATION AND RATES Missouri Gas Energy. On November 4, 2003, Missouri Gas Energy filed a request with the Missouri Public Service Commission (MPSC) to increase base rates by $44,800,000 and to implement a weather mitigation rate design that would significantly reduce the impact of weather-related fluctuations on customer bills. Statutes require that the MPSC reach a decision in the case within an eleven-month period. It is not presently possible to determine what action the MPSC will ultimately take with respect to this rate increase request. New England Gas Company. On May 22, 2003, the Rhode Island Public Utilities Commission (RIPUC) approved a Settlement Offer filed by New England Gas Company 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 $5,227,000. The net result of the excess revenues and the Energize Rhode Island weather mitigation and non-firm margin sharing provisions is the crediting to customers of $949,000 over a twelve-month period starting July 1, 2003. On May 24, 2002, the RIPUC approved a settlement agreement between the New England Gas Company and the Rhode Island Division of Public Utilities and Carriers. The settlement agreement resulted in a $3,900,000 decrease in base revenues 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. Panhandle Energy. In December 2002, FERC approved a Trunkline LNG certificate application to expand the Lake Charles facility to approximately 1.2 billion cubic feet per day of sendout capacity versus the current capacity of 630 million cubic feet per day. BG LNG Services, Inc., a subsidiary of BG Group of the United Kingdom (BG LNG Services) has contract rights for the 570 million cubic feet per day of additional capacity. Construction on the Trunkline LNG expansion project commenced in September 2003. In October 2003, FERC approved an amended filing with certain facility modifications. The filing included modifications which will not affect the authorized additional storage capacity and daily sendout capability and confirms the revised in-service date of January 1, 2006. 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 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. 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 will have a material adverse effect on the Company's financial position, results of operations or cash flows. Local Distribution Company Environmental Matters -- 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 gas distribution service territories, principally in Texas, Arizona and New Mexico, and present gas distribution 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 gas distribution service territories certain MGP sites are currently the subject of governmental actions. These sites are as follows: Missouri 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 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 submitted the two sites to MDNR's Voluntary Cleanup Program (VCP) and, subsequently, performed environmental assessments of the sites. Following the submission of these assessments to MDNR, MGE was required by MDNR to initiate remediation of Station A. Following the selection of a qualified contractor in a competitive bidding process, the Company began remediation of Station A in the first calendar quarter of 2003. The project was completed in July 2003, at an approximate cost of $4 million. The remediation of Station B has not been required by MDNR. Rhode Island and Massachusetts Sites. Prior to its acquisition by the Company, Providence Gas performed environmental studies and initiated an environmental remediation project at Providence Gas' primary gas distribution facility located at 642 Allens Avenue in Providence, Rhode Island. Providence Gas spent more than $13 million on environmental assessment and remediation at this MGP site under the supervision of the Rhode Island Department of Environmental Management (RIDEM). Following the acquisition, environmental remediation at the site was temporarily suspended. During this suspension, the Company requested certain modifications to the 1999 Remedial Action Work Plan from RIDEM. After receiving approval to some of the requested modifications to the 1999 Remedial Action Work Plan, environmental work was reinitiated on April 17, 2002, by a qualified contractor selected in a competitive bidding process. Remediation was completed on October 10, 2002, and a Closure Report was filed with RIDEM in December 2002. The approximate cost of the environmental work conducted after environmental work resumed was $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 RIDEM relating to possible contamination at a site that operated as a MGP in the early 1900's in Providence, Rhode Island. Subsequent to its use as a MGP, this site was operated for over eighty years as a bulk fuel oil storage yard by a succession of companies including Cargill, Inc. (Cargill). Cargill has also received a letter of responsibility from RIDEM for the site. An investigation has 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 Cargill, under which Providence Gas is responsible for approximately twenty percent (20%) of the costs related to the investigation. To date, approximately $300,000 has been spent on environmental assessment work at this site. 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. 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 (the Cory Lane Site) in Tiverton, Rhode Island. 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 Cory Lane Site sufficient to obtain a final letter of compliance from the RIDEM. In a letter dated March 17, 2003, RIDEM sent the New England Gas Company division of Southern Union (NEGC) a letter of responsibility pertaining to alleged historical MGP impacted soils in a residential neighborhood 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 (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 specified by RIDEM. After receiving approval from RIDEM on a Work Plan and upon obtaining access agreements from a number of property owners, NEGC began assessment work on June 2, 2003. Assessment fieldwork is now complete on the Work Plan within the Bay Street Area. Upon the validation of the assessment data, assessment analytical data was communicated to RIDEM and to the residents. An assessment report was filed with RIDEM on October 31, 2003. As the Bay Street Area is built on a historic dumpsite, research is underway to identify other potentially responsible parties associated with the area. 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 Environmental Protection Agency (EPA) (Commonwealth of Massachusetts v. Blackstone Valley Electric Company, 67 F.3d 981 (1995)). The requested rulemaking concerned the question of whether or not ferric ferrocyanide (FFC) is among the "cyanides" listed as toxic substances under the Clean Water Act and, therefore, is a "hazardous substance" under the Comprehensive Environmental Response, Compensation and Liability Act. On October 6, 2003, the EPA issued a Final Administrative Determination declaring that FFC is one of the "cyanides" under the environmental statutes. While the Blackstone Litigation was 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. 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 MGP property owned by NEGC at 66 5th Street, Fall River. Pennsylvania Sites. During 2002, PG Energy received inquiries from the Pennsylvania Department of Environmental Protection (PADEP) pertaining to three Pennsylvania former MGP sites. Of these three sites, PG Energy is currently performing environmental assessment work at the Scranton MGP at the request of PADEP. PG Energy has participated financially in PPL Electric Utilities Corporation's (PPL's) environmental and health assessment of a MGP site located in Sunbury, Pennsylvania. In May 2003, PPL commenced a remediation project at the Sunbury site that was completed in August 2003. PG Energy has contributed to PPL's remediation project by removing and relocating gas utility lines located in the path of the remediation. The Company does not believe the outcome of these matters will have a material adverse effect on its financial position, results of operations or cash flows. 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 gas distribution 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 ten-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. Similarly, environmental costs associated with Massachusetts' facilities are recoverable in rates over a seven-year period. Panhandle Energy Environmental Matters -- Panhandle Energy has identified environmental contamination at certain sites on its gas transmission systems and has undertaken clean-up programs at these sites. The contamination resulted from the past use of lubricants containing polychlorinated bi-phenyls (PCBs) in compressed air systems; the past use of paints containing PCBs; and the past use of wastewater collection facilities and other on-site disposal areas. Panhandle has developed and is implementing a program to remediate such contamination in accordance with federal, state and local regulations. Some remediation is being performed by former Panhandle Energy affiliates in accordance with indemnity agreements that also indemnify against certain future environmental litigation and claims. As part of the clean-up program resulting from contamination due to the use of lubricants containing PCBs in compressed air systems, Panhandle Eastern Pipe Line and Trunkline Gas Company have identified PCB levels above acceptable levels inside the auxiliary buildings that house air compressor equipment at thirty-two compressor station sites. Panhandle has developed and is implementing an EPA-approved process to remediate this PCB contamination in accordance with federal, state and local regulations. One site has been decontaminated per the EPA process as prescribed in the EPA regulations. At some locations, PCBs have been identified in paint that was applied many years ago. In accordance with EPA regulations, Panhandle is implementing a program to remediate sites where such issues have been identified during painting activities. If PCBs are identified above acceptable levels, the paint is removed and disposed of in an EPA-approved manner. Approximately 15% of the paint projects in the last few years have required this special procedure. The Illinois Environmental Protection Agency (IEPA) notified Panhandle Eastern Pipe Line and Trunkline Gas Company, together with other non-affiliated parties, of contamination at three former waste oil disposal sites in Illinois. Panhandle and 21 other non-affiliated parties conducted an initial investigation of one of the sites. Based on the information found during the initial investigation, Panhandle and the 21 other non-affiliated parties have decided to further delineate the extent of contamination by authorizing a Phase II investigation at this site. Once data from the Phase II investigation is evaluated, Panhandle and the 21 other non-affiliated parties will determine what additional actions will be taken. Panhandle Eastern Pipe Line's and Trunkline Gas Company's estimated share for the costs of assessment and remediation of the sites, based on the volume of waste sent to the facilities, is approximately 17%. Based on information available at this time, it would appear the amount reserved for all of the above is adequate to cover the potential exposure for clean-up costs. Air Quality Control In 1998, the EPA issued a final rule on regional ozone control that requires Panhandle Energy to place controls on engines in five Midwestern states. The part of the rule that affects Panhandle Energy was challenged in court by various states, industry and other interests, including Interstate Natural Gas Association of America (INGAA), an industry group to which Panhandle Energy belongs. In March 2000, the court upheld most aspects of the EPA's rule, but agreed with INGAA's position and remanded to the EPA the sections of the rule that affected Panhandle Energy. The final rule is expected no earlier than early 2004. Based on an EPA guidance document negotiated with gas industry representatives in 2002, it is believed that Panhandle Energy will be required to reduce NOx emissions by 82% on the identified large internal combustion (IC) engines and will be able to trade off engines within a company and State in an effort to create a cost effective NOx reduction solution. The implementation date is expected to be May 2007. The rule impacts 20 large internal combustion engines on the Panhandle Energy system in Illinois and Indiana at an approximate cost of $17 million for capital improvements, consistent with budget projections. EPA proposed various Maximum Achievable Control Technology (MACT) rules in late 2002 and early 2003. The rules require that Panhandle Eastern Pipe Line and Trunkline Gas Company control Hazardous Air Pollutants (HAPS) emitted from Major sources by 90% of carbon monoxide (CO) emissions. Most of Panhandle Eastern Pipe Line and Trunkline Gas Company compressor stations are major sources. The HAP's pollutant of concern for Panhandle Eastern Pipe Line and Trunkline Gas Company is formaldehyde. As proposed, the rule seeks to reduce CO emissions as a surrogate for formaldehyde. For IC engines, the control technology would be the use of non-selective catalytic reduction (NSCR) catalysts and the expected implementation date is February 2007. For Turbines, the control technology would be the use of oxidation catalysts and the expected implementation date is December 2007. Panhandle Eastern Pipe Line and Trunkline Gas Company have 28 IC engines and two turbines subject to the rules. It is expected to cost approximately $8 million, consistent with budget projections. The IEPA issued a permit in February of 2002, requiring the installation of certain capital improvements at the Glenarm compressor station facility at a cost of approximately $3 million. Controls were installed on two engines in 2002 and on two additional engines in 2003 in accordance with the 2002 permit. Regulatory 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. This matter went into recess following a hearing in May of 2003. Following the May hearing, the Commission staff reduced its disallowance recommendation to approximately $9.3 million. The hearing is set to resume in November 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 2003. No date for this hearing has been set. 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, no claims remain 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. (ONEOK) 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 denied numerous post-trial motions by Commissioner Irvin, who has filed a notice of appeal. The Company intends to vigorously pursue collection of the award. With the exception of ongoing legal fees associated with the collection of damages from Commissioner Irvin, 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 In conjunction with a FERC Order issued in September 1997, certain natural gas producers were required to refund previously collected Kansas ad valorem taxes to interstate natural gas pipelines. These pipelines were ordered to refund these amounts to their customers. All payments were to be made in compliance with prescribed FERC requirements. In June 2001, Panhandle Energy filed a proposed settlement of these proceedings which all the customers and most of the producers supported. The settlement provides for the producers to refund and the customers to accept a reduction from the amounts originally billed to the producers. In September 2001, the FERC approved the settlement without modification and the settlement became effective on October 15, 2001. On January 2, 2003, FERC established hearing procedures for resolving refunds owed by the non-settling producers. The hearing was conducted on October 16, 2003. Initial briefs are due on November 20, 2003, reply briefs are due on December 19, 2003 and an initial decision is scheduled to be issued in February 2004. The amounts have not yet been finally settled with a number of non-settling producers. Settlement efforts are continuing. In 1993, the U.S. Department of the Interior announced its intention to seek, through its Minerals Management Service (MMS) additional royalties from gas producers as a result of payments received by such producers in connection with past take-or-pay settlements and buyouts or buy downs of gas sales contracts with natural gas pipelines. Panhandle Energy's pipelines, with respect to certain producer contract settlements, may be contractually required to reimburse or, in some instances, to indemnify producers against such royalty claims. The potential liability of the producers to the government and of the pipelines to the producers involves complex issues of law and fact which are likely to take substantial time to resolve. If required to reimburse or indemnify the producers, Panhandle Energy's pipelines may file with the FERC to recover a portion of these costs from pipeline customers. Panhandle Energy does not believe the outcome of this matter will have a material adverse effect on its financial position, results of operations or cash flows. Following its acquisition by the Company in June 2003, Panhandle Energy initiated a workforce reduction initiative designed to reduce the workforce by approximately 5 percent. The workforce reduction initiative was an involuntary plan with a voluntary component, and was fully implemented by September 30, 2003. Total estimated workforce reduction initiative costs are approximately $9 million which are a portion of the $30 million of additional transaction costs incurred (see Acquisition and Sales). 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. 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 $437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In accordance with accounting principles generally accepted in the United States of America, the assets and liabilities sold have been segregated and reported as "held for sale" in the Consolidated Balance Sheet as of September 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 Consolidated Statement of Cash Flows for all periods presented. 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 at September 30, 2002:
September 30, ASSETS: 2002 ------------- Property, plant and equipment: Utility plant, at cost.................................................. $ 508,992 Accumulated depreciation and amortization............................... (221,430) -------------- Net property, plant and equipment.................................... 287,562 Current assets.............................................................. 29,339 Goodwill, net............................................................... 70,469 Deferred charges and other assets........................................... 8,901 ------------- Total assets...................................................... $ 396,271 ============= LIABILITIES: Current liabilities......................................................... $ 40,995 Deferred credits and other liabilities...................................... 21,915 ------------- Total liabilities................................................. $ 62,910 =============
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 Twelve Months Ended September 30, September 30, 2003 2002 2003 2002 ----------- ----------- ----------- ----------- Operating revenues....................... $ -- $ 47,689 $ 96,801 $ 304,332 =========== =========== =========== =========== Net operating margin (a)................. $ -- $ 21,620 $ 29,860 $ 107,976 =========== =========== =========== =========== Net earnings from discontinued operations (b) $ -- $ 2,691 $ 29,829 $ 21,292 =========== =========== =========== ===========
- --------------------------------- (a) Net operating margin consists of operating revenues less gas purchase costs and revenue-related taxes. (b) Net earnings from discontinued operations do not include any allocation of interest expense or other corporate costs, in accordance with generally accepted accounting principles. At the time of the sale, all outstanding debt of Southern Union Company and subsidiaries was maintained at the corporate level, and no debt was assumed by ONEOK, Inc. in the sale of the Texas Operations. Net earnings from discontinued operations for the twelve-month period ended September 30, 2003, includes a $62,992,000 pre-tax gain on sale recorded during the quarter ended March 31, 2003. REPORTABLE SEGMENTS The Company's operations include two reportable segments: (i) Transportation and Storage, and (ii) Distribution. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy, which the Company acquired on June 11, 2003. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, Pennsylvania, Rhode Island and Massachusetts. Its operations are conducted through the Company's three regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas Company. Revenue included in the All Other category is attributable to several operating subsidiaries of the Company: PEI Power Corporation generates and sells electricity; Fall River Gas Appliance Company, Inc. and Valley Appliance and Merchandising Company rent gas burning appliances and/or equipment and, along with PG Energy Services Inc., offer appliance service contracts; ProvEnergy Power Company LLC (ProvEnergy Power) provides outsourced energy management services and owns 50% of Capital Center Energy Company LLC, a joint venture formed between ProvEnergy and ERI Services, Inc. to provide retail power and conditioned air; and Alternate Energy Corporation provides energy consulting services. None of these businesses have ever met the quantitative thresholds for determining reportable segments individually or in the aggregate. The Company also has corporate operations that do not generate any revenues. The Company evaluates segment performance based on several factors, of which the primary financial measure is net operating revenues. Net Operating Revenues is defined as operating margin, less operating, maintenance and general expenses, depreciation and amortization, and taxes other than on income and revenues. The following table sets forth certain selected financial information for the Company's segments for the three- and twelve-month periods ended September 30, 2003 and 2002. Financial information for the Transportation and Storage segment reflects the operations of Panhandle Energy beginning on its acquisition date of June 11, 2003. There were no material intersegment revenues during the periods presented.
Three Months Ended Twelve Months Ended September 30, September 30, 2003 2002 2003 2002 ------------ ------------------ ------------- ----------- Revenues from external customers: Distribution....................................... $ 116,029 $ 98,135 $ 1,176,858 $ 952,003 Transportation and Storage......................... 114,219 -- 138,747 -- All Other.......................................... 1,146 1,575 4,586 7,645 ------------- ------------- ------------- ------------- Total consolidated operating revenues................... $ 231,394 $ 99,710 $ 1,320,191 $ 959,648 ============= ============= ============= ============= Operating Margin: Distribution....................................... $ 54,334 $ 53,271 $ 395,823 $ 368,050 Transportation and Storage......................... 114,219 -- 138,747 -- All Other.......................................... 756 1,193 3,686 4,966 ------------- ------------- ------------- ------------- Total consolidated operating margin..................... $ 169,309 $ 54,464 $ 538,256 373,016 ============= ============= ============= ============= Depreciation and amortization: Distribution....................................... $ 14,680 $ 14,210 $ 56,866 $ 54,662 Transportation and Storage......................... 16,348 -- 19,545 -- All Other.......................................... 149 144 595 664 ------------ ------------- ------------- ------------- Total segment depreciation and amortization............. 31,177 14,354 77,006 55,326 Reconciling Item -- Corporate........................... 157 30 586 2,034 ------------- ------------- ------------- ------------- Total consolidated depreciation and amortization........ $ 31,334 $ 14,384 $ 77,592 $ 57,360 ============= ============= ============= =============
Three Months Ended Twelve Months Ended September 30, September 30, 2003 2002 2003 2002 ------------- ------------ ------------ ------------ Net operating revenues (loss): Distribution....................................... $ (11,336) $ (6,208) $ 137,635 $ 132,727 Transportation and Storage......................... 37,918 -- 47,552 -- All Other.......................................... (314) 151 (454) 1,395 ------------- ------------ ------------ ------------ Total segment net operating revenues (loss)............. 26,268 (6,057) 184,733 134,122 Reconciling Items: Corporate.......................................... (2,289) (1,732) (10,594) (12,144) Business restructuring charges..................... -- -- -- 1,394 ------------- ------------- ------------- ------------- Total consolidated net operating revenues (loss)........ $ 23,979 $ (7,789) $ 174,139 $ 123,372 ============= ============= ============= ============= Expenditures for long-lived assets: Distribution....................................... $ 17,493 $ 18,373 $ 66,448 $ 67,574 Transportation and Storage......................... 20,281 -- 25,409 -- All Other.......................................... 50 225 1,477 1,013 ------------- ------------- ------------- ------------- Total segment expenditures for long-lived assets........ 37,824 18,598 93,334 68,587 Reconciling item - Corporate............................ 2,428 1,302 6,748 2,408 ------------- ------------- ------------- ------------- Total consolidated expenditures for long-lived assets... $ 40,252 $ 19,900 $ 100,082 $ 70,995 ============= ============= ============= ============= Reconciliation of net operating revenues (loss) to earnings from continuing operations before income taxes: Net operating revenues (loss)...................... $ 23,979 $ (7,789) $ 174,139 $ 123,372 Interest........................................... (33,964) (21,001) (96,306) (85,008) Dividends on preferred securities of subsidiary trust -- (2,370) (7,110) (9,480) Other income, net.................................. 3,807 16,439 5,762 7,238 ------------- ------------- ------------- ------------- Earnings (loss) from continuing operations before income taxes (benefit)............................... $ (6,178) $ (14,721) $ 76,485 $ 36,122 ============= ============= ============= ============= September 30, June 30, 2003 2002 2003 ------------- ------------- ------------- Total assets: Distribution....................................... $ 2,286,323 $ 2,196,956 $ 2,243,257 Transportation and Storage......................... 2,146,385 -- 2,212,467 All Other.......................................... 46,428 50,940 50,073 ------------ ------------- ------------- Total segment assets.................................... 4,479,136 2,247,896 4,505,797 Reconciling Items: Corporate.......................................... 103,706 75,876 91,928 Sale of assets - Texas Operations.................. -- 396,271 -- ------------- ------------- ------------- Total consolidated assets............................... $ 4,582,842 $ 2,720,043 $ 4,597,725 ============= ============= =============
SOUTHERN UNION COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview. Southern Union Company (Southern Union and together with its subsidiaries, the Company) is primarily engaged in the transportation, storage and distribution of natural gas in the United States. The Company's interstate natural gas transportation and storage operations are conducted through Panhandle Energy, which serves approximately 500 customers in the Midwest and Southwest. Panhandle Energy was acquired by Southern Union on June 11, 2003, as further described below. The Company's local natural gas distribution operations are conducted through its three regulated utility divisions, Missouri Gas Energy, PG Energy and New England Gas Company, which collectively serve over 950,000 residential, commercial and industrial customers in Missouri, Pennsylvania, Rhode Island and Massachusetts. On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy Corporation for approximately $582 million in cash and three million shares of Southern Union common stock (before adjustment for subsequent stock dividends) valued at approximately $49 million based on market prices at closing and in connection therewith incurred transaction costs estimated at approximately $30 million. Southern Union also incurred additional deferred state income tax liabilities estimated at $18 million as a result of the transaction. At the time of the acquisition, Panhandle Energy had approximately $1.159 billion of debt outstanding that it retained. The Company funded the cash portion of the acquisition with approximately $437 million in cash proceeds it received for the January 1, 2003 sale of its Texas operations, approximately $121 million of the net proceeds it received from concurrent common stock and equity units offerings and with working capital available to the Company. The Company structured the Panhandle Energy acquisition and the sale of its Texas operations to qualify as a like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended. The acquisition was accounted for using the purchase method of accounting in accordance with accounting principles generally accepted in the United States of America with the purchase price paid by the Company being allocated to Panhandle Energy's net assets as of the acquisition date based on preliminary estimates. The Panhandle Energy assets acquired and liabilities assumed have been recorded at their estimated fair value as of the acquisition date and are subject to further assessment and adjustment pending the results of outside appraisals. The outside appraisals are expected to be completed prior to December 31, 2003. Panhandle Energy's results of operations have been included in the Consolidated Statement of Operations since June 11, 2003. Thus, the Consolidated Statement of Operations for the periods subsequent to the acquisition is not comparable to the same periods in prior years. Panhandle Energy is primarily engaged in the interstate transportation and storage of natural gas and also provides liquefied natural gas (LNG) terminalling and regasification services and is subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). The Panhandle Energy entities include Panhandle Eastern Pipe Line Company, LLC (Panhandle Eastern Pipe Line), Trunkline Gas Company, LLC (Trunkline), a wholly-owned subsidiary of Panhandle Eastern Pipe Line, Sea Robin Pipeline Company (Sea Robin), a Louisiana joint venture and indirect wholly-owned subsidiary of Panhandle Eastern Pipe Line, Trunkline LNG Company, LLC (Trunkline LNG), a wholly-owned subsidiary of Trunkline LNG Holdings, LLC (LNG Holdings) and Southwest Gas Storage, LLC (Southwest Gas Storage), a wholly-owned subsidiary of Panhandle Eastern Pipe Line. Collectively, the pipeline assets include more than 10,000 miles of interstate pipelines that transport natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes region. The pipelines have a combined peak day delivery capacity of 5.4 billion cubic feet per day and 72 billion cubic feet of owned underground storage capacity. Trunkline LNG, located on Louisiana's Gulf Coast, operates one of the largest LNG import terminals in North America and has 6.3 billion cubic feet of above ground LNG storage facilities. 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 $437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In accordance with accounting principles generally accepted in the United States of America, the assets and liabilities sold have been segregated and reported as "held for sale" in the Consolidated Balance Sheet as of September 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 Consolidated Statement of Cash Flows for all periods presented. 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. No financial gain or loss was recognized on this sales transaction. RESULTS OF OPERATIONS The Company's results of operations are discussed on a consolidated basis and on a segment basis for each of the two reportable segments. The Company's reportable segments include the Transportation and Storage segment and the Distribution segment. Segment results of operations are presented on a net operating revenues basis. Net operating revenues is defined as operating margin, less operating, maintenance and general expenses, depreciation and amortization, and taxes other than on income and revenues, and represents one of the financial measures that the Company uses to internally manage its business. For additional segment reporting information, see Reportable Segments in Notes to Consolidated Financial Statements. Consolidated Results The following table provides selected financial data regarding the Company's consolidated results of operations for the three- and twelve-month periods ended September 30, 2003 and 2002:
Three Months Ended Twelve Months Ended September 30, September 30, 2003 2002 2003 2002 ------------ ------------ ------------ ------------ (thousands of dollars) Net operating revenues (loss): Distribution segment..................................... $ (11,336) $ (6,208) $ 137,635 $ 132,727 Transportation and storage segment....................... 37,918 -- 47,552 -- All other segment........................................ (314) 151 (454) 1,395 Business restructuring charges........................... -- -- -- 1,394 Corporate................................................ (2,289) (1,732) (10,594) (12,144) ------------ ------------ ------------ ------------ Total net operating revenues (loss).................. 23,979 (7,789) 174,139 123,372 Other income (expenses): Interest ................................................ (33,964) (21,001) (96,306) (85,008) Dividends on preferred securities of subsidiary trust.... -- (2,370) (7,110) (9,480) Other, net............................................... 3,807 16,439 5,762 7,238 ------------ ------------ ------------ ------------ Total other expenses, net............................ (30,157) (6,932) (97,654) (87,250) ------------ ------------ ------------ ------------ Federal and state income taxes (benefit)...................... (2,471) (5,535) 27,337 13,882 ------------ ------------ ------------ ------------ Net earnings (loss) from continuing operations................ (3,707) (9,186) 49,148 22,240 ------------ ------------ ------------ ------------ Discontinued operations: Earnings from discontinued operations before income taxes.................................. -- 4,313 80,460 35,181 Federal and state income taxes........................... -- 1,622 50,631 13,889 ------------ ------------ ------------ ------------ Net earnings from discontinued operations..................... -- 2,691 29,829 21,292 ------------ ------------ ------------ ------------ Net earnings (loss) available for (attributable to) $ (3,707) $ (6,495) $ 78,977 $ 43,532 common stock ============ ============ ============ ============
Three Months Ended September 30, 2003 Compared to 2002. The Company recorded a net loss attributable to common stock of $3,707,000 for the three-month period ended September 30, 2003 compared with a net loss of $6,495,000 for the same period in 2002. Net loss per common share, based on weighted average shares outstanding during the period, was $.05 in 2003 compared with $.11 in 2002. Due to the seasonal nature of the Company's natural gas distribution segment, the three-month period ending September 30 is typically a loss period. Net loss from continuing operations was $3,707,000 for the three-month period ended September 30, 2003 compared with $9,186,000 for the same period in 2002. Net loss from continuing operations per share was $.05 in 2003 compared with a net loss of $.16 in 2002. The $5,479,000 decrease in net loss was primarily attributable to an increase in net operating revenues from the Transportation and Storage segment of $37,918,000, which was partially offset by an increase in net operating loss from the Distribution segment of $5,128,000, an increase in interest expense of $12,963,000, a decrease in dividends on preferred securities of $2,370,000, a decrease in other income of $12,632,000 and a decrease in income tax benefit of $3,064,000 (see Business Segment Results, Interest Expense, Dividends on Preferred Securities of Subsidiary Trust, Other Income (Expense), Net and Federal and State Income Taxes, below). Net earnings from discontinued operations were nil for the three-month period ended September 30, 2003 compared with $2,691,000 for the same period in 2002. Net earnings from discontinued operations per share was nil in 2003 compared with $.05 in 2002. Twelve Months Ended September 30, 2003 Compared to 2002. The Company recorded net earnings available for common stock of $78,977,000 for the twelve-month period ended September 30, 2003 compared with net earnings of $43,532,000 for the same period in 2002. Net earnings per diluted share were $1.25 in 2003 compared with $.74 in 2002. Net earnings from continuing operations were $49,148,000 for the twelve-month period ended September 30, 2003 compared with $22,240,000 for the same period in 2002. Net earnings from continuing operations per diluted share were $.78 in 2003 compared with $.38 in 2002. The $26,908,000 increase in net earnings was primarily attributable to increases in net operating revenues from the Transportation and Storage segment and Distribution segment of $47,552,000 and $4,908,000, respectively, and a decrease in dividends on preferred securities of $2,370,000. These items were partially offset by an increase in interest expense of $11,298,000, a decrease in other income of $1,476,000 and an increase in income tax expense of $13,455,000 (see Business Segment Results, Interest Expense, Dividends on Preferred Securities of Subsidiary Trust, Other Income (Expense), Net and Federal and State Income Taxes, below). Net earnings from discontinued operations were $29,829,000 for the twelve-month period ended September 30, 2003 compared with $21,292,000 for the same period in 2002. Net earnings from discontinued operations per diluted share were $.47 in 2003 compared with $.36 in 2002 (see Discontinued Operations, below). Interest Expense. Interest expense was $33,964,000 for the three-month period ended September 30, 2003, compared with $21,001,000 in 2002. Interest expense for the three-month period ended September 30, 2003 increased by $11,723,000 on debt related to the Panhandle properties and by $2,370,000 related to dividends on preferred securities of subsidiary trust (see Dividends on Preferred Securities of Subsidiary Trust). These items were partially offset by decreased interest expense of $1,245,000 on the $311,087,000 bank note (the 2002 Term Note) entered into by the Company on July 15, 2002 to refinance a portion of the $485 million Term Note entered into by the Company on August 28, 2000 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) acquisition costs of the New England Operations. This decrease in the 2002 Term Note interest was due to reductions in LIBOR rates during 2003 and the principal repayment of $125,000,000 of the 2002 Term Note since its inception. The average rate of interest on all debt decreased from 6.5% in 2002 to 5.0% in 2003. Interest expense was $96,306,000 for the twelve-month period ended September 30, 2003, compared with $85,008,000 in 2002. Interest expense for the twelve-month period ended September 30, 2003 increased by $13,403,000 on debt related to the Panhandle properties and by $2,370,000 related to dividends on preferred securities of subsidiary trust (see Dividends on Preferred Securities of Subsidiary Trust). These items were partially offset by a decrease in interest expense of $5,796,000 in 2003 on the aforementioned 2002 Term Note. The average rate of interest on all debt decreased from 6.1% in 2002 to 5.5% in 2003. Dividends on Preferred Securities of Subsidiary Trust. Dividends on preferred securities of subsidiary trust were nil and $2,370,000 for the three-month periods ended September 30, 2003 and 2002, respectively, and $7,110,000 and $9,480,000 for the twelve-month periods ended September 30, 2003 and 2002, respectively. Effective July 1, 2003, the Company adopted the FASB standard, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which requires dividends on preferred securities of subsidiary trusts to be classified as interest expense; the reclassification of amounts reported as dividends in prior periods is not permitted. In accordance with the Statement, $2,370,000 of dividends on preferred securities of subsidiary trust recorded by the Company subsequent to July 1, 2003, have been classified as interest expense (see Interest Expense). Other Income (Expense), Net. Other income for the three-month period ended September 30, 2003 was $3,807,000 compared with $16,439,000 for the same period in 2002. Other income for the three-month period ended September 30, 2003 includes a gain of $6,123,000 on the early extinguishment of debt and income of $784,000 generated from the sale and/or rental of gas-fired equipment and appliances by various operating subsidiaries. These items were partially offset by charges of $1,603,000 and $1,150,000 to reserve for the impairment of Southern Union's investments in a technology company and in an energy-related joint venture, respectively, and $278,000 of legal costs associated with the collection of damages from former Arizona Corporation Commissioner James Irvin related to the unsuccessful acquisition of Southwest Gas Corporation (Southwest). Other income for the three-month period ended September 30, 2002 includes a gain of $17,500,000 on the settlement of the Company's claims related to the Southwest case, which was partially offset by $2,131,000 of related legal costs, and income of $601,000 generated from the sale and/or rental of gas-fired equipment and appliances. Other income for the twelve-month period ended September 30, 2003 was $5,762,000 compared with $7,238,000 for the same period in 2002. Other income for the twelve-month period ended September 30, 2003 includes a gain of $6,123,000 on the early extinguishment of debt, a gain of $5,000,000 on the settlement of the Company's claims related to the Southwest case, income of $1,833,000 generated from the sale and/or rental of gas-fired equipment and appliances and $605,000 in previously recorded deferred income related to financial derivative energy trading activity of a former subsidiary. These items were partially offset by $4,096,000 of legal costs associated with the Southwest case, $1,298,000 of selling costs associated with the Texas operations' disposition and charges of $1,603,000 and $1,150,000 to reserve for the impairment of Southern Union's investments in a technology company and in an energy-related joint venture, respectively. Other income for the twelve-month period ended September 30, 2002 includes a gain of $17,500,000 on the settlement of the Company's claims related to the Southwest case, the recognition of $5,997,000 in previously recorded deferred income related to financial derivative energy trading activity, income of $2,134,000 generated from the sale and/or rental of gas-fired equipment and appliances, a gain of $1,004,000 realized on the sale of investment securities and a gain of $1,200,000 realized through the sale of certain propane assets. These items were partially offset by a $10,380,000 charge to reserve for the impairment of the Company's investment in a technology company, $9,625,000 of legal costs associated with the Southwest case and a $1,500,000 loss on the sale of the Florida Operations. Federal and State Income Taxes. Federal and state income tax benefit from continuing operations for the three-month period ended September 30, 2003 and 2002 was $2,471,000 and $5,535,000, respectively. The Company's consolidated federal and state effective income tax rate was 40% and 38% for the three-month period ended September 30, 2003 and 2002, respectively. The increase in the effective tax rate is primarily the result of a change in the level of pre-tax earnings and additional state income taxes due to the acquisition of Panhandle Energy. Federal and state income tax expense from continuing operations for the twelve-month period ended September 30, 2003 and 2002 was $27,337,000 and $13,882,000, respectively. The Company's consolidated federal and state effective income tax rate was 36% and 38% for the twelve-month period ended September 30, 2003 and 2002, respectively. The decline in the effective tax rate is a result of non-tax deductible write-off of goodwill as a result of the sale of the Florida Operations during the twelve-month period ended September 30, 2002 along with a change in the level of pre-tax earnings. Discontinued Operations. Net earnings from discontinued operations were $29,829,000 for the twelve-month period ended September 2003 compared with $21,292,000 for the same period in 2002. The Company completed the sale of its Texas Operations effective January 1, 2003, resulting in the recording of an after-tax gain on sale of $18,928,000 during the quarter ended March 31, 2003 that is reported in earnings from discontinued operations in accordance with the Financial Accounting Standards Board (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. The timing of the Texas Operations' disposition resulted in a $19,160,000 decrease in pre-tax earnings from discontinued operations in 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 previously mentioned FASB standard, once the assets of the Texas Operations were deemed to be "held for sale" in October 2002, depreciation of such assets ceased. Business Segment Results Distribution Segment -- The Company's Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, Pennsylvania, Rhode Island and Massachusetts. Its operations are conducted through the Company's three regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas Company. Collectively, the utility divisions serve more than 950,000 residential, commercial and industrial customers. The following table provides summary data regarding the Distribution segment's results of operations for the three- and twelve-month periods ending September 30, 2003 and 2002:
Three Months Ended Twelve Months Ended September 30, September 30, 2003 2002 2003 2002 ------------- ------------- ------------- -------------- (thousands of dollars) Operating revenues........................................ $ 116,029 $ 98,135 $ 1,176,858 $ 952,003 Cost of gas and other energy.............................. (57,370) (41,678) (739,412) (551,264) Revenue-related taxes..................................... (4,325) (3,186) (41,623) (32,689) ------------- ------------- ------------- ------------- Operating margin...................................... 54,334 53,271 395,823 368,050 Operating expenses: Operating, maintenance, and general................... 45,273 39,033 177,702 158,045 Depreciation and amortization......................... 14,680 14,210 56,866 54,662 Taxes other than on income and revenues............... 5,717 6,236 23,620 22,616 ------------- ------------- ------------- -------------- Total operating expense............................ 65,670 59,479 258,188 235,323 ------------- ------------- ------------- -------------- Net operating revenues (loss)...................... $ (11,336) $ (6,208) $ 137,635 $ 132,727 ============= ============= ============= ==============
Operating Revenues. Operating revenues were $116,029,000 for the three-month period ended September 30, 2003, compared with $98,135,000 for the same period in 2002. Gas purchase and other energy costs for the three-month period ended September 30, 2003 were $57,370,000, compared with $41,678,000 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 and 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 16% increase in gas sales volumes to 8,695 MMcf in 2003 from 7,490 MMcf in 2002, and by a 19% increase in the average cost of gas from $5.56 per Mcf in 2002 to $6.60 per Mcf in 2003. 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 entire energy industry. Operating revenues were $1,176,858,000 for the twelve-month period ended September 30, 2003, compared with $952,003,000 for the same period in 2002. Gas purchase and other energy costs for the twelve-month period ended September 30, 2003 were $739,412,000, compared with $551,264,000 in 2002. The increase in both operating revenues and gas purchase costs between periods was primarily due to a 21% increase in gas sales volumes to 121,607 MMcf in 2003 from 100,640 MMcf in 2002, and by an 11% increase in the average cost of gas from $5.48 per Mcf in 2002 to $6.08 per Mcf in 2003. The increase in gas sales volume is primarily due to normal or colder-than-normal weather in the Company's utility service territories in 2003 as compared with warmer-than-normal weather in 2002. 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 entire energy industry. Weather in Missouri Gas Energy's service territories was 100% of a 30-year measure for the twelve-month period ended September 30, 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 107% of a 30-year measure for 2003, compared with 86% in 2002. Operating Margin. Operating margin (operating revenues less gas purchase and other energy costs and revenue-related taxes) increased $1,063,000 for the three-month period ended September 30, 2003 compared with the same period in 2002. Operating margins and earnings are primarily dependent upon gas sales volumes and gas service rates. The level of gas sales volumes is sensitive to the variability of the weather as well as the timing of acquisitions and divestitures. Operating margin increased $27,773,000 for the twelve-month period ended September 30, 2003 compared with the same period in 2002, principally as a result of the colder-than-normal weather, previously discussed. Operating Expenses. Operating expenses, which include operating, maintenance and general expenses, depreciation and amortization and taxes other than on income and revenues, were $65,670,000 for the three-month period ended September 30, 2003, an increase of $6,191,000, compared with $59,479,000 for the same period in 2002. Operating expenses were impacted by increased pension and other post retirement benefits costs primarily due to the impact of stock market volatility on plan assets, increased bad debt expense resulting from higher customer receivables due to higher gas prices, and increased insurance expense. Operating expenses were $258,188,000 for the twelve-month period ended September 30, 2003, an increase of $22,865,000, as compared with $235,323,000 for the same period in 2002. Operating expenses were impacted by increased employee payroll and other operating and maintenance costs primarily as a result of the colder weather in 2003, as well as $8,291,000 of increased pension and other post retirement benefits costs, $3,562,000 of increased bad debt expense and $975,000 of increased insurance expense, all previously discussed. Transportation and Storage Segment -- The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy, which the Company acquired on June 11, 2003. Panhandle Energy operates a large natural gas pipeline network, which provides approximately 500 customers in the Midwest and Southwest with a comprehensive array of transportation services. Panhandle Energy's major customers include 25 utilities located primarily in the United States Midwest market area, which encompasses large portions of Illinois, Indiana, Michigan, Missouri, Ohio and Tennessee. The results of operations from Panhandle Energy have been included in the Consolidated Statement of Operations since June 11, 2003. The following table provides summary data regarding the Transportation and Storage segment's results of operations for the three- and twelve-month periods ended September 30, 2003.
Three Months June 12, 2003 Ended to September 30, 2003 September 30, 2003 ------------------ ------------------ (thousands of dollars) Financial Results Transportation and storage revenues............................... $ 96,369 $ 116,970 LNG terminalling revenues......................................... 15,636 18,880 Other revenues .................................................. 2,214 2,897 ----------------- ----------------- Total operating revenues...................................... 114,219 138,747 Operating expenses: Operating, maintenance, and general........................... 52,934 63,036 Depreciation and amortization................................. 16,348 19,545 Taxes other than on income and revenues....................... 7,019 8,614 ----------------- ----------------- Total operating expense.................................... 76,301 91,195 ----------------- ----------------- Net operating revenues..................................... $ 37,918 $ 47,552 ================= =================
The following table sets forth gas throughput and related information for the Company's Distribution segment and Transportation and Storage segment for the three- and twelve-month periods ended September 30, 2003 and 2002:
Three Months Twelve Months Ended September 30, Ended September 30, ----------------------- --------------------------- 2003 2002 2003 2002 ----------- ---------- ------------ ------------ Distribution Segment Average number of gas sales customers served: Residential................................................. 834,690 831,382 841,770 838,363 Commercial.................................................. 98,880 96,863 100,938 95,948 Industrial and irrigation................................... 445 658 444 3,020 Public authorities and other................................ 388 373 381 363 ----------- ---------- ------------ ------------ Total average gas sales customers served................ 934,403 929,276 943,533 937,694 Average number of transportation customers served................ 2,561 2,532 2,543 2,552 ----------- ---------- ------------ ------------ Total average gas sales and transportation customers.... 936,964 931,808 946,076 940,246 =========== ========== ============ ============ Gas sales in millions of cubic feet (MMcf) Residential................................................. 5,103 4,723 84,055 69,916 Commercial.................................................. 2,527 2,339 34,046 27,398 Industrial and irrigation................................... 440 609 2,652 3,705 Public authorities and other................................ 19 20 360 169 ----------- ---------- ------------ ------------ Gas sales billed........................................ 8,089 7,691 121,113 101,188 Net change in unbilled gas sales............................ 606 (201) 494 (548) ----------- ---------- ------------ ------------ Total gas sales......................................... 8,695 7,490 121,607 100,640 Gas transported in MMcf.......................................... 12,929 13,262 65,885 64,943 ----------- ---------- ------------ ------------ Total gas sales and gas transported in MMcf............. 21,624 20,752 187,492 165,583 =========== ========== ============ ============ Gas sales revenues (thousands of dollars): Residential................................................. $ 71,316 $ 62,326 $ 811,908 $ 669,200 Commercial.................................................. 27,817 22,093 298,247 231,519 Industrial and irrigation................................... 3,770 4,147 22,041 28,673 Public authorities and other................................ 259 288 3,159 1,563 ----------- ---------- ------------ ------------ Gas revenues billed..................................... 103,162 88,854 1,135,355 930,955 Net change in unbilled gas sales revenues................... 5,190 1,876 (5,774) (7,650) ----------- ---------- ------------ ------------ Total gas sales revenues................................ 108,352 90,730 1,129,581 923,305 Gas transportation revenues (thousands of dollars)............... 6,014 6,834 38,208 36,090 ----------- ---------- ------------ ------------ Total gas sales and gas transportation revenues......... $ 114,366 $ 97,564 $ 1,167,789 $ 959,395 =========== ========== ============ ============ Gas sales revenue per thousand cubic feet billed: Residential................................................. $ 13.98 $ 13.20 $ 9.66 $ 9.57 Commercial.................................................. 11.01 9.45 8.76 8.45 Industrial and irrigation................................... 8.57 6.81 8.31 7.74 Public authorities and other................................ 13.63 14.40 8.78 9.25 Weather: Degree days: Missouri Gas Energy service territories................ 87 14 5,178 4,366 PG Energy service territories.......................... 105 100 6,659 5,278 New England Gas Company service territories............ 32 25 6,153 4,930 Percent of 30-year measure: Missouri Gas Energy service territories................ 134% 22% 100% 84% PG Energy service territories.......................... 64% 61% 106% 84% New England Gas Company service territories............ 28% 22% 107% 86% Transportation and Storage Segment Gas transported in billions of British thermal units (Bbtu)...... 325,198 -- 394,057 -- Gas transportation revenues (thousands of dollars)............... $ 86,378 $ -- $ 104,882 $ --
______________________________________________ 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 September 30, 2003 and 2002. The information for the twelve-months ended September 30, 2003, includes Panhandle Energy's operations since the June 11, 2003 acquisition date. 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. FINANCIAL CONDITION The Company's operations are seasonal in nature with a significant percentage of the annual revenues and earnings occurring in the traditional heating-load months. In the Distribution segment, 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 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 April 3, 2003, the Company entered into a short-term credit facility in the amount of $140,000,000 (the Short Term Facility), that matures April 1, 2004. The Short-Term Facility was increased to $150,000,000 as of September 25, 2003. Also on April 3, 2003, 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 September 30, 2003, the commitment fees were an annualized 0.15% 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 $229,400,000 was outstanding under the Facilities at November 7, 2003. In July 2003, Panhandle Energy announced a tender offer for any and all of the $747 million outstanding principal amount of five of its series of senior notes outstanding at that point in time (the Panhandle Tender Offer) and also called for redemption all of the outstanding $135 million principal amount of its two series of debentures that were outstanding (the Panhandle Calls). Panhandle Energy repurchased approximately $378 million of the principal amount of its outstanding debt through the Panhandle Tender Offer for total consideration of approximately $396 million plus accrued interest through the purchase date. Panhandle Energy also redeemed approximately $135 million of debentures through the Panhandle Calls for total consideration of $139 million, plus accrued interest through the redemption dates. As a result of the Panhandle Tender Offer, the Company has recorded a pre-tax gain on the extinguishment of debt of approximately $6.1 million in August 2003. In August 2003, Panhandle Energy issued $300 million of its 4.80% Senior Notes due 2008 and $250 million of its 6.05% Senior Notes due 2013 principally to refinance the repurchased notes and redeemed debentures. Also in August and September 2003, Panhandle Energy repurchased $3.2 million principal amount of its senior notes on the open market through two transactions for total consideration of $3.4 million, plus accrued interest through the repurchase date. On October 1, 2003, the Company called its Subordinated Notes for redemption, and its Subordinated Notes and related Preferred Securities were redeemed on October 31, 2003 (see Preferred Securities in Notes to Consolidated Financial Statements). The Company financed the redemption with borrowings under its revolving credit facilities, which were paid down with the net proceeds of a $230 million offering of preferred stock by the Company on October 8, 2003, as further described below. On October 8, 2003, the Company issued 800,000 shares of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) to the public through the issuance of 8,000,000 Depositary Shares, each representing a one-tenth interest in a 7.55% Noncumulative Preferred Stock, Series A share (the Depositary Shares) at a public offering price of $25.00 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions, of $195.2 million in the aggregate. The Company granted the underwriters a 30-day over-allotment option to purchase up to an additional 1,200,000 Depositary Shares under the same terms and conditions, which was exercised on October 8, 2003, resulting in additional net proceeds to the Company of $29.0 million. The total net proceeds were used to pay down debt under the Company's revolving credit facilities. The principal source of funds during the three-month period ended September 30, 2003 were $550,000,000 from the issuance of long-term debt and $72,300,000 in net borrowings under revolving credit facilities. This provided funds of $577,917,000 for the repayment of debt and capital lease obligations and $40,252,000 for on-going property, plant and equipment additions; as well as seasonal working capital needs of the Company. The effective interest rate under the Company's current debt structure is 5.33% (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. The Company has an effective shelf registration statement on file with the Securities and Exchange Commission for a total principal amount of $800,000,000 in securities of which $47,750,000 in securities is available for issuance as of November 7, 2003, which may be issued by the Company in the form of debt securities, common stock, preferred stock, guarantees, warrants to purchase common stock, preferred stock and debt securities, stock purchase contracts, stock purchase units and depositary shares in the event that the Company elects to offer fractional interests in preferred stock, and also trust preferred securities to be issued by Southern Union Financing II and Southern Union Financing III. Southern Union may sell such securities up to such amounts from time to time, at prices determined at the time of any such offering. 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, 2003. 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, 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 Customer Concentrations. In the Transportation and Storage segment, aggregate sales to Panhandle Energy's top 10 customers accounted for 71% of segment operating revenues and 35% of total consolidated operating revenues for the three-month period ended September 30, 2003. This included sales to BG LNG Services, a nonaffiliated gas marketer, which accounted for 20% of segment operating revenues; sales to Proliance Energy, LLC, a nonaffiliated local distribution company and gas marketer, which accounted for 15% of segment operating revenues; and sales to CMS Energy Corporation, Panhandle Energy's former parent, which accounted for 13% of segment operating revenues. No other customer accounted for 10% or more of the Transportation and Storage segment operating revenues, and no customer accounted for 10% or more of total consolidated operating revenues, for the three-month period ended September 30, 2003. Cash Management. FERC issued Order No. 634, effective December 1, 2003. Order No. 634 requires all FERC-regulated entities that participate in cash management programs (i) to establish and file with FERC for public review written cash management procedures including specification of duties and responsibilities of cash management program participants and administrators, specification of the methods for calculating interest and allocation of interest income and expenses, and specification of any restrictions on deposits or borrowings by participants, and (ii) to document monthly cash management activity. Order No. 634 also requires a FERC-regulated entity to notify FERC within 45 days when its proprietary capital ratio falls below 30 percent or subsequently returns to or exceeds 30 percent. New FERC Reporting Requirements. On June 29, 2003, the FERC proposed substantial new quarterly reporting requirements for each FERC-regulated entity. The Notice of Proposed Rulemaking (NOPR) is proposed to be effective for reporting first quarter 2004 results. Panhandle Energy is currently studying the implications of the NOPR to Panhandle Eastern Pipe Line, Trunkline, Trunkline LNG, Sea Robin and Southwest Gas Storage. Marketing Affiliate Notice of Proposed Rulemaking. In September 2001, the FERC issued a NOPR proposing to apply the standards of conduct governing the relationship between interstate pipelines and marketing affiliates to all energy affiliates. The proposed regulations, if adopted by the FERC, would dictate how energy affiliates conduct business and interact with interstate pipelines. At this time, Panhandle Energy cannot predict the outcome of the NOPR, but adoption of the regulations in their proposed form would, at a minimum, result in additional administrative and operational burdens. Pipeline Safety Notice of Proposed Rulemaking. In January 2003, the U.S.Department of Transportation issued a NOPR proposing to establish a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the notice refers to as "high consequence areas." The proposed rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002, a new bill signed into law in December 2002. Comments on the NOPR were filed on April 30, 2003. Although the Company cannot predict the outcome of this rulemaking, the order is not expected to have a material impact on the Company's Transportation and Storage segment operations. 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 Quarterly Report on Form 10-Q 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. Similarly, statements that describe our objectives, plans or goals are or may be 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 results, performance and achievements may differ materially from what is expressed or forecasted in such forward-looking statements. The Company undertakes no obligation to publicly update 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 actual results to differ materially from those expressed in our forward-looking statements include, but are not limited to, the following: cost of gas; gas sales volumes; gas throughput volumes and available sources of natural gas; discounting of transportation rates due to competition; abnormal weather conditions in our service territories; the impact of relations with labor unions of bargaining-unit union employees; the receipt of timely and adequate rate relief and the impact of future rate cases or regulatory rulings; the outcome of pending and future litigation; the speed and degree to which competition is introduced to our gas distribution business; new legislation and government regulations affecting or involving the Company; unanticipated environmental liabilities; the Company's ability to comply with or to challenge successfully existing or new environmental regulations; changes in business strategy and the success of new business ventures; the nature and impact of any extraordinary transactions, such as any acquisition or divestiture of a business unit or any assets; the economic climate and growth in our industry and service territories and competitive conditions of energy markets in general; inflationary trends; changes in gas or other energy market commodity prices and interest rates; the current market conditions causing more customer contracts to be of shorter duration, which may increase revenue volatility; exposure to customer concentration with a significant portion of revenues realized from a relatively small number of customers and any credit risks associated with the financial position of those customers; our or any of our subsidiaries' debt securities ratings; factors affecting operations such as maintenance or repairs, environmental incidents or gas pipeline system constraints; the possibility of war or terrorist attacks; and other risks and unforeseen events. In light of these risks, uncertainties and assumptions, the results reflected in our forward-looking statements might not occur. In addition, we 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. SOUTHERN UNION COMPANY AND SUBSIDIARIES CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures We performed an evaluation 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 the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of September 30, 2003 and have communicated that determination to the Audit Committee of our Board of Directors. Changes in Internal Controls There have been no significant changes in our internal controls or other factors that could significantly affect internal controls subsequent to their evaluation for the quarterly period ended September 30, 2003. EXHIBITS AND REPORTS ON FORM 8-K Exhibits: The following exhibits are filed as part of this amended quarterly report on Form 10-Q/A of Southern Union Company: 31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350. 32.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350. Reports on Form 8-K: The Company filed the following Current Reports on Form 8-K during the quarter ended September 30, 2003: Date Filed Description of Filing ---------- -------------------------------------------------------------- 7/09/03 Announcement that Southern Union Company's wholly-owned subsidiary, Panhandle Eastern Pipe Line Company, LLC announced the commencement of cash tender offers to purchase certain of its debt. 8/06/03 Announcement of operating performance for the quarter and year ended June 30, 2003 and 2002 and filing, under Item 12, summary statements of income of Southern Union Company for the quarter and year ended June 30, 2003 and 2002 (unaudited) and notes thereto. 8/12/03 Furnishing under Item 9, the unaudited pro forma consolidated condensed statement of operations of Panhandle Eastern Pipe Line Company, LLC for the following periods: June 12 through June 30, 2003; January 1 through June 11, 2003; and the year ended December 31, 2002. 8/19/03 Announcement of the consideration to be paid by Panhandle Eastern Pipe Line Company, LLC in its previously announced cash tender offers to purchase certain of its debt. Also, announcement by Panhandle Eastern Pipe Line Company, LLC of the following: completion of the cash tender offers on August 18, 2003 and the amounts of each series of its notes that it repurchased; the redemption of all of its outstanding debentures on August 12 and 15, 2003; and a private placement of new senior notes. 9/02/03 Filing under Item 11, notice of the temporary suspension of trading under Southern Union Company's employee benefit plans necessitated in order for the plan administrator to enhance services under the plan and to transfer and reconcile the plan's records. 9/29/03 Announcement that Southern Union Company plans to offer $200,000,000 of depositary shares, which represent interests in its shares of noncumulative preferred stock, series A, and filing, under Item 7, the following exhibits: Consent of Independent Public Accountants, Ernst & Young LLP, relating to certain historical financial statements of Panhandle Eastern Pipe Line Company attached to a Current Report on Form 8-K filed by Southern Union Company on May 30, 2003; Computation of Ratio of Earnings to Fixed Charges of Southern Union Company; and certain material contracts relating to Panhandle Eastern Pipe Line Company, LLC. 9/30/03 Filing under Item 7, certain material contracts of Panhandle Eastern Pipe Line Company, LLC. - -------------------------------------------------------------------------------- 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 7, 2004 By DAVID J. KVAPIL ------------------------------ ------------------------------------- David J. Kvapil Executive Vice President and Chief Financial Officer Exhibit 31.1 CERTIFICATIONS I, George L. Lindemann, certify that: (1) I have reviewed this amended quarterly report on Form 10-Q/A of Southern Union Company; (2) Based on my knowledge, this 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 report; (3) Based on my knowledge, the financial statements, and other financial information included in this 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 report; (4) The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and (5) The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 7, 2004 GEORGE L. LINDEMANN - ---------------------------------------------------------- George L. Lindemann Chairman of the Board and Chief Executive Officer (principal executive officer) Exhibit 31.2 CERTIFICATIONS I, David J. Kvapil, certify that: (1) I have reviewed this amended quarterly report on Form 10-Q/A of Southern Union Company; (2) Based on my knowledge, this 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 report; (3) Based on my knowledge, the financial statements, and other financial information included in this 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 report; (4) The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and (5) The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 7, 2004 DAVID J. KVAPIL - ---------------------------------------------------------- David J. Kvapil Executive Vice President and Chief Financial Officer (principal financial officer) Exhibit 32.1 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/A of Southern Union Company (the "Company") for the quarter ended September 30, 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 7, 2004 This certification is furnished pursuant to Item 601 of Regulation S-K and shall not be deemed filed by the Company for purposes of ss.18 of the Securities Exchange Act of 1934, as amended, or otherwise be subject to the liability of that section. Such certification shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the Company specifically incorporates it by reference. Exhibit 32.2 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/A of Southern Union Company (the "Company") for the quarter ended September 30, 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 7, 2004 This certification is furnished pursuant to Item 601 of Regulation S-K and shall not be deemed filed by the Company for purposes of ss.18 of the Securities Exchange Act of 1934, as amended, or otherwise be subject to the liability of that section. Such certification shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the Company specifically incorporates it by reference. -----END PRIVACY-ENHANCED MESSAGE-----