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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
For the quarterly period ended
September 30, 2004
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
7.55% Depositary Shares New York Stock Exchange
5.75% Equity Units 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 October 29,
2004 was 82,351,829.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
FORM 10-Q
September 30, 2004
Index
PART I. FINANCIAL INFORMATION Page(s)
Item 1. Financial Statements:
Consolidated statement of operations - three months ended September 30, 2004
and 2003 2
Consolidated balance sheet - September 30, 2004 and June 30, 2004 3-4
Consolidated statement of stockholders' equity and comprehensive income --
three months ended September 30, 2004 and twelve months ended June 30, 2004 5
Consolidated statement of cash flows - three months ended
September 30, 2004 and 2003 6
Notes to consolidated financial statements 7-21
Item 2. Management's Discussion and Analysis of Financial Condition and Results 22-31
Of Operations
Item 3. Quantitative and Qualitative Disclosures about Market Risk 30
Item 4. Controls and Procedures 30
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
(See "COMMITMENTS AND CONTINGENCIES" in Notes to Consolidated
Financial Statements) 14-20
Item 6. Exhibits and Reports on Form 8-K 31
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
Three Months Ended September 30,
--------------------------------
2004 2003
---- ----
(thousands of dollars, except
shares and per share amounts)
Operating revenues:
Gas distribution .................................................................... $ 124,021 $ 116,029
Gas transportation and storage ...................................................... 109,318 114,218
Other ............................................................................... 1,237 1,147
----- -----
Total operating revenues ........................................................ 234,576 231,394
Cost of gas and other energy ............................................................. (65,492) (57,760)
Revenue-related taxes .................................................................... (4,435) (4,325)
------ ------
Net operating revenues, excluding depreciation and amortization ..................... 164,649 169,309
Operating expenses:
Operating, maintenance and general .................................................. 101,705 101,080
Depreciation and amortization........................................................ 30,593 31,334
Taxes, other than on income and revenues ............................................ 13,557 12,916
------ ------
Total operating expenses ........................................................ 145,855 145,330
------- -------
Operating income ................................................................ 18,794 23,979
------- -------
Other income (expense):
Interest ............................................................................ (30,618) (33,964)
Other, net .......................................................................... 369 3,807
------ ------
Total other expenses, net ....................................................... (30,249) (30,157)
------- -------
Loss before income tax benefit ........................................................... (11,455) (6,178)
Federal and state income tax benefit ..................................................... (4,315) (2,471)
------ ------
Net loss ................................................................................. (7,140) (3,707)
Preferred stock dividends ................................................................ (4,341) --
------ ------
Net loss applicable to common shareholders ............................................... $ (11,481) $ (3,707)
========= =========
Net loss applicable to common shareholders per share:
Basic................................................................................ $ (.15) $ (.05)
========= =========
Diluted.............................................................................. $ (.15) $ (.05)
========= =========
Weighted average shares outstanding:
Basic................................................................................ 79,043,523 75,325,511
========== ==========
Diluted.............................................................................. 79,043,523 75,325,511
========== ==========
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
September 30, June 30,
2004 2004
---- ----
ASSETS (thousands of dollars)
Property, plant and equipment:
Plant in service ............................................................ $ 3,822,609 $ 3,772,616
Construction work in progress ............................................... 190,495 169,264
------- -------
4,013,104 3,941,880
Less accumulated depreciation and amortization .............................. (755,417) (734,367)
-------- --------
Net property, plant and equipment ...................................... 3,257,687 3,207,513
--------- ---------
Current assets:
Cash and cash equivalents ................................................... 27,372 19,971
Accounts receivable, billed and unbilled, net ............................... 143,063 181,924
Federal and state taxes receivable .......................................... 6,775 --
Inventories ................................................................. 266,193 200,295
Deferred gas purchase costs ................................................. -- 3,933
Gas imbalances - receivable ................................................. 24,068 22,045
Prepayments and other ....................................................... 49,702 27,561
------- -------
Total current assets ................................................... 517,173 455,729
------- -------
Goodwill ......................................................................... 640,547 640,547
Deferred charges ................................................................. 192,668 190,735
Investment securities, at cost ................................................... 8,038 8,038
Other ............................................................................ 70,818 69,896
------- -------
Total assets ................................................................ $ 4,686,931 $ 4,572,458
=========== ===========
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET (Continued)
(Unaudited)
September 30, June 30,
2004 2004
---- ----
STOCKHOLDERS' EQUITY AND LIABILITIES (thousands of dollars)
Stockholders' equity:
Common stock, $1 par value; authorized 200,000,000 shares;
issued 82,334,737 and 77,140,087 shares, respectively ..................... $ 82,335 $ 77,141
Preferred stock, no par value; authorized 6,000,000 shares;
issued 920,000 shares ......................................................... 230,000 230,000
Premium on capital stock .......................................................... 1,063,315 975,104
Less treasury stock, 404,536 shares at cost ....................................... (12,870) (12,870)
Less common stock held in trust: 1,176,704 and 1,089,147 shares,
respectively .................................................................. (17,488) (15,812)
Deferred compensation plans ....................................................... 13,636 11,960
Accumulated other comprehensive loss .............................................. (51,214) (50,224)
Retained earnings ................................................................. 30,475 46,692
--------- ---------
Total stockholders' equity ........................................................ 1,338,189 1,261,991
Long-term debt and capital lease obligation ............................................ 2,074,689 2,154,615
--------- ---------
Total capitalization .......................................................... 3,412,878 3,416,606
Current liabilities:
Long-term debt and capital lease obligation due within one year ................... 124,188 99,997
Notes payable ..................................................................... 157,500 21,000
Accounts payable .................................................................. 96,546 122,309
Federal, state and local taxes .................................................... 29,491 32,866
Accrued interest .................................................................. 25,403 36,891
Customer deposits ................................................................. 12,014 12,043
Gas imbalances - payable .......................................................... 60,501 72,057
Other ............................................................................. 129,754 116,783
------- -------
Total current liabilities ..................................................... 635,397 513,946
------- -------
Deferred credits and other ............................................................. 288,588 292,946
Accumulated deferred income taxes ...................................................... 350,068 348,960
Commitments and contingencies...........................................................
----------- -----------
Total stockholders' equity and liabilities ........................................ $ 4,686,931 $ 4,572,458
=========== ===========
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(Unaudited)
Accumulated
Common Other Total
Common Preferred Premium Treasury Stock Comprehen- Stock-
Stock, $1 Stock, No on Capital Stock, at Held in sive Income Retained holders'
Par Value Par Value Stock Cost Trust (Loss) Earnings Equity
--------- --------- ----- ---- ----- ------ -------- ------
(thousands of dollars)
Balance July 1, 2003................ $ 73,074 $ -- $ 909,191 $ (10,467) $ (5,657) $ (62,579) $ 16,856 $ 920,418
Comprehensive income (loss):
Net earnings.................... -- -- -- -- -- -- 114,025 114,025
Unrealized loss in investment
securities, net of tax benefit. -- -- -- -- -- (21) -- (21)
Minimum pension liability
adjustment, net of tax......... -- -- -- -- -- 10,768 -- 10,768
Unrealized gain on hedging
activities, net of tax......... -- -- -- -- -- 1,608 -- 1,608
-------
Comprehensive income............ 126,380
-------
Preferred stock dividends.......... -- -- -- -- -- -- (12,686) (12,686)
Payment on note receivable......... -- -- 347 -- -- -- -- 347
Purchase of treasury stock......... -- -- -- (2,403) -- -- -- (2,403)
5% stock dividend.................. 3,656 -- 67,847 -- -- -- (71,503) --
Sale of common stock held in trust. -- -- 598 -- 1,805 -- -- 2,403
Issuance of preferred stock........ -- 230,000 (6,590) -- -- -- -- 223,410
Exercise of stock options.......... 411 -- 3,711 -- -- -- -- 4,122
------ ------- -------- ------- ------- ------- ------ ----------
Balance June 30, 2004............... 77,141 230,000 975,104 (12,870) (3,852) (50,224) 46,692 1,261,991
Comprehensive income (loss):
Net loss......................... -- -- -- -- -- -- (7,140) (7,140)
Unrealized loss on hedging
activities, net of tax benefit.. -- -- -- -- -- (990) -- (990)
-------
Comprehensive loss............... (8,130)
-------
Preferred stock dividends.......... -- -- -- -- -- -- (4,341) (4,341)
5% stock dividend.................. 242 -- 4,494 -- -- -- (4,736) --
Issuance of common stock........... 4,800 -- 81,763 -- -- -- -- 86,563
Exercise of stock options.......... 152 -- 1,954 -- -- -- -- 2,106
-------- --------- ----------- ---------- -------- ----------- ---------- ------------
Balance September 30, 2004.......... $ 82,335 $ 230,000 $ 1,063,315 $ (12,870) $ (3,852) $ (51,214) $ 30,475 $ 1,338,189
======== ========= =========== ========== ======== =========== ========== ============
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
(Unaudited)
Three Months Ended September 30,
--------------------------------
2004 2003
---- ----
(thousands of dollars)
Cash flows provided by (used in) operating activities:
Net loss .................................................................................... $ (7,140) $ (3,707)
Adjustments to reconcile net loss to net cash flows provided by
(used in) operating activities:
Depreciation and amortization ........................................................... 30,593 31,334
Amortization of debt expense ............................................................ 1,155 764
Amortization of debt premium ............................................................ (906) (4,501)
Deferred income taxes ................................................................... 128 13,560
Provision for bad debts ................................................................. 9,562 5,178
Provision for impairment of other assets ................................................ -- 2,753
Gain on extinguishment of debt .......................................................... -- (6,123)
Other ................................................................................... (438) (525)
Changes in operating assets and liabilities:
Accounts receivable, billed and unbilled ........................................... 29,299 34,866
Gas imbalance receivable ........................................................... (2,023) 16,344
Accounts payable ................................................................... (25,763) (30,593)
Gas imbalance payable .............................................................. (11,556) (8,135)
Accrued interest ................................................................... (11,488) (15,648)
Deferred gas purchase costs ........................................................ (8,579) (18,461)
Inventories ........................................................................ (65,898) (71,491)
Deferred charges and credits ....................................................... (5,988) (7,598)
Federal and state taxes receivable ................................................. (6,775) (18,358)
Prepaids and other assets .......................................................... (7,799) (2,053)
Taxes and other liabilities ........................................................ 4,891 10,179
------- -------
Net cash flows used in operating activities ............................................... (78,725) (72,215)
------- -------
Cash flows provided by (used in) investing activities:
Additions to property, plant and equipment .................................................. (77,341) (40,252)
Other ....................................................................................... (869) (1,053)
------- -------
Net cash flows used in investing activities ............................................... (78,210) (41,305)
------- -------
Cash flows provided by (used in) financing activities:
Issuance of common stock .................................................................... 86,563 --
Issuance of long-term debt .................................................................. -- 550,000
Issuance cost of debt ....................................................................... (337) (3,996)
Repayment of debt and capital lease obligation .............................................. (56,156) (577,917)
Net borrowings under revolving credit facilities ............................................ 136,500 72,300
Dividends paid on preferred stock ........................................................... (4,341) --
Proceeds from exercise of stock options ..................................................... 2,107 866
------- ------
Net cash flows provided by financing activities ........................................... 164,336 41,253
------- ------
Change in cash and cash equivalents ............................................................ 7,401 (72,267)
Cash and cash equivalents at beginning of period ............................................... 19,971 86,997
------- -------
Cash and cash equivalents at end of period ..................................................... $ 27,372 $ 14,730
========= =========
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest .................................................................................. $ 46,429 $ 50,237
========= =========
Income taxes .............................................................................. $ 7,757 $ 112
========= =========
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, 2004. 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, the results of operations and cash flows for any interim period are
not necessarily indicative of results for the full year.
SIGNIFICANT ACCOUNTING POLICIES
In December 2003, the FASB issued Consolidation of Variable Interest Entities.
The Interpretation introduced a new consolidation model, which determines
control and consolidation based on potential variability in gains and losses of
the entity being evaluated for consolidation. The Interpretation requires a
company to consolidate a variable interest entity if the company is allocated a
majority of the entity's gains and/or losses, including fees paid by the entity.
The Interpretation is effective for companies that have an interest in variable
interest entities or potential variable interest entities commonly referred to
as special-purpose entities for periods ending after December 15, 2003.
Application by companies for all other types of entities is required in
financial statements for periods ending after March 15, 2004. The Company has
not identified any material variable interest entities or interests in variable
interest entities for which the provisions of this Interpretation would require
a change in the Company's current accounting for such interests.
In March 2004, the Emerging Issues Task Force (EITF) reached final consensuses
on Issue 03-6, Participating Securities and the Two-Class Method under FASB 128,
Earnings per Share. The Issue addresses the computation of earnings per share by
companies that have issued securities other than common stock that contractually
entitle the holder to participate in dividends and earnings of the company when,
and if, it declares dividends on its common stock. The Issue is effective for
interim periods beginning after March 31, 2004. Based on the Company's capital
structure at September 30, 2004, this Issue did not change the method used by
the Company to calculate its loss per share for the period ended September
30, 2004.
In accordance with FASB Financial Staff Position (FSP), Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug, Improvement
and Modernization Act of 2003, the benefit obligation and net periodic
post-retirement cost in the Company's consolidated financial statements and
accompanying notes do not reflect the effects of the Act on the Company's
post-retirement healthcare plan because the employer is unable to conclude
whether benefits provided by the plan are actuarially equivalent to Medicare
Part D under the Act. The method of determining whether a sponsor's plan will
qualify for actuarial equivalency is pending until the US Department of Health
and Human Services (HHS) completes its interpretative work on the Act. Once the
interpretative guidance is released by HHS, if eligible, the Company will
account for the subsidy as an actuarial gain pursuant to the guidelines of this
standard.
PENDING ACQUISITION
Pursuant to a purchase agreement dated as of June 24, 2004 and amended as of
September 1, 2004, CCE Holdings, LLC (CCE), a joint venture between Southern
Union Company and its 50% equity partner GE Commercial Finance Energy Financial
Services, agreed to acquire 100% of the equity interests of CrossCountry Energy,
LLC (CrossCountry) from Enron Corp. and its affiliates for $2,450,000,000 in
cash including the assumption of certain consolidated debt (the Transaction).
The closing of the Transaction is subject to approval by certain state and
federal regulatory bodies, in addition to satisfaction of customary closing
conditions, and is expected to occur on or before December 17, 2004. It is
currently contemplated that CCE will be operated by Southern Union, including
the involvement of Panhandle Energy management personnel.
CrossCountry and it subsidiaries own or operate approximately 9,700 miles of
pipeline having the capacity to transport approximately 8.6 Bcf/d (billion cubic
feet per day) of natural gas through its wholly-owned subsidiary, Transwestern
Pipeline Company, LLC (TWP), its 50% interest in Citrus Corp. (Citrus) and its
wholly-owned subsidiary, Northern Plains Natural Gas Company (Northern Plains),
which holds general and limited partnership interests in Northern Border
Partners, L.P. (NBP). TWP's 2,400 mile pipeline system provides a key link
between the natural gas rich San Juan, Anadarko and Permian basins and the fast
growing energy market of California. The bi-directional flow capabilities of the
east end of TWP's pipeline system provide TWP with flexibility to quickly adapt
to regional demand swings and reallocate capacity to regions where demand is
high; further, it provides a competitive advantage in securing long-term firm
transportation contracts. Citrus is the principal transporter of natural gas to
the Florida energy market through its wholly-owned pipeline subsidiary, Florida
Gas Transmission Company (FGT). FGT's 5,000 miles of pipeline connect the
natural gas supply basins of the Texas and Louisiana Gulf Coasts and the Gulf of
Mexico to most of the gas-fired power plants of Florida. NBP is a leading
transporter of natural gas imported from Canada to the Midwestern United States
through its 2,300 mile pipeline network. CCE has entered into a purchase
agreement to sell Northern Plains to ONEOK, Inc. for $175,000,000 in cash. The
closing of the ONEOK purchase of Northern Plains is expected to occur
concurrently with the closing of the Transaction, with the funds received
applied to CCE's acquisition of CrossCountry.
GOODWILL
There was no change in the carrying amount of goodwill for the three-month
period ended September 30, 2004. As of September 30, 2004, the Company has
goodwill of $640,547,000 from its Distribution segment. The Distribution segment
is tested annually for impairment in the fourth quarter, after the annual
forecasting process.
DEFERRED CHARGES AND CREDITS
September 30, June 30,
2004 2004
---- ----
Deferred Charges
Pensions....................................... $ 46,114 $ 45,625
Unamortized debt expense....................... 37,778 38,596
Income taxes................................... 32,662 31,441
Retirement costs other than pensions........... 25,287 26,008
Environmental.................................. 11,210 12,220
Service Line Replacement program............... 15,962 16,722
Other.......................................... 23,655 20,123
------------- --------------
Total Deferred Charges....................... $ 192,668 $ 190,735
============= ==============
As of September 30, 2004 and June 30, 2004, the Company's deferred charges
include regulatory assets relating to Distribution segment operations in the
aggregate amount of $98,063,431 and $99,314,000, respectively, of which
$60,369,733 and $63,010,000, respectively, is being recovered through current
rates. As of September 30, 2004 and June 30, 2004, the remaining recovery period
associated with these assets ranges from 1 month to 202 months and from 1 month
to 208 months, respectively. None of these regulatory assets, which primarily
relate to pensions, retirement costs other than pensions, income taxes, Year
2000 costs, Missouri Gas Energy's Service Line Replacement program and
environmental remediation costs, are included in rate base. The Company records
regulatory assets in accordance with the FASB standard, Accounting for the
Effects of Certain Types of Regulation.
September 30, June 30,
2004 2004
---- ----
Deferred Credits
Pensions....................................... $ 84,493 $ 86,796
Retirement costs other than pensions........... 59,883 60,404
Cost of Removal................................ 28,929 28,519
Environmental.................................. 21,668 23,082
Derivative instrument liability................ 15,104 15,041
Customer advances for construction............. 14,231 13,518
Provision for self-insured claims.............. 10,225 10,542
Investment tax credit.......................... 5,132 5,367
Other.......................................... 48,923 49,677
------------- --------------
Total Deferred Credits....................... $ 288,588 $ 292,946
============= ==============
The Company's deferred credits include regulatory liabilities relating to
Distribution segment operations in the aggregate amount of $11,103,538 and
$11,164,000, respectively, as of September 30, 2004, and June 30, 2004. These
regulatory liabilities primarily relate to retirement benefits other than
pensions, environmental insurance recoveries and income taxes. The Company
records regulatory liabilities in accordance with the FASB standard, Accounting
for the Effects of Certain Types of Regulation.
INVESTMENT SECURITIES
As of September 30, 2004, 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 in PointServe of $2,603,000 at September 30, 2004 may be subject to
future market value risk. The Company will continue to monitor the value of its
investment and periodically assess the impact, if any, on reported earnings in
future periods.
STOCKHOLDERS' EQUITY
Stock Based Compensation. The Company accounts for stock option grants using the
intrinsic-value method in accordance with APB Opinion, Accounting for Stock
Issued to Employees, and related authoritative interpretations. Under the
intrinsic-value method, because the exercise price of the Company's employee
stock options is greater than or equal to the market price of the underlying
stock on the date of grant, no compensation expense is recognized.
The following table illustrates the effect on net loss and net loss applicable
to common shareholders per share if the Company had applied the fair value
recognition provisions of the FASB Standard, Accounting for Stock-Based
Compensation, as amended by the FASB Standard, Accounting for Stock-Based
Compensation--Transition and Disclosure, to stock-based employee compensation:
Three months Ended
September 30,
-------------
2004 2003
---- ----
Net loss, as reported.............................................$ (7,140) $ (3,707)
Deduct total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related taxes........................................... 671 601
--------- ---------
Pro forma net loss................................................$ (7,811) $ (4,308)
Net loss applicable to common shareholders per share:
Basic -- as reported..............................................$ (.15) $ (.05)
========= =========
Basic -- pro forma................................................$ (.15) $ (.06)
========= =========
Diluted -- as reported............................................$ (.15) $ (.05)
========= =========
Diluted -- pro forma..............................................$ (.15) $ (.06)
========= =========
Common Stock Issuance. On July 30, 2004, the Company issued 4,800,000 shares of
common stock at the public offering price of $18.75 per share, resulting in net
proceeds to the Company, after underwriting discounts and commissions, of
$86,900,000. The Company also sold 6,200,000 shares of the Company's common
stock through forward sale agreements with its underwriters and granted the
underwriters a 30-day over-allotment option to purchase up to an additional
1,650,000 shares of the Company's common stock at the same price, which was
exercised by the underwriters. Under the terms of the forward sale agreements,
the Company has the option to settle its obligation to the forward purchasers
through either (i) paying a net settlement in cash, (ii) delivering an
equivalent number of shares of its common stock to satisfy its net settlement
obligation, or (iii) through the physical delivery of shares. The Company will
only receive additional proceeds from the sale of the 7,850,000 shares of the
Company's common stock that were sold through the forward sale agreements if it
settles its obligation under such agreements through the physical delivery of
shares, in which case it will receive additional net proceeds of $142,000,000.
The forward sale agreements are required to be settled within 12 months from the
date of the offering. Until the settlement date, the forward sale agreements
will have a dilutive effect on earnings per share if the Company's average
common stock price for the period exceeds the forward sales price, which was
$17.25 per share as of September 30, 2004.
COMPREHENSIVE INCOME
The Company reports comprehensive income and its components in accordance with
the FASB Standard, Reporting Comprehensive Income. The main components of
comprehensive income that relate to the Company are net earnings, unrealized
holding gains and losses on investment securities, minimum pension liability
adjustments and unrealized gain (loss) on hedging activities, all of which are
presented in the Consolidated Statement of Stockholders' Equity and
Comprehensive Income.
The table below gives an overview of comprehensive income for the periods
indicated.
Three Months Ended
September 30,
-------------
2004 2003
---- ----
Net loss ...........................................................$ (7,140) $ (3,707)
Other comprehensive income (loss):
Unrealized loss in investment securities, net of tax benefit..... -- (21)
Unrealized (loss) gain on hedging activities, net of tax......... (990) 885
-------- ---------
Other comprehensive (loss) income................................... (990) 864
-------- ---------
Comprehensive loss..................................................$ (8,130) $ (2,843)
======== =========
Accumulated other comprehensive income reflected in the Consolidated Balance
Sheet at September 30, 2004, 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. The Company is party to interest rate swap agreements with an
aggregate notional amount of $195,902,000 as of September 30, 2004 that fix the
interest rate applicable to floating rate long-term debt and which qualify for
hedge accounting. For the three-month period ended September 30, 2004, the
amount of the swap ineffectiveness was not significant. As of September 30,
2004, floating rate London InterBank Offered Rate (LIBOR) based interest
payments were exchanged for weighted fixed rate interest payments of 5.88%,
which does not include the spread on the underlying variable debt rate of
1.625%. Interest rate swaps are carried on the Consolidated Balance Sheet at
fair value with the effective portion of the unrealized gain or loss adjusted
through accumulated other comprehensive income. As such, payments or receipts on
interest rate swap agreements, in excess of the liability recorded, are
recognized as adjustments to interest expense. As of September 30, 2004 and June
30, 2004, the fair value liability position of the swaps was $14,299,000 and
$14,445,000, respectively. As of September 30, 2004, approximately $734,000 of
net after-tax gains included in accumulated other comprehensive income related
to these swaps 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.
In March and April 2003, the Company entered into a series of treasury rate
locks with an aggregate notional amount of $250,000,000 to manage its exposure
against changes in future interest payments attributable to changes in the
benchmark interest rate prior to the anticipated issuance of fixed-rate debt.
These treasury rate locks expired on June 30, 2003, resulting in a $6,862,000
after-tax loss that was recorded in accumulated other comprehensive income and
will be amortized into interest expense over the lives of the associated debt
instruments. As of September 30, 2004, approximately $967,000 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.
Fair Value Hedges. In March 2004, Panhandle Energy entered into interest rate
swaps to hedge the risk associated with the fair value of its $200,000,000 2.75%
Senior Notes. These swaps are designated as fair value hedges and qualify for
the short cut method under FASB standard, Accounting for Derivative Instruments
and Hedging Activities, as amended. Under the swap agreements Panhandle Energy
will receive fixed interest payments at a rate of 2.75% and will make floating
interest payments based on the six-month LIBOR. No ineffectiveness is assumed in
the hedging relationship between the debt instrument and the interest rate swap.
As of September 30, 2004 and June 30, 2004, the fair values of the swaps are
included in the Consolidated Balance Sheet as liabilities and matching
adjustments to the underlying debt of $3,633,000 and $4,960,000, respectively.
Trading and Non-Hedging Activities. During fiscal 2004, the Company acquired
natural gas commodity swap derivatives and collar transactions in order to
mitigate price volatility of natural gas passed through to utility customers.
The cost of the derivative products and the settlement of the respective
obligations are recorded through the gas purchase adjustment clause as
authorized by the applicable regulatory authority and therefore do not impact
earnings. The fair value of the contracts is recorded as an adjustment to a
regulatory asset/ liability in the Consolidated Balance Sheet. As of September
30, 2004 and June 30, 2004, the fair values of the contracts, which expire at
various times through March 2005, are included in the Consolidated Balance Sheet
as assets and matching adjustments to deferred cost of gas of $15,265,000 and
$1,337,000, respectively.
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, 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
September 30, June 30,
2004 2004
---- ----
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........................................ 111,087 111,087
6.50% to 10.25% First Mortgage Bonds, due 2008 to 2029..... 112,476 113,435
Capital lease due 2004 to 2007............................. 261 277
--------- ---------
1,008,589 1,009,564
--------- ---------
Panhandle Energy
2.75% Senior Notes due 2007................................ 200,000 200,000
4.80% Senior Notes due 2008................................ 300,000 300,000
6.05% Senior Notes due 2013................................ 250,000 250,000
7.875% Senior Notes due 2004............................... -- 52,455
6.50% Senior Notes due 2009................................ 60,623 60,623
8.25% Senior Notes due 2010................................ 40,500 40,500
7.00% Senior Notes due 2029................................ 66,305 66,305
Term Loan due 2007......................................... 261,200 263,926
Net premiums on long-term debt............................. 15,293 16,199
--------- ---------
1,193,921 1,250,008
--------- ---------
Total consolidated debt and capital lease.................. 2,202,510 2,259,572
Less current portion................................... 124,188 99,997
Less fair value swap of Panhandle Energy............... 3,633 4,960
--------- ---------
Total consolidated long-term debt and capital lease........ $ 2,074,689 $ 2,154,615
=============== =============
The Company has $2,202,510,000 of debt recorded at September 30, 2004, of which
$124,188,000 is current. Debt of $1,540,804,000, including net premiums of
$15,293,000 and unamortized interest rate swaps of $3,633,000, is at fixed rates
ranging from 2.75% to 10.25%, with $533,885,000 of variable rate bank loans
having an average rate of 2.71% as of September 30, 2004. The variable rate bank
loans are unsecured with the exception of the $261,200,000 Panhandle Energy Term
Loan that is secured by the Trunkline LNG facilities.
As of September 30, 2004, the Company has scheduled debt payments of
$43,909,000, $90,467,000, $565,718,000, $1,648,000, $301,646,000 and
$1,183,829,000 due during the remainder of fiscal year 2005 and for fiscal years
2006 through 2009 and thereafter, respectively.
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 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.
Term Note. On July 16, 2002, the Company issued a $311,087,000 Term Note dated
July 15, 2002 (the 2002 Term Note). 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 is currently LIBOR
plus 105 basis points. A balance of $111,087,000 was outstanding on this 2002
Term Note as of September 30, 2004 and June 30, 2004 at an effective interest
rate of 2.73% and 2.42%, respectively. 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 recorded a pre-tax gain on the extinguishment of debt
of $6,354,000 in fiscal 2004. 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 March 12, 2004, Panhandle Energy issued $200,000,000 of its 2.75% Senior
Notes due 2007, the proceeds of which were used to fund the redemption of the
remaining $146,080,000 principal amount of its 6.125% Senior Notes due 2004 that
matured on March 15, 2004 and to provide working capital to the Company. A
portion of the remaining net proceeds was also used to repay the remaining
$52,455,000 principal amount of Panhandle Energy's 7.875% Senior Notes due 2004
that matured on August 15, 2004.
NOTES PAYABLE
On May 28, 2004, the Company entered into a new five-year long-term credit
facility in the amount of $400,000,000 (the Long-Term Facility) that matures on
May 29, 2009. The Company has additional availability under uncommitted line of
credit facilities (Uncommitted Facilities) with various banks. The Long-Term
Facility is subject to a commitment fee based on the rating of the Company's
senior unsecured notes (the Senior Notes). As of September 30, 2004 and June 30,
2004, the commitment fees were an annualized 0.15%. A balance of $157,500,000
and $21,000,000 was outstanding under the Company's credit facilities at an
effective interest rate of 2.70% and 2.64% at September 30, 2004 and June 30,
2004, respectively. As of October 29, 2004, there was a balance of $175,000,000
outstanding under the Long-Term Facility.
EMPLOYEE BENEFITS
Components of Net Periodic Benefit Cost. Net periodic benefit cost for the
three-months ended September 30, 2004 and 2003 includes the following
components:
Pension Benefits Post-Retirement
---------------- ---------------
Benefits
--------
2004 2003 2004 2003
---- ---- ---- ----
Service cost ........................... $ 1,956 $ 1,738 $ 1,144 $ 913
Interest cost .......................... 5,693 5,586 2,344 1,975
Expected return on plan assets ......... (6,031) (5,244) (588) (419)
Amortization of prior service cost ..... 381 263 163 19
Recognized actuarial gain .............. 2,051 1,906 225 144
Settlement recognition ................. 94 (119) -- --
---- ---- ---- ----
Net periodic pension cost .............. $ 4,144 $ 4,130 $ 3,288 $ 2,632
======= ======= ======= =======
Employer Contributions. For the three-month period ended September 30, 2004,
approximately $7,525,000 and $2,850,000 of contributions were made to the
Company's pension plans and post-retirement plans, respectively.
REGULATION AND RATES
Missouri Gas Energy. On September 21, 2004, the Missouri Public Service
Commission issued a rate order authorizing Missouri Gas Energy to increase base
revenues by $22,370,000, effective October 2, 2004. The rate order, based on a
10.5% return on equity, also produced an improved rate design that should help
stabilize revenue streams and implemented an incentive mechanism for the sharing
of capacity release and off-system sales revenues between customers and the
Company.
Panhandle Energy. In December 2002, the Federal Energy Regulatory Commission
(FERC) approved a Trunkline LNG certificate application to expand the Lake
Charles facility to approximately 1.2 billion cubic feet (Bcf) per day of
sustainable send out capacity versus the current sustainable send out capacity
of .63 Bcf per day and increase terminal storage capacity to 9 Bcf from the
current 6.3 Bcf. BG LNG Services has contract rights for the .57 Bcf per day of
additional capacity. Construction on the Trunkline LNG expansion project (Phase
I) commenced in September 2003 and is expected to be completed by the end of the
2005 calendar year. On September 17, 2004, as modified on September 23, 2004,
the FERC approved Trunkline LNG's further incremental LNG expansion project
(Phase II). Phase II would increase the LNG terminal sustainable send out
capacity to 1.8 Bcf per day. Phase II has an expected in-service date of
mid-calendar 2006. BG LNG Services has contracted for all the proposed
additional capacity, subject to Trunkline LNG achieving certain construction
milestones at this facility. Approximately $107,000,000 of costs are included
in the line item Construction Work In Progress for the expansion projects
through September 30, 2004.
In February 2004, Trunkline filed an application with the FERC to request
approval of a 30-inch diameter, approximately 23-mile natural gas pipeline loop
from the LNG terminal. Trunkline's filing was approved on September 17, 2004, as
modified on September 23, 2004. 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. Approximately
$5,000,000 of costs are included in the line item Construction Work In Progress
for this project through September 30, 2004.
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
the 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 Gas Energy. 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 entered the two sites into 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 $4,000,000. Remediation of
Station B has not been requested by MDNR at this time.
Following a failed tank tightness test, MGE removed an underground storage tank
(UST) system in December, 2002 from a former MGP site in St. Joseph, Missouri.
An UST closure report was filed with MDNR on August 12, 2003. In a letter dated
September 26, 2003, MDNR indicated that its review of the analytical data
submitted for this site indicated that contamination existed at the site above
the action levels specified in Missouri guidance documents. In a letter dated
January 28, 2004, MDNR indicated that the Department would provide MGE a final
version of the Missouri Risk-Based Corrective Action (MRBCA) process. On April
28, 2004, MDNR provided MGE with information regarding the MRBCA process, and
requested a work plan on the St. Joseph site within 60 days of MGE's receipt of
this information. MGE submitted a UST Site Characterization Work Plan which was
approved by MDNR on August 20, 2004.
New England Gas Company. Prior to its acquisition by the Company in September
2000, 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 $13,000,000 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
$4,000,000. 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 (acquired in September 2000 by the Company) was a
defendant in a civil action seeking to recover anticipated remediation costs
associated with contamination found at property owned by the plaintiffs (Cory's
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's Lane Site
sufficient to obtain a final letter of compliance from the RIDEM. Following the
performance of a site investigation, the Company submitted a Site Investigation
Report on December 5, 2003, to RIDEM. On April 15, 2004, the Company obtained
verbal approval from RIDEM to conduct additional investigation activity at the
site.
In a letter dated March 17, 2003, RIDEM sent the New England Gas Company (NEG) a
letter of responsibility pertaining to alleged historical MGP impacted soils in
a residential neighborhood along Bay and Judson Streets (Bay Street Area) in
Tiverton, Rhode Island. The letter requested that NEG prepare a 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, NEG 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, NEG began assessment work on June 2, 2003. A Site
Inspection Report and a Human Health Risk Assessment were filed with RIDEM on
October 31, 2003, and RIDEM provided NEG comments to the Site Inspection Report
in a letter dated January 27, 2004. The January 27, 2004, RIDEM letter included
the comment that additional assessment work was necessary in the Bay Street
Area. On July 19, 2004, NEG submitted a Supplemental Site Investigation Work
Plan and Phase 2 Site Investigation Work Plan for the further assessment of the
Bay Street Area. In a letter dated August 18, 2004, RIDEM communicated its
conditional concurrence of NEG's Work Plan. NEG initiated assessment field work
on August 26, 2004.
In connection with the investigation of the Bay Street Area, two former
residents of the area filed a tort action on August 20, 2003, against NEG
alleging personal injury to the plaintiffs. This litigation has not been served
on the Company. The Company has also received a demand letter dated July 1,
2004, sent by lawyers on behalf of the owners of a property in the Bay Street
Area. This demand alleges property damage and personal injury. Parts of the Bay
Street Area appear to have been built on fill placed at various times and
include one or more historic dump sites. Research is therefore underway to
identify other potentially responsible parties associated with the fill
materials and the dumping.
The Company received a Notice of Responsibility, Request for Information and
Request for Immediate Response Action Plan dated July 1, 2004, for an area in
Fall River, Massachusetts along State Avenue (State Avenue Area) that is
contiguous to the Bay Street Area of Rhode Island. In response to this Notice
from the Massachusetts Department of Environmental Protection (MADEP), the
Company submitted an Immediate Response Action Plan (IRAP) to the MADEP on July
26, 2004. The Company's IRAP proposes an investigation to determine whether or
not coal gasification related material was historically dumped in the State
Avenue Area and this investigation is scheduled to begin before the end of the
2004 calendar year.
Valley Gas Company (acquired in September 2000 by the 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 in May 2000 with Narragansett Electric
Company, a subsidiary of National Grid) 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, the Company and Stone & Webster that provided
for the payment of $5,000,000 out of the bankruptcy estates. This settlement
resulted in a payment of $1,250,000 to the Company for environmental costs
associated with the former Fall River Gas Company, and a $3,750,000 payment to
the Company and National Grid jointly for 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 the Company additional
rights against historic Stone & Webster insurers.
In a letter dated March 11, 2003, the MADEP provided NEG a Notice of
Responsibility for 66 5th Street in Fall River, Massachusetts. This Notice of
Responsibility requested that site assessment activities be conducted at the
former MGP at 66 5th Street to determine whether or not there was a release of
cyanide into the groundwater at this site that impacted downgradient properties
at 60 and 82 Hartwell Street. NEG submitted an Immediate Response Action (IRA)
Work Plan on May 20, 2003. The IRA Report was submitted to MADEP on July 18,
2003. Investigation work performed to date indicates that cyanide concentrations
at the downgradient properties are unrelated to the NEG property at 66 5th
Street.
In 2003, NEG conducted a Phase I environmental site assessment at a former MGP
site in North Attleboro, Massachusetts (the Mt. Hope Street Site) to determine
if the property could be redeveloped as a service center. During the site walk,
coal tar was found in the adjacent creek bed, and notice to the MADEP was made.
On September 18, 2003, a Phase I Initial Site Investigation Report and Tier
Classification were submitted to MADEP. On November 25, 2003, MADEP issued a
Notice of Responsibility letter to NEG. Based upon the Phase I filing, NEG is
required to file a Phase II report with MADEP by September 18, 2005 to complete
the site characterization.
PG Energy. During 2002, PG Energy received inquiries from the Pennsylvania
Department of Environmental Protection (PADEP) pertaining to three Pennsylvania
former MGP sites located in Scranton, Bloomsburg, and Carbondale. At the request
of PADEP, PG Energy is currently performing environmental assessment work at the
Scranton MGP site. On March 23, 2004, PG Energy filed an Initial Site Assessment
Characterization report on the Scranton site and is preparing to submit a
Comprehensive Site Assessment Characterization Work Plan for the further
assessment of this site. 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.
On March 31, 2004, PG Energy entered into a voluntary Consent Order and
Agreement (Multi-Site Agreement) with the PADEP. This Multi-Site Agreement is
for the purpose of developing and implementing an environmental assessment and
remediation program for five MGP sites (including the Scranton, Bloomsburg and
Carbondale sites) and six MGP holder sites owned by PG Energy in the State of
Pennsylvania. Under the Multi-Site Agreement, PG Energy is to perform
environmental assessments of these sites within two years of the effective date
of the Multi-Site Agreement. Thereafter, PG Energy is required to perform
additional assessment and remediation activity as is deemed to be necessary
based upon the results of the initial assessments. The Company does not believe
the outcome of these matters will have a material adverse effect on its
financial position, results of operations or cash flows.
To the extent that potential costs associated with former MGPs are quantified,
the Company expects to provide any appropriate accruals and seek recovery for
such remediation costs through all appropriate means, including in rates charged
to gas distribution customers, insurance and regulatory relief. At the time of
the closing of the acquisition of the Company's Missouri service territories,
the Company entered into an Environmental Liability Agreement that provides that
Western Resources retains financial responsibility for certain liabilities under
environmental laws that may exist or arise with respect to Missouri Gas Energy.
In addition, the New England Division has reached agreement with its Rhode
Island rate regulators on a regulatory plan that creates a mechanism for the
recovery of environmental costs over a ten-year period. This plan, effective
July 1, 2002, establishes an environmental fund for the recovery of evaluation,
remedial and clean-up costs arising out of the Company's MGPs and sites
associated with the operation and disposal activities from MGPs. Similarly,
environmental costs associated with Massachusetts' facilities are recoverable in
rates over a seven-year period.
Panhandle Energy Environmental Matters - Panhandle Energy has identified
environmental impacts at certain sites on its gas transmission systems and has
undertaken clean-up programs at these sites. These impacts resulted from (i) the
past use of lubricants containing polychlorinated bi-phenyls (PCBs) in
compressed air systems; (ii) the past use of paints containing PCBs; (iii) prior
use of wastewater collection facilities; and (iv) other on-site disposal areas.
Panhandle Energy communicated with the EPA and appropriate state regulatory
agencies on these matters, and 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 cleanup program resulting from contamination due to the use of
lubricants containing PCBs in compressed air systems, Panhandle Eastern Pipe
Line Company (Panhandle Eastern Pipe Line) and Trunkline Gas Company (Trunkline)
have identified PCB levels above acceptable levels inside the auxiliary
buildings that house the air compressor equipment at thirty-three 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. Thirteen sites have been decontaminated
per the EPA approved 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 has implemented
a program to remediate sites where such issues are identified during painting
activities. If PCBs are identified above acceptable levels, the paint is removed
and disposed of in an EPA approved manner.
The Illinois Environmental Protection Agency (Illinois EPA) notified Panhandle
Eastern Pipe Line and Trunkline, together with other non-affiliated parties, of
contamination at three former waste oil disposal sites in Illinois. Panhandle
Eastern Pipe Line's and Trunkline'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 percent. Panhandle Energy and 21 other
non-affiliated parties conducted an initial voluntary investigation of the
Pierce Oil Springfield site, one of the three 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 it has referred the Pierce
Oil Springfield site to the EPA so that environmental contamination present at
the site can be addressed through the federal Superfund program. No formal
notice has yet been received from either agency concerning the referral.
However, the EPA is expected to issue special notice letters in calendar 2004
and has begun the process of listing the site on the National Priority List.
Panhandle Energy and three of the other non-affiliated parties associated with
the Pierce Oil Springfield site met with the EPA and Illinois EPA regarding this
issue. Panhandle Energy was given no indication as to when the listing process
was to be completed.
Based on information available at this time, the Company believes the amount
reserved for all of the above environmental matters 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 certain large internal combustion 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 was
promulgated by the EPA in April 2004. The five Midwestern states have one year
to promulgate state laws and regulations to address the requirements of this
rule. Based on an EPA guidance document negotiated with gas industry
representatives in 2002, it is believed that Panhandle Energy will be required
under state rules to reduce nitrogen oxide (NOx) emissions by 82% on the
identified large internal combustion engines and will be able to trade off
engines within the company and within each of the five Midwestern states
affected by the rule in an effort to create a cost effective NOx reduction
solution. The final implementation date is May 2007. The rule impacts 20 large
internal combustion engines on the Panhandle Energy system in Illinois and
Indiana at an approximate cost of $17,000,000 for capital improvements through
2007, based on current projections.
In 2002, the Texas Commission on Environmental Quality enacted the
Houston/Galveston State Implementation Plan (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. New regulations also require certain
grandfathered facilities in Texas to enter into the new source permit program
which may require the installation of emission controls at five additional
facilities. These rules affect six Company facilities in Texas at an estimated
cost of approximately $12,000,000 for capital improvements through March 2007,
based on current projections.
The EPA promulgated various Maximum Achievable Control Technology (MACT) rules
in February 2004. The rules require that Panhandle Eastern Pipe Line and
Trunkline control Hazardous Air Pollutants (HAPs) emitted from certain internal
combustion engines at major HAPs sources. Most of Panhandle Eastern Pipe Line
and Trunkline compressor stations are major HAPs sources. The HAPs pollutant of
concern for Panhandle Eastern Pipe Line and Trunkline is formaldehyde. As
promulgated, the rule seeks to reduce formaldehyde emissions by 76% from these
engines. Catalytic controls will be required to reduce emissions under these
rules with a final implementation date of May 2007. Panhandle Eastern Pipe Line
and Trunkline have 22 internal combustion engines subject to the rules. It is
expected that compliance with these regulations will cost an estimated
$5,000,000 for capital improvements, based on current projections.
Regulatory
On May 31, 2002, the staff of the MPSC recommended that the Commission disallow
approximately $15,000,000 in gas costs incurred during the period July 1, 2000
through June 30, 2001. Missouri Gas Energy filed its response in opposition to
the Commission 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 $9,300,000. The hearing concluded
in November 2003 and the matter was fully submitted to the Commission in
February 2004 and is awaiting decision by the Commission.
On November 27, 2001, August 1, 2000 and August 12, 1999, the staff of the MPSC
recommended that the Commission disallow approximately $5,900,000, $5,900,000
and $4,300,000, 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.
Missouri Gas Energy 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
During 1999, several actions were commenced in federal courts by persons
involved in competing efforts to acquire Southwest Gas Corporation (Southwest).
All of these actions eventually were transferred to the U.S. District Court for
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. 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 District 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. A
decision on the appeal by the Ninth Circuit is expected by the first calendar
quarter of 2005. 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.
Other
The Company is now investigating an incident involving the release of mercury
stored in a NEG facility in Pawtucket, Rhode Island. On October 19, 2004, New
England Gas Company discovered that a NEG facility had been broken into and that
mercury had been spilled both inside a building and in the immediate vicinity.
Mercury had also been removed from the Pawtucket facility and a quantity had
been spilled in a parking lot in the neighborhood. Mercury from the parking lot
spill was apparently tracked into some nearby apartment units, as well as some
other buildings. Spill cleanup has been completed at the NEG property, and is
currently underway at the apartment units near the parking lot. Investigation of
some other neighborhood properties has been undertaken, with cleanup conducted
in a few instances. The investigatory work is still underway to determine
whether any other locations associated with the parking lot spill require
cleanup. State and federal authorities are also investigating the incident and
have arrested the alleged vandals of the Pawtucket facility. In addition, they
are conducting inquiries regarding NEG's compliance with relevant environmental
requirements, including hazardous waste management provisions, spill and release
notification procedures, and hazard communication requirements. NEG has received
a subpoena requesting documents relating to this matter. The Company believes
the outcome of this matter will not have a material adverse effect on its
financial position, results of operations or cash flows.
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, buyouts and buy downs of gas sales contracts with
natural gas pipelines. Panhandle Eastern Pipe Line and Trunkline, 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 Eastern Pipe Line and Trunkline may file with
the FERC to recover a portion of these costs from pipeline customers. Panhandle
Energy believes the outcome of this matter will not have a material adverse
effect on its financial position, results of operations or cash flows.
REPORTABLE SEGMENTS
The Company's operating segments are aggregated into reportable business
segments based on similarities in economic characteristics, products and
services, types of customers, methods of distribution and regulatory
environment. The Company operates in two reportable segments. 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. 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.
Revenue included in the All Other category is attributable to several operating
subsidiaries of the Company: PEI Power Corporation generates and sells
electricity; PG Energy Services Inc. offers appliance service contracts;
ProvEnergy Power Company LLC (ProvEnergy Power), which was 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 operating income. Sales of products or services
between segments are billed at regulated rates or at market rates, as
applicable. There were no material intersegment revenues during the three-month
periods ended September 30, 2004 and 2003.
The following table sets forth certain selected financial information for the
Company's segments for the three-month periods ended September 30, 2004 and
2003.
Three Months Ended
September 30,
-------------
2004 2003
---- ----
Revenues from external customers:
Distribution .................................................................. $ 124,021 $ 116,029
Transportation and Storage .................................................... 109,318 114,218
------- -------
Total segment operating revenues .......................................... 233,339 230,247
All Other ..................................................................... 1,237 1,147
------- -------
Total consolidated operating revenues ..................................... $ 234,576 $ 231,394
========= =========
Depreciation and amortization:
Distribution .................................................................. $ 15,071 $ 14,680
Transportation and Storage .................................................... 15,178 16,348
------ ------
Total segment depreciation and amortization ............................... 30,249 31,028
All Other ..................................................................... 150 149
Corporate ..................................................................... 194 157
------ ------
Total consolidated depreciation and amortization .......................... $ 30,593 $ 31,334
========= =========
Operating income (loss):
Distribution .................................................................. $ (18,096) $ (11,336)
Transportation and Storage .................................................... 37,971 37,919
------ ------
Total segment operating income ............................................ 19,875 26,583
All Other ..................................................................... (81) (314)
Corporate ..................................................................... (1,000) (2,290)
------ ------
Total consolidated operating income ....................................... $ 18,794 $ 23,979
========= =========
Expenditures for long-lived assets:
Distribution .................................................................. $ 21,192 $ 17,493
Transportation and Storage .................................................... 50,960 20,281
------ ------
Total segment expenditures for long-lived assets .......................... 72,152 37,774
All Other ..................................................................... 130 50
Corporate ..................................................................... 5,059 2,428
------ ------
Total consolidated expenditures for long-lived assets ..................... $ 77,341 $ 40,252
========= =========
Reconciliation of operating income to loss before income tax benefit:
Operating income .............................................................. $ 18,794 $ 23,979
Interest ...................................................................... (30,618) (33,964)
Other income, net ............................................................. 369 3,807
------ ------
Loss before income tax benefit ............................................ $ (11,455) $ (6,178)
========== =========
September 30, June 30,
2004 2004
---- ----
Total assets:
Distribution..........................$ 2,275,717 $ 2,231,970
Transportation and Storage............ 2,247,058 2,197,289
--------- ---------
Total segment assets.............. 4,522,775 4,429,259
All Other............................. 41,988 42,133
Corporate............................. 122,168 101,066
------- -------
Total consolidated assets.........$ 4,686,931 $ 4,572,458
============= =============
SOUTHERN UNION COMPANY AND SUBSIDIARIES
MANAGEMENT DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of
Operations is provided as a supplement to the accompanying consolidated
financial statements and footnotes to help provide an understanding of Southern
Union's financial condition, changes in financial condition and results of
operations. The following section includes an overview of Southern Union's
business as well as recent developments that the Company believes are important
in understanding its results of operations, and to anticipate future trends in
those operations. Subsequent sections include an analysis of Southern Union's
results of operations on a consolidated basis and on a segment basis for each
reportable segment, and information relating to Southern Union's liquidity and
capital resources, quantitative and qualitative disclosures about market risk
and other matters.
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 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
960,000 residential, commercial and industrial customers in Missouri,
Pennsylvania, Rhode Island and Massachusetts. 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.
Pursuant to a purchase agreement dated as of June 24, 2004 and amended as of
September 1, 2004, CCE Holdings, LLC (CCE), a joint venture between Southern
Union Company and its 50% equity partner GE Commercial Finance Energy Financial
Services, agreed to acquire 100% of the equity interests of CrossCountry Energy,
LLC (CrossCountry) from Enron Corp. and its affiliates for $2,450,000,000 in
cash including the assumption of certain consolidated debt (the Transaction).
The closing of the Transaction is subject to approval by certain state and
federal regulatory bodies, in addition to satisfaction of customary closing
conditions, and is expected to occur on or before December 17, 2004. It is
currently contemplated that CCE will be operated by Southern Union, including
the involvement of Panhandle Energy management personnel.
CrossCountry and it subsidiaries own or operate approximately 9,700 miles of
pipeline having the capacity to transport approximately 8.6 Bcf/d (billion cubic
feet per day) of natural gas through its wholly-owned subsidiary, Transwestern
Pipeline Company, LLC (TWP), its 50% interest in Citrus Corp. (Citrus) and its
wholly-owned subsidiary, Northern Plains Natural Gas Company (Northern Plains),
which holds general and limited partnership interests in Northern Border
Partners, L.P. (NBP). TWP's 2,400 mile pipeline system provides a key link
between the natural gas rich San Juan, Anadarko and Permian basins and the fast
growing energy market of California. The bi-directional flow capabilities of the
east end of TWP's pipeline system provide TWP with flexibility to quickly adapt
to regional demand swings and reallocate capacity to regions where demand is
high; further, it provides a competitive advantage in securing long-term firm
transportation contracts. Citrus is the principal transporter of natural gas to
the Florida energy market through its wholly-owned pipeline subsidiary, Florida
Gas Transmission Company (FGT). FGT's 5,000 miles of pipeline connect the
natural gas supply basins of the Texas and Louisiana Gulf Coasts and the Gulf of
Mexico to most of the gas-fired power plants of Florida. NBP is a leading
transporter of natural gas imported from Canada to the Midwestern United States
through its 2,300 mile pipeline network. CCE has entered into a purchase
agreement to sell Northern Plains to ONEOK, Inc. for $175,000,000 in cash. The
closing of the ONEOK purchase of Northern Plains is expected to occur
concurrently with the closing of the Transaction, with the funds received
applied to CCE's acquisition of CrossCountry.
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 Distribution segment and the Transportation and
Storage segment. Segment results of operations are presented on an operating
income basis, which is 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 information regarding the
Company's consolidated results of operations for the three-month periods ended
September 30, 2004 and 2003:
Three Months Ended
September 30,
-------------
2004 2003
---- ----
(thousands of dollars)
Operating income (loss):
Distribution segment ........................................... $ (18,096) $ (11,336)
Transportation and storage segment ............................. 37,971 37,919
All other ...................................................... (81) (314)
Corporate ...................................................... (1,000) (2,290)
------ ------
Total operating income ..................................... 18,794 23,979
Other income (expenses):
Interest ....................................................... (30,618) (33,964)
Other, net ..................................................... 369 3,807
------- -------
Total other expenses, net .................................. (30,249) (30,157)
------- -------
Loss before income tax benefit ...................................... (11,455) (6,178)
Federal and state income tax benefit ................................ (4,315) (2,471)
------ ------
Net loss ............................................................ (7,140) (3,707)
Preferred stock dividends ........................................... (4,341) --
------ ------
Net loss applicable to common shareholders .......................... $ (11,481) $ (3,707)
============= =============
Three Months Ended September 30, 2004 Compared to 2003. The Company recorded a
net loss applicable to common shareholders of $11,481,000 for the three-month
period ended September 30, 2004 compared with a net loss applicable to common
shareholders of $3,707,000 for the same period in 2003. Net loss applicable to
common shareholders per share, based on weighted average shares outstanding
during the period, was $.15 in 2004 compared with $.05 in 2003