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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
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.
- --------------------------------------------------------------------------------
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 June 30, 2003 4-5
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 ended
September 30, 2003 and 2002 7-8
Notes to consolidated financial statements 9-25
Item 2. Management's Discussion and Analysis of Financial Condition and Results 26-37
of 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 Quarterly Report on Form 10-Q:
31.1 Certificate by 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 Certificate by 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 Certificate by 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 Certificate by 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 November 14, 2003 By DAVID J. KVAPIL
------------------------------ ---------------------------------
David J. Kvapil
Executive Vice President and
Chief Financial Officer
Exhibit 31.1
CERTIFICATE PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
I, George L. Lindemann, certify that:
(1) I have reviewed this quarterly report on Form 10-Q of Southern Union
Company;
(2) Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
(3) Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
(4) The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
(5) The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
Audit Committee of the Company's Board of Directors:
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
(6) The registrant's other certifying officer and I have indicated in
this quarterly report whether or not there were significant changes
in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
GEORGE L. LINDEMANN
- ----------------------------------------------------------
George L. Lindemann
Chairman of the Board and
Chief Executive Officer
November 14, 2003
Exhibit 31.2
CERTIFICATE PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
I, David J. Kvapil, certify that:
(1) I have reviewed this quarterly report on Form 10-Q of Southern Union
Company;
(2) Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
(3) Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
(4) The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
(5) The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
Audit Committee of the Company's Board of Directors:
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
(6) The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
DAVID J. KVAPIL
- ----------------------------------------------------------
David J. Kvapil
Executive Vice President and
Chief Financial Officer
November 14, 2003
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 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
November 14, 2003
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 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
November 14, 2003
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.