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