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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED
DECEMBER 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
--- ---
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
Yes |X| No
--- ---
The number of shares of the registrant's Common Stock outstanding on February 6,
2004 was 73,087,107.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
FORM 10-Q
DECEMBER 31, 2003
INDEX
PART I. FINANCIAL INFORMATION Page(s)
-------
Item 1. Financial Statements:
Consolidated statements of operations - three and six months ended
December 31, 2003 and 2002 2-3
Consolidated balance sheet - December 31, 2003 and June 30, 2003 4-5
Consolidated statement of stockholders' equity - six months ended December 31, 2003
and twelve months ended June 30, 2003 6
Consolidated statements of cash flows - three and six months ended
December 31, 2003 and 2002 7-8
Notes to consolidated financial statements 9-24
Item 2. Management's Discussion and Analysis of Financial Condition and Results 25-37
of Operations
Item 3. Quantitative and Qualitative Disclosures about Market Risk 34
Item 4. Controls and Procedures 36
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
(See "COMMITMENTS AND CONTINGENCIES" in Notes to Consolidated
Financial Statements) 17-22
Item 4. Result of Votes of Security Holders 37
Item 6. Exhibits and Reports on Form 8-K 38
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
THREE MONTHS ENDED DECEMBER 31,
-------------------------------
2003 2002
---- ----
(THOUSANDS OF DOLLARS, EXCEPT
SHARES AND PER SHARE AMOUNTS)
Operating revenues ......................................................... $ 507,113 $ 346,104
Cost of gas and other energy ............................................... (253,880) (215,505)
Revenue-related taxes ...................................................... (13,136) (12,568)
--------- ---------
Operating margin ...................................................... 240,097 118,031
Operating expenses:
Operating, maintenance and general .................................... 100,888 42,249
Depreciation and amortization ......................................... 31,697 14,067
Taxes, other than on income and revenues .............................. 12,135 6,213
--------- ---------
Total operating expenses .......................................... 144,720 62,529
--------- ---------
Net operating revenues ............................................ 95,377 55,502
--------- ---------
Other income (expense):
Interest .............................................................. (32,636) (20,742)
Dividends on preferred securities of subsidiary trust ................. -- (2,370)
Other, net ............................................................ 514 (2,712)
--------- ---------
Total other expenses, net ......................................... (32,122) (25,824)
--------- ---------
Earnings from continuing operations before income taxes .................... 63,255 29,678
Federal and state income taxes ............................................. 24,833 11,159
--------- ---------
Net earnings from continuing operations .................................... 38,422 18,519
--------- ---------
Discontinued operations:
Earnings from discontinued operations before income taxes ............. -- 17,468
Federal and state income taxes ........................................ -- 6,568
--------- ---------
Net earnings from discontinued operations .................................. -- 10,900
--------- ---------
Net earnings ............................................................... 38,422 29,419
Preferred stock dividends .................................................. (4,004) --
--------- ---------
Net earnings available for common stock .................................... $ 34,418 $ 29,419
========= =========
Net earnings available for common stock from continuing operations:
per share:
Basic ................................................................. $ 0.48 $ .33
========= ========
Diluted................................................................ $ 0.47 $ .32
========= ========
Net earnings available for common stock per share:
Basic ................................................................. $ 0.48 $ .52
========= ========
Diluted ............................................................... $ 0.47 $ .50
========= ========
Weighted average shares outstanding:
Basic ................................................................. 71,759,349 56,919,821
========== ==========
Diluted ............................................................... 73,957,901 58,737,336
========== ==========
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
SIX MONTHS ENDED DECEMBER 31,
-----------------------------
2003 2002
---- ----
(THOUSANDS OF DOLLARS, EXCEPT
SHARES AND PER SHARE AMOUNTS)
Operating revenues ......................................................... $ 738,507 $ 445,814
Cost of gas and other energy ............................................... (311,640) (257,565)
Revenue-related taxes ...................................................... (17,461) (15,754)
--------- ---------
Operating margin ...................................................... 409,406 172,495
Operating expenses:
Operating, maintenance and general .................................... 201,968 83,620
Depreciation and amortization ......................................... 63,031 28,451
Taxes, other than on income and revenues .............................. 25,051 12,711
--------- ---------
Total operating expenses .......................................... 290,050 124,782
--------- ---------
Net operating revenues ............................................ 119,356 47,713
--------- ---------
Other income (expense):
Interest .............................................................. (66,600) (41,743)
Dividends on preferred securities of subsidiary trust ................. -- (4,740)
Other, net ............................................................ 4,321 13,726
--------- ---------
Total other expenses, net ......................................... (62,279) (32,757)
--------- ---------
Earnings from continuing operations before income taxes .................... 57,077 14,956
Federal and state income taxes ............................................. 22,362 5,623
--------- ---------
Net earnings from continuing operations .................................... 34,715 9,333
--------- ---------
Discontinued operations:
Earnings from discontinued operations before income taxes ............. -- 21,781
Federal and state income taxes ........................................ -- 8,190
--------- --------
Net earnings from discontinued operations .................................. -- 13,591
--------- --------
Net earnings ............................................................... 34,715 22,924
Preferred stock dividends .................................................. (4,004) --
--------- --------
Net earnings available for common stock .................................... $ 30,711 $ 22,924
========== ==========
Net earnings available for common stock from continuing operations:
per share:
Basic ................................................................. $ .43 $ .16
========= =========
Diluted ............................................................... $ .42 $ .16
========= =========
Net earnings available for common stock per share:
Basic ................................................................. $ .43 $ .40
========= =========
Diluted ............................................................... $ .42 $ .39
========= =========
Weighted average shares outstanding:
Basic ................................................................. 71,748,220 56,713,616
========== ==========
Diluted ............................................................... 73,804,782 58,671,826
========== ==========
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
ASSETS
DECEMBER 31, JUNE 30,
2003 2003
---- ----
(THOUSANDS OF DOLLARS)
Property, plant and equipment:
Plant in service .............................. $ 3,763,036 $ 3,710,541
Construction work in progress ................. 119,132 75,484
----------- -----------
3,882,168 3,786,025
Less accumulated depreciation and amortization (698,858) (641,225)
----------- -----------
Net property, plant and equipment ........ 3,183,310 3,144,800
----------- -----------
Current assets:
Cash and cash equivalents ..................... 20,810 86,997
Accounts receivable, billed and unbilled, net.. 309,038 192,402
Federal and state taxes receivable ............ 22,468 6,787
Inventories ................................... 230,854 173,757
Deferred gas purchase costs ................... 26,445 24,603
Gas imbalances - receivable ................... 26,974 34,911
Prepayments and other ......................... 29,948 18,971
----------- -----------
Total current assets ..................... 666,537 538,428
----------- -----------
Goodwill, net ...................................... 642,921 642,921
Deferred charges ................................... 186,959 188,261
Investment securities, at cost ..................... 8,038 9,641
Other .............................................. 67,310 73,674
----------- -----------
Total assets .................................. $ 4,755,075 $ 4,597,725
=========== ===========
See accompanying notes.
- --------------------------------------------------------------------------------
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET (CONTINUED)
STOCKHOLDERS' EQUITY AND LIABILITIES
DECEMBER 31, JUNE 30,
2003 2003
---- ----
(THOUSANDS OF DOLLARS)
Stockholders' equity:
Common stock, $1 par value; authorized 200,000,000 shares;
issued 73,181,995 shares ............................................ $ 73,182 $ 73,074
Premium on capital stock .................................................... 903,757 909,191
Preferred stock, no par value; authorized 6,000,000 shares;
issued 920,000 shares ................................................... 230,000 --
Less treasury stock, 282,333 shares at cost ................................. (10,467) (10,467)
Less common stock held in trust ............................................. (16,904) (15,617)
Deferred compensation plans ................................................. 11,247 9,960
Accumulated other comprehensive income (loss) ............................... (61,880) (62,579)
Retained earnings ........................................................... 47,567 16,856
----------- -----------
Total stockholders' equity .................................................. 1,176,502 920,418
Company-obligated mandatorily redeemable preferred securities of subsidiary
trust holding solely subordinated notes of Southern Union ................... -- 100,000
Long-term debt and capital lease obligation ...................................... 2,004,408 1,611,653
----------- -----------
Total capitalization .................................................... 3,180,910 2,632,071
Current liabilities:
Long-term debt and capital lease obligation due within one year ............. 260,729 734,752
Notes payable ............................................................... 252,000 251,500
Accounts payable ............................................................ 143,797 112,840
Federal, state and local taxes .............................................. 36,395 13,530
Accrued interest ............................................................ 38,484 40,871
Customer deposits ........................................................... 12,834 12,585
Gas imbalances - payable .................................................... 66,049 64,519
Other ....................................................................... 130,754 130,196
----------- -----------
Total current liabilities ............................................... 941,042 1,360,793
----------- -----------
Deferred credits and other ....................................................... 312,306 322,154
Accumulated deferred income taxes ................................................ 320,817 282,707
----------- -----------
Total stockholders' equity and liabilities .................................. $ 4,755,075 $ 4,597,725
============ ============
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
COMMON PREMIUM PREFERRED TREASURY
STOCK, $1 ON CAPITAL STOCK, NO STOCK, AT
PAR VALUE STOCK PAR VALUE COST
--------- ----- --------- ----
(THOUSANDS OF DOLLARS)
Balance July 1, 2002 ..................................... $ 58,055 $ 707,912 $ -- $ (57,673)
Comprehensive income (loss):
Net earnings .......................................... -- -- -- --
Unrealized loss in investment
securities, net of tax benefit ...................... -- -- -- --
Minimum pension liability
adjustment, net of tax benefit ...................... -- -- -- --
Unrealized loss on hedging
activities, net of tax benefit ...................... -- -- -- --
Comprehensive income
Payment on note receivable ............................ -- 305 -- --
Purchase of treasury stock ............................ -- -- -- (2,181)
5% stock dividend ..................................... 3,468 55,832 -- --
Stock compensation plan ............................... -- 480 -- --
Issuance of stock for acquisition ..................... -- -- -- 48,900
Issuance of common stock .............................. 10,925 157,757 -- --
Issuance costs of equity units ........................ -- (3,443) -- --
Contract adjustment payment ........................... -- (11,713) -- --
Sale of common stock held in trust .................... -- (243) -- --
Exercise of stock options ............................. 626 2,304 -- 487
-------- --------- -------- ----------
Balance June 30, 2003 .................................... 73,074 909,191 -- (10,467)
Comprehensive income (loss):
Net earnings ......................................... -- -- -- --
Preferred stock dividends ............................ -- -- -- --
Unrealized loss in investment
securities, net of tax benefit ..................... -- -- -- --
Unrealized gain on hedging
activities, net of tax ............................. -- -- -- --
Comprehensive income
Issuance of preferred stock ........................... -- (6,413) 230,000 --
Exercise of stock options ............................. 108 979 -- --
--------- --------- --------- ---------
Balance December 31, 2003 ................................ $ 73,182 $ 903,757 $ 230,000 $ (10,467)
========= ========= ========= =========
ACCUMULATED
COMMON OTHER
STOCK COMPREHEN-
HELDIN SIVE INCOME RETAINED
TRUST (LOSS) EARNINGS TOTAL
----- ------ -------- -----
(THOUSANDS OF DOLLARS)
Balance July 1, 2002 .................................... $ (8,448) $ (14,500) $ -- $ 685,346
Comprehensive income (loss):
Net earnings ......................................... -- -- 76,189 76,189
Unrealized loss in investment
securities, net of tax benefit ..................... -- (581) -- (581)
Minimum pension liability
adjustment, net of tax benefit ..................... -- (41,930) -- (41,930)
Unrealized loss on hedging
activities, net of tax benefit ..................... -- (5,568) -- (5,568)
------ ------
Comprehensive income ............................... 28,110
------
Payment on note receivable ........................... -- -- -- 305
Purchase of treasury stock ........................... -- -- -- (2,181)
5% stock dividend .................................... -- -- (59,333) (33)
Stock compensation plan .............................. 737 -- -- 1,217
Issuance of stock for acquisition .................... -- -- -- 48,900
Issuance of common stock ............................. -- -- -- 168,682
Issuance costs of equity units ....................... -- -- -- (3,443)
Contract adjustment payment .......................... -- -- -- (11,713)
Sale of common stock held in trust ................... 2,424 -- -- 2,181
Exercise of stock options ............................ (370) -- -- 3,047
-------- -------- ----------- -----------
Balance June 30, 2003 ................................... (5,657) (62,579) 16,856 920,418
Comprehensive income (loss):
Net earnings ........................................ -- -- 34,715 34,715
Preferred stock dividends ........................... -- -- (4,004) (4,004)
Unrealized loss in investment
securities, net of tax benefit ................... -- (21) -- (21)
Unrealized gain on hedging
activities, net of tax ........................... -- 720 -- 720
--- ------
Comprehensive income 31,410
------
Issuance of preferred stock .......................... -- -- -- 223,587
Exercise of stock options ............................ -- -- -- 1,087
-------- ---------- ---------- -----------
Balance December 31, 2003 .............................. $ (5,657) $ (61,880) $ 47,567 $ 1,176,502
======== ========== ========== ===========
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 DECEMBER 31,
2003 2002
---- ----
(THOUSANDS OF DOLLARS)
Cash flows from (used in) operating activities:
Net earnings available for common stock ......................................................... $ 34,418 $ 29,419
Adjustments to reconcile net earnings to net cash flows from
operating activities:
Depreciation and amortization ............................................................... 31,697 14,067
Amortization of debt premium ................................................................ (2,500) --
Deferred income taxes ....................................................................... 12,159 1,249
Provision for bad debts ..................................................................... 2,809 2,912
Net cash used in assets held for sale ....................................................... -- (25,502)
Other ....................................................................................... 236 862
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable, billed and unbilled ................................................ (155,851) (149,177)
Gas imbalance receivable ................................................................ (8,407) --
Accounts payable ........................................................................ 61,550 79,356
Gas imbalance payable .................................................................. 9,665 --
Customer deposits ....................................................................... 849 (2)
Deferred gas purchase costs ............................................................. 16,619 11,645
Inventories ............................................................................. 14,089 24,694
Deferred charges and credits ............................................................ 6,204 (1,588)
Prepaids and other current assets ....................................................... 8,018 1,900
Dividends payable on preferred stock .................................................... 4,004 --
Federal and state taxes receivable ...................................................... 2,677 --
Federal, state and local taxes payable .................................................. 16,460 24,964
Other liabilities ....................................................................... 8,739 (4,990)
--------- ---------
Net cash flows from operating activities ...................................................... 63,435 9,809
--------- ---------
Cash flows from (used in) investing activities:
Additions to property, plant and equipment ...................................................... (70,839) (18,206)
Changes in assets and liabilities held for sale ................................................. -- (7,771)
Notes receivable ................................................................................ (1,000) (4,750)
Customer advances ............................................................................... 867 391
Other ........................................................................................... 844 (1,986)
--------- ---------
Net cash flows used in investing activities ................................................... (70,128) (32,322)
--------- ---------
Cash flows from (used in) financing activities:
Issuance of preferred stock ..................................................................... 230,000 --
Issuance costs of preferred stock ............................................................... (6,413) --
Issuance cost of debt ........................................................................... -- (313)
Repayment of debt and capital lease obligation .................................................. (139,236) (38,949)
Net (payments) borrowings under revolving credit facilities ..................................... (71,800) 59,300
Proceeds from exercise of stock options ......................................................... 222 1,490
--------- ---------
Net cash flows from financing activities ...................................................... 12,773 21,528
--------- ---------
Change in cash and cash equivalents ................................................................ 6,080 (985)
Cash and cash equivalents at beginning of period ................................................... 14,730 985
--------- ---------
Cash and cash equivalents at end of period ......................................................... $ 20,810 $ --
========= =========
Supplemental disclosures of cash flow information: Cash paid (refunded) during
the period for:
Interest ...................................................................................... $ 23,450 $ 22,337
========= =========
Income taxes .................................................................................. $ (76) $ 282
========= =========
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
SIX MONTHS ENDED DECEMBER 31,
2003 2002
---- ----
(THOUSANDS OF DOLLARS)
Cash flows from (used in) operating activities:
Net earnings available for common stock ......................................................... $ 30,711 $ 22,924
Adjustments to reconcile net earnings to net cash flows from (used in)
operating activities:
Depreciation and amortization ............................................................... 63,031 28,451
Amortization of debt premium ................................................................ (7,001) --
Deferred income taxes ....................................................................... 25,719 (1,120)
Provision for bad debts ..................................................................... 7,987 6,397
Provision for impairment of other assets .................................................... 2,753 --
Gain on extinguishment of debt .............................................................. (6,123) --
Net cash used in assets held for sale ....................................................... -- (23,698)
Other ....................................................................................... 475 1,821
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable, billed and unbilled ................................................ (120,985) (128,166)
Gas imbalance receivable ................................................................ 7,937 --
Accounts payable ........................................................................ 30,957 57,447
Gas imbalance payable ................................................................... 1,530 --
Customer deposits ....................................................................... 249 (678)
Deferred gas purchase costs ............................................................. (1,842) (9,187)
Inventories ............................................................................. (57,402) (6,263)
Deferred charges and credits ............................................................ (1,394) 4,199
Prepaids and other current assets ....................................................... 6,565 4,184
Dividends payable on preferred stock .................................................... 4,004 --
Federal and state taxes receivable ...................................................... 21,035 --
Federal, state and local taxes payable .................................................. 10,055 29,879
Other liabilities ....................................................................... (27,041) (4,186)
--------- ---------
Net cash flows used in operating activities ................................................... (8,780) (17,996)
--------- ---------
Cash flows from (used in) investing activities:
Additions to property, plant and equipment ...................................................... (111,091) (38,106)
Changes in assets and liabilities held for sale ................................................. -- (13,410)
Notes receivable ................................................................................ (1,000) (6,750)
Customer advances ............................................................................... (2,809) 618
Other ........................................................................................... 3,467 (1,664)
--------- ---------
Net cash flows used in investing activities ................................................... (111,433) (59,312)
--------- ---------
Cash flows from (used in) financing activities:
Issuance of long-term debt ...................................................................... 550,000 311,087
Issuance of preferred stock ..................................................................... 230,000 --
Issuance cost of debt ........................................................................... (3,996) (1,367)
Issuance costs of preferred stock ............................................................... (6,413) --
Repayment of debt and capital lease obligation .................................................. (717,153) (393,054)
Net borrowings under revolving credit facilities ................................................ 500 158,200
Proceeds from exercise of stock options ......................................................... 1,088 2,442
--------- ---------
Net cash flows from financing activities ...................................................... 54,026 77,308
--------- ---------
Change in cash and cash equivalents ................................................................ (66,187) --
Cash and cash equivalents at beginning of period ................................................... 86,997 --
--------- ---------
Cash and cash equivalents at end of period ......................................................... $ 20,810 $ --
========= =========
Supplemental disclosures of cash flow information: Cash paid during the period
for:
Interest ...................................................................................... $ 73,687 $ 48,161
========= =========
Income taxes .................................................................................. $ 36 $ 491
========= =========
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FINANCIAL STATEMENTS
These interim financial statements should be read in conjunction with the
financial statements and notes thereto contained in Southern Union Company's
(Southern Union and together with its subsidiaries, the Company) Annual Report
on Form 10-K for the fiscal year ended June 30, 2003. All dollar amounts in the
tables herein, except per share amounts, are stated in thousands unless
otherwise indicated. Certain prior period amounts have been reclassified to
conform with the current period presentation.
These interim financial statements are unaudited but, in the opinion of
management, reflect all adjustments (including both normal recurring as well as
any non-recurring) necessary for a fair presentation of the results of
operations for such periods. Because of the seasonal nature of the Company's
operations, as well as the timing of significant acquisitions and sales of
operations (see Acquisitions and Sales, below), the results of operations and
cash flows for any interim period are not necessarily indicative of results for
the full year.
SIGNIFICANT ACCOUNTING POLICIES
Effective July 1, 2002, the Company adopted the Financial Accounting Standards
Board (FASB) standard, Accounting for Asset Retirement Obligations (ARO). The
Statement requires legal obligations associated with the retirement of
long-lived assets to be recognized at their fair value at the time the
obligations are incurred. Upon initial recognition of a liability, costs should
be capitalized as part of the related long-lived asset and allocated to expense
over the useful life of the asset. Over time, the liability is accreted to its
present value each period, and the capitalized cost is depreciated over the
useful life of the related long-lived asset. In certain rate jurisdictions, the
Company is permitted to include annual charges for cost of removal in its
regulated cost of service rates charged to customers. The adoption of the
Statement did not have a material impact on the Company's financial position,
results of operations or cash flows for all periods presented.
Panhandle Eastern Pipe Line Company, LLC (Panhandle Eastern Pipe Line and
together with its subsidiaries, Panhandle Energy) has an ARO liability relating
to the retirement of certain of its offshore lateral lines with an aggregate
carrying amount of approximately $7,479,000 and $6,757,000 as of December 31,
2003 and June 30, 2003, respectively. During the six-month period ended December
31, 2003, changes in the carrying amount of the ARO liability were attributable
to $358,000 of additional liabilities incurred and $364,000 of accretion
expense. Liabilities settled and cash flow revisions were nil for the current
period.
In April 2003, the FASB issued Amendment of Statement 133 on Derivative
Instruments and Hedging Activities. The Statement is effective for contracts
entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. The Statement (i) clarifies under what
circumstances a contract with an initial net investment meets the
characteristics of a derivative, (ii) clarifies when a derivative contains a
financing component, (iii) amends the definition of an underlying to conform it
to language used in FASB Interpretation Guarantor's Accounting and Disclosure
Requirement for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, and (iv) amends certain other existing pronouncements. The Statement is
not expected to materially change the methods the Company uses to account for
and report its derivatives and hedging activities.
Effective July 1, 2003, the Company adopted the FASB standard, Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity. The Statement establishes guidelines on how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. The Statement further defines and requires that certain instruments
within its scope be classified as liabilities on the financial statements. The
adoption of the Statement did not have a material impact on the Company's
financial position, results of operations or cash flows for all periods
presented.
In December 2003, the FASB issued Employers' Disclosures about Pensions and
Other Postretirement Benefits - an amendment of FASB Statements No. 87, 88, and
106. The Statement revises employers' disclosures about pension plans and other
postretirement benefit plans. It retains the disclosure requirements contained
in FASB Statement No. 132, Employers' Disclosures about Pensions and Other
Postretirement Benefits, which it replaces, and requires additional disclosure
about the assets, obligations, cash flows and net periodic benefit cost of
defined benefit pension plans and other defined benefit postretirement plans.
The Statement does not change the measurement or recognition of those plans
required by FASB Statements No. 87, Employers' Accounting for Pensions, No. 88,
Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits, and No. 106, Employers' Accounting
for Postretirement Benefits Other Than Pensions. The Statement is effective for
fiscal years ending after December 15, 2003. The interim-period disclosures
required by the Statement are effective for interim periods beginning after
December 15, 2003.
ACQUISITIONS AND SALES
On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy
Corporation for approximately $581,729,000 in cash and 3,000,000 shares of
Southern Union common stock (before adjustment for subsequent stock dividends)
valued at approximately $48,900,000 based on market prices at closing and in
connection therewith incurred transaction costs estimated at approximately
$30,448,000. Southern Union also incurred additional deferred state income tax
liabilities estimated at $18,388,000 as a result of the transaction. At the time
of the acquisition, Panhandle Energy had approximately $1,157,228,000 of debt
outstanding that it retained. The Company funded the cash portion of the
acquisition with approximately $437,000,000 in cash proceeds it received from
the January 1, 2003 sale of its Texas operations, approximately $121,250,000 of
the net proceeds it received from concurrent common stock and equity units
offerings and with working capital available to the Company. The Company
structured the Panhandle Energy acquisition and the sale of its Texas operations
to qualify as a like-kind exchange of property under Section 1031 of the
Internal Revenue Code of 1986, as amended. The acquisition was accounted for
using the purchase method of accounting in accordance with accounting principles
generally accepted in the United States of America with the purchase price paid
by the Company being allocated to Panhandle Energy's net assets as of the
acquisition date based on preliminary estimates. The Panhandle Energy assets
acquired and liabilities assumed have been recorded at their estimated fair
value as of the acquisition date and are subject to further assessment and
adjustment pending the results of outside appraisals. The outside appraisals are
expected to be completed prior to June 30, 2004. Panhandle Energy's results of
operations have been included in the Consolidated Statement of Operations since
June 11, 2003. Thus, the Consolidated Statement of Operations for the periods
subsequent to the acquisition is not comparable to the same periods in prior
years.
Panhandle Energy is primarily engaged in the interstate transportation and
storage of natural gas and also provides liquefied natural gas (LNG)
terminalling and regasification services and is subject to the rules and
regulations of the Federal Energy Regulatory Commission (FERC). The Panhandle
Energy entities include Panhandle Eastern Pipe Line Company, LLC (Panhandle
Eastern Pipe Line), Trunkline Gas Company, LLC (Trunkline), a wholly-owned
subsidiary of Panhandle Eastern Pipe Line, Sea Robin Pipeline Company (Sea
Robin), a Louisiana joint venture and indirect wholly-owned subsidiary of
Panhandle Eastern Pipe Line, Trunkline LNG Company, LLC (Trunkline LNG), a
wholly-owned subsidiary of Trunkline LNG Holdings, LLC (LNG Holdings) and
Southwest Gas Storage, LLC (Southwest Gas Storage), a wholly-owned subsidiary of
Panhandle Eastern Pipe Line. Collectively, the pipeline assets include more than
10,000 miles of interstate pipelines that transport natural gas from the Gulf of
Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major
U.S. markets in the Midwest and Great Lakes region. The pipelines have a
combined peak day delivery capacity of 5.4 billion cubic feet (bcf) per day and
72 bcf of owned underground storage capacity. Trunkline LNG, located on
Louisiana's Gulf Coast, operates one of the largest LNG import terminals in
North America and has 6.3 bcf of above ground LNG storage facilities.
The following table summarizes the estimated fair values of the Panhandle Energy
assets acquired and liabilities assumed at the date of acquisition.
AT JUNE 11, 2003
----------------
Property, plant and equipment (including intangibles) ......... $ 1,945,104
Current assets (1) ............................................ 208,407
Other non-current assets ...................................... 30,204
-----------
Total assets acquired .................................... 2,183,715
-----------
Long-term debt ................................................ (1,207,617)
Current liabilities ........................................... (161,357)
Other non-current liabilities ................................. (135,276)
-----------
Total liabilities assumed ................................ (1,504,250)
-----------
Net assets acquired .................................. $ 679,465
===========
(1) Includes cash and cash equivalents of approximately $59 million.
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK, Inc. (ONEOK) for
approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000.
In accordance with accounting principles generally accepted in the United States
of America, the results of operations and gain on sale of the Texas operations
have been segregated and reported as "discontinued operations" in the
Consolidated Statement of Operations and Consolidated Statement of Cash Flows
for the respective periods.
PRO FORMA FINANCIAL INFORMATION
The following unaudited pro forma financial information for the three- and
six-month periods ended December 31, 2002 is presented as though the following
events had occurred at the beginning of the periods presented: (i) acquisition
of Panhandle Energy; and (ii) the issuance of the common stock and equity units
in June 2003. The pro forma financial information is not necessarily indicative
of the results which would have actually been obtained had the acquisition of
Panhandle Energy or the issuance of the common stock and equity units been
completed as of the assumed date for the periods presented or which may be
obtained in the future.
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
2002 2002
---- ----
Operating revenues.................................................... $ 485,279 $ 694,784
Net earnings from continuing operations............................... 49,385 52,443
Net earnings per share from continuing operations:
Basic.............................................................. 0.69 0.74
Diluted............................................................ 0.67 0.72
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
six-month period ended December 31, 2002.
EARNINGS PER SHARE
The following table summarizes the Company's basic and diluted earnings per
share calculations for the three- and six-month periods ending December 31,2003
and 2002:
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
2003 2002 2003 2002
---- ---- ---- ----
Net earnings available for common stock
from continuing operations (1) ...................... $ 34,418 $ 18,519 $ 30,711 $ 9,333
Net earnings from discontinued operations .............. -- 10,900 -- 13,591
------------ ------------ -------------- -----------
Net earnings available for common stock ................ $ 34,418 $ 29,419 $ 30,711 $ 22,924
============ ============ ============== ===========
Weighted average shares outstanding - basic ............ 71,759,349 56,919,821 71,748,220 56,713,616
============ ============ ============== ===========
Weighted average shares outstanding - diluted .......... 73,957,901 58,737,336 73,804,782 58,671,826
============ ============ ============== ===========
Basic earnings per share:
Net earnings available for common stock
from continuing operations (1) .................... $ 0.48 $ 0.33 $ 0.43 $ 0.16
Net earnings from discontinued operations ........... -- 0.19 -- 0.24
------------ ------------ -------------- -----------
Net earnings available for common stock ............. $ 0.48 $ 0.52 $ 0.43 $ 0.40
============ ============ ============== ===========
Diluted earnings per share:
Net earnings available for common stock
from continuing operations (1) .................... $ 0.47 $ 0.32 $ 0.42 $ 0.16
Net earnings from discontinued operations ........... -- 0.18 -- 0.23
------------ ------------ -------------- -----------
Net earnings available for common stock ............. $ 0.47 $ 0.50 $ 0.42 $ 0.39
============ ============ ============== ===========
(1) Includes $4,004,000 of preferred stock dividends accrued for the three-
and six-month periods ended December 31, 2003.
Diluted earnings per share include average shares outstanding as well as common
stock equivalents from stock options and warrants. Common stock equivalents were
1,075,805 and 545,140 for the three-month periods ended December 31, 2003 and
2002, respectively, and 957,875 and 712,628 for the six-month periods ended
December 31, 2003 and 2002, respectively. Stock options to purchase 2,361,179
shares of common stock were outstanding during the three- and six-month periods
ended December 31, 2002, 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 "anti-dilutive" options outstanding for the same periods in 2003. At
December 31, 2003, 1,136,461 shares of common stock were held by various rabbi
trusts for certain of the Company's benefit plans and 105,710 shares were held
in a rabbi trust for certain employees who deferred receipt of Company shares
for stock options exercised. From time to time, the Company's benefit plans may
purchase shares of Southern Union common stock subject to regular restrictions.
GOODWILL AND INTANGIBLES
There was no change in the carrying amount of goodwill for the six-month period
ended December 31, 2003. As of December 31, 2003, the Company has goodwill of
$642,921,000 from its Distribution segment. The Distribution segment is tested
annually for impairment in the fourth quarter, after the annual forecasting
process.
On June 11, 2003, the Company completed its acquisition of Panhandle Energy.
Based on the preliminary purchase price allocations, which rely on estimates and
are subject to change based on final outside appraisal, the acquisition resulted
in no recognition of goodwill as of the acquisition date. The final appraisal
may result in some of the purchase price being allocated to goodwill. In
addition, based on the preliminary purchase price allocations which are subject
to change, the acquisition resulted in the recognition of intangible assets
relating to customer contracts and relationships of approximately $20,000,000 as
of the acquisition date. These intangibles are currently being amortized over a
period of five years, pending final determination of value and estimated
remaining useful life. As of December 31, 2003, the carrying amount of these
intangibles was approximately $18,000,000 and is included in Property, Plant and
Equipment on the Consolidated Balance Sheet.
DEFERRED CHARGES AND CREDITS
DECEMBER 31, JUNE 30,
2003 2003
---- ----
Deferred Charges
Pensions......................................................................... $ 38,920 $ 39,088
Unamortized debt expense......................................................... 37,711 34,209
Income taxes..................................................................... 31,441 30,514
Retirement costs other than pensions............................................. 27,519 29,028
Service Line Replacement program................................................. 17,949 18,974
Environmental.................................................................... 16,894 14,304
Other............................................................................ 16,525 22,144
------------- --------------
Total Deferred Charges.......................................................... $ 186,959 $ 188,261
============= ==============
As of December 31, 2003 and June 30, 2003, the Company's deferred charges
include regulatory assets relating to Distribution segment operations in the
aggregate amount of $84,169,000 and $84,023,000, respectively, of which
$47,456,000 and $50,244,000, respectively, is being recovered through current
rates. As of December 31, 2003 and June 30, 2003, the remaining recovery period
associated with these assets ranges from 1 to 211 months and from 6 months to
147 months, respectively. None of these regulatory assets, which primarily
relate to pensions, retirement costs other than pensions, income taxes, Year
2000 costs, Missouri Gas Energy's Service Line Replacement program and
environmental remediation costs, are included in rate base. The Company records
regulatory assets in accordance with the FASB standard, Accounting for the
Effects of Certain Types of Regulation.
DECEMBER 31, JUNE 30,
2003 2003
---- ----
Deferred Credits
Pensions........................................................................ $ 92,995 $ 88,016
Retirement costs other than pensions............................................ 63,353 65,144
Environmental................................................................... 29,419 32,322
Cost of Removal................................................................. 27,701 27,286
Derivative liability............................................................ 18,395 26,151
Customer advances for construction.............................................. 12,340 12,008
Self-insurance.................................................................. 12,222 12,000
Investment tax credit........................................................... 5,451 5,661
Other........................................................................... 50,430 53,566
------------- --------------
Total Deferred Credits........................................................ $ 312,306 $ 322,154
============= ==============
The Company's deferred credits include regulatory liabilities relating to
Distribution segment operations in the aggregate amount of $11,229,000 and
$10,084,000, respectively, at December 31, 2003, and June 30, 2003. These
regulatory liabilities primarily relate to retirement benefits other than
pensions, environmental insurance recoveries and income taxes. The Company
records regulatory liabilities in accordance with the FASB standard, Accounting
for the Effects of Certain Types of Regulation.
INVESTMENT SECURITIES
As of December 31, 2003, all securities owned by Southern Union are accounted
for under the cost method. The Company's investments in securities consist of
common and preferred stock in non-public companies whose value is not readily
determinable. Various Southern Union executive management personnel, Board of
Directors and employees also have an equity ownership in one of these
investments.
The Company reviews its portfolio of investment securities on a quarterly basis
to determine whether a decline in value is other than temporary. Factors that
are considered in assessing whether a decline in value is other than temporary
include, but are not limited to: earnings trends and asset quality; near term
prospects and financial condition of the issuer, including the availability and
terms of any additional financing requirements; financial condition and
prospects of the issuer's region and industry, customers and markets and
Southern Union's intent and ability to retain the investment. If Southern Union
determines that the decline in value of an investment security is other than
temporary, the Company will record a charge on its Consolidated Statement of
Operations to reduce the carrying value of the security to its estimated fair
value.
In September 2003, Southern Union determined that the decline in value of its
investment in PointServe was other than temporary. Accordingly, the Company
recorded a non-cash charge of $1,603,000 to reduce the carrying value of this
investment to its estimated fair value. The Company recognized this valuation
adjustment to reflect lower private equity valuation metrics and changes in the
business outlook of PointServe. PointServe is a closely held, privately owned
company and, as such, has no published market value. The Company's remaining
investment of $2,603,000 at December 31, 2003 is carried at its estimated fair
value and may be subject to future market value risk. The Company will continue
to monitor the value of its investment and periodically assess the impact, if
any, on reported earnings in future periods.
STOCKHOLDERS' EQUITY
The Company accounts for its incentive plans under the Accounting Principles
Board Opinion, Accounting for Stock Issued to Employees and related
authoritative interpretations. The Company recorded no compensation expense for
the three- and six- month periods ended December 31, 2003 and 2002. During 1997,
the Company adopted the FASB Standard, Accounting for Stock-Based Compensation,
for footnote disclosure purposes only. Had compensation cost for these incentive
plans been determined consistent with this Statement, the Company's net earnings
available for common stock from continuing operations and diluted earnings per
share would have been $34,055,000 and $.46, and $18,120,000 and $.31,
respectively, for the three-month periods ended December 31, 2003 and 2002, and
$29,984,000 and $.41, and $8,532,000 and $.15, respectively, for the six-month
periods ended December 31, 2003 and 2002. Had compensation cost for these
incentive plans been determined consistent with this Statement, the Company's
net earnings available for common stock and diluted earnings per share would
have been $34,055,000 and $.46, and $29,020,000 and $.49, respectively, for the
three-month periods ended December 31, 2003 and 2002, and $29,984,000 and $.41,
and $22,123,000 and $.38, respectively, for the six-month periods ended December
31, 2003 and 2002.
COMPREHENSIVE INCOME
The table below gives an overview of comprehensive income for the periods
indicated.
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
------------ ------------
2003 2002 2003 2002
---- ---- ---- ----
Net earnings available for common stock ..................................... $ 34,418 $ 29,419 $ 30,711 $ 22,924
Other comprehensive income (loss):
Unrealized loss in investment securities, net of tax benefit ............. -- 141 (21) (346)
Unrealized gain (loss) on hedging activities, net of tax (benefit) ....... (165) 85 720 129
-------- -------- -------- --------
Other comprehensive income (loss) ........................................... (165) 226 699 (217)
-------- -------- -------- --------
Comprehensive income ........................................................ $ 34,253 $ 29,645 $ 31,410 $ 22,707
======== ======== ======== ========
Accumulated other comprehensive income reflected in the Consolidated Balance
Sheet at December 31, 2003, includes unrealized gains and losses on hedging
activities and minimum pension liability adjustments.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Company utilizes derivative instruments on a limited basis to manage certain
business risks. Interest rate swaps and treasury rate locks are employed to
manage the Company's exposure to interest rate risk.
CASH FLOW HEDGES. As a result of the acquisition of Panhandle Energy, the
Company is party to interest rate swap agreements with an aggregate notional
amount of $202,179,000 as of December 31, 2003 that fix the interest rate
applicable to floating rate long-term debt and which qualify for hedge
accounting. For the six-month period ended December 31, 2003, the swap
ineffectiveness was immaterial. As of December 31, 2003, floating rate London
InterBank Offered Rate (LIBOR) based interest payments were exchanged for
weighted fixed rate interest payments of 5.08%. As such, payments or receipts on
interest rate swap agreements are recognized as adjustments to interest expense.
As of December 31, 2003 and June 30, 2003, the fair value liability position of
the swaps was $19,806,000 and $26,850,000, respectively. As of December 31, 2003
and since the acquisition date, an unrealized gain of $2,293,000 ($1,371,000,
net of tax), was included in accumulated other comprehensive income related to
these swaps, of which approximately $289,000, net of tax, is expected to be
reclassified to interest expense during the next twelve months as the hedged
interest payments occur. Current market pricing models were used to estimate
fair values of interest rate swap agreements.
The Company was also party to an interest rate swap agreement with a notional
amount of $8,199,000 at June 30, 2003 that fixed the interest rate applicable to
floating rate long-term debt and which qualified for hedge accounting. The fair
value liability position of the swap was $93,000 at June 30, 2003. In October
2003, the swap expired and $15,000 of unrealized after-tax losses included in
accumulated other comprehensive income relating to this swap was reclassified to
interest expense during the quarter ended December 31, 2003.
In March and April 2003, the Company entered into a series of treasury rate
locks with an aggregate notional amount of $250,000,000 to manage its exposure
against changes in future interest payments attributable to changes in the
benchmark interest rate prior to the anticipated issuance of fixed-rate debt.
These treasury rate locks expired on June 30, 2003, resulting in a $6,862,000
after-tax loss that was recorded in accumulated other comprehensive income and
will be amortized into interest expense over the lives of the associated debt
instruments. As of December 31, 2003, approximately $846,000 of net after-tax
losses in accumulated other comprehensive income will be amortized into interest
expense during the next twelve months.
The notional amounts of the interest rate swaps are not exchanged and do not
represent exposure to credit loss. In the event of default by a counterparty,
the risk in these transactions is the cost of replacing the agreements at
current market rates.
PREFERRED SECURITIES
On May 17, 1995, Southern Union Financing I (Subsidiary Trust), a consolidated
wholly-owned subsidiary of Southern Union, issued $100,000,000 of 9.48% Trust
Originated Preferred Securities (Preferred Securities). In connection with the
Subsidiary Trust's issuance of the Preferred Securities and the related purchase
by Southern Union of all of the Subsidiary Trust's common securities (Common
Securities), Southern Union issued to the Subsidiary Trust $103,092,800
principal amount of its 9.48% Subordinated Deferrable Interest Notes, due 2025
(Subordinated Notes). The sole assets of the Subsidiary Trust are the
Subordinated Notes. On October 1, 2003, the Company called the Subordinated
Notes for redemption, and the Subordinated Notes and the Preferred Securities
were redeemed on October 31, 2003. The Company financed the redemption with
borrowings under its revolving credit facilities, which were paid down with the
net proceeds of a $230,000,000 offering of preferred stock by the Company on
October 8, 2003, as further described below.
On October 8, 2003, the Company issued 920,000 shares of its 7.55% Noncumulative
Preferred Stock, Series A (Liquidation Preference $250 Per Share) to the public
through the issuance of 9,200,000 Depositary Shares, each representing a
one-tenth interest in a 7.55% Noncumulative Preferred Stock, Series A share at
the public offering price of $25.00 per share, or $230,000,000 in the aggregate.
The total net proceeds were used to repay debt under the Company's revolving
credit facilities.
DEBT AND CAPITAL LEASE
DECEMBER 31, JUNE 30,
2003 2003
---- ----
SOUTHERN UNION COMPANY
7.60% Senior Notes, due 2024.......................................................... $ 359,765 $ 359,765
8.25% Senior Notes, due 2029.......................................................... 300,000 300,000
2.75% Senior Notes, due 2006.......................................................... 125,000 125,000
Term Note, due 2005................................................................... 161,087 211,087
6.50% to 10.25% First Mortgage Bonds, due 2008 to 2029................................ 113,504 115,884
7.70% Debentures, due 2027............................................................ -- 6,756
Capital lease and other due 2004 to 2007.............................................. 338 9,179
--------------- -------------
1,059,694 1,127,671
--------------- -------------
PANHANDLE ENERGY
4.80% Senior Notes due 2008........................................................... 300,000 --
6.05% Senior Notes due 2013........................................................... 250,000 --
6.125% Senior Notes due 2004.......................................................... 146,080 292,500
7.875% Senior Notes due 2004.......................................................... 52,455 100,000
6.50% Senior Notes due 2009........................................................... 60,623 158,980
8.25% Senior Notes due 2010........................................................... 40,500 60,000
7.00% Senior Notes due 2029........................................................... 66,305 135,890
Term Loan due 2007.................................................................... 269,569 275,358
7.95% Debentures due 2023............................................................. -- 76,500
7.20% Debentures due 2024............................................................. -- 58,000
Net premiums on long-term debt........................................................ 19,911 61,506
--------------- -------------
1,205,443 1,218,734
--------------- -------------
Total consolidated debt and capital lease............................................. 2,265,137 2,346,405
Less current portion.............................................................. 260,729 734,752
--------------- -------------
Total consolidated long-term debt and capital lease................................... $ 2,004,408 $ 1,611,653
=============== =============
Each note, debenture or bond is an obligation of Southern Union Company or a
unit of Panhandle Energy, as noted above. The Panhandle Energy Term Loan due
2007 is debt related to Panhandle's Trunkline LNG Holdings subsidiary, and is
non-recourse to other units of Panhandle Energy or Southern Union Company. The
remainder of Panhandle Energy's debt is non-recourse to Southern Union. All
debts that are listed as debt of Southern Union Company are direct obligations
of Southern Union Company, and no debt is cross-collateralized.
The Company is not party to any lending agreement that would accelerate the
maturity date of any obligation due to a failure to maintain any specific credit
rating. Certain covenants exist in certain of the Company's debt agreements that
require the Company to maintain a certain level of net worth, to meet certain
debt to total capitalization ratios, and to meet certain ratios of earnings
before depreciation, interest and taxes to cash interest expense. A failure by
the Company to satisfy any such covenant would be considered an event of default
under the associated debt, which could become immediately due and payable if the
Company did not cure such default within any permitted cure period or if the
Company did not obtain amendments, consents or waivers from its lenders with
respect to such covenants.
CAPITAL LEASE. The Company completed the installation of an Automated Meter
Reading (AMR) system at Missouri Gas Energy during the first quarter of fiscal
year 1999. The installation of the AMR system involved an investment of
approximately $30,000,000 which is accounted for as a capital lease obligation.
The final lease payment was made on October 1, 2003, and the Company has no
further obligations with respect to the capital lease.
CREDIT FACILITIES. On April 3, 2003, the Company entered into a short-term
credit facility in the amount of $140,000,000 (the Short Term Facility), that
matures April 1, 2004. The Short-Term Facility was increased to $150,000,000 as
of September 25, 2003. Also on April 3, 2003, the Company amended the terms and
conditions of its $225,000,000 long-term credit facility (the Long-Term
Facility), which expires on May 29, 2004. The Company has additional
availability under uncommitted line of credit facilities (Uncommitted
Facilities) with various banks. Borrowings under the facilities are available
for Southern Union's working capital, letter of credit requirements and other
general corporate purposes. The Short-Term Facility and the Long-Term Facility
(together, the Facilities) are subject to a commitment fee based on the rating
of the Senior Notes. As of December 31, 2003, the commitment fees were an
annualized 0.15% on the Facilities. The interest rate on borrowings on the
Facilities is calculated based upon a formula using the LIBOR or prime interest
rates. A balance of $252,000,000 was outstanding under the Facilities at
December 31, 2003, at an effective weighted average interest rate of 2.02%.
TERM NOTE. On August 28, 2000 the Company entered into the Term Note to fund (i)
the cash portion of the consideration to be paid to the Fall River Gas'
stockholders; (ii) the all cash consideration to be paid to the ProvEnergy and
Valley Resources stockholders, (iii) repayment of approximately $50,000,000 of
long- and short-term debt assumed in the mergers, and (iv) all related
acquisition costs. The Term Note, which initially expired on August 27, 2001,
was extended through August 26, 2002. On July 16, 2002, the Company repaid the
Term Note with the proceeds from the issuance of a $311,087,000 Term Note dated
July 15, 2002 (the 2002 Term Note) and borrowings under the Company's lines of
credit. The 2002 Term Note is held by a syndicate of sixteen banks, led by
JPMorgan Chase Bank, as Agent. Eleven of the sixteen banks were also among the
lenders of the Term Note, and they are also lenders under at least one of the
Facilities. The 2002 Term Note carries a variable interest rate that is tied to
either the LIBOR or prime interest rates at the Company's option. The interest
rate spread over the LIBOR rate varies with the credit rating of the Senior
Notes by S&P and Moody's, and is currently LIBOR plus 105 basis points. As of
December 31, 2003, a balance of $161,087,000 was outstanding under this 2002
Term Note at an effective interest rate of 2.24%. The 2002 Term Note requires
principal payments of $25,000,000 on August 15, 2004, $35,000,000 on February
15, 2005, $35,000,000 on August 15, 2005 and $66,087,000 on August 26, 2005. No
additional draws can be made on the 2002 Term Note.
PANHANDLE REFINANCING. In July 2003, Panhandle Energy announced a tender offer
for any and all of the $747,370,000 outstanding principal amount of five of its
series of senior notes outstanding at that point in time (the Panhandle Tender
Offer) and also called for redemption all of the outstanding $134,500,000
principal amount of its two series of debentures that were outstanding (the
Panhandle Calls). Panhandle Energy repurchased approximately $378,257,000 of the
principal amount of its outstanding debt through the Panhandle Tender Offer for
total consideration of approximately $396,445,000 plus accrued interest through
the purchase date. Panhandle Energy also redeemed approximately $134,500,000 of
debentures through the Panhandle Calls for total consideration of $139,411,000,
plus accrued interest through the redemption dates. As a result of the Panhandle
Tender Offer, the Company has recorded a pre-tax gain on the extinguishment of
debt of $6,123,000 in August 2003, which has been classified as other income,
net, in the Consolidated Statement of Operations. In August 2003, Panhandle
Energy issued $300,000,000 of its 4.80% Senior Notes due 2008 and $250,000,000
of its 6.05% Senior Notes due 2013 principally to refinance the repurchased
notes and redeemed debentures. Also in August and September 2003, Panhandle
Energy repurchased $3,150,000 principal amount of its senior notes on the open
market through two transactions for total consideration of $3,398,000, plus
accrued interest through the repurchase date.
REGULATION AND RATES
MISSOURI GAS ENERGY. On November 4, 2003, Missouri Gas Energy filed a request
with the Missouri Public Service Commission (MPSC) to increase base rates by
$44,800,000 and to implement a weather mitigation rate design that would
significantly reduce the impact of weather-related fluctuations on customer
bills. On January 8, 2004, Missouri Gas Energy filed an updated claim which
raised the amount of the base rate increase request to $54,200,000. Statutes
require that the MPSC reach a decision in the case within an eleven-month period
from the original filing date. It is not presently possible to determine what
action the MPSC will ultimately take with respect to this rate increase request.
NEW ENGLAND GAS COMPANY. On October 30, 2003, the Rhode Island Public Utilities
Commission (RIPUC) approved the Company's gas cost filing and allowed full
recovery of the deferred fuel balance effective November 1. At the same open
meeting, the RIPUC ordered the Company to begin to refund, through the
Distribution Adjustment Clause, the Division of Public Utilities and Carriers
(Division) position on the Company's over earnings, which were substantially
accrued for by the Company at June 30, 2003, pending a final decision by the
RIPUC. The Division's position generated incremental over earnings for fiscal
2003 of $700,000. It is uncertain at this time when a final decision will be
made.
On May 22, 2003, the RIPUC approved a Settlement Offer filed by New England Gas
Company related to the final calculation of earnings sharing for the 21-month
period covered by the Energize Rhode Island Extension settlement agreement. This
calculation generated excess revenues of $5,227,000. The net result of the
excess revenues and the Energize Rhode Island weather mitigation and non-firm
margin sharing provisions is the crediting to customers of $949,000 over a
twelve-month period starting July 1, 2003.
PANHANDLE ENERGY. In December 2002, FERC approved a Trunkline LNG certificate
application to expand the Lake Charles facility to approximately 1.2 bcf per day
of sendout capacity versus the current capacity of .63 bcf per day. BG LNG
Services, Inc., a subsidiary of BG Group of the United Kingdom (BG LNG Services)
has contract rights for the 570 million cubic feet per day of additional
capacity. Construction on the Trunkline LNG expansion project commenced in
September 2003 and is expected to be completed by the end of 2005. In February
2004, Trunkline LNG plans to file a further incremental LNG expansion project
(Phase II) with the FERC. Phase II would increase the LNG terminal capacity to
1.8 bcf per day by mid-2006.
In February 2004, Trunkline filed an application with the FERC to request
approval of a 30-inch diameter, 23-mile natural gas pipeline loop from the LNG
terminal. The pipeline creates additional transport capacity in association with
the Trunkline LNG expansion and also includes new and expanded delivery points
with major interstate pipelines.
COMMITMENTS AND CONTINGENCIES
ENVIRONMENTAL
The Company is subject to federal, state and local laws and regulations relating
to the protection of the environment. These evolving laws and regulations may
require expenditures over a long period of time to control environmental
impacts. The Company has established procedures for the on-going evaluation of
its operations to identify potential environmental exposures and assure
compliance with regulatory policies and procedures.
The Company follows the provisions of an American Institute of Certified Public
Accountants Statement of Position, Environmental Remediation Liabilities, for
recognition, measurement, display and disclosure of environmental remediation
liabilities.
In certain of the Company's jurisdictions the Company is allowed to recover
environmental remediation expenditures through rates. Although significant
charges to earnings could be required prior to rate recovery for jurisdictions
that do not have rate recovery mechanisms, management does not believe that
environmental expenditures will have a material adverse effect on the Company's
financial position, results of operations or cash flows.
LOCAL DISTRIBUTION COMPANY ENVIRONMENTAL MATTERS -- The Company is investigating
the possibility that the Company or predecessor companies may have been
associated with Manufactured Gas Plant (MGP) sites in its former gas
distribution service territories, principally in Texas, Arizona and New Mexico,
and present gas distribution service territories in Missouri, Pennsylvania,
Massachusetts and Rhode Island. At the present time, the Company is aware of
certain MGP sites in these areas and is investigating those and certain other
locations. While the Company's evaluation of these Texas, Missouri, Arizona, New
Mexico, Pennsylvania, Massachusetts and Rhode Island MGP sites is in its
preliminary stages, it is likely that some compliance costs may be identified
and become subject to reasonable quantification. Within the Company's gas
distribution service territories certain MGP sites are currently the subject of
governmental actions. These sites are as follows:
MISSOURI SITES. In a letter dated May 10, 1999, the Missouri Department of
Natural Resources (MDNR) sent notice of a planned Site Inspection/Removal Site
Evaluation of the Kansas City Coal Gas Former MGP site. This site (comprised of
two adjacent MGP operations previously owned by two separate companies and
hereafter referred to as Station A and Station B) is located at East 1st Street
and Campbell in Kansas City, Missouri and is owned by Missouri Gas Energy (MGE).
During July 1999, the Company submitted the two sites to MDNR's Voluntary
Cleanup Program (VCP) and, subsequently, performed environmental assessments of
the sites. Following the submission of these assessments to MDNR, MGE was
required by MDNR to initiate remediation of Station A. Following the selection
of a qualified contractor in a competitive bidding process, the Company began
remediation of Station A in the first calendar quarter of 2003. The project was
completed in July 2003, at an approximate cost of $4 million. The remediation of
Station B has not been required by MDNR.
RHODE ISLAND AND MASSACHUSETTS SITES. Prior to its acquisition by the Company,
Providence Gas performed environmental studies and initiated an environmental
remediation project at Providence Gas' primary gas distribution facility located
at 642 Allens Avenue in Providence, Rhode Island. Providence Gas spent more than
$13 million on environmental assessment and remediation at this MGP site under
the supervision of the Rhode Island Department of Environmental Management
(RIDEM). Following the acquisition, environmental remediation at the site was
temporarily suspended. During this suspension, the Company requested certain
modifications to the 1999 Remedial Action Work Plan from RIDEM. After receiving
approval to some of the requested modifications to the 1999 Remedial Action Work
Plan, environmental work was reinitiated on April 17, 2002, by a qualified
contractor selected in a competitive bidding process. Remediation was completed
on October 10, 2002, and a Closure Report was filed with RIDEM in December 2002.
The approximate cost of the environmental work conducted after environmental
work resumed was $4 million. Remediation of the remaining 37.5 acres of the site
(known as the "Phase 2" remediation project) is not scheduled at this time.
In November 1998, Providence Gas received a letter of responsibility from RIDEM
relating to possible contamination at a site that operated as a MGP in the early
1900's in Providence, Rhode Island. Subsequent to its use as a MGP, this site
was operated for over eighty years as a bulk fuel oil storage yard by a
succession of companies including Cargill, Inc. (Cargill). Cargill has also
received a letter of responsibility from RIDEM for the site. An investigation
has begun to determine the extent of contamination, as well as the extent of the
Company's responsibility. Providence Gas entered into a cost-sharing agreement
with Cargill, under which Providence Gas is responsible for approximately twenty
percent (20%) of the costs related to the investigation. To date, approximately
$300,000 has been spent on environmental assessment work at this site. Until
RIDEM provides its final response to the investigation, and the Company knows
its ultimate responsibility respective to other potentially responsible parties
with respect to the site, the Company cannot offer any conclusions as to its
ultimate financial responsibility with respect to the site.
Fall River Gas Company was a defendant in a civil action seeking to recover
anticipated remediation costs associated with contamination found at property
owned by the plaintiffs (the Cory Lane Site) in Tiverton, Rhode Island. This
claim was based on alleged dumping of material by Fall River Gas Company trucks
at the site in the 1930s and 1940s. In a settlement agreement effective December
3, 2001, the Company agreed to perform all assessment, remediation and
monitoring activities at the Cory Lane Site sufficient to obtain a final letter
of compliance from the RIDEM.
In a letter dated March 17, 2003, RIDEM sent the New England Gas Company
division of Southern Union (NEGC) a letter of responsibility pertaining to
alleged historical MGP impacted soils in a residential neighborhood along Bay
Street, Judson Street, Canonicus Street, Hooper Street, Hilton Street, Chase
Street and Foote Street (collectively the Bay Street Area) in Tiverton, Rhode
Island. The letter requested that NEGC prepare a draft Site Investigation Work
Plan (Work Plan) for submittal to RIDEM by April 10, 2003, and subsequently
perform a Site Investigation of the Bay Street Area. Without admitting
responsibility or accepting liability, NEGC responded to RIDEM in a letter dated
March 19, 2003, and agreed to perform the activities requested by the State
within the period specified by RIDEM. After receiving approval from RIDEM on a
Work Plan and upon obtaining access agreements from a number of property owners,
NEGC began assessment work on June 2, 2003. On August 20, 2003, two former
residents of the area filed a tort action against NEGC alleging personal injury
to the plaintiffs. This litigation has not been served on the Company. An
assessment report was filed with RIDEM on October 31, 2003, and RIDEM provided
NEGC comments to the assessment report in a letter dated January 27, 2004. As
the Bay Street Area is built on a historic dumpsite, research is underway to
identify other potentially responsible parties associated with the area.
Valley Gas Company is a party to an action in which Blackstone Valley Electric
Company (Blackstone) brought suit for contribution to its expenses of cleanup of
a site on Mendon Road in Attleboro, Massachusetts, to which coal manufacturing
waste was transported from a former MGP site in Pawtucket, Rhode Island (the
Blackstone Litigation). Blackstone Valley Electric Company v. Stone & Webster,
Inc., Stone & Webster Engineering Corporation, Stone & Webster Management
Consultants, Inc. and Valley Gas Company, C. A. No. 94-10178JLT, United States
District Court, District of Massachusetts. Valley Gas Company takes the position
in that litigation that it is indemnified for any cleanup expenses by Blackstone
pursuant to a 1961 agreement signed at the time of Valley Gas Company's
creation. This suit was stayed in 1995 pending the issuance of rulemaking at the
United States Environmental Protection Agency (EPA) (Commonwealth of
Massachusetts v. Blackstone Valley Electric Company, 67 F.3d 981 (1995)). The
requested rulemaking concerned the question of whether or not ferric
ferrocyanide (FFC) is among the "cyanides" listed as toxic substances under the
Clean Water Act and, therefore, is a "hazardous substance" under the
Comprehensive Environmental Response, Compensation and Liability Act. On October
6, 2003, the EPA issued a Final Administrative Determination declaring that FFC
is one of the "cyanides" under the environmental statutes. While the Blackstone
Litigation was stayed, Valley Gas Company and Blackstone (merged with
Narragansett Electric Company in May 2000) have received letters of
responsibility from the RIDEM with respect to releases from two MGP sites in
Rhode Island. RIDEM issued letters of responsibility to Valley Gas Company and
Blackstone in September 1995 for the Tidewater MGP in Pawtucket, Rhode Island,
and in February 1997 for the Hamlet Avenue MGP in Woonsocket, Rhode Island.
Valley Gas Company entered into an agreement with Blackstone (now Narragansett)
in which Valley Gas Company and Blackstone agreed to share equally the expenses
for the costs associated with the Tidewater site subject to reallocation upon
final determination of the legal issues that exist between the companies with
respect to responsibility for expenses for the Tidewater site and otherwise. No
such agreement has been reached with respect to the Hamlet site.
While the Blackstone Litigation has been stayed, National Grid and the Company
have jointly pursued claims against the bankrupt Stone & Webster entities
("Stone & Webster") based upon Stone & Webster's historic management of MGP
facilities on behalf of the alleged predecessors of both companies. On January
9, 2004, the U.S. Bankruptcy Court for the District of Delaware issued an order
approving a settlement between National Grid, Southern Union and Stone & Webster
that provided for the payment of $5 million out of the bankruptcy estates. This
payment is payable $1.25 million to Southern Union for payment of environmental
costs associated with the former Fall River Gas Company, and $3.75 million
payable to Southern Union and National Grid jointly for payment of future
environmental costs at the Tidewater and Hamlet sites. The settlement further
provides an admission of liability by Stone & Webster that gives National Grid
and Southern Union additional rights against historic Stone & Webster insurers.
In a letter dated March 11, 2003, the Commonwealth of Massachusetts Department
of Environmental Protection provided New England Gas Company a Notice of
Responsibility for 60 and 82 Hartwell Street in Fall River, Massachusetts. This
Notice of Responsibility requested that site assessment activities be conducted
with respect to the listed properties and with respect to the adjacent former
MGP property owned by NEGC at 66 5th Street, Fall River.
PENNSYLVANIA SITES. During 2002, PG Energy received inquiries from the
Pennsylvania Department of Environmental Protection (PADEP) pertaining to three
Pennsylvania former MGP sites. Of these three sites, PG Energy is currently
performing environmental assessment work at the Scranton MGP at the request of
PADEP. PG Energy has participated financially in PPL Electric Utilities
Corporation's (PPL's) environmental and health assessment of an additional MGP
site located in Sunbury, Pennsylvania. In May 2003, PPL commenced a remediation
project at the Sunbury site that was completed in August 2003. PG Energy has
contributed to PPL's remediation project by removing and relocating gas utility
lines located in the path of the remediation. In a letter dated January 12,
2004, PADEP notified PPL of its approval of the Remedy Certification Report
submitted by PPL for the Sunbury MGP clean-up project. The Company does not
believe the outcome of these matters will have a material adverse effect on its
financial position, results of operations or cash flows.
To the extent that potential costs associated with former MGPs are quantified,
the Company expects to provide any appropriate accruals and seek recovery for
such remediation costs through all appropriate means, including in rates charged
to gas distribution customers, insurance and regulatory relief. At the time of
the closing of the acquisition of the Company's Missouri service territories,
the Company entered into an Environmental Liability Agreement that provides that
Western Resources retains financial responsibility for certain liabilities under
environmental laws that may exist or arise with respect to Missouri Gas Energy.
In addition, the New England Division has reached agreement with its Rhode
Island rate regulators on a regulatory plan that creates a mechanism for the
recovery of environmental costs over a ten-year period. This plan, effective
July 1, 2002, establishes an environmental fund for the recovery of evaluation,
remedial and clean-up costs arising out of the Company's MGPs and sites
associated with the operation and disposal activities from MGPs. Similarly,
environmental costs associated with Massachusetts' facilities are recoverable in
rates over a seven-year period.
PANHANDLE ENERGY ENVIRONMENTAL MATTERS - Panhandle Energy's interstate natural
gas transportation operations are subject to federal, state and local
regulations regarding water quality, hazardous and solid waste disposal and
other environmental matters. Panhandle Energy has identified environmental
contamination at certain sites on its gas transmission systems and has
undertaken clean-up programs at these sites. The contamination resulted from the
past use of lubricants containing polychlorinated bi-phenyls (PCBs) in
compressed air systems; the past use of paints containing PCBs; and the past use
of wastewater collection facilities and other on-site disposal areas. Panhandle
has developed and is implementing a program to remediate such contamination in
accordance with federal, state and local regulations. Some remediation is being
performed by former Panhandle Energy affiliates in accordance with indemnity
agreements that also indemnify against certain future environmental litigation
and claims.
As part of the clean-up program resulting from contamination due to the use of
lubricants containing PCBs in compressed air systems, Panhandle Eastern Pipe
Line and Trunkline Gas Company have identified PCB levels above acceptable
levels inside the auxiliary buildings that house air compressor equipment at
thirty-two compressor station sites. Panhandle Energy has developed and is
implementing an EPA-approved process to remediate this PCB contamination in
accordance with federal, state and local regulations. Two sites have been
decontaminated per the EPA process as prescribed in the EPA regulations.
At some locations, PCBs have been identified in paint that was applied many
years ago. In accordance with EPA regulations, Panhandle Energy is implementing
a program to remediate sites where such issues have been identified during
painting activities. If PCBs are identified above acceptable levels, the paint
is removed and disposed of in an EPA-approved manner. Approximately 15% of the
paint projects in the last few years have required this special procedure.
The Illinois Environmental Protection Agency (IEPA) notified Panhandle Eastern
Pipe Line and Trunkline Gas Company, together with other non-affiliated parties,
of contamination at three former waste oil disposal sites in Illinois. Panhandle
Energy and 21 other non-affiliated parties conducted an initial investigation of
one of the sites. Based on the information found during the initial
investigation, Panhandle Energy and the 21 other non-affiliated parties have
decided to further delineate the extent of contamination by authorizing a Phase
II investigation at this site. Once data from the Phase II investigation is
evaluated, Panhandle Energy and the 21 other non-affiliated parties will
determine what additional actions will be taken. In addition, Illinois EPA has
informally indicated that the Pierce Oil Site is being considered for referral
to the U.S. EPA, so that environmental contamination present at the site can be
addressed through the federal Superfund program. Panhandle Eastern Pipe Line's
and Trunkline Gas Company's estimated share for the costs of assessment and
remediation of the sites, based on the volume of waste sent to the facilities,
is approximately 17%.
Based on information available at this time, it would appear the amount reserved
for all of the above is adequate to cover the potential exposure for clean-up
costs.
AIR QUALITY CONTROL
In 1998, the EPA issued a final rule on regional ozone control that requires
Panhandle Energy to place controls on engines in five Midwestern states. The
part of the rule that affects Panhandle Energy was challenged in court by
various states, industry and other interests, including Interstate Natural Gas
Association of America (INGAA), an industry group to which Panhandle Energy
belongs. In March 2000, the court upheld most aspects of the EPA's rule, but
agreed with INGAA's position and remanded to the EPA the sections of the rule
that affected Panhandle Energy. The final rule is expected in 2004. Based on an
EPA guidance document negotiated with gas industry representatives in 2002, it
is believed that Panhandle Energy will be required to reduce NOx emissions by
82% on the identified large internal combustion (IC) engines and will be able to
trade off engines within a company and State in an effort to create a cost
effective NOx reduction solution. The implementation date is expected to be May
2007. The rule impacts 20 large internal combustion engines on the Panhandle
Energy system in Illinois and Indiana at an approximate cost of $17 million for
capital improvements through 2007, consistent with budget projections.
In 2002, the Texas Commission on Environmental Quality enacted the
Houston/Galveston SIP regulations requiring reductions in NOx emissions in an
eight-county area surrounding Houston. Trunkline's Cypress compressor station is
affected and may require the installation of emission controls. In 2003, new
regulations will also require certain grandfathered facilities in Texas to enter
into a new source permit program which may require the installation of emission
controls at five additional facilities. These two rules affect six company
facilities in Texas at an estimated cost of $12 million for capital improvements
through 2007, based on current projections.
EPA proposed various Maximum Achievable Control Technology (MACT) rules in late
2002 and early 2003. The rules require that Panhandle Eastern Pipe Line and
Trunkline Gas Company control Hazardous Air Pollutants (HAPS) emitted from major
sources by 90% of carbon monoxide (CO) emissions. Most of Panhandle Eastern Pipe
Line and Trunkline Gas Company compressor stations are major sources. The HAP's
pollutant of concern for Panhandle Eastern Pipe Line and Trunkline Gas Company
is formaldehyde. As proposed, the rule seeks to reduce CO emissions as a
surrogate for formaldehyde. For IC engines, the control technology would be the
use of non-selective catalytic reduction (NSCR) catalysts and the expected
implementation date is February 2007. For turbines, the control technology would
be the use of oxidation catalysts and the expected implementation date is
December 2007. Panhandle Eastern Pipe Line and Trunkline Gas Company have 26 IC
engines and two turbines subject to the rules. It is expected that compliance
with these regulations will cost approximately $8 million, based on current
projections.
REGULATORY
On May 31, 2002, the staff of the MPSC recommended that the Commission disallow
approximately $15 million in gas costs incurred during the period July 1, 2000
through June 30, 2001. Missouri Gas Energy filed its response in opposition to
the Staff's recommendation on July 11, 2002, vigorously disputing the Commission
staff's assertions. Missouri Gas Energy intends to vigorously defend itself in
this proceeding. This matter went into recess following a hearing in May of
2003. Following the May hearing, the Commission staff reduced its disallowance
recommendation to approximately $9.3 million. The hearing concluded in November
2003 and the matter will be fully submitted by late February 2004.
On November 27, 2001, August 1, 2000 and August 12, 1999, the staff of the MPSC
recommended that the Commission disallow approximately $5.9 million, $5.9
million and $4.3 million, respectively, in gas costs incurred during the period
July 1, 1999 through June 30, 2000, July 1, 1998 through June 30, 1999, and July
1, 1997 through June 30, 1998, respectively. The basis of these proposed
disallowances appears to be the same as was rejected by the Commission through
an order dated March 12, 2002, applicable to the period July 1, 1996 through
June 30, 1997. MGE intends to vigorously defend itself in these proceedings. On
November 4, 2002, the Commission adopted a procedural schedule calling for a
hearing in this matter some time after May 2003. No date for this hearing has
been set.
SOUTHWEST GAS LITIGATION
Several actions were commenced in federal courts 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 were no claims allowed against Southern Union. Southern
Union's claims against Southwest were settled on August 6, 2002, by Southwest's
payment to Southern Union of $17,500,000. Southern Union's claims against ONEOK,
Inc. (ONEOK) and the individual defendants associated with ONEOK were settled on
January 3, 2003, following the closing of Southern Union's sale of the Texas
assets to ONEOK, by ONEOK's payment to Southern Union of $5,000,000. Southern
Union's claims against Jack Rose, former aide to former 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, former 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 former Commissioner Irvin. The Court denied former
Commissioner Irvin's motions to set aside the verdict and reduce the amount of
punitive damages. Former Commissioner Irvin has appealed to the Ninth Circuit
Court of Appeals. The Company intends to vigorously pursue collection of the
award. With the exception of ongoing legal fees associated with the collection
of damages from former Commissioner Irvin, the Company believes that the results
of the above-noted Southwest litigation and any related appeals will not have a
materially adverse effect on the Company's financial condition, results of
operations or cash flows.
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.
OTHER
In 1993, the U.S. Department of the Interior announced its intention to seek,
through its Minerals Management Service (MMS) additional royalties from gas
producers as a result of payments received by such producers in connection with
past take-or-pay settlements and buyouts or buy downs of gas sales contracts
with natural gas pipelines. Panhandle Energy's pipelines, with respect to
certain producer contract settlements, may be contractually required to
reimburse or, in some instances, to indemnify producers against such royalty
claims. The potential liability of the producers to the government and of the
pipelines to the producers involves complex issues of law and fact which are
likely to take substantial time to resolve. If required to reimburse or
indemnify the producers, Panhandle Energy's pipelines may file with the FERC to
recover a portion of these costs from pipeline customers. Panhandle Energy does
not believe the outcome of this matter will have a material adverse effect on
its financial position, results of operations or cash flows.
Following its acquisition by the Company in June 2003, Panhandle Energy
initiated a workforce reduction initiative designed to reduce the workforce by
approximately 5 percent. The workforce reduction initiative was an involuntary
plan with a voluntary component, and was fully implemented by September 30,
2003. Total estimated workforce reduction initiative costs are approximately
$9,000,000 which are a portion of the $30,448,000 of additional transaction
costs incurred (see Acquisition and Sales).
DISCONTINUED OPERATIONS
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK, Inc. (ONEOK) for
approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000.
In accordance with accounting principles generally accepted in the United States
of America, the results of operations and gain on sale of the Texas operations
have been segregated and reported as "discontinued operations" in the
Consolidated Statement of Operations and Consolidated Statement of Cash Flows
for the respective periods.
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 SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
2003 2002 2003 2002
Operating revenues....................... $ -- $ 96,801 $ -- $ 144,490
=========== =========== =========== ===========
Net operating margin (a)................. $ -- $ 29,860 $ -- $ 51,480
=========== =========== =========== ===========
Net earnings from discontinued
operations (b) $ -- $ 10,900 $ -- $ 13,591
=========== =========== =========== ===========
- ---------------------------------
(a) Net operating margin consists of operating revenues less gas purchase costs
and revenue-related taxes.
(b) Net earnings from discontinued operations do not include any allocation of
interest expense or other corporate costs, in accordance with generally
accepted accounting principles. At the time of the sale, all outstanding
debt of Southern Union Company and subsidiaries was maintained at the
corporate level, and no debt was assumed by ONEOK, Inc. in the sale of the
Texas operations.
REPORTABLE SEGMENTS
The Company's operations include two reportable segments: (i) Transportation and
Storage, and (ii) Distribution. The Transportation and Storage segment is
primarily engaged in the interstate transportation and storage of natural gas in
the Midwest and Southwest, and also provides LNG terminalling and regasification
services. Its operations are conducted through Panhandle Energy, which the
Company acquired on June 11, 2003. The Distribution segment is primarily engaged
in the local distribution of natural gas in Missouri, Pennsylvania, Rhode Island
and Massachusetts. Its operations are conducted through the Company's three
regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas
Company.
Revenue included in the All Other category is attributable to several operating
subsidiaries of the Company: PEI Power Corporation generates and sells
electricity; Fall River Gas Appliance Company, Inc. and Valley Appliance and
Merchandising Company rent gas burning appliances and/or equipment and, along
with PG Energy Services Inc., offer appliance service contracts; ProvEnergy
Power Company LLC (ProvEnergy Power), which the Company sold effective October
31, 2003, provided outsourced energy management services and owned 50% of
Capital Center Energy Company LLC, a joint venture formed between ProvEnergy and
ERI Services, Inc. to provide retail power and conditioned air; and Alternate
Energy Corporation provides energy consulting services. None of these businesses
have ever met the quantitative thresholds for determining reportable segments
individually or in the aggregate. The Company also has corporate operations that
do not generate any revenues.
The Company evaluates segment performance based on several factors, of which the
primary financial measure is net operating revenues. Net Operating Revenues is
defined as operating margin, less operating, maintenance and general expenses,
depreciation and amortization, and taxes other than on income and revenues.
The following table sets forth certain selected financial information for the
Company's segments for the three- and six-month periods ended December 31, 2003
and 2002. Financial information for the Transportation and Storage segment
reflects the operations of Panhandle Energy beginning on its acquisition date of
June 11, 2003. There were no material intersegment revenues during the periods
presented.
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31
2003 2002 2003 2002
---- ---- ---- ----
Revenues from external customers:
Distribution....................................... $ 375,822 $ 345,370 $ 491,851 $ 443,506
Transportation and Storage......................... 130,344 -- 244,563 --
All Other.......................................... 947 734 2,093 2,308
------------- ------------- ------------- -------------
Total consolidated operating revenues................... $ 507,113 $ 346,104 $ 738,507 $ 445,814
============= ============= ============= =============
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31
2003 2002 2003 2002
---- ---- ---- ----
Operating Margin:
Distribution....................................... $ 108,954 $ 117,301 $ 163,288 $ 170,573
Transportation and Storage......................... 130,344 -- 244,563 --
All Other.......................................... 799 730 1,555 1,922
------------ -------------- ------------- -------------
Total consolidated operating margin..................... $ 240,097 $ 118,031 $ 409,406 172,495
============= ============= ============= =============
Depreciation and amortization:
Distribution....................................... $ 14,583 $ 13,895 $ 29,263 $ 28,106
Transportation and Storage......................... 16,810 -- 33,158 --
All Other.......................................... 141 141 289 285
------------- ------------- ------------- -------------
Total segment depreciation and amortization............. 31,534 14,036 62,710 28,391
Reconciling Item -- Corporate........................... 163 31 321 60
------------- ------------- ------------- -------------
Total consolidated depreciation and amortization........ $ 31,697 $ 14,067 $ 63,031 $ 28,451
============= ============= ============= =============
Net operating revenues (loss):
Distribution....................................... $ 44,252 $ 58,699 $ 32,916 $ 52,490
Transportation and Storage......................... 52,601 -- 90,520 --
All Other.......................................... (421) (455) (736) (304)
-------------- ----------- ------------ -------------
Total segment net operating revenues (loss)............. 96,432 58,244 122,700 52,186
Reconciling Items:
Corporate.......................................... (1,055) (2,742) (3,344) (4,473)
------------- ---------- ---------- ------------
Total consolidated net operating revenues .............. $ 95,377 $ 55,502 $ 119,356 $ 47,713
============= ============= ============= =============
Expenditures for long-lived assets:
Distribution....................................... $ 24,299 $ 16,170 $ 41,792 $ 34,542
Transportation and Storage......................... 43,075 -- 63,356 --
All Other.......................................... 236 879 286 1,104
------------ ------------ ------------ ------------
Total segment expenditures for long-lived assets........ 67,610 17,049 105,434 35,646
Reconciling item - Corporate............................ 3,229 1,157 5,657 2,460
------------- ------------- ------------- -------------
Total consolidated expenditures for long-lived assets... $ 70,839 $ 18,206 $ 111,091 $ 38,106
============== ============= ============== =============
Reconciliation of net operating revenues to earnings from continuing operations
before income taxes:
Net operating revenues ............................ $ 95,377 $ 55,502 $ 119,356 $ 47,713
Interest........................................... (32,636) (20,742) (66,600) (41,743)
Dividends on preferred securities of subsidiary trust -- (2,370) -- (4,740)
Other income, net.................................. 514 (2,712) 4,321 13,726
------------- ------------- ------------- -------------
Earnings from continuing operations before income taxes $ 63,255 $ 29,678 $ 57,077 $ 14,956
============== ============== ============= =============
DECEMBER 31, JUNE 30,
2003 2003
---- ----
Total assets:
Distribution....................................... $ 2,403,517 $ 2,243,257
Transportation and Storage......................... 2,190,394 2,212,467
All Other.......................................... 42,821 50,073
------------- --------------
Total segment assets.................................... 4,636,732 4,505,797
Reconciling Items -- Corporate.......................... 118,343 91,928
------------- -------------
Total consolidated assets............................... $ 4,755,075 $ 4,597,725
============= =============
SOUTHERN UNION COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW. Southern Union Company (Southern Union and together with its
subsidiaries, the Company) is primarily engaged in the transportation, storage
and distribution of natural gas in the United States. The Company's interstate
natural gas transportation and storage operations are conducted through
Panhandle Energy, which serves approximately 500 customers in the Midwest and
Southwest. Panhandle Energy was acquired by Southern Union on June 11, 2003, as
further described below. The Company's local natural gas distribution operations
are conducted through its three regulated utility divisions, Missouri Gas
Energy, PG Energy and New England Gas Company, which collectively serve over
950,000 residential, commercial and industrial customers in Missouri,
Pennsylvania, Rhode Island and Massachusetts.
On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy
Corporation for approximately $581,729,000 in cash and 3,000,000 shares of
Southern Union common stock (before adjustment for subsequent stock dividends)
valued at approximately $48,900,000 based on market prices at closing and in
connection therewith incurred transaction costs estimated at approximately
$30,448,000. Southern Union also incurred additional deferred state income tax
liabilities estimated at $18,388,000 as a result of the transaction. At the time
of the acquisition, Panhandle Energy had approximately $1,157,228,000 of debt
outstanding that it retained. The Company funded the cash portion of the
acquisition with approximately $437,000,000 in cash proceeds it received from
the January 1, 2003 sale of its Texas operations, approximately $121,250,000 of
the net proceeds it received from concurrent common stock and equity units
offerings and with working capital available to the Company. The Company
structured the Panhandle Energy acquisition and the sale of its Texas operations
to qualify as a like-kind exchange of property under Section 1031 of the
Internal Revenue Code of 1986, as amended. The acquisition was accounted for
using the purchase method of accounting in accordance with accounting principles
generally accepted in the United States of America with the purchase price paid
by the Company being allocated to Panhandle Energy's net assets as of the
acquisition date based on preliminary estimates. The Panhandle Energy assets
acquired and liabilities assumed have been recorded at their estimated fair
value as of the acquisition date and are subject to further assessment and
adjustment pending the results of outside appraisals. The outside appraisals are
expected to be completed prior to June 30, 2004. Panhandle Energy's results of
operations have been included in the Consolidated Statement of Operations since
June 11, 2003. Thus, the Consolidated Statement of Operations for the periods
subsequent to the acquisition is not comparable to the same periods in prior
years.
Panhandle Energy is primarily engaged in the interstate transportation and
storage of natural gas and also provides liquefied natural gas (LNG)
terminalling and regasification services and is subject to the rules and
regulations of the Federal Energy Regulatory Commission (FERC). The Panhandle
Energy entities include Panhandle Eastern Pipe Line Company, LLC (Panhandle
Eastern Pipe Line), Trunkline Gas Company, LLC (Trunkline), a wholly-owned
subsidiary of Panhandle Eastern Pipe Line, Sea Robin Pipeline Company (Sea
Robin), a Louisiana joint venture and indirect wholly-owned subsidiary of
Panhandle Eastern Pipe Line, Trunkline LNG Company, LLC (Trunkline LNG), a
wholly-owned subsidiary of Trunkline LNG Holdings, LLC (LNG Holdings) and
Southwest Gas Storage, LLC (Southwest Gas Storage), a wholly-owned subsidiary of
Panhandle Eastern Pipe Line. Collectively, the pipeline assets include more than
10,000 miles of interstate pipelines that transport natural gas from the Gulf of
Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major
U.S. markets in the Midwest and Great Lakes region. The pipelines have a
combined peak day delivery capacity of 5.4 billion cubic feet (bcf) per day and
72 bcf of owned underground storage capacity. Trunkline LNG, located on
Louisiana's Gulf Coast, operates one of the largest LNG import terminals in
North America and has 6.3 bcf of above ground LNG storage facilities.
Upon acquiring Panhandle Energy it was determined that Panhandle Energy's
operations could not be integrated efficiently into Southern Union, but that a
new operating platform would have to be established. By doing this at Panhandle
Energy, the Company obviated the need for any corporate information technology
allocation and, established a more efficient platform from which to operate all
of the Company's businesses. Direct integration savings of $15,000,000 are
expected from this process of which approximately $11,000,000 have been achieved
to date.
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK, Inc. (ONEOK) for
approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000.
In accordance with accounting principles generally accepted in the United States
of America, the results of operations and gain on sale of the Texas operations
have been segregated and reported as "discontinued operations" in the
Consolidated Statement of Operations and Consolidated Statement of Cash Flows
for the respective periods.
RESULTS OF OPERATIONS
The Company's results of operations are discussed on a consolidated basis and on
a segment basis for each of the two reportable segments. The Company's
reportable segments include the Transportation and Storage segment and the
Distribution segment. Segment results of operations are presented on a net
operating revenues basis. Net operating revenues is defined as operating margin,
less operating, maintenance and general expenses, depreciation and amortization,
and taxes other than on income and revenues, and represents one of the financial
measures that the Company uses to internally manage its business. For additional
segment reporting information, see Reportable Segments in Notes to Consolidated
Financial Statements.
CONSOLIDATED RESULTS
The following table provides selected financial data regarding the Company's
consolidated results of operations for the three- and six-month periods ended
December 31, 2003 and 2002:
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
2003 2002 2003 2002
------------ ------------ ------------ -----------
(THOUSANDS OF DOLLARS)
Net operating revenues (loss):
Distribution segment..................................... $ 44,252 $ 58,699 $ 32,916 $ 52,490
Transportation and storage segment....................... 52,601 -- 90,520 --
All other................................................ (421) (455) (736) (304)
Corporate................................................ (1,055) (2,742) (3,344) (4,473)
------------ ------------ ------------ ------------
Total net operating revenues ........................ 95,377 55,502 119,356 47,713
Other income (expenses):
Interest ................................................ (32,636) (20,742) (66,600) (41,743)
Dividends on preferred securities of subsidiary trust.... -- (2,370) -- (4,740)
Other, net............................................... 514 (2,712) 4,321 13,726
------------ ------------ ------------ ------------
Total other expenses, net............................ (32,122) (25,824) (62,279) (32,757)
------------ ------------ ------------ ------------
Federal and state income taxes ............................... 24,833 11,159 22,362 5,623
------------ ------------ ------------ ------------
Net earnings from continuing operations....................... 38,422 18,519 34,715 9,333
------------ ------------ ------------ ------------
Discontinued operations:
Earnings from discontinued operations
before income taxes.................................. -- 17,468 -- 21,781
Federal and state income taxes........................... -- 6,568 -- 8,190
------------ ------------ ------------ ------------
Net earnings from discontinued operations..................... -- 10,900 -- 13,591
------------ ------------ ------------ ------------
Net earnings ................................................ 38,422 29,419 34,715 22,924
Preferred stock dividends..................................... (4,004) -- (4,004) --
------------ ------------ ------------ ------------
Net earnings available for common stock....................... $ 34,418 $ 29,419 $ 30,711 $ 22,924
============ ============ ============ ============
THREE MONTHS ENDED DECEMBER 31, 2003 COMPARED TO 2002. The Company recorded net
earnings available for common stock from continuing operations (hereafter
referred to as "net earnings from continuing operations") of $34,418,000 for the
three-month period ended December 31, 2003 compared with net earnings from
continuing operations of $18,519,000 for the same period in 2002. Earnings from
continuing operations per diluted share were $.47 in 2003 compared with $.32 in
2002. The Company recorded net earnings available for common stock of
$34,418,000 for the three-month period ended December 31, 2003 compared with net
earnings of $29,419,000 for the same period in 2002. Earnings per diluted share
were $.47 in 2003 compared with $.50 in 2002.
The $15,899,000 increase in net earnings from continuing operations was
primarily attributable to an increase in net operating revenues from the
Transportation and Storage segment of $52,601,000, a decrease in dividends on
preferred securities of subsidiary trust of $2,370,000, and an increase in other
income of $3,226,000, which was offset by a decrease in net operating revenues
from the Distribution segment of $14,447,000, an increase in interest expense of
$11,894,000, an increase in income taxes of $13,674,000 and an increase in
preferred stock dividends of $4,004,000 (see Business Segment Results, Interest
Expense, Dividends on Preferred Securities of Subsidiary Trust, Other Income
(Expense), Net, Federal and State Income Taxes, and Preferred Stock Dividends,
below).
Net earnings from discontinued operations were nil for the three-month period
ended December 31, 2003 compared with $10,900,000 for the same period in 2002.
Earnings from discontinued operations per diluted share were nil in 2003
compared with $.18 in 2002.
SIX MONTHS ENDED DECEMBER 31, 2003 COMPARED TO 2002. The Company recorded net
earnings from continuing operations of $30,711,000 for the six-month period
ended December 31, 2003 compared with net earnings from continuing operations of
$9,333,000 for the same period in 2002. Earnings from continuing operations per
diluted share were $.42 in 2003 compared with $.16 in 2002. The Company recorded
net earnings available for common stock of $30,711,000 for the six-month period
ended December 31, 2003 compared with net earnings of $22,924,000 for the same
period in 2002. Earnings per diluted share were $.42 in 2003 compared with $.39
in 2002.
The $21,378,000 increase in net earnings from continuing operations was
primarily attributable to an increase in net operating revenues from the
Transportation and Storage segment of $90,520,000, and a decrease in dividends
on preferred securities of subsidiary trust of $4,740,000 which was offset by a
decrease in net operating revenues from the Distribution segment of $19,574,000,
an increase in interest expense of $24,857,000, a decrease in other income of
$9,405,000, an increase in income taxes of $16,739,000 and an increase in
preferred stock dividends of $4,004,000 (see Business Segment Results, Interest
Expense, Dividends on Preferred Securities of Subsidiary Trust, Other Income
(Expense), Net, Federal and State Income Taxes, and Preferred Stock Dividends,
below).
Net earnings from discontinued operations were nil for the six-month period
ended December 31, 2003 compared with $13,591,000 for the same period in 2002.
Earnings from discontinued operations per diluted share were nil in 2003
compared with $.23 in 2002.
INTEREST EXPENSE. Interest expense was $32,636,000 for the three-month period
ended December 31, 2003, compared with $20,742,000 in 2002. Interest expense for
the three-month period ended December 31, 2003 increased by $11,726,000 on debt
related to the Panhandle properties and by $790,000 related to dividends on
preferred securities of subsidiary trust (see Dividends on Preferred Securities
of Subsidiary Trust). These items were partially offset by decreased interest
expense of $1,168,000 on the $311,087,000 bank note (the 2002 Term Note) entered
into by the Company on July 15, 2002 to refinance a portion of the $485 million
Term Note entered into by the Company on August 28, 2000 to (i) fund the cash
consideration paid to stockholders of Fall River Gas, ProvEnergy and Valley
Resources, (ii) refinance and repay long- and short-term debt assumed in the New
England Operations, and (iii) acquisition costs of the New England Operations.
This decrease in the 2002 Term Note interest was due to reductions in LIBOR
rates during 2003 and the principal repayment of $125,000,000 of the 2002 Term
Note since its inception. The average rate of interest on all debt decreased
from 5.8% in 2002 to 5.1% in 2003.
Interest expense was $66,600,000 for the six-month period ended December 31,
2003, compared with $41,743,000 in 2002. Interest expense for the six-month
period ended December 31, 2003 increased by $23,449,000 on debt related to the
Panhandle properties and by $3,160,000 related to dividends on preferred
securities of subsidiary trust (see Dividends on Preferred Securities of
Subsidiary Trust.) These items were partially offset by a decrease in interest
expense of $2,412,000 in 2003 on the aforementioned 2002 Term Note. The average
rate of interest on all debt decreased from 5.9% in 2002 to 5.1% in 2003.
DIVIDENDS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST. Dividends on preferred
securities of subsidiary trust were nil and $2,370,000 for the three-month
periods ended December 31, 2003 and 2002, respectively, and nil and $4,740,000
for the six-month periods ended December 31, 2003 and 2002, respectively.
Effective July 1, 2003, the Company adopted the FASB standard, Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity, which requires dividends on preferred securities of subsidiary trusts to
be classified as interest expense; the reclassification of amounts reported as
dividends in prior periods is not permitted. In accordance with the Statement,
$3,160,000 of dividends on preferred securities of subsidiary trust recorded by
the Company subsequent to July 1, 2003, have been classified as interest expense
(see Interest Expense). On October 1, 2003, the Company called the Subordinated
Notes for redemption, and the Subordinated Notes and Preferred Securities were
redeemed on October 31, 2003.
OTHER INCOME (EXPENSE), NET. Other income for the three-month period ended
December 31, 2003 was $514,000 compared with other expense of $2,712,000 for the
same period in 2002. Other income for the three-month period ended December 31,
2003 includes income of $743,000 generated from the sale and/or rental of
gas-fired equipment and appliances by various operating subsidiaries. This item
was partially offset by $377,000 of legal costs associated with the collection
of damages from former Arizona Corporation Commissioner James Irvin related to
the Company's unsuccessful acquisition of Southwest Gas Corporation (Southwest).
Other expense for the three-month period ended December 31, 2002 includes
$2,838,000 of legal costs associated with the Southwest litigation and
$1,298,000 of selling costs related to the disposition of the Company's Texas
operations. These items were partially offset by $669,000 of income generated
from the sale and/or rental of gas-fired equipment and appliances.
Other income for the six-month period ended December 31, 2003 was $4,321,000
compared with $13,726,000 for the same period in 2002. Other income for the
six-month period ended December 31, 2003 includes a gain of $6,123,000 on the
early extinguishment of debt and income of $1,527,000 generated from the sale
and/or rental of gas-fired equipment and appliances. These items were partially
offset by charges of $1,603,000 and $1,150,000 to reserve for the impairment of
Southern Union's investments in a technology company and in an energy-related
joint venture, respectively, and $655,000 of legal costs associated with the
collection of damages from former Arizona Corporation Commissioner James Irvin
related to the Southwest litigation. Other income for the six-month period ended
December 31, 2002 includes a gain of $17,500,000 on the settlement of the
Southwest litigation and income of $1,242,000 generated from the sale and/or
rental of gas-fired equipment and appliances. These items were partially offset
by $4,969,000 of legal costs associated with the Southwest litigation and
$1,298,000 of selling costs related to the disposition of the Company's Texas
operations.
FEDERAL AND STATE INCOME TAXES. Federal and state income tax expense from
continuing operations for the three-month period ended December 31, 2003 and
2002 was $24,833,000 and $11,159,000, respectively. The Company's consolidated
federal and state effective income tax rate was 39% and 38% for the three-month
period ended December 31, 2003 and 2002, respectively. The increase in the
effective tax rate is primarily the result of a change in the level of pre-tax
earnings and additional state income taxes due to the acquisition of Panhandle
Energy.
Federal and state income tax expense from continuing operations for the
six-month period ended December 31, 2003 and 2002 was $22,362,000 and
$5,623,000, respectively. The Company's consolidated federal and state effective
income tax rate was 39% and 38% for the six-month period ended December 31, 2003
and 2002, respectively. The increase in the effective tax rate is primarily the
result of a change in the level of pre-tax earnings and additional state income
taxes due to the acquisition of Panhandle Energy.
PREFERRED STOCK DIVIDENDS. Dividends on preferred securities were $4,004,000 and
nil for the three-month periods ended December 31, 2003 and 2002, respectively,
and $4,004,000 and nil for the six-month periods ended December 31, 2003 and
2002, respectively. On October 8, 2003, the Company issued $230,000,000 of 7.55%
Noncummulative Preferred Stock, Series A to the public (see Financial Condition,
below).
DISCONTINUED OPERATIONS. Net earnings from discontinued operations were nil for
the three- and six-month periods ended December 31, 2003 compared with
$10,900,000 and $13,591,000 for the same periods in 2002. The Company completed
the sale of its Texas operations effective January 1, 2003, resulting in the
recording of an after-tax gain on sale of $18,928,000 during the fiscal year
ended June 30, 2003 that is reported in earnings from discontinued operations in
accordance with the Financial Accounting Standards Board (FASB) standard,
Accounting for the Impairment or Disposal of Long-Lived Assets. The after-tax
gain on the sale of the Texas operations was impacted by the elimination of
$70,469,000 of goodwill related to these operations which was primarily non-tax
deductible.
BUSINESS SEGMENT RESULTS
DISTRIBUTION SEGMENT -- The Company's Distribution segment is primarily engaged
in the local distribution of natural gas in Missouri, Pennsylvania, Rhode Island
and Massachusetts. Its operations are conducted through the Company's three
regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas
Company. Collectively, the utility divisions serve more than 950,000
residential, commercial and industrial customers.
The following table provides summary data regarding the Distribution segment's
results of operations for the three- and six-month periods ending December 31,
2003 and 2002:
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31, DECEMBER 31,
2003 2002 2003 2002
------------- ------------- ------------- --------------
(THOUSANDS OF DOLLARS)
Operating revenues........................................ $ 375,822 $ 345,370 $ 491,851 $ 443,506
Cost of gas and other energy.............................. (253,732) (215,501) (311,102) (257,180)
Revenue-related taxes..................................... (13,136) (12,568) (17,461) (15,753)
------------- ------------- ------------- --------------
Operating margin...................................... 108,954 117,301 163,288 170,573
Operating expenses:
Operating, maintenance, and general................... 44,216 38,711 89,489 77,745
Depreciation and amortization......................... 14,583 13,895 29,263 28,106
Taxes other than on income and revenues............... 5,903 5,996 11,620 12,232
------------- ------------- ------------- --------------
Total operating expense............................ 64,702 58,602 130,372 118,083
------------- ------------- ------------- --------------
Net operating revenues ............................ $ 44,252 $ 58,699 $ 32,916 $ 52,490
============= ============= ============= ==============
OPERATING REVENUES. Operating revenues were $375,822,000 for the three-month
period ended December 31, 2003, compared with $345,370,000 for the same period
in 2002. Gas purchase and other energy costs for the three-month period ended
December 31, 2003 were $253,732,000, compared with $215,501,000 in 2002. The
Company's operating revenues are affected by the level of sales volumes and by
the pass-through of increases or decreases in the Company's gas purchase costs
through its purchased gas adjustment clauses. Additionally, revenues are
affected by increases and decreases in gross receipts taxes (revenue-related
taxes) which are levied on sales revenue as collected from customers and
remitted to the various taxing authorities. The increase in both operating
revenues and gas purchase costs between periods was primarily due to a 34%
increase in the average cost of gas from $5.59 per thousand cubic feet (Mcf) in
2002 to $7.50 per Mcf in 2003, which was partially offset by a 12% decrease in
gas sales volumes to 33,840 million cubic feet (MMcf) in 2003 from 38,549 MMcf
in 2002. The increase in the average cost of gas is due to increases in the
average spot market prices throughout the Company's distribution system as a
result of current competitive pricing occurring within the entire energy
industry. The decrease in gas sales volumes is primarily due to
warmer-than-normal weather in 2003 as compared with colder-than-normal weather
in 2002.
Weather in Missouri Gas Energy's service territories was 89% of a 30-year
measure for the three-month period ended December 31, 2003, compared with 102%
in 2002. PG Energy's service territories experienced weather that was 99% of a
30-year measure in 2003 for the three-month period ended December 31, 2003,
compared with 106% in 2002. Weather for the New England Gas Company service
territories was 93% of a 30-year measure for the three-month period ended
December 31, 2003, compared with 103% in 2002.
Operating revenues were $491,851,000 for the six-month period ended December 31,
2003, compared with $443,506,000 for the same period in 2002. Gas purchase and
other energy costs for the six-month period ended December 31, 2003 were
$311,102,000 compared with $257,180,000 in 2002. The increase in both operating
revenues and gas purchase costs between periods was primarily due to a 35%
increase in the average cost of gas from $5.59 per Mcf in 2002 to $7.53 per Mcf
in 2003, which was partially offset by a 10% decrease in gas sales volumes to
41,328 MMcf in 2003 from 46,039 MMcf in 2002. The increase in the average cost
of gas is due to increases in the average spot market prices throughout the
Company's distribution system as a result of current competitive pricing
occurring within the entire energy industry. The decrease in gas sales volumes
is primarily due to warmer-than-normal weather in 2003 as compared with
near-normal or colder-than-normal weather in 2002.
Weather in Missouri Gas Energy's service territories was 90% of a 30-year
measure for the six-month period ended December 31, 2003, compared with 99% in
2002. PG Energy's service territories experienced weather that was 96% of a
30-year measure in 2003 for the six-month period ended December 31, 2003,
compared with 103% in 2002. Weather for the New England Gas Company service
territories was 90% of a 30-year measure for the six-month period ended December
31, 2003, compared with 99% in 2002.
OPERATING MARGIN. Operating margin (operating revenues less gas purchase and
other energy costs and revenue-related taxes) decreased $8,347,000 for the
three-month period ended December 31, 2003 compared with the same period in
2002, principally as a result of the warmer-than-normal weather, previously
discussed. Operating margins and earnings are primarily dependent upon gas sales
volumes and gas service rates. The level of gas sales volumes is sensitive to
the variability of the weather as well as the timing of acquisitions and
divestitures. Operating margin was also impacted by a $1,819,000 decrease in gas
transportation revenues for the three-month period ended December 31, 2003
compared with the same period in 2002. Gas transportation revenues were impacted
by certain customers utilizing alternative energy sources such as fuel oil,
customer closure of certain facilities and various customers reducing
production.
Operating margin decreased $7,285,000 for the six-month period ended December
31, 2003 compared with the same period in 2002, principally as a result of the
warmer-than-normal weather, and a $1,516,000 reduction in gas transportation
revenues, both previously discussed.
OPERATING EXPENSES. Operating expenses, which include operating, maintenance and
general expenses, depreciation and amortization and taxes other than on income
and revenues, were $64,702,000 for the three-month period ended December 31,
2003, an increase of $6,100,000, compared with $58,602,000 for the same period
in 2002. Operating expenses were impacted by $2,458,000 of increased pension and
other post retirement benefits costs primarily due to the impact of stock market
volatility on plan assets, $593,000 of increased bad debt expense resulting from
higher customer receivables due to higher gas prices, increased insurance
expense of $949,000, increased depreciation and amortization of $688,000
primarily due to normal growth in plant, and increased employee payroll costs
due to general wage increases and increased overtime due to meter turn-ons,
system maintenance and Sarbanes-Oxley Section 404 documentation procedures.
Operating expenses were $130,372,000 for the six-month period ended December 31,
2003, an increase of $12,289,000, as compared with $118,083,000 for the same
period in 2002. Operating expenses were impacted by $4,763,000 of increased
pension and other post retirement benefits costs, $2,303,000 of increased bad
debt expense, $1,489,000 of increased insurance expense, $1,157,000 of increased
depreciation and amortization, and increased employee payroll costs all
previously discussed.
Due to the colder than normal weather during January 2004 in the Northeast and
higher gas costs during such period as compared with the previous year, the
Company anticipates an increase in operating revenues for the quarter ended
March 31, 2004. This could put some pressure on collections and increase the
Company's exposure to bad debts during fiscal 2004 and thus may affect the
operating results for this segment for the remainder of the fiscal year. The
Company also anticipates increased costs related to pension and other post
retirement benefits and insurance costs which were anticipated in the Company's
fiscal year 2004 earnings guidance.
TRANSPORTATION AND STORAGE SEGMENT -- The Transportation and Storage segment is
primarily engaged in the interstate transportation and storage of natural gas in
the Midwest and Southwest, and also provides LNG terminalling and regasification
services. Its operations are conducted through Panhandle Energy, which the
Company acquired on June 11, 2003.
Panhandle Energy operates a large natural gas pipeline network, which provides
approximately 500 customers in the Midwest and Southwest with a comprehensive
array of transportation services. Panhandle Energy's major customers include 25
utilities located primarily in the United States Midwest market area, which
encompasses large portions of Illinois, Indiana, Michigan, Missouri, Ohio and
Tennessee.
The results of operations from Panhandle Energy have been included in the
Consolidated Statement of Operations since June 11, 2003. The following table
provides summary data regarding the Transportation and Storage segment's results
of operations for the three- and six-month periods ended December 31, 2003.
THREE MONTHS SIX MONTHS
ENDED ENDED
DECEMBER 31, 2003 DECEMBER 31, 2003
----------------- -----------------
(THOUSANDS OF DOLLARS)
FINANCIAL RESULTS
Transportation and storage revenues............................... $ 113,622 $ 209,991
LNG terminalling revenues......................................... 14,748 30,384
Other revenues .................................................. 1,974 4,188
----------------- -----------------
Total operating revenues...................................... 130,344 244,563
Operating expenses:
Operating, maintenance, and general........................... 54,862 107,796
Depreciation and amortization................................. 16,810 33,158
Taxes other than on income and revenues....................... 6,071 13,089
----------------- -----------------
Total operating expense.................................... 77,743 154,043
----------------- -----------------
Net operating revenues..................................... $ 52,601 $ 90,520
================= =================
The following table sets forth gas throughput and related information for the
Company's Distribution segment and Transportation and Storage segment for the
three- and six-month periods ended December 31, 2003 and 2002:
THREE MONTHS SIX Months
ENDED DECEMBER 31, ENDED DECEMBER 31,
------------------ ------------------
2003 2002 2003 2002
---- ---- ---- ----
DISTRIBUTION SEGMENT
- --------------------
Average number of customers:
Residential ....................................................... 842,370 838,892 838,530 835,055
Commercial ........................................................ 101,288 99,617 100,085 97,602
Industrial and irrigation ......................................... 438 449 442 913
Public authorities and other ...................................... 386 380 387 376
-------- -------- -------- --------
Total average gas sales customers ............................. 944,482 939,338 939,444 933,946
Transportation customers .......................................... 2,578 2,435 2,570 2,499
-------- -------- -------- --------
Total average gas sales and transportation customers .......... 947,060 941,773 942,014 936,445
======== ======== ======== ========
Gas sales in millions of cubic feet (MMcf)
Residential ....................................................... 16,479 19,589 21,582 24,312
Commercial ........................................................ 6,821 7,890 9,349 10,229
Industrial and irrigation ......................................... 787 865 1,227 1,474
Public authorities and other ...................................... 92 115 111 135
-------- -------- -------- --------
Gas sales billed .............................................. 24,179 28,459 32,269 36,150
Net change in unbilled gas sales .................................. 9,661 10,090 9,059 9,889
-------- -------- -------- --------
Total gas sales ............................................... 33,840 38,549 41,328 46,039
Gas transported ................................................... 15,888 18,236 28,858 31,498
-------- -------- -------- --------
Total gas sales and gas transported ........................... 49,728 56,785 70,186 77,537
======== ======== ======== ========
Gas sales revenues (thousands of dollars):
Residential ....................................................... $190,143 $182,019 $261,460 $244,345
Commercial ........................................................ 71,081 65,283 98,899 87,376
Industrial and irrigation ......................................... 6,187 5,787 9,957 9,934
Public authorities and other ...................................... 893 657 1,152 945
-------- -------- -------- --------
Gas revenues billed ........................................... 268,304 253,746 371,468 342,600
Net change in unbilled gas sales revenues ......................... 94,096 77,813 99,287 79,689
-------- -------- -------- --------
Total gas sales revenues ...................................... 362,400 331,559 470,755 422,289
Gas transportation revenues ....................................... 9,221 11,040 15,236 16,752
-------- -------- -------- --------
Total gas sales and gas transportation revenues ............... $371,621 $342,599 $485,991 $439,041
======== ======== ======== ========
Gas sales revenue per thousand cubic feet billed:
Residential ....................................................... $ 11.54 $ 9.29 $ 12.11 $ 10.05
Commercial ........................................................ 10.42 8.27 10.58 8.54
Industrial and irrigation ......................................... 7.86 6.69 8.11 6.74
Public authorities and other ...................................... 9.71 5.71 10.38 7.00
Weather:
Degree days:
Missouri Gas Energy service territories ...................... 1,740 1,995 1,827 2,009
PG Energy service territories ................................ 2,163 2,325 2,268 2,425
New England Gas Company service territories .................. 1,846 2,034 1,878 2,059
Percent of 30-year measure:
Missouri Gas Energy service territories ...................... 89% 102% 90% 99%
PG Energy service territories ................................ 99% 106% 96% 103%
New England Gas Company service territories .................. 93% 103% 90% 99%
TRANSPORTATION AND STORAGE SEGMENT
Gas transported in billions of British thermal units (Bbtu) ............ 341,318 -- 666,516 --
Gas transportation revenues (thousands of dollars) ..................... $103,473 $ -- $189,851 $ --
______________________________________________
- --------------------------------------------------------------------------------
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 December 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.
FINANCIAL CONDITION
The Company's operations are seasonal in nature with a significant percentage of
the annual revenues and earnings occurring in the traditional heating-load
months. In the Distribution segment, this seasonality results in a high level of
cash flow needs immediately preceding the peak winter heating season months, due
to the required payments to natural gas suppliers in advance of the receipt of
cash payments from customers. The Company has historically used internally
generated funds and its credit facilities to provide funding for its seasonal
working capital, continuing construction and maintenance programs and
operational requirements.
On April 3, 2003, the Company entered into a short-term credit facility in the
amount of $140,000,000 (the Short Term Facility), that matures April 1, 2004.
The Short-Term Facility was increased to $150,000,000 as of September 25, 2003.
Also on April 3, 2003, the Company amended the terms and conditions of its
$225,000,000 long-term credit facility (the Long-Term Facility), which expires
on May 29, 2004. The Company has additional availability under uncommitted line
of credit facilities (Uncommitted Facilities) with various banks. Borrowings
under the facilities are available for Southern Union's working capital, letter
of credit requirements and other general corporate purposes. The Short-Term
Facility and the Long-Term Facility (together, the Facilities) are subject to a
commitment fee based on the rating of the Senior Notes. As of December 31, 2003,
the commitment fees were an annualized 0.15% on the Facilities. The interest
rate on borrowings on the Facilities is calculated based upon a formula using
the LIBOR or prime interest rates. A balance of $220,000,000 was outstanding
under the Facilities at February 6, 2004.
In July 2003, Panhandle Energy announced a tender offer for any and all of the
$747,370,000 outstanding principal amount of five of its series of senior notes
outstanding at that point in time (the Panhandle Tender Offer) and also called
for redemption all of the outstanding $134,500,000 principal amount of its two
series of debentures that were outstanding (the Panhandle Calls). Panhandle
Energy repurchased approximately $378,257,000 of the principal amount of its
outstanding debt through the Panhandle Tender Offer for total consideration of
approximately $396,445,000 plus accrued interest through the purchase date.
Panhandle Energy also redeemed approximately $134,500,000 of debentures through
the Panhandle Calls for total consideration of $139,411,000, plus accrued
interest through the redemption dates. As a result of the Panhandle Tender
Offer, the Company has recorded a pre-tax gain on the extinguishment of debt of
$6,123,000 in August 2003. In August 2003, Panhandle Energy issued $300,000,000
of its 4.80% Senior Notes due 2008 and $250,000,000 of its 6.05% Senior Notes
due 2013 principally to refinance the repurchased notes and redeemed debentures.
Also in August and September 2003, Panhandle Energy repurchased $3,150,000
principal amount of its senior notes on the open market through two transactions
for total consideration of $3,398,000, plus accrued interest through the
repurchase date.
On October 1, 2003, the Company called its Subordinated Notes for redemption,
and its Subordinated Notes and related Preferred Securities were redeemed on
October 31, 2003 (see Preferred Securities in Notes to Consolidated Financial
Statements). The Company financed the redemption with borrowings under its
revolving credit facilities, which were paid down with the net proceeds of a
$230,000,000 offering of preferred stock by the Company on October 8, 2003, as
further described below.
On October 8, 2003, the Company issued 920,000 shares of its 7.55% Noncumulative
Preferred Stock, Series A (Liquidation Preference $250 Per Share) to the public
through the issuance of 9,200,000 Depositary Shares, each representing a
one-tenth interest in a 7.55% Noncumulative Preferred Stock, Series A share at
the public offering price of $25.00 per share, or $230,000,000 in the aggregate.
After the payment of issuance costs, including underwriting discounts and
commissions, the Company realized net proceeds of $223,587,000. The total net
proceeds were used to repay debt under the Company's revolving credit
facilities. The issuance of this Preferred Stock and use of proceeds is
continued evidence of the Company's commitment to the rating agencies to
strengthen the Company's balance sheet and solidify its current investment grade
status.
The principal source of funds during the three-month period ended December 31,
2003 were $230,000,000 from the issuance of preferred stock and $63,435,000 in
cash flow from operations. This provided funds of $139,236,000 for the repayment
of debt and capital lease obligations, repayment of $71,800,000 under the
revolving credit facilities and $70,839,000 for on-going property, plant and
equipment additions.
The principal source of funds during the six-month period ended December 31,
2003 were $550,000,000 from the issuance of long-term debt and $230,000,000 from
the issuance of preferred stock. This provided funds of $717,153,000 for the
repayment of debt and capital lease obligations and $111,091,000 for on-going
property, plant and equipment additions, as well as seasonal working capital
needs of the Company.
The effective interest rate under the Company's current debt structure is 5.40%
(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. The Company recently began discussions with its bank groups to
renew the existing lending commitments under the Facilities, which expire in
April and May 2004. The Company expects to be able to raise sufficient new
commitments from banks to fully replace the existing commitments, although the
ability to replace such commitments will be subject to future economic
conditions and financial, business and other factors beyond the Company's
control. 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, operational needs
and the periodic reduction of outstanding debt.
Panhandle Energy has begun the processes necessary to facilitate the refinancing
of the $146,080,000 principal amount of Panhandle Energy's debt which matures
March 15, 2004 and the $52,455,000 principal amount of Panhandle Energy's debt
that matures August 15, 2004, in the most credit efficient manner possible. The
Company and Panhandle Energy believe that they will be able to successfully
refinance this indebtedness, although such refinancing will be subject to future
economic conditions and financial, business and other factors beyond the
Company's or Panhandle Energy's control.
The Company has an effective shelf registration statement on file with the
Securities and Exchange Commission for a total principal amount of $800,000,000
in securities of which $42,170,000 in securities is available for issuance as of
February 6, 2004, which may be issued by the Company in the form of debt
securities, common stock, preferred stock, guarantees, warrants to purchase
common stock, preferred stock and debt securities, stock purchase contracts,
stock purchase units and depositary shares in the event that the Company elects
to offer fractional interests in preferred stock, and also trust preferred
securities to be issued by Southern Union Financing II and Southern Union
Financing III. Southern Union may sell such securities up to such amounts from
time to time, at prices determined at the time of any such offering.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There are no material changes in market risks faced by the Company from those
reported in the Company's Annual Report on Form 10-K for the year ended June 30,
2003.
The information contained in Item 3 updates, and should be read in conjunction
with, information set forth in Part II, Item 7 in the Company's Annual Report on
Form 10-K for the year ended June 30, 2003, in addition to the interim
consolidated financial statements, accompanying notes, and Management's
Discussion and Analysis of Financial Condition and Results of Operations
presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.
OTHER MATTERS
CUSTOMER CONCENTRATIONS. In the Transportation and Storage segment, aggregate
sales to Panhandle Energy's top 10 customers accounted for 70% of segment
operating revenues and 23% of total consolidated operating revenues for the
six-month period ended December 31, 2003. This included sales to Proliance
Energy, LLC, a nonaffiliated local distribution company and gas marketer, which
accounted for 17% of segment operating revenues, sales to BG LNG Services, a
nonaffiliated gas marketer, which accounted for 17% and sales to CMS Energy
Corporation, Panhandle Energy's former parent, which accounted for 11% of
segment operating revenues. No other customer accounted for 10% or more of the
Transportation and Storage segment operating revenues, and no customer accounted
for 10% or more of total consolidated operating revenues, for the six-month
period ended December 31, 2003.
CASH MANAGEMENT. FERC issued Order No. 634, effective December 1, 2003. Order
No. 634 requires all FERC-regulated entities that participate in cash management
programs (i) to establish and file with FERC for public review written cash
management procedures including specification of duties and responsibilities of
cash management program participants and administrators, specification of the
methods for calculating interest and allocation of interest income and expenses,
and specification of any restrictions on deposits or borrowings by participants,
and (ii) to document monthly cash management activity. Order No. 634 also
requires a FERC-regulated entity to notify FERC within 45 days when its
proprietary capital ratio falls below 30 percent or subsequently returns to or
exceeds 30 percent. In compliance with FERC Order No. 634, Panhandle filed its
cash management plan with FERC on December 11, 2003.
NEW FERC REPORTING REQUIREMENTS. On February 11, 2004, the FERC adopted new
quarterly financial reporting requirements for regulated entities. The new
requirement is effective for the quarterly results for the period ending March
31, 2004 and requires major public utilities and licensees and major natural gas
companies to submit the first report on or before July 9, 2003. All subsequent
quarterly reports for major public utilities and licensees, and major natural
gas companies are required to be submitted 60 days after the end of each
quarter. The Company is currently studying the implications of the adopted
regulation to its regulated entities.
MARKETING AFFILIATE RULEMAKING. In response to changes in the structure of the
energy industry, the FERC adopted Order No. 2004 on November 25, 2003 that will
establish standards of conduct that will apply uniformly to natural gas
pipelines and their energy affiliates. The final rule revises and conforms the
current gas and electric standards by broadening the definition of an energy
affiliate covered by the standards of conduct to include, in addition to,
current marketers or merchant affiliates, gathering, processing, intrastate
pipelines and Hinshaw pipelines. The final rule is effective February 9, 2004.
On that date, each transmission provider is required to submit an informational
filing describing the measures it will take to bring itself into compliance with
the standards of conduct by June 1, 2004.
PIPELINE SAFETY NOTICE OF PROPOSED RULEMAKING. On December 12, 2003, the U.S.
Department of Transportation issued a final rule requiring pipeline operators to
develop integrity management programs to comprehensively evaluate their
pipelines, and take measures to protect pipeline segments located in "high
consequence areas." The final rule takes effect on January 14, 2004 and
incorporates requirements of the Pipeline Safety Improvement Act of 2002, a new
bill enacted in December 2002. Although the Company cannot predict the actual
costs of compliance with this rule, it does not expect the order to have a
material effect on the Company's Transportation and Storage segment operations.
INVESTMENT SECURITIES. The Company reviews its portfolio of investment
securities on a quarterly basis to determine whether a decline in value is other
than temporary. Factors that are considered in assessing whether a decline in
value is other than temporary include, but are not limited to: earnings trends
and asset quality; near term prospects and financial condition of the issuer,
including the availability and terms of any additional financing requirements;
financial condition and prospects of the issuer's region and industry, customers
and markets and Southern Union's intent and ability to retain the investment. If
Southern Union determines that the decline in value of an investment security is
other than temporary, the Company will record a charge on its Consolidated
Statement of Operations to reduce the carrying value of the security to its
estimated fair value.
CAPITAL EXPENDITURES. Capital expenditures, which consist primarily of
expenditures to expand and maintain the Company's gas distribution and pipeline
systems, were $111,091,000 and $70,839,000 for the six- and three- month
periods ended December 31, 2003, respectively. Capital expenditures are expected
to be approximately $150,000,000 for the year ended June 30, 2004, which
excludes the Trunkline LNG expansion, modification and pipeline loop (see
additional discussion below).
On February 2, 2004, the Company announced a Phase II modification at Trunkline
LNG to expand the capacity of the facility to a sustained send out of 1.8 Bcf
per day and a peak send out of 2.1 Bcf per day. In addition, Trunkline will
construct a 23-mile loop pipeline from the Trunkline LNG facility that will
increase the takeaway capacity from 1.3 Bcf per day to 2.1 Bcf per day. The
total cost of these projects is expected to be approximately $115,000,000,
excluding capitalized interest. It is anticipated that the 23-mile loop pipeline
will be in service by mid 2005 and that the Phase II modification will be
completed by mid 2006. Including Trunkline LNG's Phase I, Phase II and the
23-mile loop pipeline construction, total capital expenditures are expected to
approximately $250,000,000 of which approximately $40,000,000 has been spent to
date, and are expected to generate approximately $80,000,000 of annualized
revenue, once all projects are in service.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Management's Discussion and Analysis of Results of Operations and Financial
Condition and other sections of this Quarterly Report on Form 10-Q contain
forward-looking statements that are based on current expectations, estimates and
projections about the industry in which the Company operates, management's
beliefs and assumptions made by management. Words such as "expects,"
"anticipates," "intends," "plans," "believes," "seeks," "estimates," variations
of such words and similar expressions are intended to identify such
forward-looking statements. Similarly, statements that describe our objectives,
plans or goals are or may be forward-looking statements. These statements are
not guarantees of future performance and involve certain risks, uncertainties
and assumptions, which are difficult to predict and many of which are outside
the Company's control. Therefore, actual results, performance and achievements
may differ materially from what is expressed or forecasted in such
forward-looking statements. The Company undertakes no obligation to publicly
update any forward-looking statements, whether as a result of new information,
future events or otherwise. Readers are cautioned not to put undue reliance on
such forward-looking statements. Stockholders may review the Company's reports
filed in the future with the Securities and Exchange Commission for more current
descriptions of developments that could cause actual results to differ
materially from such forward-looking statements.
Factors that could cause actual results to differ materially from those
expressed in our forward-looking statements include, but are not limited to, the
following: cost of gas; gas sales volumes; gas throughput volumes and available
sources of natural gas; discounting of transportation rates due to competition;
customer growth; abnormal weather conditions in the Company's service
territories; impact of relations with labor unions of bargaining-unit employees;
the receipt of timely and adequate rate relief and the impact of future rate
cases or regulatory rulings; the outcome of pending and future litigation; the
speed and degree to which competition is introduced to our gas distribution
business; new legislation and government regulations and proceedings affecting
or involving the Company; unanticipated environmental liabilities; the Company's
ability to comply with or to challenge successfully existing or new
environmental regulations; changes in business strategy and the success of new
business ventures; exposure to customer concentration with a significant portion
of revenues realized from a relatively small number of customers and any credit
risks associated with the financial position of those customers; factors
affecting operations such as maintenance or repairs, environmental incidents or
gas pipeline system constraints; our or any of our subsidiaries debt securities
ratings; the economic climate and growth in our industry and service territories
and competitive conditions of energy markets in general; inflationary trends;
changes in gas or other energy market commodity prices and interest rates; the
current market conditions causing more customer contracts to be of shorter
duration, which may increase revenue volatility; the possibility of war or
terrorist attacks; the nature and impact of any extraordinary transactions such
as any acquisition or divestiture of a business unit or any assets.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
We performed an evaluation under the supervision and with the participation of
our management, including our Chief Executive Officer (CEO) and Chief Financial
Officer (CFO), and with the participation of personnel from our Legal, Internal
Audit, Risk Management and Financial Reporting Departments, of the effectiveness
of the design and operation of the Company's disclosure controls and procedures
(as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of
the end of the period covered by this report. Based on that evaluation, our CEO
and CFO concluded that our disclosure controls and procedures were effective as
of December 31, 2003 and have communicated that determination to the Audit
Committee of our Board of Directors.
CHANGES IN INTERNAL CONTROLS
There have been no significant changes in our internal controls or other factors
that could significantly affect internal controls subsequent to their evaluation
for the quarterly period ended December 31, 2003.
RESULTS OF VOTES OF SECURITY HOLDERS
Southern Union held its Annual Meeting of Stockholders on November 4, 2003. The
following matters were submitted for a vote by Southern Union's security
holders:
(I) A proposal to elect the following three persons to serve as Class I
directors until the 2006 Annual Meeting of Stockholders or until their
successors are duly elected and qualified was approved, and the number
of votes for and withheld for the nominees elected were as follows:
For Withheld
John E. Brennan 62,718,879 3,375,637
Frank W. Denius 54,686,378 11,408,138
Ronald W. Simms 62,678,766 3,415,750
(II) A proposal to approve the Southern Union Company 2003 Stock and
Incentive Plan was approved, and the number of affirmative votes,
negative votes, abstentions and broker non-votes with respect to the
matter were as follows:
For 38,981,664
Against 12,975,444
Abstain 154,717
Broker Non-votes 13,982,691
(III)A proposal to approve the Southern Union Company Executive Incentive
Bonus Plan was approved, and the number of affirmative votes, negative
votes, abstentions and broker non-votes with respect to the matter were
as follows:
For 47,493,747
Against 4,362,204
Abstain 255,874
Broker Non-votes 13,982,691
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:
31.1 Certificate by Chief Executive Officer pursuant to Rule 13a-14(a)
or Rule 15d-14(a) promulgated under the Securities Exchange Act of
1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2 Certificate by Chief Financial Officer pursuant to Rule 13a-14(a)
or Rule 15d-14(a) promulgated under the Securities Exchange Act of
1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
32.1 Certificate by Chief Executive Officer pursuant to Rule 13a-14(b)
or Rule 15d-14(b) promulgated under the Securities Exchange Act of
1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C.
Section 1350.
32.2 Certificate by Chief Financial Officer pursuant to Rule 13a-14(b)
or Rule 15d-14(b) promulgated under the Securities Exchange Act of
1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C.
Section 1350.
REPORTS ON FORM 8-K:
The Company filed the following Current Reports on Form 8-K during the quarter
ended December 31, 2003:
DATE FILED DESCRIPTION OF FILING
10/1/03 Filing under Item 5, the Underwriting Agreement dated as
of October 1, 2003, between Southern Union Company and J.P.
Morgan Securities Inc. and Merrill Lynch, Pierce, Fenner &
Smith Incorporated with respect to Southern Union Company's
proposed issuance of 8,000,000 Depositary Shares, and up to
an additional 1,200,000 Depositary Shares, each representing
one-tenth of a share of 7.55% Noncumulative preferred stock,
series A.
10/8/03 Furnishing under Item 9, the press release issued by the
Southern Union Company announcing the closing of its
offering of 9,200,000 Depositary Shares, each representing
one-tenth of a share of 7.55% Noncumulative preferred stock,
series A.
10/29/03 Announcement of operating performance for the quarter ended
September 30, 2003 and 2002 and filing, under Item 12,
summary statements of income of Southern Union Company for
the quarter ended September 30, 2003 and 2002 (unaudited)
and notes thereto.
- --------------------------------------------------------------------------------
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 February 17, 2004 By DAVID J. KVAPIL
------------------------------ ---------------------
David J. Kvapil
Executive Vice
President and Chief
Financial Officer
EXHIBIT 31.1
CERTIFICATE PURSUANT TO RULE 13A-14(A) AND 15D-14(A) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
I, George L. Lindemann, certify that:
(1) I have reviewed this quarterly report on Form 10-Q of Southern Union
Company;
(2) Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this 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 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) and internal
controls for the registrant and we have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this quarterly report is being prepared;
(b) designed such internal controls, or caused such internal controls to
be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with
generally accepted accounting principles;
(c) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this quarterly report our conclusions
about the effectiveness of the disclosure controls and procedures as
of the end of the period covered by this report based on such
evaluation; and
(d) disclosed in this report any change in the registrant's internal
controls that occurred during the registrant's most recent fiscal
quarter that has materially affected, or is reasonably likely to
materially affect, the registrant's internal controls; and
(5) The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation of internal controls, 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.
GEORGE L. LINDEMANN
- ----------------------------------------------------------
George L. Lindemann
Chairman of the Board and
Chief Executive Officer
February 17, 2004
EXHIBIT 31.2
CERTIFICATE PURSUANT TO RULE 13A-14(A) AND 15D-14(A) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
I, David J. Kvapil, certify that:
(1) I have reviewed this quarterly report on Form 10-Q of Southern Union
Company;
(2) Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this 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 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) and internal
controls for the registrant and we have:
(e) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this quarterly report is being prepared;
(f) designed such internal controls, or caused such internal controls to
be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with
generally accepted accounting principles;
(g) evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this quarterly report our conclusions
about the effectiveness of the disclosure controls and procedures as
of the end of the period covered by this report based on such
evaluation; and
(h) disclosed in this report any change in the registrant's internal
controls that occurred during the registrant's most recent fiscal
quarter that has materially affected, or is reasonably likely to
materially affect, the registrant's internal controls; and
(5) The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation of internal controls, to the
registrant's auditors and the Audit Committee of the Company's Board
of Directors:
(c) 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
(d) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls.
DAVID J. KVAPIL
- ----------------------------------------------------------
David J. Kvapil
Executive Vice President and
Chief Financial Officer
February 17, 2004
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Form 10-Q of Southern Union Company (the "Company")
for the quarter ended December 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
February 17, 2004
This certification is furnished pursuant to Item 601 of Regulation S-K
and shall not be deemed filed by the Company for purposes of ss.18 of the
Securities Exchange Act of 1934, as amended, or otherwise be subject to the
liability of that section. Such certification shall not be deemed to be
incorporated by reference into any filing under the Securities Act or the
Exchange Act, except to the extent the Company specifically incorporates it by
reference.
EXHIBIT 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Form 10-Q of Southern Union Company (the "Company")
for the quarter ended December 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
February 17, 2004
This certification is furnished pursuant to Item 601 of Regulation S-K
and shall not be deemed filed by the Company for purposes of ss.18 of the
Securities Exchange Act of 1934, as amended, or otherwise be subject to the
liability of that section. Such certification shall not be deemed to be
incorporated by reference into any filing under the Securities Act or the
Exchange Act, except to the extent the Company specifically incorporates it by
reference.