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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. Due to the
seasonal nature of the Company's Distribution segment, the three-month period
ending September 30 is typically a loss period.
The $7,774,000 increase in net loss applicable to common shareholders in 2004
was primarily attributable to an increase in operating loss from the
Distribution segment of $6,760,000 (see Segment Results - Distribution Segment),
a decrease in other income of $3,438,000 (see Other Income (Expense), Net), and
an increase in preferred stock dividends of $4,341,000 (see Preferred Stock
Dividends), which were partially offset by a decrease in operating loss from
Corporate operations of $1,290,000 (see Corporate) and a decrease in interest
expense of $3,346,000 (see Interest Expense).
Corporate. Operating loss from Corporate operations decreased $1,290,000 for the
three-month period ended September 30, 2004 compared with the same period in
2003 primarily due to lower legal fees and provisions for legal matters, reduced
financial reporting costs and lower financing-related fees. These items were
partially offset by increased outside service fees related to Sarbanes-Oxley
Section 404 documentation procedures.
Interest Expense. Interest expense decreased $3,346,000 for the three-month
period ended September 30, 2004 compared with the same period in 2003. Interest
expense in 2004 was impacted by a $2,370,000 decrease in interest expense on
preferred securities of subsidiary trust (see Preferred Securities in Notes to
Consolidated Financial Statements), a $1,134,000 decrease in interest expense on
borrowings under the Company's bank credit facilities due to a lower level of
average outstanding borrowings, and a $393,000 decrease in interest expense
related to the 2002 Term Note. This decrease was partially offset by a $756,000
increase in interest expense related to the Panhandle properties primarily due
to lower debt premium amortization in 2004. The average rate of interest on all
debt increased from 5.0% in 2003 to 5.3% in 2004 primarily due to higher
interest rates on the Company's floating rate debt.
Other Income (Expense), Net. Other income for the three-month period ended
September 30, 2004 was $369,000 compared with $3,807,000 for the same period in
2003. Other income for the three-month period ended September 30, 2004 includes
income of $532,000 generated from the sale and/or rental of gas-fired equipment
and appliances by various operations subsidiaries, which was partially offset by
$200,000 of legal costs associated with the Company's attempt to collect damages
from former Arizona Corporation Commissioner James Irvin related to the
Southwest Gas Corporation (Southwest) litigation. Other income for the
three-month period ended September 30, 2003 includes a gain of $6,123,000 on the
early extinguishment of debt and income of $784,000 generated from the sale
and/or rental of gas-fired equipment and appliances. These items were partially
offset by charges of $1,603,000 and $1,150,000 to reserve for impairment of
Southern Union's investments in a technology company and in an energy-related
joint venture, respectively, and $278,000 of legal costs related to the
Southwest litigation.
Federal and State Income Taxes. The Company's consolidated federal and state
effective income tax rate was 38% and 40% for the three-month period ended
September 30, 2004 and 2003, respectively. The reduction in the effective income
tax rate resulted primarily from restructuring the Panhandle Energy legal
entities.
Preferred Stock Dividends. Dividends on preferred securities increased
$4,341,000 for the three-month period ended September 30, 2004 compared with the
same period in 2003. On October 8, 2003, the Company issued $230,000,000 of
7.55% Non-cumulative Preferred Stock, Series A to the public (see Preferred
Securities in Notes to Consolidated Financial Statements).
Segment Results
Distribution Segment -- The Company's Distribution segment is primarily engaged
in the local distribution of natural gas in Missouri, Pennsylvania, Rhode Island
and Massachusetts. Its operations are conducted through the Company's three
regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas
Company. Collectively, the utility divisions serve more than 960,000
residential, commercial and industrial customers. The utility divisions'
operations are regulated as to rates and other matters by the regulatory
commissions of the states in which each operates. The utility divisions'
operations are generally sensitive to weather and seasonal in nature, with a
significant percentage of annual operating revenues and net earnings occurring
in the traditional winter heating season in the first and fourth calendar
quarters.
The following table provides summary financial information regarding the
Distribution segment's results of operations for the three-month periods ended
September 30, 2004 and 2003:
Three Months Ended
September 30,
-------------
2004 2003
---- ----
(thousands of dollars)
Financial Results
Operating revenues ............................................................... $ 124,021 $ 116,029
Cost of gas and other energy ..................................................... (65,352) (57,370)
Revenue-related taxes ............................................................ (4,435) (4,325)
------ ------
Net operating revenues, excluding depreciation and amortization .............. 54,234 54,334
Operating expenses:
Operating, maintenance, and general .......................................... 50,971 45,273
Depreciation and amortization ................................................ 15,071 14,680
Taxes other than on income and revenues ...................................... 6,288 5,717
----- -----
Total operating expense ................................................... 72,330 65,670
------ ------
Operating loss ............................................................ $ (18,096) $ (11,336)
========== ==========
Three Months Ended September 30, 2004 Compared to 2003. The Distribution segment
recorded an operating loss of $18,096,000 for the three-month period ended
September 30, 2004, which reflects a $6,760,000 increase in operating loss
compared with the same period in 2003. Due to the seasonal nature of the
Company's Distribution segment, the three-month period ending September 30 is
typically a loss period.
Operating Revenues. Operating revenues increased $ 7,992,000 for the three-month
period ended September 30, 2004 compared with the same period in 2003. Gas
purchase and other energy costs increased $ 7,982,000 for the three-month period
ended September 30, 2004 compared with the same period in 2003. The Company's
operating revenues are affected by the level of sales volumes and by the
pass-through of increases or decreases in the Company's gas purchase costs
through its purchased gas adjustment clauses. Additionally, revenues are
affected by increases and decreases in gross receipts taxes (revenue-related
taxes) which are levied on sales revenue as collected from customers and
remitted to the various taxing authorities. The increase in both operating
revenues and gas purchase costs between periods was primarily due to a 20%
increase in the average cost of gas from $6.60 per thousand cubic feet (Mcf) in
2003 to $7.89 per Mcf in 2004, which was partially offset by a 5% decrease in
gas sales volumes to 8,217 million cubic feet (MMcf) in 2004 from 8,695 MMcf in
2003. The increase in the average cost of gas is due to increases in the average
spot market prices throughout the Company's distribution system as a result of
current competitive pricing occurring within the entire energy industry.
Operating Expenses. Operating expenses, which include operating, maintenance and
general expenses, depreciation and amortization and taxes other than on income
and revenues, increased $6,660,000 for the three-month period ended September
30, 2004 compared with the same period in 2003. The increase in 2004 was
primarily due to $4,385,000 of increased provisions for bad debts resulting from
the aging of higher customer receivables due to higher gas prices, $570,000 of
increased medical costs, $549,000 of increased pension and other post-retirement
benefit costs and increased employee payroll costs primarily due to general wage
increases. In addition, taxes other than on income and revenues increased
$571,000 in 2004 primarily due to increased property taxes.
As of September 30, 2004, the Company believes that its reserves for bad debts
are adequate based on historical trends and collections. However, to the extent
that the cost of gas remains above historical averages, the Company may
experience increased pressure on collections and exposure to bad debts which can
impact the operating results of this segment for the remainder of fiscal 2005.
The following table sets forth gas throughput and related information for the
Company's Distribution segment for the three-month periods ended September 30,
2004 and 2003:
Three Months
Ended September 30,
-------------------
2004 2003
---- ----
Distribution Segment
- --------------------
Average number of customers:
Residential ............................................................. 836,649 834,690
Commercial .............................................................. 99,898 98,880
Industrial and irrigation ............................................... 417 445
Public authorities and other ............................................ 388 388
------ ------
Total average customers served ........................................ 937,352 934,403
Transportation customers ..................................................... 2,690 2,561
------ ------
Total average gas sales and transportation customers .................. 940,042 936,964
======= =======
Gas sales in millions of cubic feet (MMcf):
Residential.............................................................. 5,070 5,103
Commercial............................................................... 2,600 2,527
Industrial and irrigation................................................ 699 440
Public authorities and other............................................. 15 19
-- --
Gas sales billed...................................................... 8,384 8,089
Net change in unbilled gas sales......................................... (167) 606
------ ------
Total gas sales....................................................... 8,217 8,695
Gas transported.......................................................... 11,669 12,929
------ ------
Total gas sales and gas transported................................... 19,886 21,624
====== ======
Gas sales revenues (thousands of dollars):
Residential.............................................................. $ 78,418 $ 71,316
Commercial............................................................... 31,843 27,817
Industrial and irrigation................................................ 6,286 3,770
Public authorities and other............................................. 245 259
------ ------
Gas revenues billed................................................... 116,792 103,162
Net change in unbilled gas sales revenues................................ (1,412) 5,190
------ ------
Total gas sales revenues.............................................. 115,380 108,352
Gas transportation revenues................................................... 5,741 6,014
------ ------
Total gas sales and gas transportation revenues....................... $ 121,121 $ 114,366
============ ============
Gas sales revenue per thousand cubic feet billed:
Residential.............................................................. $ 15.47 $ 13.98
Commercial............................................................... 12.25 11.01
Industrial and irrigation................................................ 8.99 8.57
Public authorities and other............................................. 16.33 13.63
Three Months
Ended September 30,
-------------------
2004 2003
---- ----
Weather:
Degree days:
Missouri Gas Energy service territories.............. 15 87
PG Energy service territories........................ 120 105
New England Gas Company service territories.......... 71 32
Percent of 30-year measure:
Missouri Gas Energy service territories.............. 23% 134%
PG Energy service territories........................ 73% 64%
New England Gas Company service territories.......... 63% 28%
Transportation and Storage Segment -- The Transportation and Storage segment is
primarily engaged in the interstate transportation and storage of natural gas in
the Midwest and Southwest, and also provides LNG terminalling and regasification
services. Its operations are conducted through Panhandle Energy, which provides
approximately 500 customers in the Midwest and Southwest with a comprehensive
array of transportation and storage services. Panhandle Energy also operates one
of the largest LNG terminal facilities in North America. Panhandle Energy's
operations are regulated as to rates and other matters by FERC, and are somewhat
sensitive to the weather and seasonal in nature with a significant percentage of
annual operating revenues and net earnings occurring in the traditional winter
heating season.
The following table provides summary financial information regarding the
Transportation and Storage segment's results of operations for the three-month
periods ended September 30, 2004 and 2003:
Three Months Ended
September 30,
-------------
2004 2003
---- ----
(thousands of dollars)
Financial Results
Reservation revenue ........................................ $ 77,081 $ 80,232
LNG terminalling revenue ................................... 15,004 15,577
Commodity revenue .......................................... 14,719 16,138
Other revenues ............................................. 2,514 2,271
----- -----
Total operating revenues ............................... 109,318 114,218
Operating expenses:
Operating, maintenance, and general .................... 49,125 52,933
Depreciation and amortization .......................... 15,178 16,348
Taxes other than on income and revenues ................ 7,044 7,018
----- -----
Total operating expenses ............................ 71,347 76,299
------ ------
Operating income .................................... $ 37,971 $ 37,919
======== ========
Operating Information
Gas transported in trillions of British thermal units (Tbtu) 302 325
Three Months Ended September 30, 2004 Compared to 2003. The Transportation and
Storage segment recorded operating income of $37,971,000 for the three-month
period ended September 30, 2004, which reflects a $52,000 increase in operating
income compared with the same period in 2003.
Operating Revenues. Operating revenues decreased $4,900,000 for the three-month
period ended September 30, 2004, compared with the same period in 2003. The
decrease in 2004 is primarily due to lower reservation revenues of $3,151,000
primarily due to replacement of contract expirations on Trunkline during 2004 at
lower average reservation rates than were in effect in 2003, and lower commodity
revenues of $1,419,000 primarily due to a 7% reduction in throughput volumes
resulting from lower storage refills and lower parking revenue activity in 2004.
Commodity revenues are dependent upon a number of variable factors, including
weather, storage levels, and customer demand for firm, interruptible and parking
services. In addition, LNG terminalling revenues were $573,000 lower than in
2003 primarily due to reduced volumes received in 2004.
Operating Expenses. Operating expenses, which include operating, maintenance and
general expenses, depreciation and amortization and taxes other than on income
and revenues, decreased $4,952,000 for the three-month period ended September
30, 2004 compared with the same period in 2003. The decrease in 2004 was
primarily due to the net overrecovery of approximately $1,790,000 in 2004 of
previously underrecovered fuel volumes compared with a net underrecovery of
approximately $1,481,000 of fuel volumes in 2003, and a $968,000 reduction in
contract storage expenses due to a reduction in contracted storage capacity
beginning in March 2004. In addition, depreciation and amortization decreased
$1,170,000 in 2004 primarily due to preliminary purchase price allocations used
in 2003 which were subsequently revised in fiscal 2004.
FINANCIAL CONDITION
The Company's operations are seasonal in nature with a significant percentage of
the annual revenues and earnings occurring in the traditional heating-load
months. In the Distribution segment, this seasonality results in a high level of
cash flow needs immediately preceding the peak winter heating season months, due
to the required payments to natural gas suppliers in advance of the receipt of
cash payments from customers. The Company has historically used internally
generated funds and its credit facilities to provide funding for its seasonal
working capital, continuing construction and maintenance programs and
operational requirements.
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 October 1, 2003, the Company called its Subordinated Notes for redemption,
and its Subordinated Notes and related Preferred Securities were redeemed on
October 31, 2003 (see Preferred Securities in Notes to Consolidated Financial
Statements). The Company financed the redemption with borrowings under its
revolving credit facilities, which were paid down with the net proceeds of a
$230,000,000 offering of preferred stock by the Company on October 8, 2003, as
further described below.
On October 8, 2003, the Company issued 920,000 shares of its 7.55% Noncumulative
Preferred Stock, Series A (Liquidation Preference $250 Per Share) to the public
through the issuance of 9,200,000 Depositary Shares, each representing a
one-tenth interest in a 7.55% Noncumulative Preferred Stock, Series A share at
the public offering price of $25.00 per share, or $230,000,000 in the aggregate.
The total net proceeds were used to repay debt under the Company's revolving
credit facilities.
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.
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.
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. The Company expects that it will settle its obligation under the
forward sale agreements through the physical delivery of shares upon
consummation of the acquisition of CrossCountry Energy, LLC (see Pending
Acquisition in Notes to Consolidated Financial Statements).
The principal sources of funds during the three-month period ended September 30,
2004 were $136,500,000 in net borrowings under revolving credit facilities and
$86,563,000 from the issuance of common stock. This provided funds of
$77,341,000 for ongoing property, plant and equipment additions and $56,156,000
for the repayment of debt and capital lease obligations; as well as seasonal
working capital needs of the Company.
The effective interest rate under the Company's current debt structure is 5.54%
( including interest and the amortization of debt issuance costs and redemption
premiums on refinanced debt).
The Company retains its borrowing availability under the Long Term Facility, as
discussed above. Borrowings under these credit facilities will continue to be
used, as needed, to provide funding for the seasonal working capital needs of
the Company. Internally-generated funds from operations will be used principally
for the Company's ongoing construction and maintenance programs, operational
needs and the periodic reduction of outstanding debt.
The Company has an effective shelf registration statement on file with the
Securities and Exchange Commission for a total principal amount of
$1,000,000,000 in securities of which $762,812,500 in securities is available
for issuance as of October 29, 2004, which may be issued by the Company in the
form of debt securities, common stock, preferred stock, guarantees, warrants to
purchase common stock, preferred stock and debt securities, stock purchase
contracts, stock purchase units and depositary shares in the event that the
Company elects to offer fractional interests in preferred stock, and also trust
preferred securities to be issued by Southern Union Financing II and Southern
Union Financing III. Southern Union may sell such securities up to such amounts
from time to time, at prices determined at the time of any such offering.
OTHER MATTERS
Customer Concentrations. In the Transportation and Storage segment, aggregate
sales to Panhandle Energy's top 10 customers accounted for 70% of segment
operating revenues and 33% of total operating revenues for the three-month
period ended September 30, 2004. This included sales to BG LNG Services, a
nonaffiliated gas marketer, which accounted for 19% of segment operating
revenues, sales to ProLiance Energy, LLC, a nonaffiliated local distribution
company and gas marketer, which accounted for 16% of segment operating revenues
and sales to CMS Energy Corporation, Panhandle Energy's former parent, which
accounted for 10% of segment operating revenues. No other customer accounted for
10% or more of the Transportation and Storage segment operating revenues, and no
single customer or group of customers under common control accounted for 10% or
more of the Company's total operating revenues for the three-month period ended
September 30, 2004.
Pipeline Safety Notice of Proposed Rulemaking. On December 12, 2003, the U.S.
Department of Transportation issued a final rule requiring pipeline operators to
develop integrity management programs to comprehensively evaluate their
pipelines, and take measures to protect pipeline segments located in "high
consequence areas." The final rule took effect on January 14, 2004 and
incorporates requirements of the Pipeline Safety Improvement Act, enacted in
December 2002. Although the Company cannot predict the actual costs of
compliance with this rule, it does not expect the order to have a material
incremental effect on the Company's Transportation and Storage segment
operations because such required activities were already being undertaken.
Investment Securities. The Company reviews its portfolio of investment
securities on a quarterly basis to determine whether a decline in value is other
than temporary. Factors that are considered in assessing whether a decline in
value is other than temporary include, but are not limited to: earnings trends
and asset quality; near term prospects and financial condition of the issuer,
including the availability and terms of any additional financing requirements;
financial condition and prospects of the issuer's region and industry, customers
and markets and Southern Union's intent and ability to retain the investment. If
Southern Union determines that the decline in value of an investment security is
other than temporary, the Company will record a charge on its Consolidated
Statement of Operations to reduce the carrying value of the security to its
estimated fair value.
Capital Expenditures. Capital expenditures, which consist primarily of
expenditures to expand and maintain the Company's gas distribution and pipeline
systems, were $77,341,000 for the three-month period ended September 30, 2004.
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.
Construction on the Trunkline LNG expansion project (Phase I) commenced in
September 2003 and is expected to be completed at an estimated cost totaling
$137,000,000, plus capitalized interest, 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
is estimated to cost approximately $77,000,000, plus capitalized interest, and
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. Also on
September 17, 2004, as modified on September 23, 2004, the FERC approved
Trunkline's 30-inch diameter, approximately 23-mile natural gas pipeline loop
from the LNG terminal. The pipeline project is estimated to cost approximately
$41,000,000, plus capitalized interest, and will create additional transport
capacity in association with the Trunkline LNG expansion as well as new and
expanded delivery points with major interstate pipelines. The pipeline has an
expected in-service date of mid-calendar 2005. Including Trunkline LNG's Phase
I, Phase II and the 23-mile loop pipeline expansion, total capital expenditures
are expected to approximate $255,000,000, plus capitalized interest, of which
approximately $112,000,000 of costs are included in the line item Construction
Work-In-Progress through September 30, 2004. Collectively, these projects are
expected to generate approximately $80,000,000 of annualized revenue, once all
projects are in service.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Management's Discussion and Analysis of Financial Condition and Results of
Operations and other sections of this Quarterly Report on Form 10-Q contain
forward-looking statements that are based on current expectations, estimates and
projections about the industry in which the Company operates, management's
beliefs and assumptions made by management. Words such as "expects,"
"anticipates," "intends," "plans," "believes," "seeks," "estimates," variations
of such words and similar expressions are intended to identify such
forward-looking statements. Similarly, statements that describe our objectives,
plans or goals are or may be forward-looking statements. These statements are
not guarantees of future performance and involve certain risks, uncertainties
and assumptions, which are difficult to predict and many of which are outside
the Company's control. Therefore, actual results, performance and achievements
may differ materially from what is expressed or forecasted in such
forward-looking statements. The Company undertakes no obligation to publicly
update any forward-looking statements, whether as a result of new information,
future events or otherwise. Readers are cautioned not to put undue reliance on
such forward-looking statements. Stockholders may review the Company's reports
filed in the future with the Securities and Exchange Commission for more current
descriptions of developments that could cause actual results to differ
materially from such forward-looking statements.
Factors that could cause actual results to differ materially from those
expressed in our forward-looking statements include, but are not limited to, the
following: cost of gas; gas sales volumes; gas throughput volumes and available
sources of natural gas; discounting of transportation rates due to competition;
customer growth; abnormal weather conditions in the Company's service
territories; the Company's ability to control costs successfully and achieve
operating efficiencies, including the purchase and implementation of new
technologies for achieving such efficiencies; impact of relations with labor
unions of bargaining-unit employees; the receipt of timely and adequate rate
relief and the impact of future rate cases or regulatory rulings; the outcome of
pending and future litigation; the speed and degree to which competition is
introduced to our gas distribution business; new legislation and government
regulations and proceedings affecting or involving the Company; unanticipated
environmental liabilities; the Company's ability to comply with or to challenge
successfully existing or new environmental regulations; changes in business
strategy and the success of new business ventures; the risk that the businesses
acquired and any other businesses or investments that Southern Union has
acquired or may acquire may not be successfully integrated with the businesses
of Southern Union; exposure to customer concentration with a significant portion
of revenues realized from a relatively small number of customers and any credit
risks associated with the financial position of those customers; factors
affecting operations such as maintenance or repairs, environmental incidents or
gas pipeline system constraints; our or any of our subsidiaries debt securities
ratings; the economic climate and growth in our industry and service territories
and competitive conditions of energy markets in general; inflationary trends;
changes in gas or other energy market commodity prices and interest rates; the
current market conditions causing more customer contracts to be of shorter
duration, which may increase revenue volatility; the possibility of war or
terrorist attacks; the nature and impact of any extraordinary transactions such
as any acquisition or divestiture of a business unit or any assets. These are
representative of the factors that could affect the outcome of the
forward-looking statements. In addition, such statements could be affected by
general industry and market conditions, and general economic conditions,
including interest rate fluctuations, federal, state and local laws and
regulations affecting the retail gas industry or the energy industry generally,
and other factors.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There are no material changes in market risks faced by the Company from those
reported in the Company's Annual Report on Form 10-K for the year ended June 30,
2004.
The information contained in Item 3 updates, and should be read in conjunction
with, information set forth in Part II, Item 7 and 7A in the Company's Annual
Report on Form 10-K for the year ended June 30, 2004, in addition to the interim
consolidated financial statements, accompanying notes, and Management's
Discussion and Analysis of Financial Condition and Results of Operations
presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Southern Union performed an evaluation under the supervision and with the
participation of its management, including its Chief Executive Officer (CEO) and
Chief Financial Officer (CFO), and with the participation of personnel from its
Legal, Internal Audit, Risk Management and Financial Reporting Departments, of
the effectiveness of the design and operation of the Company's disclosure
controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) under
the Securities Exchange Act of 1934) as of the end of the period covered by this
report. Based on that evaluation, Southern Union's CEO and CFO concluded that
the Company's disclosure controls and procedures were effective as of September
30, 2004 and have communicated that determination to the Audit Committee of
Southern Union's Board of Directors.
Changes in Internal Controls
There has not been any change in Southern Union's internal controls over
financial reporting identified in connection with the Company's evaluation
thereof that occurred during the quarter ended September 30, 2004 that
materially affected, or is reasonably likely to materially affect, Southern
Union's internal controls over financial reporting.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
PART II. OTHER INFORMATION
EXHIBITS AND REPORTS ON FORM 8-K
Exhibits:
The following exhibits are filed as part of this Quarterly Report on Form 10-Q:
4 Supplemental Indenture No. 1 between Southern Union Company and
JPMorgan Chase Bank, as Trustee, dated as of June 11, 2003. (Filed
as Exhibit 4.5 to Form 8-A filed on June 20, 2003 and incorporated
herein by reference.)
31.1 Certificate by Chief Executive Officer pursuant to Rule 13a-14(a)
or Rule 15d-14(a) promulgated under the Securities Exchange Act of
1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2 Certificate by Chief Financial Officer pursuant to Rule 13a-14(a)
or Rule 15d-14(a) promulgated under the Securities Exchange Act of
1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
32.1 Certificate by Chief Executive Officer pursuant to Rule 13a-14(b)
or Rule 15d-14(b) promulgated under the Securities Exchange Act of
1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C.
Section 1350.
32.2 Certificate by Chief Financial Officer pursuant to Rule 13a-14(b)
or Rule 15d-14(b) promulgated under the Securities Exchange Act of
1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C.
Section 1350.
Reports on Form 8-K:
The Company filed the following Current Reports on Form 8-K during the quarter
ended September 30, 2004:
Date Filed Description of Filing
7/19/2004 Filing under Item 12, the press release issued by Southern
Union Company announcing the reconfirmation of fiscal year
ended June 30, 2004 earning guidance of $1.35 to $1.40 per
common share diluted for outstanding options and warrants.
7/20/2004 Furnishing under Item 9, the press release issued by
Southern Union Company announcing plans to make a public
offering of 11,000,000 shares of common stock, of which
6,200,000 shares are being offered in connection with a
forward sales agreement with J.P. Morgan Securities Inc. and
an affiliate of Merrill Lynch, Pierce, Fenner & Smith
Incorporated; an additional 1,650,000 shares are being
offered to the underwriters for over-allotments under an
option to purchase.
7/20/2004 Filing under Item 5, certain historical financial statements
and notes thereto of Panhandle Eastern Pipe Line Company,
LP, a wholly-owned subsidiary of Southern Union Company,
including the audited historical financial statements and
related notes at December 31, 2002 and 2001, and for each of
the three years in the period ended December 31, 2002, and
the unaudited financial statements and related notes at
March 31, 2003 and for the three months ended March 31, 2003
and 2002.
7/21/2004 Furnishing under Item 9, the press release issued by
Southern Union Company announcing fiscal year 2005 earnings
guidance of $1.30 to $1.40 per common share diluted for
outstanding options and inclusive of the 4,800,000 share
issuance announced on July 20, 2004.
7/26/2004 Filing under Item 8.01 , the Forward Agreement among
Southern Union Company, Merrill Lynch International, and
Merrill Lynch, Pierce, Fenner & Smith Inc., as well as the
Forward Agreement between Southern Union Company, JP Morgan
Chase Bank, and J.P. Morgan Securities, Inc., and the
Underwriting Agreement, as amended, between Southern Union
Company, J.P. Morgan Securities, Inc., Merrill Lynch,
Pierce, Fenner & Smith Inc., with respect to Southern
Union's offering of 12,650,000 shares of its common stock.
7/27/2004 Furnishing under Item 9, the press release issued by
Southern Union Company announcing that it had priced its
public offering of 11,000,000 shares of its common stock at
$18.75 per share.
8/02/2004 Announcement of operating performance for the quarter and
year ended June 30, 2004 and 2003 and filing, under Item 12,
summary statements of income of Southern Union Company for
the quarter and year ended June 30, 2004 and 2003
(unaudited) and notes thereto.
9/01/2004 Filing under Item 8.01, the press release issued by Southern
Union Company announcing that CCE Holdings, LLC, a joint
venture of Southern Union and its equity partner, GE
Commercial Finance Energy Financial Services, entered into
an agreement to acquire for cash 100 percent of the equity
interests of CrossCountry Energy, LLC from Enron Corp., and
its affiliates.
9/10/2004 Filing under Item 1.01, the press release issued by Southern
Union Company announcing that the U.S. Bankruptcy Court for
the Southern District of New York issued a Final Sale Order
approving the purchase Agreement, as amended, between CCE
Holdings, LLC and Enron Corp. and its affiliates to acquire
100 percent of the equity interests of CrossCountry Energy,
LLC for $2.45 billion, including the assumption of certain
consolidated debt.
9/16/2004 Filing under Item 1.01, the press release issued by Southern
Union Company announcing that CCE Holdings, LLC entered into
a definitive agreement with ONEOK, Inc. to sell its interest
in Northern Plains Natural Gas Company for $175,000,000
immediately upon closing its acquisition of CrossCountry
Energy, LLC from Enron Corp. and its affiliates.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHERN UNION COMPANY
----------------------
(Registrant)
Date November 9, 2004 By DAVID J. KVAPIL
------------------- -------------------
David J. Kvapil
Executive Vice President
and Chief Financial Officer
Exhibit 31.1
CERTIFICATIONS
I, George L. Lindemann, certify that:
(1) I have reviewed this quarterly report on Form 10-Q of Southern Union
Company;
(2) Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this report;
(3) Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
report;
(4) The registrant's other certifying officer(s) and I are responsible
for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
(a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during
the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this
report based on such evaluation; and
(c) Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's most recent fiscal quarter (the registrant's fourth
fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting; and
(5) The registrant's other certifying officer(s) and I have disclosed,
based on our most recent evaluation of internal control over
financial reporting, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons
performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the
design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant's
ability to record, process, summarize and report financial
information; and
(b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal control over financial reporting.
Date: November 9, 2004
GEORGE L. LINDEMANN
- -------------------
George L. Lindemann
Chairman of the Board and
Chief Executive Officer
(principal executive officer)
Exhibit 31.2
CERTIFICATIONS
I, David J. Kvapil, certify that:
(1) I have reviewed this quarterly report on Form 10-Q of Southern Union
Company;
(2) Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this report;
(3) Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this
report;
(4) The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the
registrant and have:
(a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during
the period in which this report is being prepared;
(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this
report based on such evaluation; and
(c) Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's most recent fiscal quarter (the registrant's fourth
fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting; and
(5) The registrant's other certifying officer(s) and I have disclosed,
based on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of the
registrant's board of directors (or persons performing the equivalent
functions):
(a) All significant deficiencies and material weaknesses in the
design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant's
ability to record, process, summarize and report financial
information; and
(b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal control over financial reporting.
Date: November 9, 2004
DAVID J. KVAPIL
- ---------------
David J. Kvapil
Executive Vice President and
Chief Financial Officer
(principal financial officer)
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the quarterly report on Form 10-Q of Southern Union Company
(the "Company") for the quarter ended September 30, 2004, as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), I, George
L. Lindemann, Chairman of the Board and Chief Executive Officer of the Company,
certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the
Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies
with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act
of 1934, as amended, and (ii) the information contained in the Report fairly
presents, in all material respects, the financial condition and results of
operations of the Company.
GEORGE L. LINDEMANN
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George L. Lindemann
Chairman of the Board and
Chief Executive Officer
November 9, 2004
This Certification is being furnished solely to accompany the Report pursuant to
18 U.S.C. ss.1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, and shall not be deemed "filed" by the Company for purposes of Section
18 of the Securities Exchange Act of 1934, as amended, and shall not be
incorporated by reference into any filing of the Company under the Securities
Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended,
whether made before or after the date of this Report, irrespective of any
general incorporation language contained in such filing.
A signed original of this written statement required by Section 906, or other
documents authenticating, acknowledging, or otherwise adopting the signature
that appears in typed form within the electronic version of this written
statement required by Section 906, has been provided to the Company and will be
retained by the Company and furnished to the Securities and Exchange Commission
or its staff upon request.
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the quarterly report on Form 10-Q of Southern Union Company
(the "Company") for the quarter ended September 30, 2004, as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), I, David
J. Kvapil, Executive Vice President and Chief Financial Officer of the Company,
certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the
Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies
with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act
of 1934, as amended, and (ii) the information contained in the Report fairly
presents, in all material respects, the financial condition and results of
operations of the Company.
DAVID J. KVAPIL
- ---------------
David J. Kvapil
Executive Vice President and
Chief Financial Officer
November 9, 2004
This Certification is being furnished solely to accompany the Report pursuant to
18 U.S.C. ss.1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, and shall not be deemed "filed" by the Company for purposes of Section
18 of the Securities Exchange Act of 1934, as amended, and shall not be
incorporated by reference into any filing of the Company under the Securities
Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended,
whether made before or after the date of this Report, irrespective of any
general incorporation language contained in such filing.
A signed original of this written statement required by Section 906, or other
documents authenticating, acknowledging, or otherwise adopting the signature
that appears in typed form within the electronic version of this written
statement required by Section 906, has been provided to the Company and will be
retained by the Company and furnished to the Securities and Exchange Commission
or its staff upon request.