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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
- --- THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended June 30, 2004
OR
- --- TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
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 on which registered
- ------------------- ----------------------------------------------
Common Stock, par value New York Stock Exchange
$1 per share
7.55% Depositary Shares New York Stock Exchange
5.75% Equity Units New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: None
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 if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ___
Indicate by check mark whether the registrant is an Accelerated Filer (as
defined in Exchange Act Rule 12D-2). Yes X No
---- ----
The aggregate market value of the Common Stock held by non-affiliates of the
Registrant as of December 31, 2003 was $1,002,204,375 (based on the closing
sales price of Common Stock on the New York Stock Exchange on December 31,
2003). For purposes of this calculation, shares held by non-affiliates exclude
only those shares beneficially owned by executive officers, directors and
stockholders of more than ten percent of the Common Stock of the Company.
The number of shares of the registrant's Common Stock outstanding on August 16,
2004 was 81,886,254.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's proxy statement for its annual meeting of
stockholders to be held on October 28, 2004, are incorporated by reference into
Part III.
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PART I
ITEM 1. Business.
Our Business
Introduction
Southern Union Company (Southern Union and together with its subsidiaries, the
Company) was incorporated under the laws of the State of Delaware in 1932. The
Company is primarily engaged in the transportation, storage and distribution of
natural gas in the United States. The Company's interstate natural gas
transportation and storage operations are conducted through Panhandle Eastern
Pipe Line Company, LP and its subsidiaries (hereafter collectively referred to
as Panhandle Energy), which operate more than 10,000 miles of interstate
pipelines that transport natural gas from the Gulf of Mexico, South Texas and
the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest
and Great Lakes regions. Panhandle Energy also operates a liquefied natural gas
(LNG) import terminal, located on Louisiana's Gulf Coast, which is one of the
largest operating LNG facilities in North America based on current send out
capacity. 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.
Acquisition of Panhandle Energy - On June 11, 2003, Southern Union acquired
Panhandle Energy from CMS Energy Corporation for approximately $581,729,000 in
cash and 3,000,000 shares of Southern Union common stock (before adjustment for
subsequent stock dividends) valued at approximately $48,900,000 based on market
prices at closing of the Panhandle Energy acquisition and in connection
therewith incurred transaction costs of approximately $31,922,000. At the time
of the acquisition, Panhandle Energy had approximately $1,157,228,000 of debt
principal outstanding that it retained. The Company funded the cash portion of
the acquisition with approximately $437,000,000 in cash proceeds it received for
the January 1, 2003 sale of its Texas operations, approximately $121,250,000 of
the net proceeds it received from concurrent common stock and equity unit
offerings (see Note X - Stockholders' Equity) and with working capital available
to the Company. The Company structured the Panhandle Energy acquisition and the
sale of its Texas operations to qualify as a like-kind exchange of property
under Section 1031 of the Internal Revenue Code of 1986, as amended. The
acquisition was accounted for using the purchase method of accounting in
accordance with accounting principles generally accepted within the United
States of America with the purchase price paid and acquisition costs incurred by
the Company allocated to Panhandle Energy's net assets as of the acquisition
date. The Panhandle Energy assets acquired and liabilities assumed have been
recorded at their estimated fair value as of the acquisition date based on the
results of outside appraisals. Panhandle Energy's results of operations have
been included in the Consolidated Statement of Operations since June 11, 2003.
Thus, the Consolidated Statement of Operations for the periods subsequent to the
acquisition is not comparable to the same periods in prior years.
Panhandle Energy is primarily engaged in the interstate transportation and
storage of natural gas and also provides LNG terminalling and regasification
services and is subject to the rules and regulations of the Federal Energy
Regulatory Commission (FERC). The Panhandle Energy entities include Panhandle
Eastern Pipe Line Company, LP (Panhandle Eastern Pipe Line), Trunkline Gas
Company, LLC (Trunkline), a wholly-owned subsidiary of Panhandle Eastern Pipe
Line, Sea Robin Pipeline Company (Sea Robin), a Louisiana joint venture and an
indirect wholly-owned subsidiary of Panhandle Eastern Pipe Line, Trunkline LNG
Company, LLC (Trunkline LNG) which is a wholly-owned subsidiary of Trunkline LNG
Holdings, LLC (LNG Holdings), an indirect wholly-owned subsidiary of Panhandle
Eastern Pipe Line and Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage), a
wholly-owned subsidiary of Panhandle Eastern Pipe Line. Collectively, the
pipeline assets include more than 10,000 miles of interstate pipelines that
transport natural gas from the Gulf of Mexico, South Texas and the Panhandle
regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great
Lakes region. The pipelines have a combined peak day delivery capacity of 5.4
billion cubic feet (Bcf) per day and 72 Bcf of owned underground storage
capacity and 6.3 Bcf of above ground LNG storage capacity. Trunkline LNG,
located on Louisiana's Gulf Coast, operates one of the largest LNG import
terminals in North America, based on current send out capacity.
Sale of Southern Union Gas and Related Assets - Effective January 1, 2003, the
Company completed the sale of its Southern Union Gas natural gas operating
division and related assets to ONEOK, Inc. (ONEOK) for approximately
$437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In addition to
Southern Union Gas, the sale involved the disposition of Mercado Gas Services,
Inc. (Mercado), SUPro Energy Company (SUPro), Southern Transmission Company
(STC), Southern Union Energy International, Inc. (SUEI), Southern Union
International Investments, Inc. (Investments) and Norteno Pipeline Company
(Norteno) (collectively, the Texas Operations). Southern Union Gas distributed
natural gas as a public utility to approximately 535,000 customers throughout
Texas, including the cities of Austin, El Paso, Brownsville, Galveston and Port
Arthur. Mercado marketed natural gas to commercial and industrial customers.
SUPro provided propane gas services to approximately 4,000 customers located
principally in Austin, El Paso and Alpine, Texas as well as Las Cruces, New
Mexico and surrounding communities. STC owned and operated 118.8 miles of
intrastate pipeline that served commercial, industrial and utility customers in
central, southern and coastal Texas. SUEI and Investments participated in
energy-related projects internationally. Energia Estrella del Sur, S. A. de C.
V., a wholly-owned Mexican subsidiary of SUEI and Investments, had a 43% equity
ownership in a natural gas distribution company, along with other related
operations, which served 23,000 customers in Piedras Negras, Mexico, across the
border from Southern Union Gas' Eagle Pass, Texas service area. Norteno owned
and operated interstate pipelines that served the gas distribution properties of
Southern Union Gas and the Public Service Company of New Mexico. Norteno also
transported gas through its interstate network to the country of Mexico for
Pemex Gas y Petroquimica Basica. In accordance with accounting principles
generally accepted in the United States of America, the results of operations
and gain on sale have been segregated and reported as "discontinued operations"
in the Consolidated Statement of Operations and as "assets held for sale" in the
Consolidated Statement of Cash Flows for the respective periods.
Other Sales - In July 2001, the Company implemented a Cash Flow Improvement Plan
that was designed to increase annualized pre-tax cash flow from operations by at
least $50 million by the end of fiscal year 2002. The three-part initiative was
composed of strategies designed to achieve results enabling its utility
divisions to meet their allowed rates of return, restructure its corporate
operations, and accelerate the sale of non-core assets and use the proceeds
exclusively for debt reduction. In connection with the Cash Flow Improvement
Plan and subsequent strategic initiatives, the Company sold certain non-core
subsidiaries and assets described below during the three-year period ended June
30, 2004.
Subsidiary or Asset Sold Date Sold Proceeds Pre-tax Gain(Loss)
- ----------------------------------------------------- -------------- ------------- --------------------
ProvEnergy Power Company LLC (a) October 2003 $ 2,175,000 $(1,150,000)
PG Energy Services' propane operations (b) April 2002 2,300,000 1,200,000
Carrizo Springs Pipeline (c) December 2001 1,000,000 561,000
South Florida Natural Gas and Atlantic Gas
Corporation (d) December 2001 10,000,000 (1,500,000)
Morris Merchants, Inc. (e) October 2001 1,586,000 --
Valley Propane, Inc. (f) September 2001 5,301,000 --
ProvEnergy Oil Enterprises (g) August 2001 15,776,000 --
PG Energy Services' commercial and
industrial gas marketing contracts July 2001 4,972,000 4,653,000
- ----------------------------------------------------
(a) Provided outsourced energy management services and owned 50% of Capital
Center Energy Company LLC.
(b) Sold liquid propane to residential, commercial and industrial customers in
northeastern and central Pennsylvania.
(c) Asset was a 43-mile pipeline operated by Southern Transmission Company.
(d) South Florida Natural Gas was a natural gas division of Southern Union and
Atlantic Gas Corporation was a propane subsidiary of the Company.
(e) Served as a manufacturers' representative agency for franchised plumbing and
heating supplies throughout New England.
(f) Sold liquid propane to residential, commercial and industrial customers in
Rhode Island and Massachusetts.
(g) Operated a fuel oil distribution business through its subsidiary, ProvEnergy
Fuels, Inc. for residential and commercial customers in Rhode Island
and Massachusetts.
Business Segments
The Company's operations include two reportable segments:
o The Transportation and Storage segment, which is primarily engaged in the
interstate transportation and storage of natural gas in the Midwest and
Southwest and also provides LNG terminalling and regasification services.
Its operations are conducted through Panhandle Energy, which the Company
acquired on June 11, 2003;
o The Distribution segment, which 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.
For a more detailed description of the Company's reportable segments, see Item
1. Business - Transportation and Storage Segment and Item 1. Business -
Distribution Segment.
The Company's operations also include certain subsidiaries established to
support and expand natural gas sales and other energy sales, which are not
included in the Transportation and Storage segment or the Distribution segment.
These subsidiaries, described below, do not meet the quantitative thresholds for
determining reportable segments and have been combined for disclosure purposes
in the "All Other" category (for information about the revenues, operating
income (which the Company formerly referred to as net operating revenues),
assets and other financial information relating to the All Other category, see
Note XXI - Reportable Segments).
o PEI Power Corporation (Power Corp.), an exempt wholesale generator (within
the meaning of the Public Utility Holding Company Act of 1935), generates
and sells electricity provided by two power plants that share a site in
Archbald, Pennsylvania. Power Corp. wholly owns one plant, a 25-megawatt
cogeneration facility fueled by a combination of natural gas and methane.
Power Corp. owns 49.9% of the second plant, a 45-megawatt natural gas-fired
facility, in a joint venture with Cayuga Energy. These plants sell
electricity to the broad mid-Atlantic wholesale energy market administered
by PJM Interconnection, L.L.C.
o Fall River Gas Appliance Company, Inc. rents water heaters and conversion
burners (primarily for residential use) to over 16,400 customers and offers
service contracts on gas appliances in the city of Fall River and the towns
of Somerset, Swansea and Westport, all located in southeastern
Massachusetts.
o Valley Appliance and Merchandising Company (VAMCO) rents natural gas
burning appliances and offers appliance service contract programs to
residential customers. In fiscal 2002, VAMCO provided construction
management services for natural gas-related projects to commercial and
industrial customers.
o PG Energy Services, Inc. (Energy Services) offers the inspection,
maintenance and servicing of residential and small commercial gas-fired
equipment to 16,100 residential and commercial users primarily in central
and northeastern Pennsylvania.
o Alternate Energy Corporation is an energy consulting firm that also retains
patents on a natural gas/diesel co-firing system and on "Passport" FMS
(Fuel Management System) which monitors and controls the transfer of fuel
on dual-fuel equipment.
The Company also has corporate operations that do not generate operating
revenues. Corporate functions include Accounting, Corporate Communications,
Human Resources, Information Technology, Internal Audit, Investor Relations,
Legal, Payroll, Purchasing, Risk Management, Tax and Treasury.
The Company also maintains a venture capital investment portfolio. The Company's
significant venture capital investments are listed below.
o PointServe, Inc. (PointServe) --The Company has a remaining investment of
$2,603,000 in PointServe, a business-to-business online scheduling
solution, after recording non-cash charges of $1,603,000 and $10,380,000
during fiscal 2004 and 2002, respectively to recognize a decrease in fair
value. The Company recognized these valuation adjustments to reflect
significant 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.
o Advent Networks, Inc. (Advent) -- Southern Union has a $5,433,000 equity
interest in Advent and holds $11,500,000 of convertible notes receivable
from Advent. Additionally, a wholly owned subsidiary of Southern Union has
guaranteed a $4,000,000 line of credit between Advent and a bank. Advent's
UltraBand(TM) technology is expected to deliver digital broadband services
40 times faster than digital subscriber lines (DSL) or cable modems, and
1,000 times faster than dial-up modems, over the "last mile". UltraBand(TM)
should provide cable network overbuilders a competitive advantage with its
capability to deliver content at a quality and speed that cannot be
provided over cable modem. All of the convertible notes bear interest at
10% per annum and convert into equity at a ratio determined upon the next
equity financing of Advent or upon a change of control of Advent. The
convertible notes are due on demand at the request of Southern Union.
Advent is a closely held, privately owned company and, as such, has no
published market value. Certain Southern Union executive officers,
directors and employees have invested an aggregate of approximately
$2,600,000 in Advent and beneficially own in the aggregate approximately
three percent equity ownership interest in Advent either directly,
indirectly or through a partnership unrelated to Southern Union through
which such persons vote their beneficial interest at their own discretion.
As a result of an early round of financings, the Company has the right to
name one of seven directors to the Advent Board. However, currently Thomas
F. Karam and John E. Brennan, officers and directors of the Company, serve
as the Company's representatives on the Advent Board of Directors.
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; financial condition and
prospects of the issuer's region and industry; 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, it will record a
charge on its Consolidated Statement of Operations to reduce the carrying value
of the security to its estimated fair value.
Transportation and Storage Segment
Services
The Transportation and Storage segment is primarily engaged in the interstate
transportation and storage of natural gas in the Midwest and Southwest, and also
provides LNG terminalling and regasification services. Its operations are
conducted through Panhandle Energy, which the Company acquired on June 11, 2003.
In fiscal 2004, this segment represented 27 percent of the Company's total
operating revenues.
Panhandle Energy owns and operates a large natural gas pipeline network
consisting of more than 10,000 miles of pipeline. The pipeline network,
consisting of the Panhandle Eastern Pipe Line transmission system, the Trunkline
transmission system and the Sea Robin transmission system provides approximately
500 customers in the Midwest and Southwest with a comprehensive array of
transportation and storage services. Panhandle Eastern Pipe Line's transmission
system, with approximately 6,500 miles of pipeline, consists of four large
diameter pipelines extending approximately 1,300 miles from producing areas in
the Anadarko Basin of Texas, Oklahoma and Kansas through the states of Missouri,
Illinois, Indiana, Ohio and into Michigan. Trunkline's transmission system, with
approximately 3,500 miles of pipeline, consists of two large diameter pipelines
extending approximately 1,400 miles from the Gulf Coast areas of Texas and
Louisiana through the states of Arkansas, Mississippi, Tennessee, Kentucky,
Illinois and Indiana to a point on the Indiana-Michigan border. Sea Robin's
transmission system consists of two offshore Louisiana natural gas supply
systems and is comprised of approximately 400 miles of pipeline extending
approximately 81 miles into the Gulf of Mexico.
Panhandle Energy has approximately 87 Bcf of total storage available for use in
connection with its gas transmission systems. Panhandle Energy owns and operates
47 compressor stations, and has five gas storage fields located in Illinois,
Kansas, Louisiana, Michigan and Oklahoma and with a combined maximum working
storage capacity of 72 Bcf. Panhandle Energy also has contracts with third
parties that provide for approximately 15 Bcf of storage.
Through Trunkline LNG, Panhandle Energy owns and operates a LNG terminal in Lake
Charles, Louisiana, which is one of the largest operating LNG facilities in
North America based on its sustainable send out capacity of approximately .63
Bcf per day. Trunkline LNG is currently in the process of expanding the
terminal, which will increase sustainable send out capacity to approximately 1.2
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 with an estimated
cost totaling $137 million, plus capitalized interest, by the end of the 2005
calendar year. In February 2004, Trunkline LNG filed a further incremental LNG
expansion project (Phase II) with FERC and is awaiting commission approval.
Phase II is estimated to cost approximately $77 million, 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.
BG LNG Services has contracted for all the proposed additional capacity, subject
to Trunkline LNG achieving certain construction milestones at this facility.
In February 2004, Trunkline filed an application with FERC to request approval
of a 30-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal.
The estimated cost of this pipeline expansion is approximately $41 million, plus
capitalized interest. 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.
A significant portion of Panhandle Energy's revenue comes from reservation fees
related to long-term service agreements with local distribution company
customers and their affiliates. Panhandle Energy also provides firm
transportation services under contract to gas marketers, producers, other
pipelines, electric power generators, and a variety of other end-users. In
addition, the pipelines offer both firm and interruptible transportation to
customers on a short-term or seasonal basis. Demand for gas transmission on
Panhandle Energy's pipeline systems is somewhat seasonal, with the highest
throughput and a higher portion of annual operating revenues and net earnings
occurring in the traditional winter heating season in the first and fourth
calendar quarters. In fiscal 2004 and 2003 (from June 12 to June 30, 2003),
Panhandle Energy's combined throughput was 1,321 trillion British thermal units
(TBtu) and 69 TBtu, respectively.
In fiscal 2004, Panhandle Energy's operating revenues were $491,083,000, of
which 86 percent was generated from transportation and storage services, 12
percent from LNG terminalling services, and 2 percent from other services.
Aggregate sales to Panhandle Energy's top ten customers accounted for 70 percent
of the segment's operating revenues in fiscal 2004 (see Item 7. Management's
Discussion and Analysis - Other Matters (Customer Concentrations)). Panhandle
Energy has no single customer, or group of customers under common control, which
accounted for ten percent or more of the Company's total operating revenues in
fiscal 2004.
For information about the operating revenues, operating income, assets and other
financial information relating to the Transportation and Storage segment, see
ITEM 7. Management's Discussion and Analysis - Business Segment Results and Note
XXI - Reportable Segments.
Regulation
Panhandle Energy is subject to regulation by various federal, state and local
governmental agencies, including those specifically described below. See also
Item 1. Business - Environmental.
FERC has comprehensive jurisdiction over Panhandle Eastern Pipe Line, Southwest
Gas Storage, Trunkline, Trunkline LNG and Sea Robin as natural gas companies
within the meaning of the Natural Gas Act of 1938. FERC jurisdiction relates,
among other things, to the acquisition, operation and disposal of assets and
facilities and to the service provided and rates charged.
FERC has authority to regulate rates and charges for transportation or storage
of natural gas in interstate commerce. FERC also has authority over the
construction and operation of pipeline and related facilities utilized in the
transportation and sale of natural gas in interstate commerce, including the
extension, enlargement or abandonment of service using such facilities.
Panhandle Eastern Pipe Line, Trunkline, Sea Robin, Trunkline LNG, and Southwest
Gas Storage hold certificates of public convenience and necessity issued by
FERC, authorizing them to construct and operate the pipelines, facilities and
properties now in operation for which such certificates are required, and to
transport and store natural gas in interstate commerce.
The Secretary of Energy regulates the importation and exportation of natural gas
and has delegated various aspects of this jurisdiction to FERC and the
Department of Energy's Office of Fossil Fuels.
Panhandle Energy is also subject to the Natural Gas Pipeline Safety Act of 1968
and the Pipeline Safety Improvement Act of 2002, which regulate the safety of
gas pipelines. Panhandle Energy is also subject to the Hazardous Liquid Pipeline
Safety Act of 1979, which regulates oil and petroleum pipelines.
For a discussion of the effect of certain FERC orders on Panhandle Energy, see
Item 7. Management's Discussion and Analysis - Other Matters.
Competition
Panhandle Energy's interstate pipelines compete with other interstate and
intrastate pipeline companies in the transportation and storage of natural gas.
The principal elements of competition among pipelines are rates, terms of
service and flexibility, and reliability of service. Panhandle Energy's direct
competitors include Alliance Pipeline LP, ANR Pipeline Company, Natural Gas
Pipeline Company of America, Northern Border Pipeline Company, Texas Gas
Transmission Corporation, Northern Natural Gas Company and Vector Pipeline.
Natural gas competes with other forms of energy available to Panhandle Energy's
customers and end-users, including electricity, coal and fuel oils. The primary
competitive factor is price. Changes in the availability or price of natural gas
and other forms of energy, the level of business activity, conservation,
legislation and governmental regulations, the capability to convert to alternate
fuels, and other factors, including weather and natural gas storage levels,
affect the demand for natural gas in the areas served by Panhandle Energy.
Distribution Segment
Services
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.
Collectively, the utility divisions serve over 960,000 residential, commercial
and industrial customers through local distribution systems consisting of 14,243
miles of mains, 9,605 miles of service lines and 76 miles of transmission lines.
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. In fiscal 2004, this segment represented 72 percent of the
Company's total operating revenues.
In fiscal 2004, 2003 and 2002, the Distribution segment's operating revenues
were $1,304,000,000, $1,159,000,000 and $968,900,000, respectively; average
customers served totaled 949,978, 944,657 and 935,229, respectively; and gas
volumes sold or transported totaled 173,119 million cubic feet (MMcf), 188,333
MMcf and 166,793 MMcf, respectively. The Distribution segment has no single
customer, or group of customers under common control, which accounted for ten
percent or more of the Company's total operating revenues in fiscal 2004.
For information about the operating revenues, operating income, assets and other
financial information relating to the Distribution segment, see ITEM 7.
Management's Discussion and Analysis - Business Segment Results and Note XXI -
Reportable Segments.
A description of each of the Company's regulated utility divisions follows.
Missouri Gas Energy - Missouri Gas Energy, headquartered in Kansas City,
Missouri, serves approximately 503,000 customers in central and western Missouri
(including Kansas City, St. Joseph, Joplin and Monett) through a local
distribution system that consists of approximately 8,074 miles of mains, 5,022
miles of service lines and 47 miles of transmission lines. Its service
territories have a total population of approximately 1.5 million. Missouri Gas
Energy's natural gas rates are regulated by the Missouri Public Service
Commission (MPSC) (see Item 1. Business - Regulation and Rates).
The Missouri Gas Energy customers served, gas volumes sold or transported and
weather-related information for the past three fiscal years are as follows:
Year Ended June 30,
-------------------------
2004 2003 2002
---- ---- ----
Average number of customers:
Residential ............................................................... 432,037 430,861 428,215
Commercial ................................................................ 61,957 60,774 58,749
Industrial ................................................................ 95 99 95
-------- -------- --------
Total average gas sales customers ..................................... 494,089 491,734 487,059
Transportation customers .................................................. 786 461 378
-------- -------- --------
Total average gas sales and transportation customers .................. 494,875 492,195 487,437
======== ======== ========
Gas sales in millions of cubic feet (MMcf):
Residential ............................................................... 36,880 39,821 35,039
Commercial ................................................................ 16,026 17,399 15,686
Industrial ................................................................ 338 391 417
-------- -------- --------
Gas sales billed ...................................................... 53,244 57,611 51,142
Net change in unbilled gas sales .......................................... 112 61 (16)
-------- -------- --------
Total gas sales ....................................................... 53,356 57,672 51,126
Gas transported ........................................................... 25,761 26,893 27,324
-------- -------- --------
Total gas sales and gas transported ................................... 79,117 84,565 78,450
======== ======== ========
Weather:
Degree days (a)............................................................ 4,770 5,105 4,419
Percent of 10-year measure (b)............................................. 92% 98% 85%
Percent of 30-year measure (b)............................................. 92% 98% 85%
- --------------------------------------------------------------------------------
(a) "Degree days" are a measure of the coldness of the weather experienced. A
degree day is equivalent to each degree that the daily mean temperature for
a day falls below 65 degrees Fahrenheit.
(b) Information with respect to weather conditions is provided by the National
Oceanic and Atmospheric Administration. Percentages of 10- and 30-year
measure are computed based on the weighted average volumes of gas sales
billed. The 10- and 30-year measure is used for consistent external
reporting purposes. Measures of normal weather used by the Company's
regulatory authorities to set rates vary by jurisdiction. Periods used to
measure normal weather for regulatory purposes range from 10 years to 30
years.
PG Energy - PG Energy, headquartered in Wilkes-Barre, Pennsylvania, serves
approximately 159,000 customers in northeastern and central Pennsylvania
(including Wilkes-Barre, Scranton and Williamsport) through a local distribution
system that consists of approximately 2,514 miles of mains, 1,515 miles of
service lines and 29 miles of transmission lines. Its service territories have a
total population of approximately 755,000. PG Energy's natural gas rates are
regulated by the Pennsylvania Public Utility Commission (PPUC) (see Item 1.
Business - Regulation and Rates).
The PG Energy customers served, gas volumes sold or transported and
weather-related information for the past three fiscal years are as follows:
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Average number of customers:
Residential ............................................................... 142,422 141,769 141,223
Commercial ................................................................ 14,384 14,141 13,707
Industrial ................................................................ 116 120 104
Public authorities and other .............................................. 340 337 212
-------- -------- --------
Total average customers served ........................................ 157,262 156,367 155,246
Transportation customers .................................................. 602 613 624
-------- -------- --------
Total average gas sales and transportation customers .................. 157,864 156,980 155,870
======== ======== ========
Gas sales in MMcf:
Residential ............................................................... 17,133 18,372 15,053
Commercial ................................................................ 6,505 6,732 5,325
Industrial ................................................................ 379 376 277
Public authorities and other .............................................. 290 334 145
-------- -------- --------
Gas sales billed ...................................................... 24,307 25,814 20,800
Net change in unbilled gas sales .......................................... 34 4 (22)
-------- --------- --------
Total gas sales ....................................................... 24,341 25,818 20,778
Gas transported ........................................................... 26,007 28,366 26,976
-------- -------- --------
Total gas sales and gas transported ................................... 50,348 54,184 47,754
======== ======== ========
Weather:
Degree days................................................................ 6,240 6,654 5,373
Percent of 10-year measure................................................. 100% 109% 89%
Percent of 30-year measure................................................. 103% 106% 86%
New England Gas Company - New England Gas Company, headquartered in Providence,
Rhode Island, serves approximately 301,000 customers in Rhode Island and
Massachusetts (including Providence, Newport and Cumberland, Rhode Island and
Fall River, North Attleboro and Somerset, Massachusetts) through a local
distribution system that consists of approximately 3,655 miles of mains and
3,068 miles of service lines. Its service territories have a total population of
approximately 1.2 million. In Rhode Island and Massachusetts, New England Gas
Company's natural gas rates are regulated by the Rhode Island Public Utilities
Commission (RIPUC) and Massachusetts Department of Telecommunications and Energy
(MDTE), respectively (see Item 1. Business -Regulation and Rates).
The New England Gas Company's customers served, gas volumes sold or transported
and weather-related information for the past three fiscal years are as follows:
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Average number of customers:
Residential ............................................................... 269,926 268,312 265,206
Commercial ................................................................ 25,798 25,442 21,696
Industrial and irrigation ................................................. 226 225 3,472
Public authorities and other .............................................. 47 41 43
-------- -------- --------
Total average customers served ........................................ 295,997 294,020 290,417
Transportation customers .................................................. 1,242 1,462 1,505
-------- -------- --------
Total average gas sales and transportation customers .................. 297,239 295,482 291,922
======== ======== ========
Gas sales in MMcf:
Residential ............................................................... 24,194 25,481 19,975
Commercial ................................................................ 9,753 9,725 6,196
Industrial and irrigation ................................................. 1,968 2,055 3,271
Public authorities and other .............................................. 25 28 23
-------- -------- --------
Gas sales billed ...................................................... 35,940 37,289 29,465
Net change in unbilled gas sales .......................................... (1,366) 1,336 (333)
-------- -------- --------
Total gas sales ....................................................... 34,574 38,625 29,132
Gas transported ........................................................... 9,080 10,959 11,457
-------- -------- --------
Total gas sales and gas transported ................................... 43,654 49,584 40,589
======== ======== ========
Weather:
Degree days................................................................ 5,644 6,143 4,980
Percent of 10-year measure................................................. 98% 111% 88%
Percent of 30-year measure ................................................ 102% 107% 85%
Gas Supply
The cost and reliability of natural gas service is dependent upon the Company's
ability to contract for favorable mixes of long-term and short-term gas supply
arrangements and through favorable fixed and variable transportation contracts.
The Company has been directly acquiring its gas supplies since the mid-1980s
when interstate pipeline systems opened their systems for transportation
service. The Company has the organization, personnel and equipment necessary to
dispatch and monitor gas volumes on a daily, hourly and even a real-time basis
to ensure reliable service to customers.
FERC required the "unbundling" of services offered by interstate pipeline
companies beginning in 1992. As a result, gas purchasing and transportation
decisions and associated risks have been shifted from the pipeline companies to
the gas distributors. The increased demands on distributors to effectively
manage their gas supply in an environment of volatile gas prices provides an
advantage to distribution companies such as Southern Union who have demonstrated
a history of contracting favorable and efficient gas supply arrangements in an
open market system.
The majority of 2004 gas requirements for the utility operations of Missouri Gas
Energy and PG Energy were delivered under short- and long-term transportation
contracts through four major pipeline companies. The majority of 2004 gas
requirements for the utility operations of New England Gas Company were
delivered under long-term transportation contracts through four major pipeline
companies. These contracts have various expiration dates ranging from calendar
year 2005 through 2018. Missouri Gas Energy and New England Gas Company have
firm supply commitments for all areas that are supplied with gas purchased under
short- and long-term arrangements. PG Energy has firm supply commitments for all
areas that are supplied with gas purchased under short-term arrangements.
Missouri Gas Energy, PG Energy and New England Gas Company hold contract rights
to over 17 Bcf, 11 Bcf and 7 Bcf of storage capacity, respectively, to assist in
meeting peak demands. Storage capacity in 2004 approximated 31% of the utility
operations' annual gas distribution volumes.
Gas sales and/or transportation contracts with interruption provisions, whereby
large volume users purchase gas with the understanding that they may be forced
to shut down or switch to alternate sources of energy at times when the gas is
needed for higher priority customers, have been utilized for load management by
Southern Union and the gas industry as a whole. In addition, during times of
special supply problems, curtailments of deliveries to customers with firm
contracts may be made in accordance with guidelines established by appropriate
federal and state regulatory agencies. There have been no supply-related
curtailments of deliveries to Missouri Gas Energy, PG Energy, or New England Gas
Company utility sales customers during the last ten years.
Competition
As energy providers, Missouri Gas Energy, PG Energy, and New England Gas Company
have historically competed with alternative energy sources, particularly
electricity, propane, fuel oil, coal, natural gas liquids and other refined
products available in their service areas. At present rates, the cost of
electricity to residential and commercial customers in the Company's regulated
utility service areas generally is higher than the effective cost of natural gas
service. There can be no assurance, however, that future fluctuations in gas and
electric costs will not reduce the cost advantage of natural gas service.
Competition between the use of fuel oils, natural gas and propane, particularly
by industrial and electric generation customers has also increased, due to the
volatility of natural gas prices and increased marketing efforts from various
energy companies. In order to be more competitive with certain alternate fuels
in Pennsylvania, PG Energy offers an Alternate Fuel Rate for eligible customers.
This rate applies to commercial and industrial accounts that have the capability
of using fuel oils or propane as alternate sources of energy. Whenever the cost
of such alternate fuel drops below PG Energy's normal tariff rates, PG Energy is
permitted by the PPUC to lower its price to these customers so that PG Energy
can remain competitive with the alternate fuel. However, in no instance may PG
Energy sell gas under this special arrangement for less than its average
commodity cost of gas purchased during the month. Competition between the use of
fuel oils, natural gas and propane, is generally greater in Pennsylvania and New
England than in the Company's Missouri service area; however, this competition
affects the nationwide market for natural gas. Additionally, the general
economic conditions in the Company's regulated utility service areas continue to
affect certain customers and market areas, thus impacting the results of the
Company's operations.
The Company's regulated utility operations are not currently in significant
direct competition with any other distributors of natural gas to residential and
small commercial customers within their service areas. In 1999, the Commonwealth
of Pennsylvania enacted the Natural Gas Choice and Competition Act, which
extended the ability to choose suppliers to small commercial and residential
customers as well. Effective April 29, 2000, all of PG Energy's customers have
the ability to select an alternate supplier of natural gas, which PG Energy will
continue to deliver through its distribution system under regulated
transportation service rates (with PG Energy serving as supplier of last
resort). Customers can also choose to remain with PG Energy as their supplier
under regulated natural gas sales rates. In either case, the applicable rate
results in the same net operating revenues to PG Energy. Despite customers'
acquired right to choose, higher-than-normal wholesale prices for natural gas
have prevented suppliers from offering competitive rates.
Regulation and Rates
The utility operations are regulated as to rates and other matters by the
regulatory commissions of the states in which each operates. In Missouri and
Pennsylvania, natural gas rates are established by the MPSC and PPUC,
respectively, on a system-wide basis. In Rhode Island, the RIPUC approves
natural gas rates for New England Gas Company. In Massachusetts, natural gas
rates for New England Gas Company are subject to the regulatory authority of the
MDTE.
The Company holds non-exclusive franchises with varying expiration dates in all
incorporated communities where it is necessary to carry on its business as it is
now being conducted. Providence, Rhode Island; Fall River, Massachusetts; Kansas
City, Missouri; and St. Joseph, Missouri are the four largest cities in which
the Company's utility customers are located. The franchise in Kansas City,
Missouri expires in 2010. The Company fully expects this franchise to be renewed
upon its expiration. The franchises in Providence, Rhode Island; Fall River,
Massachusetts; and St. Joseph, Missouri are perpetual.
Gas service rates are established by regulatory authorities to permit utilities
the opportunity to recover operating, administrative and financing costs, and
the opportunity to earn a reasonable return on equity. Gas costs are billed to
customers through purchase gas adjustment (PGA) clauses, which permit the
Company to adjust its sales price as the cost of purchased gas changes. This is
important because the cost of natural gas accounts for a significant portion of
the Company's total expenses. The appropriate regulatory authority must receive
notice of such adjustments prior to billing implementation.
Other than in Pennsylvania, the Company supports any service rate changes to its
regulators using an historic test year of operating results adjusted to normal
conditions and for any known and measurable revenue or expense changes. Because
the regulatory process has certain inherent time delays, rate orders may not
reflect the operating costs at the time new rates are put into effect. In
Pennsylvania, a future test year is utilized for ratemaking purposes, therefore,
rate orders more closely reflect the operating costs at the time new rates are
put into effect.
The monthly customer bill contains a fixed service charge, a usage charge for
service to deliver gas, and a charge for the amount of natural gas used. While
the monthly fixed charge provides an even revenue stream, the usage charge
increases the Company's annual revenue and earnings in the traditional heating
load months when usage of natural gas increases. Weather normalization clauses
serve to stabilize earnings. New England Gas Company has a weather normalization
clause in the tariff covering its Rhode Island operations.
Missouri -- On November 4, 2003, Missouri Gas Energy filed a request with the
MPSC to increase base rates by $44,800,000 and to implement a weather mitigation
rate design that would significantly reduce the impact of weather-related
fluctuations on customer bills. On January 30, 2004, Missouri Gas Energy filed
an updated claim which raised the amount of the base rate increase request to
$54,200,000. As of July 19, 2004, upon the close of the record and reflecting
settlement of a number of issues, MGE's request stood at approximately
$39,000,000 and the MPSC Staff's recommendation stood at approximately
$13,000,000. Statutes require that the MPSC reach a decision in the case within
an eleven-month period from the original filing date. It is not presently
possible to determine what action the MPSC will ultimately take with respect to
this rate increase request.
Rhode Island -- On May 22, 2003, the RIPUC approved a Settlement Offer filed by
New England Gas Company related to the final calculation of earnings sharing for
the 21-month period covered by the Energize Rhode Island Extension settlement
agreement. This calculation generated excess revenues of $5,277,000. The net
result of the excess revenues and the Energize Rhode Island weather mitigation
and non-firm margin sharing provisions was the crediting to customers of
$949,000 over a twelve-month period starting July 1, 2003.
On May 24, 2002, the RIPUC approved a settlement agreement between the New
England Gas Company and the Rhode Island Division of Public Utilities and
Carriers. The settlement agreement resulted in a $3,900,000 decrease in base
revenues for New England Gas Company's Rhode Island operations, a unified rate
structure ("One State; One Rate") and an integration/merger savings mechanism.
The settlement agreement also allows New England Gas Company to retain
$2,049,000 of merger savings and to share incremental earnings with customers
when the division's Rhode Island operations return on equity exceeds 11.25%.
Included in the settlement agreement was a conversion to therm billing and the
approval of a reconciling Distribution Adjustment Clause (DAC). The DAC allows
New England Gas Company to continue its low income assistance and weatherization
programs, to recover environmental response costs over a 10-year period, puts
into place a new weather normalization clause and allows for the sharing of
nonfirm margins (non-firm margin is margin earned from interruptible customers
with the ability to switch to alternative fuels). The weather normalization
clause is designed to mitigate the impact of weather volatility on customer
billings, which will assist customers in paying bills and stabilize the revenue
stream. New England Gas Company will defer the margin impact of weather that is
greater than 2% colder-than-normal and will recover the margin impact of weather
that is greater than 2% warmer-than-normal. The non-firm margin incentive
mechanism allows New England Gas Company to retain 25% of all non-firm margins
earned in excess of $1,600,000.
In addition to the regulation of its utility businesses, the Company is affected
by other regulations, including pipeline safety requirements of the United
States Department of Transportation, safety regulations under the Occupational
Safety and Health Act, and various state and federal environmental statutes and
regulations. The Company believes that its utility operations are in material
compliance with applicable safety and environmental statutes and regulations.
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 ongoing evaluation of
its operations to identify potential environmental exposures and assure
compliance with regulatory policies and procedures.
The Company is investigating the possibility that the Company or predecessor
companies may have been associated with Manufactured Gas Plant (MGP) sites in
its former 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 distribution service territories certain MGP sites are currently the
subject of governmental actions.
The Company's interstate natural gas transportation operations are subject to
federal, state and local regulations regarding water quality, hazardous and
solid waste disposal and other environmental matters. The Company has identified
environmental impacts at certain sites on its gas transmission systems and has
undertaken cleanup programs at those 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) the
prior use of wastewater collection facilities; and (iv) other on-site disposal
areas. The Company communicated with the United States Environmental Protection
Agency (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. The Company is also subject to various federal, state and local laws
and regulations relating to air quality control. These regulations include rules
relating to regional ozone control and hazardous air pollutants. The regional
ozone control rules are known as State Implementation Plans (SIP) and are
designed to control the release of nitrogen oxide (NOx) compounds. The rules
related to hazardous air pollutants are known as Maximum Achievable Control
Technology (MACT) rules and are the result of the 1990 Clean Air Act Amendments
that regulate the emission of hazardous air pollutants from internal combustion
engines and turbines.
See Item 7. Management's Discussion and Analysis - Other Matters (Cautionary
Statement Regarding Forward-Looking Information) and Note XVIII - Commitments
and Contingencies.
Real Estate
The Company owns certain real estate that is neither material nor critical to
its operations.
Employees
As of July 31, 2004, the Company had 3,006 employees, of whom 2,139 are paid on
an hourly basis and 867 are paid on a salary basis. Of the 2,139 hourly paid
employees, unions represent 61%. Of those employees represented by unions,
Missouri Gas Energy employs 36%, New England Gas Company employs 32%, Panhandle
Energy employs 18% and PG Energy employs 14%.
Persons employed by segment are as follows: Distribution segment--1,862 persons;
Transportation and Storage segment--1,060 persons; All Other subsidiary
operations--20 persons. In addition, the corporate office of Southern Union
employed a total of 64 persons.
Effective May 1, 2004, the Company agreed to five-year contracts with each
bargaining-unit representing Missouri Gas Energy employees.
Effective April 1, 2004, the Company agreed to a three-year contract with a
bargaining unit representing a portion of PG Energy employees. Effective, August
1, 2003, the Company agreed to a three-year contract with another bargaining
unit representing the remaining PG Energy unionized employees.
Effective May 28, 2003, Panhandle Energy agreed to a three-year contract with a
bargaining unit representing Panhandle Energy employees.
During fiscal 2003, the bargaining unit representing certain employees of New
England Gas Company's Cumberland operations (formerly Valley Resources) was
merged with the bargaining unit representing the employees of the Company's Fall
River operations (formerly Fall River Gas). During fiscal 2002, the Company
agreed to five-year contracts with two bargaining units representing employees
of New England Gas Company's Providence operations (formerly ProvEnergy), which
were effective May 2002; a four-year contract with one bargaining unit
representing employees of New England Gas Company's Cumberland operations,
effective May 2002; and a four-year contract with one bargaining unit
representing employees of New England Gas Company's Fall River operations,
effective April 2002; and a one year extension of a bargaining unit representing
certain employees of the Company's Cumberland operations.
Following its acquisition by the Company in June 2003, Panhandle Energy
initiated a workforce reduction initiative designed to reduce the workforce by
approximately 5 percent. The workforce reduction initiative was an involuntary
plan with a voluntary component, and was fully implemented by September 30,
2003.
In August 2001, the Company implemented a corporate reorganization and
restructuring which was initially announced in July 2001 as part of the Cash
Flow Improvement Plan. Actions taken included (i) the offering of voluntary
Early Retirement Programs ("ERPs") in certain of its Distribution segment
operations and (ii) a limited reduction in force ("RIF") within its corporate
operations. ERPs, providing for increased benefits for those electing
retirement, were offered to approximately 325 eligible employees across the
Distribution segment operations, with approximately 59% of such eligible
employees accepting. The RIF was limited solely to certain corporate employees
in the Company's Austin and Kansas City offices where forty-eight employees were
offered severance packages (see Item 7. Management's Discussion and Analysis -
Results of Operations (Business Restructuring Charges)).
The Company believes that its relations with its employees are good. From time
to time, however, the Company may be subject to labor disputes. The Company did
not experience any strikes or work stoppages during fiscal 2004 and 2003. During
fiscal 2002, the Company and one of five bargaining units representing New
England Gas Company employees (comprising approximately 8% of Southern Union's
total workforce at that time) were unable to reach agreement on the renewal of a
contract that expired in January 2002. The resulting work stoppage, which did
not have a material adverse effect on the Company's results of operations,
financial condition or cash flows for fiscal 2002, was settled in May 2002 when
the Company and the bargaining unit agreed to a new five-year contract.
Available Information
The Company files annual, quarterly and special reports, proxy statements and
other information with the Securities and Exchange Commission (SEC). Any
document the Company files with the SEC may be read or copied at the SEC's
public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please
call the SEC at 1-800-SEC-0330 for information on the public reference room. The
Company's SEC filings are also available at the SEC's website at
http://www.sec.gov and through the Company's website at
http://www.southernunionco.com. The information on Southern Union's website is
not incorporated by reference into and is not made a part of this report.
ITEM 2. Properties.
Transportation and Storage
See ITEM 1. Business - Transportation and Storage Segment for information
concerning the general location and characteristics of the important physical
properties and assets of the Transportation and Storage segment.
Distribution
See ITEM 1. Business - Distribution Segment for information concerning the
general location and characteristics of the important physical properties and
assets of the Distribution segment.
Other
Power Corp. retains ownership of two electric power plants that share a site in
Archbald, Pennsylvania. Power Corp. acquired the first plant, a 25-megawatt
cogeneration facility fueled by a combination of natural gas and methane, in
November 1997. During fiscal 2001, Power Corp. constructed an additional
45-megawatt, natural gas-fired plant in a joint venture with Cayuga Energy.
Power Corp. owns 49.9% of the second plant.
ITEM 3. Legal Proceedings.
See Note XVIII - Commitments and Contingencies for a discussion of the Company's
legal proceedings. See ITEM 7. Management's Discussion and Analysis - Other
Matters (Cautionary Statement Regarding Forward-Looking Information).
ITEM 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of security holders of Southern Union
during the quarter ended June 30, 2004.
PART II
ITEM 5. Market for the Registrant's Common Stock and Related Stockholder
Matters.
Market Information
Southern Union's common stock is traded on the New York Stock Exchange under the
symbol "SUG". The high and low sales prices (adjusted for any stock dividends)
for shares of Southern Union common stock since July 1, 2002 are set forth
below:
$/Share
---------------
High Low
------ -----
July 1 to August 16, 2004...................................$ 20.48 $18.00
(Quarter Ended)
June 30, 2004........................................... 20.33 17.98
March 31, 2004.......................................... 18.81 16.90
December 31, 2003....................................... 17.82 15.88
September 30, 2003...................................... 17.00 14.10
(Quarter Ended)
June 30, 2003........................................... 16.19 10.98
March 31, 2003.......................................... 15.62 10.95
December 31, 2002....................................... 15.41 9.21
September 30, 2002...................................... 15.48 9.25
Holders
As of August 16, 2004, there were 6,876 holders of record of Southern Union's
common stock and 81,886,254 shares of Southern Union's common stock outstanding.
The holders of record do not include persons whose shares are held of record by
a bank, brokerage house or clearing agency, but does include any such bank,
brokerage house or clearing agency that is a holder of record. The shares as of
August 16, 2004 reflect the 5% stock dividend distributed on August 31, 2004, as
further discussed below.
On August 16, 2004, 62,294,648 shares of Southern Union's common stock were held
by non-affiliates (any director or executive officer, any of their immediate
family members, or any holder known to be the beneficial owner of 10% or more of
shares outstanding).
Dividends
Provisions in certain of Southern Union's long-term debt and its bank credit
facilities limit the payment of cash or asset dividends on capital stock. Under
the most restrictive provisions in effect, Southern Union may not declare or pay
any cash or asset dividends on its common stock or acquire or retire any of
Southern Union's common stock, unless no event of default exists and the Company
meets certain financial ratio requirements, which presently are met. Southern
Union's ability to pay cash dividends may be limited by debt restrictions at
Panhandle Energy that could limit Southern Union's access to funds from
Panhandle Energy for debt service or dividends.
Southern Union has a policy of reinvesting its earnings in its businesses,
rather than paying cash dividends. Since 1994, Southern Union has distributed an
annual stock dividend of 5%. There have been no cash dividends on its common
stock during this period. On August 31, 2004, July 31, 2003, and July 15, 2002,
the Company distributed its annual 5% common stock dividend to stockholders of
record on August 20, 2004, July 17, 2003, and July 1, 2002, respectively. A
portion of the 5% stock dividend distributed on July 15, 2002 was characterized
as a distribution of capital due to the level of the Company's retained earnings
available for distribution as of the declaration date.
Equity Compensation Plans
Equity compensation plans approved by stockholders include the 2003 Stock and
Incentive Plan, and the 1992 Long-Term Stock Incentive Plan (1992 Plan) in which
options are still outstanding but no shares are available for future grant as
the 1992 Plan expired on July 1, 2002. Under both plans, stock options are
generally issued at the fair market value on the date of grant and typically
vest ratably over five years.
Equity compensation plans not approved by stockholders include the Pennsylvania
Division Stock Incentive Plan and the Pennsylvania Division 1992 Stock Option
Plan which were both assumed by Southern Union upon the November 4, 1999
acquisition of Pennsylvania Enterprises, Inc. Following the acquisition, options
were no longer awarded under these plans.
The following table sets forth, for each type of equity compensation plan, the
number of outstanding options and the number of shares remaining available for
issuance as of June 30, 2004:
Number of Securities
Remaining Available for
Number of Securities Future Issuance Under
to be issued Upon Weighted-Average Equity Compensation
Exercise of Exercise Price of Plans (excluding securities
Plan Category Outstanding Options Outstanding Options reflected in first column)
------------- ------------------- ------------------- --------------------------
Plans approved by shareholders 3,349,921 $ 14.36 6,620,773
Plans not approved by shareholders 664,564 $ 9.70 --
ITEM 6. Selected Financial Data.
As of and for the year ended June 30,
-------------------------------------
2004(a) 2003(a) 2002(b) 2001(c) 2000(d)
------- ------- ------- ------- -------
(dollars in thousands, except per share amounts)
Total operating revenues....................... $ 1,799,974 $ 1,188,507 $ 980,614 $ 1,461,811 $ 566,833
Net earnings (loss):
Continuing operations (e)................. 101,339 43,669 1,520 40,159 (10,251)
Discontinued operations (f)............... -- 32,520 18,104 16,524 20,096
Available for common shareholders......... 101,339 76,189 19,624 57,285 9,845
Net earnings (loss) per diluted common
share (g):
Continuing operations .................... 1.30 .70 .02 .64 (.19)
Discontinued operations................... -- .52 .29 .27 .37
Available for common shareholders......... 1.30 1.22 .31 .91 .18
Total assets................................... 4,572,458 4,590,938 2,680,064 2,907,299 2,021,460
Stockholders' equity........................... 1,261,991 920,418 685,346 721,857 735,455
Short-term debt and capital lease
obligation................................ 99,997 734,752 108,203 5,913 2,193
Long-term debt and capital lease
obligation, excluding current portion..... 2,154,615 1,611,653 1,082,210 1,329,631 733,774
Company-obligated mandatorily
redeemable preferred securities of
subsidiary trust.......................... -- 100,000 100,000 100,000 100,000
Average customers served (h)................... 948,831 945,705 942,849 970,927 605,000
(a) Panhandle Energy was acquired on June 11, 2003 and was accounted for as a
purchase. The Panhandle Energy assets were included in the Company's
Consolidated Balance Sheet at June 30, 2003 and its results of operations
have been included in the Company's Consolidated Statement of Operations
since June 11, 2003. For these reasons, the Consolidated Statement of
Operations for the periods subsequent to the acquisition are not comparable
to the same periods in prior years.
(b) Effective July 1, 2001, the Company has ceased amortization of goodwill
pursuant to the Financial Accounting Standards Board Standard Accounting
for Goodwill and Other Intangible Assets. Goodwill, which was previously
classified on the Consolidated Balance Sheet as additional purchase cost
assigned to utility plant and amortized on a straight-line basis over forty
years, is now subject to at least an annual assessment for impairment by
applying a fair-value based test. Additionally, during fiscal year 2002,
the Company recorded an after-tax restructuring charge of $8,990,000. See
Note VII - Goodwill and Intangibles and Note XIV - Employee Benefits.
(c) The New England Operations, formed through the acquisition of Providence
Energy Corporation and Fall River Gas Company on September 28, 2000, and
Valley Resources, Inc. on September 20, 2000, were accounted for as a
purchase and are included in the Company's Consolidated Balance Sheet at
June 30, 2001. The results of operations for the New England Operations
have been included in the Company's Consolidated Statement of Operations
since their respective acquisition dates. For these reasons, the
Consolidated Statement of Operations for the periods subsequent to the
acquisitions are not comparable to the same periods in prior years.
(d) The Pennsylvania Operations were acquired on November 4, 1999 and were
accounted for as a purchase. The Pennsylvania Operations' assets were
included in the Company's Consolidated Balance Sheet at June 30, 2000 and
its results of operations have been included in the Company's Consolidated
Statement of Operations since November 4, 1999. For these reasons, the
Consolidated Statement of Operations for the periods subsequent to the
acquisition are not comparable to the same periods in prior years.
(e) Net earnings from continuing operations is net of dividends on preferred
stock.
(f) Effective January 1, 2003, the Company sold its Southern Union Gas Company
natural gas operating division and related assets, which have been
accounted for as discontinued operations in the Consolidated Statement of
Operations for the respective periods presented in this document. Net
earnings from discontinued operations do not include any allocation of
interest expense or other corporate costs, in accordance with generally
accepted accounting principles. At the time of the sale, all outstanding
debt of Southern Union Company and subsidiaries was maintained at the
corporate level, and no debt was assumed by ONEOK, Inc. in the sale of the
Texas Operations.
(g) Earnings per share for all periods presented were computed based on the
weighted average number of shares of common stock and common stock
equivalents outstanding during the year adjusted for the 5% stock dividends
distributed on August 31, 2004, July 31, 2003, July 15, 2002, August 30,
2001 and June 30, 2000.
(h) Includes average customers served by continuing operations.
ITEM 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
Management's Discussion and Analysis of Results of Operations and Financial
Condition 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 interstate natural gas
transportation and storage operations are conducted through Panhandle Energy,
which operates more than 10,000 miles of interstate pipelines that transport
natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of
Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions.
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 customers in
Missouri, Pennsylvania, Rhode Island and Massachusetts.
On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy
Corporation for approximately $581,729,000 in cash and 3,000,000 shares of
Southern Union common stock (before adjustment for subsequent stock dividends)
valued at approximately $48,900,000 based on market prices at closing of the
Panhandle Energy acquisition and in connection therewith incurred transaction
costs of approximately $31,922,000. At the time of the acquisition, Panhandle
Energy had approximately $1,157,228,000 of debt principal outstanding that it
retained. The Company funded the cash portion of the acquisition with
approximately $437,000,000 in cash proceeds it received for the January 1, 2003
sale of its Texas operations, approximately $121,250,000 of the net proceeds it
received from concurrent common stock and equity unit offerings (see Note X -
Stockholders' Equity) and with working capital available to the Company. The
Company structured the Panhandle Energy acquisition and the sale of its Texas
operations to qualify as a like-kind exchange of property under Section 1031 of
the Internal Revenue Code of 1986, as amended. The acquisition was accounted for
using the purchase method of accounting in accordance with accounting principles
generally accepted within the United States of America with the purchase price
paid and acquisition costs incurred by the Company allocated to Panhandle
Energy's net assets as of the acquisition date. The Panhandle Energy assets
acquired and liabilities assumed have been recorded at their estimated fair
value as of the acquisition date based on the results of outside appraisals.
Panhandle Energy's results of operations have been included in the Consolidated
Statement of Operations since June 11, 2003. Thus, the Consolidated Statement of
Operations for the periods subsequent to the acquisition is not comparable to
the same periods in prior years.
Panhandle Energy is primarily engaged in the interstate transportation and
storage of natural gas and also provides liquefied natural gas (LNG)
terminalling and regasification services and is subject to the rules and
regulations of the Federal Energy Regulatory Commission (FERC). The Panhandle
Energy entities include Panhandle Eastern Pipe Line Company, LP (Panhandle
Eastern Pipe Line), Trunkline Gas Company, LLC (Trunkline), a wholly-owned
subsidiary of Panhandle Eastern Pipe Line, Sea Robin Pipeline Company (Sea
Robin), a Louisiana joint venture and an indirect wholly-owned subsidiary of
Panhandle Eastern Pipe Line, Trunkline LNG Company, LLC (Trunkline LNG) which is
a wholly-owned subsidiary of Trunkline LNG Holdings, LLC (LNG Holdings), an
indirect wholly-owned subsidiary of Panhandle Eastern Pipe Line and Pan Gas
Storage, LLC (d.b.a. Southwest Gas Storage), a wholly-owned subsidiary of
Panhandle Eastern Pipe Line. Collectively, the pipeline assets include more than
10,000 miles of interstate pipelines that transport natural gas from the Gulf of
Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major
U.S. markets in the Midwest and Great Lakes region. The pipelines have a
combined peak day delivery capacity of 5.4 billion cubic feet (Bcf) per day and
72 Bcf of owned underground storage capacity and 6.3 Bcf of above ground LNG
storage capacity. Trunkline LNG, located on Louisiana's Gulf Coast, operates one
of the largest LNG import terminals in North America, based on current send out
capacity.
Upon acquiring Panhandle Energy it was determined that Panhandle Energy's
operations could not be integrated efficiently into Southern Union, but that a
new operating platform would have to be established. By doing this at Panhandle
Energy, the Company obviated the need for any corporate information technology
allocation and, established a more efficient platform from which to operate all
of the Company's businesses. Direct integration savings of $15,000,000 were
expected from this process of which, substantially, the entire amount has been
achieved to date.
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK, Inc. (ONEOK) for
approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000.
In accordance with accounting principles generally accepted within the United
States of America, the results of operations and gain on sale of the Texas
operations have been segregated and reported as "discontinued operations" in the
Consolidated Statement of Operations and as "assets held for sale" in the
Consolidated Statement of Cash Flows for the respective periods.
Results of Operations
The Company's results of operations are discussed on a consolidated basis and on
a segment basis for each of the two reportable segments. The Company's
reportable segments include the Transportation and Storage segment and the
Distribution segment. Segment results of operations are presented on 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 Note XXI - Reportable Segments.
Consolidated Results
The following table provides selected financial data regarding the Company's
consolidated results of operations for fiscal 2004, 2003 and 2002:
Years Ended June 30,
------------------------------------------------
2004 2003 2002
------------- ------------- -------------
(thousands of dollars)
Operating income:
Distribution segment.......................................... $ 118,894 $ 142,762 $ 135,502
Transportation and storage segment............................ 193,702 9,635 --
All other..................................................... (3,514) 13 --
Business restructuring charges.................................... -- -- (29,159)
Corporate..................................................... (3,555) (10,039) (15,218)
------------- ------------- -------------
Total operating income..................................... 305,527 142,371 91,125
Other income (expenses):
Interest...................................................... (127,867) (83,343) (90,992)
Dividends on preferred securities of subsidiary trust......... -- (9,480) (9,480)
Other, net.................................................... 5,468 18,394 14,278
------------- ------------- -------------
Total other expenses, net.................................. (122,399) (74,429) (86,194)
------------- ------------- -------------
Federal and state income taxes.................................... 69,103 24,273 3,411
------------- ------------- -------------
Net earnings from continuing operations........................... 114,025 43,669 1,520
------------- ------------- -------------
Discontinued operations:
Earnings from discontinued operations before income taxes..... -- 84,773 29,801
Federal and state income taxes................................ -- 52,253 11,697
------------- ------------- -------------
Net earnings from discontinued operations......................... -- 32,520 18,104
------------- ------------- -------------
Net earnings ..................................................... 114,025 76,189 19,624
Preferred stock dividends......................................... (12,686) -- --
------------- ------------- -------------
Net earnings available for common shareholders.................... $ 101,339 $ 76,189 $ 19,624
============= ============= =============
Net Earnings - 2004 Compared to 2003. Southern Union Company's 2004 (fiscal year
ended June 30) net earnings available for common shareholders were $101,339,000
($1.30 per diluted share, hereafter referred to as per share), compared with
$76,189,000 ($1.22 per share) in 2003. The $25,150,000 increase reflects a
$57,670,000 increase in net earnings available for common shareholders from
continuing operations (hereafter referred to as net earnings from continuing
operations) and a $32,520,000 decrease in net earnings from discontinued
operations, as further discussed below.
Net earnings from continuing operations were $101,339,000 ($1.30 per share) in
2004 compared with $43,669,000 ($.70 per share) in 2003. The increase was
primarily due to the following:
o a $184,067,000 increase in operating income from the Transportation and
Storage segment (see Business Segment Results - Transportation and Storage
Segment);
o a $6,484,000 decrease in corporate costs (see Corporate); and
o a $9,480,000 decrease in dividends on preferred securities of subsidiary trust
(see Dividends on Preferred Securities of Subsidiary Trust).
The above items were partially offset by the following:
o a $23,868,000 decrease in operating income from the Distribution segment (see
Business Segment Results - Distribution Segment);
o a $3,527,000 decrease in operating income from subsidiary operations
included in the All Other category (see All Other Operations);
o a $44,524,000 increase in interest expense (see Interest Expense);
o a $12,926,000 decrease in other income (see Other Income (Expense), Net);
o a $44,830,000 increase in income tax expense (see Federal and State Income
Taxes); and
o a $12,686,000 increase in preferred stock dividends (see Preferred Stock
Dividends).
Net earnings from discontinued operations were nil in 2004 compared with
$32,520,000 ($.52 per share) in 2003. The Company sold its Texas operations
effective January 1, 2003 (see Discontinued Operations).
Net Earnings - 2003 Compared to 2002. Southern Union Company's 2003 net earnings
available for common shareholders were $76,189,000 ($1.22 per share), compared
with $19,624,000 ($.31 per share) in 2002. The $56,565,000 increase reflects a
$42,149,000 increase in net earnings from continuing operations and a
$14,416,000 increase in net earnings from discontinued operations, as further
discussed below.
Net earnings from continuing operations were $43,669,000 ($.70 per share) in
2003 compared with $1,520,000 ($.02 per share) in 2002. The increase was
primarily due to the following:
o a $7,260,000 increase in operating income from the Distribution segment (see
Business Segment Results - Distribution Segment);
o a $9,635,000 increase in operating income from the Transportation and Storage
segment (see Business Segment Results - Transportation and Storage Segment);
o a total of $29,159,000 in business restructuring charges, recorded in the
first quarter of the fiscal 2002 with no comparable charge in fiscal 2003
(see Business Restructuring Charges);
o a $5,179,000 decrease in corporate costs (see Corporate);
o a $7,649,000 decrease in interest expense (see Interest Expense); and
o a $4,116,000 increase in other income (see Other Income (Expense), Net).
The above items were partially offset by a $20,862,000 increase in income tax
expense (see Federal and State Income Taxes).
Net earnings from discontinued operations were $32,520,000 ($.52 per share) in
2003 compared with $18,104,000 ($.29 per share) in 2002. The $14,416,000
increase was primarily due to the recording of an $18,928,000 after-tax gain on
the sale of the Texas operations (see Discontinued Operations).
All Other Operations. Operating income from subsidiary operations included in
the All Other category in 2004 decreased by $3,527,000, resulting in a net
operating loss of $3,514,000. The decrease in All Other operating income
primarily reflects a $2,985,000 charge recorded by PEI Power Corporation in 2004
to provide for the estimated future debt service payments in excess of projected
tax revenues for the tax incremental financing obtained for the development of
PEI Power Park.
Business Restructuring Charges. Business reorganization and restructuring
initiatives were commenced in August 2001 as part of a previously announced Cash
Flow Improvement Plan. Actions taken included (i) the offering of voluntary
Early Retirement Programs (ERPs) in certain of its operating divisions and (ii)
a limited reduction in force (RIF) within its corporate offices. ERPs, providing
for increased benefits for those electing retirement, were offered to
approximately 325 eligible employees across the Company's operating divisions,
with approximately 59% of such eligible employees accepting. The RIF was limited
solely to certain corporate employees in the Company's Austin and Kansas City
offices where forty-eight employees were offered severance packages. In
connection with the corporate reorganization and restructuring efforts, the
Company recorded a charge of $30,553,000 during the quarter ended September 30,
2001. This charge was reduced by $1,394,000 during the quarter ended June 30,
2002, as a result of the Company's ability to negotiate more favorable terms on
certain of its restructuring liabilities. The charge included: $16.4 million of
voluntary and accepted ERP's, primarily through enhanced benefit plan
obligations, and other employee benefit plan obligations; $6.8 million of RIF
within the corporate offices and related employee separation benefits; and $6.0
million connected with various business realignment and restructuring
initiatives. All restructuring actions were completed as of June 30, 2002.
Corporate. Operating loss from Corporate operations in 2004 decreased by
$6,484,000, or 65%, to $3,555,000. The decrease in Corporate operating loss
primarily reflects the impact of the direct allocation and recording of various
services provided by Corporate to Panhandle Energy in 2004, that were not
applicable in 2003 due to the timing of the Panhandle Energy acquisition.
Operating loss from Corporate operations in 2003 decreased by $5,179,000, or
34%, to $10,039,000. The decrease in Corporate operating loss primarily reflects
the impact of the previously discussed business reorganization and restructuring
initiatives that were commenced in August 2001.
Interest Expense. Total interest expense in 2004 increased by $44,524,000, or
53%, to $127,867,000. Interest expense in 2004 was impacted by interest expense
on Panhandle Energy debt of $47,628,000 (net of $10,783,000 of amortization of
debt premiums established in purchase accounting related to the Panhandle Energy
acquisition) and by $3,160,000 related to dividends on preferred securities of
subsidiary trust (see Dividends on Preferred Securities of Subsidiary Trust).
This increase was partially offset by decreased interest expense of $4,366,000
on the $311,087,000 bank note (the 2002 Term Note) entered into by the Company
on July 15, 2002 to refinance a portion of the $485,000,000 Term Note entered
into by the Company on August 28, 2000 to (i) fund the cash consideration paid
to stockholders of Fall River Gas, ProvEnergy and Valley Resources, (ii)
refinance and repay long- and short-term debt assumed in the New England
Operations, and (iii) acquisition costs of the New England Operations. This
decrease in the 2002 Term Note interest was due to reductions in LIBOR rates
during fiscal 2004 and the principal repayment of $200,000,000 of the 2002 Term
Note since its inception. Panhandle Energy's debt premium amortization is
expected to be lower in 2005 than during 2004 due to post-acquisition debt
retirements, while cash interest should be lower and partially offset the lower
premium amortization. The average rate of interest on all debt decreased from
5.6% in 2003 to 5.1% in 2004.
Interest expense on short-term debt in 2004 decreased by $627,000, or 7%, to
$8,041,000, primarily due to the decrease in the average amount of short-term
debt outstanding from $223,350,000 to $163,200,000 during the year. The decrease
in the average amount of short-term debt outstanding during 2004 was primarily
due to cash generated from operations, the excess proceeds from capital markets
issuances over the amounts used for the redemption of securities, and the
reduction of the Company's beginning of the year cash balances. Draws on
short-term debt arise as Southern Union is required to make payments to natural
gas suppliers in advance of the receipt of cash payments from the Company's
customers and to fund other working capital requirements, if other funds are not
then available. The average rate of interest on short-term debt decreased from
2.4% to 2.0% in 2004.
Total interest expense in 2003 decreased by $7,649,000, or 8%, to $83,343,000.
Interest expense decreased by $9,181,000 in 2003 on the $311,087,000 2002 Term
Note due to reductions in LIBOR rates during 2003 and the principal repayment of
$100,000,000 of the 2002 Term Note during 2003. The Company recorded $1,760,000
in interest on long-term debt related to the Panhandle Energy properties in
2003.
Interest expense on short-term debt in 2003 increased by $1,481,000, or 21%, to
$8,668,000, primarily due to the increase in the average amount of short-term
debt outstanding from $176,600,000 to $223,350,000 during the year. The increase
in the average amount of short-term debt outstanding during 2003 was primarily
due to (i) higher than normal short-term debt outstanding due to high gas costs
and accounts receivable in 2003 and (ii) the repayment of various principal
amounts of the 2002 Term Note and other long-term debt with borrowings under the
Company's credit facilities. The average rate of interest on short-term debt
decreased from 3.2% to 2.4% in 2003.
Dividends on Preferred Securities of Subsidiary Trust. Dividends on preferred
securities of subsidiary trust in 2004, 2003 and 2002 were nil, $9,480,000 and
$9,480,000, respectively. Effective July 1, 2003, the Company adopted the
Financial Accounting Standards Board (FASB) standard, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity, which
requires dividends on preferred securities of subsidiary trusts to be classified
as interest expense; the reclassification of amounts reported as dividends in
prior periods is not permitted. In accordance with the Statement, $3,160,000 of
dividends on preferred securities of subsidiary trust recorded by the Company
during the period July 1, 2003 to October 31, 2003 were classified as interest
expense in 2004 (see Interest Expense). On October 1, 2003, the Company called
the Subordinated Notes for redemption, and the Subordinated Notes and Preferred
Securities were redeemed on October 31, 2003 (see Note XII - Preferred
Securities).
Other Income (Expense), Net. Other income, net in 2004 was $5,468,000 compared
with $18,394,000 in 2003. Other income in 2004 includes a gain of $6,354,000 on
the early extinguishment of debt and income of $2,230,000 generated from the
sale and/or rental of gas-fired equipment and appliances from various operating
subsidiaries. These items were partially offset by charges of $1,603,000 and
$1,150,000 to reserve for the impairment of Southern Union's investments in a
technology company and in an energy-related joint venture, respectively, and
$836,000 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, net, in 2003 of $18,394,000 includes a gain of $22,500,000 on the
settlement of the Southwest litigation and income of $2,016,000 generated from
the sale and/or rental of gas-fired equipment and appliances. These items were
partially offset by $5,949,000 of legal costs related to the Southwest
litigation and $1,298,000 of selling costs related to the Texas operations'
disposition.
Other income, net, in 2002 of $14,278,000 includes gains of $17,166,000
generated through the settlement of several interest rate swaps, the recognition
of $6,204,000 in previously recorded deferred income related to financial
derivative energy trading activity, a gain of $4,653,000 realized through the
sale of marketing contracts held by Energy Services, income of $2,234,000
generated from the sale and/or rental of gas-fired equipment and appliances, a
gain of $1,200,000 realized through the sale of the propane assets of Energy
Services, $1,004,000 of realized gains on the sale of investment securities, and
power generation and sales income of $971,000. These items were partially offset
by a non-cash charge of $10,380,000 to reserve for the impairment of the
Company's investment in a technology company, $9,100,000 of legal costs
associated with Southwest, and a $1,500,000 loss on the sale of South Florida
Natural Gas and Atlantic Gas Corporation (the Florida Operations).
Federal and State Income Taxes. Federal and state income tax expense from
continuing operations in 2004, 2003 and 2002 was $69,103,000, $24,273,000 and
$3,411,000, respectively. The Company's consolidated federal and state effective
income tax rate was 38%, 36% and 69% in 2004, 2003 and 2002, respectively. The
fluctuation in the effective federal and state income tax rate in 2004 compared
with 2003 is primarily the result of the state income tax effect resulting from
the operations of Panhandle Energy being included in the consolidated results of
the Company for the entire year in 2004. The fluctuation in the effective
federal and state income tax rate in 2003 compared with 2002 is primarily the
result of non-tax deductible write-off of goodwill in 2002 as a result of the
sale of the Florida Operations, along with the change in the level of pre-tax
earnings.
Preferred Stock Dividends. Dividends on preferred securities in 2004, 2003 and
2002 were $12,686,000, nil and nil, respectively. On October 8, 2003, the
Company issued $230,000,000 of 7.55% Non-Cumulative Preferred Stock, Series A to
the public. See ITEM 7. Management's Discussion and Analysis - Financial
Condition.
Discontinued Operations. Net earnings from discontinued operations in 2004, 2003
and 2002 were nil, $32,520,000 and $18,104,000, respectively. The Company
completed the sale of its Texas operations effective January 1, 2003, resulting
in the recording of an after-tax gain on sale of $18,928,000 during 2003 that is
reported in earnings from discontinued operations in accordance with the FASB
standard, Accounting for the Impairment or Disposal of Long-Lived Assets. The
after-tax gain on the sale of the Texas operations was impacted by the
elimination of $70,469,000 of goodwill related to these operations which was
primarily non-tax deductible.
Employees. The Company's continuing operations employed 3,012, 3,041, and 1,855
individuals as of June 30, 2004, 2003 and 2002, respectively. After gas
purchases and taxes, employee costs and related benefits are the Company's most
significant expense. Such expense includes salaries, payroll and related taxes,
and employee benefits such as health, savings, retirement and educational
assistance.
Effective May 1, 2004, the Company agreed to five-year contracts with each
bargaining-unit representing Missouri Gas Energy employees.
Effective April 1, 2004, the Company agreed to a three-year contract with a
bargaining unit representing a portion of PG Energy employees. Effective, August
1, 2003, the Company agreed to a three-year contract with another bargaining
unit representing the remaining PG Energy unionized employees.
Effective May 28, 2003, Panhandle Energy agreed to a three-year contract with a
bargaining unit representing Panhandle Energy employees.
During fiscal 2003, the bargaining unit representing certain employees of New
England Gas Company's Cumberland operations (formerly Valley Resources) was
merged with the bargaining unit representing the employees of the Company's Fall
River operations (formerly Fall River Gas). During fiscal 2002, the Company
agreed to five-year contracts with two bargaining units representing employees
of New England Gas Company's Providence operations (formerly ProvEnergy), which
were effective May 2002; a four-year contract with one bargaining unit
representing employees of New England Gas Company's Cumberland operations,
effective May 2002; and a four-year contract with one bargaining unit
representing employees of New England Gas Company's Fall River operations,
effective April 2002; and a one year extension of a bargaining unit representing
certain employees of the Company's Cumberland operations.
Business Segment Results
Distribution Segment -- The Company's Distribution segment is primarily engaged
in the local distribution of natural gas in Missouri, Pennsylvania, Rhode Island
and Massachusetts. Its operations are conducted through the Company's three
regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas
Company. Collectively, the utility divisions serve over 960,000 residential,
commercial and industrial customers through local distribution systems
consisting of 14,243 miles of mains, 9,605 miles of service lines and 76 miles
of transmission lines. 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. In fiscal 2004, this segment
represented 72 percent of the Company's total operating revenues.
The Company's management is committed to achieving profitable growth of its
utility divisions in an increasingly competitive business environment and to
enhance shareholder value. Management's strategies for achieving these
objectives principally consist of: (i) to focus the divisions in meeting their
allowable rates of returns; (ii) manage capital spending and operating costs
without sacrificing customer safety or quality of service; and (iii) solidify
the Company's relationships with regulatory bodies that oversee the various
operations. Further, when appropriate, management will continue to seek rate
increases within each division. Management develops and continually evaluates
these strategies and their implementation by applying their experience and
expertise in analyzing the energy industry, technological advances, market
opportunities and general business trends. Each of these strategies, as
implemented throughout the Company's existing divisions, reflects the Company's
commitment to its natural gas utility business.
The following table provides summary data regarding the Distribution segment's
results of operations for fiscal 2004, 2003 and 2002:
Years Ended June 30,
------------------------------------------------
2004 2003 2002
------------- ------------- -------------
(thousands of dollars)
Financial Results
Operating revenues................................................ $ 1,304,405 $ 1,158,964 $ 968,933
Cost of gas and other energy...................................... (863,637) (723,719) (568,447)
Revenue-related taxes............................................. (45,395) (40,485) (33,410)
------------- ------------- -------------
Net operating revenues, excluding depreciation and
amortization............................................... 395,373 394,760 367,076
Operating expenses:
Operating, maintenance, and general........................... 194,394 171,463 154,906
Depreciation and amortization................................. 57,601 56,396 53,937
Taxes other than on income and revenues....................... 24,484 24,139 22,731
------------- ------------- -------------
Total operating expense.................................... 276,479 251,998 231,574
------------- ------------- -------------
Operating income........................................... $ 118,894 $ 142,762 $ 135,502
============= ============= =============
Operating Information
Gas sales volumes (MMcf).......................................... 112,271 122,115 101,036
Gas transported volumes (MMcf).................................... 60,848 66,218 65,757
Weather:
Degree Days:
Missouri Gas Energy service territories.................... 4,770 5,105 4,419
PG Energy service territories.............................. 6,240 6,654 5,373
New England Gas Company service territories................ 5,644 6,143 4,980
Percent of 30-year measure:
Missouri Gas Energy service territories.................... 92% 98% 85%
PG Energy service territories.............................. 103% 106% 86%
New England Gas Company service territories................ 102% 107% 85%
Operating Revenues. Operating revenues in 2004 compared with 2003 increased
$145,441,000, or 13%, to $1,304,405,000 while gas purchase and other energy
costs increased $139,918,000, or 19%, to $863,637,000. The increase in both
operating revenues and gas purchase costs between periods was primarily due to a
30% increase in the average cost of gas from $5.93 per thousand cubic feet (Mcf)
in 2003 to $7.69 per Mcf in 2004, which was partially offset by an 8% decrease
in gas sales volumes to 112,271 million cubic feet (MMcf) in 2004 from 122,115
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. The decrease in gas sales volumes is primarily due to warmer weather
in 2004 as compared with 2003 in all of the Company's service territories.
Additionally impacting operating revenues in 2004 was a $4,910,000 increase in
gross receipt taxes primarily due to an increase in gas purchase and other
energy costs. Gross receipt taxes are levied on sales revenues billed to the
customers and remitted to the various taxing authorities.
Gas purchase costs generally do not directly affect earnings since these costs
are passed on to customers pursuant to purchase gas adjustment (PGA) clauses.
Accordingly, while changes in the cost of gas may cause the Company's operating
revenues to fluctuate, net operating revenues are generally not affected by
increases or decreases in the cost of gas. Increases in gas purchase costs
indirectly affect earnings as the customer's bill increases, usually resulting
in increased bad debt and collection costs being recorded by the Company.
Gas transportation volumes in 2004 decreased 5,370 MMcf, or 8%, to 60,848 MMcf
at an average transportation rate per Mcf of $.58 in 2003 and $.57 in 2004. Gas
transportation volumes were impacted by certain customers utilizing alternative
energy sources such as fuel oil, customer closure of certain facilities and
various customers reducing production.
Operating revenues in 2003 compared with 2002 increased $190,031,000, or 20%, to
$1,158,964,000 while gas purchase and other energy costs increased $155,272,000,
or 27%, to $723,719,000. The increase in both operating revenues and gas
purchase and other energy costs between periods was primarily due to a 21%
increase in gas sales volumes to 122,115 MMcf in 2003 from 101,036 MMcf in 2002
and by a 5% increase in the average cost of gas from $5.63 per Mcf in 2002 to
$5.93 per Mcf in 2003. The increase in gas sales volume is primarily due to
colder weather in 2003 as compared with 2002 in all of the Company's service
territories. The increase in the average cost of gas is due to increases in
average spot market gas prices throughout the Company's distribution system as a
result of seasonal impacts on demands for natural gas as well as the competitive
pricing occurring within the entire energy industry. Additionally impacting
operating revenues in 2003 was a $7,076,000 increase in gross receipt taxes
primarily due to an increase in gas purchase and other energy costs.
Gas transportation volumes in 2003 increased 461 MMcf to 66,218 MMcf at an
average transportation rate per Mcf of $.56 in 2002 and $.58 in 2003.
Net Operating Revenues. Net operating revenues (which the Company formerly
referred to as operating margin) in 2004 increased by $613,000, compared with an
increase of $27,684,000 in 2003. Net operating revenues and earnings are
primarily dependent upon gas sales volumes and gas service rates. The level of
gas sales volumes is sensitive to the variability of the weather as well as the
timing of acquisitions. Sales volumes, which benefited from colder-than-normal
weather in 2004 and 2003 in the Company's Pennsylvania and New England service
territories, were negatively impacted by unusually mild temperatures in all of
the Company's service territories in 2002. Net operating revenues in 2003 were
impacted by the RIPUC Settlement Offer of $5,227,000 filed by New England Gas
Company related to excess revenues earned during the 21-month period covered by
the Energize Rhode Island Extension settlement agreement. Missouri, Pennsylvania
and New England accounted for 40%, 21% and 39%, respectively, of the segment's
net operating revenues in 2004 and 37%, 24% and 39%, respectively, in 2003.
Customers. The average number of customers served in 2004, 2003 and 2002 was
948,300, 944,657 and 935,229, respectively. Changes in customer totals between
years primarily reflect growth, net of attrition, throughout the Company's
service territories. Missouri Gas Energy served 494,875 customers in central and
western Missouri. PG Energy served 157,864 customers in northeastern and central
Pennsylvania, and New England Gas Company served 297,239 customers in Rhode
Island and Massachusetts during 2004.
Operating Expenses. Operating, maintenance and general expenses in 2004
increased $22,931,000, or 13%, to $194,394,000. The increase is primarily due to
$8,917,000 of increased pension and other post retirement benefits costs
primarily due to the impact of stock market volatility on plan assets,
$6,371,000 of increased bad debt expense resulting from higher customer
receivables due to higher gas prices, $1,596,000 of increased medical costs,
$1,468,000 of increased insurance premiums and increased employee payroll costs
due to general wage increases and increased overtime due to system maintenance
and Sarbanes-Oxley Section 404 documentation procedures.
Depreciation and amortization expense in 2004 increased $1,205,000 to
$57,601,000. The increase was primarily due to normal growth in plant.
Operating, maintenance and general expenses in 2003 increased $16,557,000, or
11%, to $171,463,000. The increase is primarily due to $6,370,000 of increased
pension and other postretirement benefit costs as a result of volatility in the
stock markets, $4,265,000 of increased insurance expense, and $3,547,000 of
increased bad debt expense resulting from higher customer receivables due to
higher gas prices and colder weather in 2003. The Company also experienced
increases in employee payroll and other operating and maintenance costs as a
result of the colder weather in 2003. These items were partially offset by
realized savings in operating costs from the Cash Flow Improvement Plan (see
Business Restructuring Charges).
Depreciation and amortization expense in 2003 increased $2,459,000 to
$56,396,000. The increase was primarily due to normal growth in plant.
Taxes other than on income and revenues, principally consisting of property,
payroll and state franchise taxes increased $1,408,000 to $24,139,000 in 2003,
primarily due to an increase in state franchise taxes.
Transportation and Storage Segment -- The Transportation and Storage segment is
primarily engaged in the interstate transportation and storage of natural gas in
the Midwest and Southwest, and also provides LNG terminalling and regasification
services. Its operations are conducted through Panhandle Energy, which the
Company acquired on June 11, 2003. In fiscal 2004, this segment represented 27
percent of the Company's total operating revenues.
Panhandle Energy operates a large natural gas pipeline network, consisting of
more than 10,000 miles of pipeline with approximately 87 Bcf of total available
storage, 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 results of operations from Panhandle Energy have been included in the
Consolidated Statement of Operations since June 11, 2003. The following table
provides summary data regarding the Transportation and Storage segment's results
of operations for fiscal 2004 and 2003 (from June 12 to June 30, 2003).
June 12, 2003
Year Ended to
June 30, 2004 June 30, 2003
------------- -------------
(thousands of dollars)
Financial Results
Natural gas transportation and storage revenues................... $ 423,755 $ 20,601
LNG terminalling revenues......................................... 57,988 3,244
Other revenues .................................................. 9,340 684
----------------- -----------------
Total operating revenues...................................... 491,083 24,529
Operating expenses:
Operating, maintenance, and general........................... 210,105 10,102
Depreciation and amortization................................. 59,988 3,197
Taxes other than on income and revenues....................... 27,288 1,595
----------------- -----------------
Total operating expense.................................... 297,381 14,894
----------------- -----------------
Operating income........................................... $ 193,702 $ 9,635
================= =================
Operating Information
Volumes transported (TBtu)........................................ 1,321 69
As a result of the acquisition, Panhandle Energy's assets acquired and
liabilities assumed were recorded at estimated fair value as of the acquisition
date based on the results of outside appraisals. The most significant impact of
recording the assets and liabilities at fair value going forward, as compared to
pre-acquisition operations, are expected to be higher depreciation expense due
to the step-up of depreciable assets, assignment of purchase price to certain
amortizable intangible assets, and lower interest costs (though not cash
payments) for the remaining life of debt due to its revaluation and related debt
premium amortization.
Liquidity and Capital Resources
Operating Activities. The seasonal nature of Southern Union's business results
in a high level of cash flow needs to finance gas purchases and other energy
costs, outstanding customer accounts receivable and certain tax payments.
Additionally, significant cash flow needs may be required to finance current
debt service obligations. To provide these funds, as well as funds for its
continuing construction and maintenance programs, the Company has historically
used cash flows from operations and its credit facilities. Because of available
credit and the ability to obtain various types of market financing, combined
with anticipated cash flows from operations, management believes it has adequate
financial flexibility and access to financial markets to meet its short-term
cash needs.
The Company has increased the scale of its natural gas transportation, storage
and distribution operations and the size of its customer base by pursuing and
consummating business acquisitions. On June 11, 2003, the Company acquired
Panhandle Energy (see Note II -- Acquisitions and Sales). Acquisitions require a
substantial increase in expenditures that may need to be financed through cash
flow from operations or future debt and equity offerings. The availability and
terms of any such financing sources will depend upon various factors and
conditions such as the Company's combined cash flow and earnings, the Company's
resulting capital structure, and conditions in the financial markets at the time
of such offerings. Acquisitions and financings also affect the Company's
combined results due to factors such as the Company's ability to realize any
anticipated benefits from the acquisitions, successful integration of new and
different operations and businesses, and effects of different regional economic
and weather conditions. Future acquisitions or related acquisition financing or
refinancing may involve the issuance of shares of the Company's common stock,
which could have a dilutive effect on the then-current stockholders of the
Company. See Item 7. Management's Discussion and Analysis - Other Matters
Cautionary Statement Regarding Forward-Looking Information.
Cash flows provided by operating activities were $341,050,000 in 2004 compared
with cash flows provided by operating activities of $55,696,000 in 2003 and
$273,616,000 for 2002. Cash flows provided by operating activities before
changes in operating assets and liabilities for 2004 were $306,675,000 compared
with $147,061,000 and $177,715,000 for 2003 and 2002, respectively. Changes in
operating assets and liabilities provided cash of $34,375,000 in 2004. Changes
in operating assets and liabilities used cash of $91,365,000 in 2003 and
provided cash of $95,901,000 in 2002. The unusually high accounts receivable
balance that occurred due to high gas costs during both 2004 and 2003, the
normal delay in the recovery of deferred gas purchase costs due to the
regulatory lag in passing along such changes in purchased gas costs to customers
and funds expended for replenishing natural gas stored in inventory in greater
volumes and at higher rates, impacted working capital in both 2004 and 2003.
At June 30, 2004, 2003 and 2002, the Company's primary source of liquidity
included borrowings available under the Company's credit facilities. 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 Long-Term Facility replaced the Company's $150,000,000 and $225,000,000
credit facilities that expired on April 1, 2004 and May 29, 2004, respectively.
The Company has additional availability under uncommitted line of credit
facilities (Uncommitted Facilities) with various banks. Borrowings under the
Long-Term Facility are available for Southern Union's working capital, letter of
credit requirements and other general corporate purposes. 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 June 30, 2004, the commitment fees
were an annualized 0.15%. The Long-Term Facility requires the Company to meet
certain covenants in order for the Company to be able to borrow under that
agreement. A balance of $21,000,000 and $251,500,000 was outstanding under the
Company's credit facilities at June 30, 2004 and 2003, respectively. As of
August 16, 2004, there was a balance of $79,500,000 outstanding under the
Long-Term Facility.
The Company leases certain facilities, equipment and office space under
cancelable and noncancelable operating leases. The minimum annual rentals under
operating leases for the next five years ending June 30 are as follows:
2005--$17,777,000; 2006--$14,708,000; 2007--$13,970,000; 2008--$10,018,000;
2009--$6,549,000 and thereafter $8,102,000. The Company is also committed under
various agreements to purchase certain quantities of gas in the future. At June
30, 2004, the Company's Distribution segment has purchase commitments for
natural gas transportation services, storage services and certain quantities of
natural gas at a combination of fixed, variable and market-based prices that
have an aggregate value of approximately $1,099,972,000. The Company's purchase
commitments may be extended over several years depending upon when the required
quantity is purchased. The Company has purchase gas tariffs in effect for all
its utility service areas that provide for recovery of its purchase gas costs
under defined methodologies and the Company believes that all costs incurred
under such commitments will be recovered through its purchase gas tariffs.
Investing Activities. Cash flow used in investing activities increased
$35,649,000 to $227,009,000 in 2004. Cash flow used in investing activities in
2003 increased $152,134,000 to $191,360,000. Investing activity cash flow was
primarily affected by additions to property, plant and equipment, acquisition
and sales of operations, and the settlement of interest rate swaps.
During 2004, 2003 and 2002, the Company expended $226,053,000, $79,730,000, and
$70,698,000, respectively, for capital expenditures excluding acquisitions. The
Transportation and Storage segment expended $131,378,000 and $5,128,000 for
capital expenditures in 2004 and 2003 (from June 12 to June 30, 2003),
respectively. Included in these capital expenditures were a total of $67,087,000
and $1,166,000 relating to the LNG terminal Phase I and Phase II expansions and
the Trunkline 30-inch diameter, 23-mile natural gas pipeline loop from the LNG
terminal in 2004 and 2003, respectively. The remaining capital expenditures for
the last three years primarily related to Distribution segment system
replacement and expansion. Included in these capital expenditures were
$6,878,000, $9,094,000, and $7,860,000 for the Missouri Gas Energy Safety
Program in 2004, 2003 and 2002, respectively. Cash flow provided by operations
has historically been utilized to finance capital expenditures and is expected
to be the primary source for future capital expenditures.
In June 2003, Southern Union acquired Panhandle Energy for approximately
$581,729,000 in cash plus 3,000,000 shares of Southern Union common stock
(before adjustment for any subsequent stock dividends). On the date of
acquisition, Panhandle Energy had approximately $60,000,000 in cash and cash
equivalents.
In January 2003, the Company completed the sale of its Southern Union Gas
natural gas operating division and related assets for approximately $437,000,000
in cash resulting in a pre-tax gain of $62,992,000. During 2003 and 2002, the
Company expended $13,410,000 and $23,215,000, respectively, for capital
expenditures relating to the assets of these operations which have been
classified as held for sale.
During 2004 and 2002, the Company sold non-core subsidiaries and assets which
generated proceeds of $2,175,000 and $40,935,000, respectively, resulting in a
net pre-tax loss of $1,150,000 in 2004 and net pre-tax gains of $4,914,000 in
2002.
In September 2001, the settlement of three interest rate swaps which the Company
had negotiated in July and August of 2001 and which were not designated as
hedges, resulted in a pre-tax gain and cash flow of $17,166,000.
The Company estimates expenditures associated with the Phase I and Phase II LNG
terminal expansions and the Trunkline 30-inch diameter, 23-mile natural gas
pipeline loop from the LNG terminal, excluding capitalized interest, to be
$172,947,000 over the next 3 fiscal years. These estimates were developed for
budget planning purposes and are subject to revision.
On June 24, 2004, CCE Holdings, LLC (CCE Holdings), a joint venture of the
Company and its equity partner, GE Commercial Finance Energy Financial Services,
entered into a Purchase Agreement to acquire for cash 100% of the equity
interests of CrossCountry Energy, LLC (CrossCountry) from Enron Corp. and its
affiliates for a total transaction value of approximately $2,350,000,000,
including assumed debt. The Purchase Agreement was granted "Stalking Horse"
status by the United States Bankruptcy Court for the Southern District of New
York by an Order entered June 24, 2004, which Order set forth certain bid
procedures by which third-parties may submit higher and/or better offers through
a court mandated auction process. Third-party bids had to be submitted by August
23, 2004 in order to be eligible to participate in the September 1, 2004
auction. If CCE Holdings is the successful bidder, the closing of the
acquisition will then be subject to approval by certain state regulatory bodies,
in addition to satisfaction of additional closing conditions. Closing is
anticipated to occur no later than December 17, 2004. If CCE Holdings is not the
successful bidder, approximately $3,890,000 of acquisition-related costs
incurred by the Company in fiscal 2004 and included in the Consolidated Balance
Sheet at June 30, 2004, would be expensed in fiscal 2005.
CrossCountry holds interests in and operates Transwestern Pipeline Company
(Transwestern), Citrus Corp. (Citrus) and Northern Plains Natural Gas Company
(Northern Plains). The pipeline system owned or operated by CrossCountry is
comprised of approximately 9,700 miles of pipeline and approximately 8.5 Bcf per
day of natural gas capacity. Transwestern owns and operates an approximately
2,400-mile pipeline that transports natural gas from the San Juan, Anadarko and
Permian Basins to markets in the Mid-Continent, Texas, Arizona, New Mexico and
California. Its bi-directional flow capabilities provide flexibility to adapt
rapidly to regional demand. Its customers include local distribution companies,
producers, marketers, electric power generators and industrial end-users. Citrus
owns Florida Gas Transmission (FGT) - an approximately 5,000-mile natural gas
pipeline extending from south Texas to south Florida with mainline capacity of
2.1 Bcf per day. FGT has access to diverse natural gas supplies from the Gulf of
Mexico, Texas and Louisiana. With over 240 delivery points and delivery
connections to more than 50 natural gas fired electric generation plants, FGT
serves the rapidly growing Florida peninsula. Its customers include electric
utilities, independent power producers, co-generation facilities, municipal
generators and local distribution companies. Northern Plains holds ownership
interests in Northern Border Pipeline Company, Midwestern Gas Transmission
Company, Viking Gas Transmission Company and Guardian Pipeline, LLC.
Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in a major gas
safety program in its service territories (Missouri Gas Energy Safety Program).
This program includes replacement of company and customer owned gas service and
yard lines, the movement and resetting of meters, the replacement of cast iron
mains and the replacement and cathodic protection of bare steel mains. In
recognition of the significant capital expenditures associated with this safety
program, the MPSC permits the deferral, and subsequent recovery through rates,
of depreciation expense, property taxes and associated carrying costs. The
continuation of the Missouri Gas Energy Safety Program will result in
significant levels of future capital expenditures. The Company estimates
incurring capital expenditures of $10,400,000 in 2005 related to this program
and approximately $157,300,000 over the remaining life of the program of 15
years.
Financing Activities. Cash flow used in financing activities was $181,067,000 in
2004 compared to cash flow provided by financing activities of $222,661,000 in
2003 and cash flow used in financing activities of $235,609,000 in 2002.
Financing activity cash flow changes were primarily due to the net impact of
acquisition financing, repayment and issuance of debt, net activity under the
revolving credit facilities, issuance of preferred stock and the redemption of
Preferred Securities of Subsidiary Trust. As a result of these financing
transactions, the Company's total debt to total capital ratio at June 30, 2004
was 64.0%, compared with 69.7% and 60.3% at June 30, 2003 and 2002,
respectively. The Company's effective debt cost rate under the current debt
structure is 5.45% (which includes interest and the amortization of debt
issuance costs and redemption premiums on refinanced debt).
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, pending
the repayment of the $52,455,000 principal amount of Panhandle Energy's 7.875%
Senior Notes due 2004 that matured on August 15, 2004.
On October 8, 2003, the Company issued 920,000 shares of its 7.55% Noncumulative
Preferred Stock, Series A (Liquidation Preference $250 Per Share) to the public
through the issuance of 9,200,000 Depositary Shares, each representing a
one-tenth interest in a 7.55% Noncumulative Preferred Stock, Series A share at
the public offering price of $25.00 per share, or $230,000,000 in the aggregate.
After the payment of issuance costs, including underwriting discounts and
commissions, the Company realized net proceeds of $223,410,000. The total net
proceeds were used to repay debt under the Company's revolving credit
facilities. The issuance of this Preferred Stock and use of proceeds is
continued evidence of the Company's commitment to the rating agencies to
strengthen the Company's balance sheet and solidify its current investment grade
status.
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. 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
previously discussed.
In July 2003, Panhandle Energy announced a tender offer for any and all of the
$747,370,000 outstanding principal amount of five of its series of senior notes
outstanding at that point in time (the Panhandle Tender Offer) and also called
for redemption all of the outstanding $134,500,000 principal amount of its two
series of debentures that were outstanding (the Panhandle Calls). Panhandle
Energy repurchased approximately $378,257,000 of the principal amount of its
outstanding debt through the Panhandle Tender Offer for total consideration of
approximately $396,445,000 plus accrued interest through the purchase date.
Panhandle Energy also redeemed approximately $134,500,000 of debentures through
the Panhandle Calls for total consideration of $139,411,000, plus accrued
interest through the redemption dates. As a result of the Panhandle Tender
Offer, the Company has recorded a pre-tax gain on the extinguishment of debt of
$6,354,000 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 June 11, 2003, the Company issued 9,500,000 shares of common stock at the
public offering price of $16.00 per share. After underwriting discounts and
commissions, the Company realized net proceeds of $146,700,000. The Company
granted the underwriters a 30-day over-allotment option to purchase up to an
additional 1,425,000 shares of the Company's common stock at the same price,
which was exercised on June 11, 2003, resulting in additional net proceeds to
the Company of $22,000,000.
Also on June 11, 2003, the Company issued 2,500,000 equity units at a public
offering price of $50 per unit, resulting in net proceeds to the Company, after
underwriting discounts and commissions, of $121,300,000. Each equity unit
consists of a stock purchase contract for the purchase of shares of the
Company's common stock and, initially, a senior note due August 16, 2006, issued
pursuant to the Company's existing Indenture. The equity units carry a total
annual coupon of 5.75% (2.75% annual face amount of the senior notes plus 3.0%
annual contract adjustment payments). Each stock purchase contract issued as a
part of the equity units carries a maximum conversion premium of up to 22% over
the $16.00 issuance price (before adjustment for subsequent stock dividends) of
the Company's common shares that were sold on June 11, 2003, as discussed
previously. The present value of the equity units contract adjustment payments
was initially charged to shareholders' equity, with an offsetting credit to
liabilities. The liability is accreted over three years by interest charges to
the Consolidated Statement of Operations. Before the issuance of the Company's
common stock upon settlement of the purchase contracts, the purchase contracts
will be reflected in the Company's diluted earnings per share calculations using
the treasury stock method.
In connection with the acquisition of the New England Operations, the Company
entered into a $535,000,000 Term Note on August 28, 2000 to fund (i) the cash
portion of the consideration to be paid to Fall River Gas' stockholders; (ii)
the all cash consideration to be paid to the ProvEnergy and Valley Resources
stockholders, (iii) repayment of approximately $50,000,000 of long- and
short-term debt assumed in the New England mergers, and (iv) related acquisition
costs. The Term Note, which initially expired on August 27, 2001, was extended
through August 26, 2002. On July 16, 2002, the Company repaid the Term Note with
the proceeds from the issuance of a $311,087,000 Term Note dated July 15, 2002
(the 2002 Term Note) and borrowings under its revolving credit facilities. The
2002 Term Note is held by a syndicate of sixteen banks, led by JPMorgan Chase
Bank, as Agent. Eleven of the sixteen banks were also among the lenders of the
Term Note. The 2002 Term Note carries a variable interest rate that is tied to
either the LIBOR or prime interest rates at the Company's option. The interest
rate spread over the LIBOR rate varies with the credit rating of the Senior
Notes by Standard and Poor's Rating Information Service (S&P) and Moody's
Investor Service, Inc. (Moody's), and is currently LIBOR plus 105 basis points.
As of June 30, 2004, a balance of $111,087,000 was outstanding on this 2002 Term
Note at an effective interest rate of 2.42%. The 2002 Term Note requires
semi-annual principal repayments on February 15th and August 15th of each year,
with payments of $35,000,000 each being due February 15, 2005 and August 15,
2005. The remaining principal amount of $41,087,000 is due August 26, 2005. No
additional draws can be made on the 2002 Term Note. See Item 7. Management's
Discussion and Analysis - Quantitative and Qualitative Disclosures About Market
Risk.
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 only settle its obligation under the
forward sale agreements through the physical delivery of shares if it is
successful in its attempt to acquire CrossCountry Energy, LLC (see Item 7.
Management's Discussion and Analysis - Liquidity and Capital Resources
(Investing Activities)).
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 August 16, 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.
The Company's ability to arrange financing, including refinancing, and its cost
of capital are dependent on various factors and conditions, including: general
economic and capital market conditions; maintenance of acceptable credit
ratings; credit availability from banks and other financial institutions;
investor confidence in the Company, its competitors and peer companies in the
energy industry; market expectations regarding the Company's future earnings and
probable cash flows; market perceptions of the Company's ability to access
capital markets on reasonable terms; and provisions of relevant tax and
securities laws.
On July 3, 2003, Moody's changed its credit rating on the Company's senior
unsecured debt to Baa3 with a negative outlook from Baa3 with a stable outlook.
The Company's senior unsecured debt is currently rated BBB by S&P, a rating that
it has held since March 2003 when it was downgraded from BBB+. S&P changed its
outlook from stable to negative on March 12, 2004. Although no further
downgrades are anticipated, such an event would not be expected to have a
material impact on the Company. The Company is not party to any lending
agreements that would accelerate the maturity date of any obligation due to a
failure to maintain any specific credit ratings.
The Company had standby letters of credit outstanding of $58,566,000 at June 30,
2004 and $7,761,000 at June 30, 2003, which guarantee payment of insurance
claims and other various commitments.
Other Matters
Stock Splits and Dividends. On August 31, 2004, July 31, 2003 and July 15, 2002,
Southern Union distributed a 5% common stock dividend to stockholders of record
on August 20, 2004, July 17, 2003 and July 1, 2002, respectively. A portion of
the July 15, 2002, 5% stock dividend was characterized as a distribution of
capital due to the level of the Company's retained earnings available for
distribution as of the declaration date. Unless otherwise stated, all per share
data included herein and in the accompanying Consolidated Financial Statements
and Notes thereto have been restated to give effect to the stock dividends.
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 19% of total operating revenues in fiscal 2004. This
included sales to Proliance Energy, LLC, a nonaffiliated local distribution
company and gas marketer, which accounted for 17% of segment operating revenues;
sales to BG LNG Services, a nonaffiliated gas marketer, which accounted for 16%
of segment operating revenues; and sales to CMS Energy Corporation, Panhandle
Energy's former parent, which accounted for 11% of segment operating revenues.
No other customer accounted for 10% or more of the Transportation and Storage
segment operating revenues, and no single customer or group of customers under
common control accounted for ten percent or more of the Company's total
operating revenues in 2004.
Off-Balance Sheet Arrangements and Aggregate Contractual Obligations. As of June
30, 2004, the Company had guarantees related to PEI Power and Advent Network,
Inc. (in which Southern Union has an equity interest) of $8,710,000 and
$4,000,000, respectively, letters of credit related to insurance claims and
other commitments of $58,566,000 and surety bonds related to construction or
repair projects of approximately $2,300,000. The Company believes that the
likelihood of having to make payments under the letters of credit or the surety
bonds is remote, and therefore has made no provisions for making payments under
such instruments.
The following table summarizes the Company's expected contractual obligations by
payment due date as of June 30, 2004:
Contractual Obligations (thousands of dollars)
--------------------------------------------------------------------------------
2010 and
Total 2005 2006 2007 2008 2009 thereafter
----------- ---------- -------- --------- --------- -------- -----------
Long-term debt,
including capital leases (1) (2)......... $ 2,243,374 $ 99,997 $ 90,475 $ 565,718 $ 1,648 $301,646 $1,183,890
Short-term borrowing,
including credit facilities (1).......... 21,000 21,000 -- -- -- -- --
Gas purchases (3) .......................... 1,099,972 266,023 196,081 158,678 141,508 127,461 210,221
Missouri Gas Energy Safety Program.......... 167,733 10,420 10,524 10,630 10,736 10,843 114,580
Storage contracts (4)....................... 447,389 79,790 68,538 63,316 53,075 49,015 133,655
LNG facilities and pipeline expansion....... 172,947 144,789 26,821 1,337 -- -- --
Operating lease payments.................... 71,124 17,777 14,708 13,970 10,018 6,549 8,102
Interest payments on debt................... 1,718,510 125,391 122,380 111,114 102,288 89,035 1,168,302
Benefit plan contributions.................. 25,657 25,657 -- -- -- -- --
Non-trading derivative liabilities.......... 19,405 6,461 6,838 6,106 -- -- --
----------- ---------- -------- --------- --------- -------- ----------
Total contractual cash obligations....... $ 5,987,111 $ 797,305 $536,365 $ 930,869 $ 319,273 $ 584,549 $2,818,750
=========== ========== ======== ========= ========= ========= ==========
- ---------------------------------
(1) The Company is party to certain debt agreements that contain certain
covenants that if not satisfied would be an event of default that would
cause such debt to become immediately due and payable. Such covenants
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.
See Note XIII - Debt and Capital Lease.
(2) The long-term debt cash obligations exclude $16,199,000 of unamortized debt
premium as of June 30, 2004. (3) The Company has purchase gas tariffs in
effect for all its utility service areas that provide for recovery of
its purchase gas costs under defined methodologies.
(4) Charges for third party storage capacity.
Cash Management. On October 25, 2003, FERC issued the final rule in Order No.
634-A on the regulation of cash management practices. Order No. 634-A requires
all FERC-regulated entities that participate in cash management programs (i) to
establish and file with FERC for public review written cash management
procedures including specification of duties and responsibilities of cash
management program participants and administrators, specification of the methods
for calculating interest and allocation of interest income and expenses, and
specification of any restrictions on deposits or borrowings by participants, and
(ii) to document monthly cash management activity. In compliance with FERC Order
No. 634-A, Panhandle Energy filed its cash management plan with FERC on December
11, 2003.
Contingencies. 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 distribution service territories certain MGP sites are currently the
subject of governmental actions. See Item 7. Management's Discussion and
Analysis - Other Matters (Cautionary Statement Regarding Forward-Looking
Information) and Note XVIII - Commitments and Contingencies.
The Company's interstate natural gas transportation operations are subject to
federal, state and local regulations regarding water quality, hazardous and
solid waste disposal and other environmental matters. The Company has identified
environmental impacts at certain sites on its gas transmission systems and has
undertaken cleanup programs at those 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) the
prior use of wastewater collection facilities; and (iv) other on-site disposal
areas. The Company communicated with the United States Environmental Protection
Agency (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. The Company is also subject to various federal, state and local laws
and regulations relating to air quality control. These regulations include rules
relating to regional ozone control and hazardous air pollutants. The regional
ozone control rules are known as State Implementation Plans (SIP) and are
designed to control the release of NOx compounds. The rules related to hazardous
air pollutants are known as Maximum Achievable Control Technology (MACT) rules
and are the result of the 1990 Clean Air Act Amendments that regulate the
emission of hazardous air pollutants from internal combustion engines and
turbines. See Item 7. Management's Discussion and Analysis - Other Matters
(Cautionary Statement Regarding Forward-Looking Information) and Note XVIII -
Commitments and Contingencies.
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, 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.
On May 31, 2002, the staff of the MPSC recommended that the Commission disallow
approximately $15 million in gas costs incurred during the period July 1, 2000
through June 30, 2001. Missouri Gas Energy filed its response in opposition to
the Staff's recommendation on July 11, 2002, vigorously disputing the Commission
staff's assertions. Missouri Gas Energy intends to vigorously defend itself in
this proceeding. This matter went into recess following a hearing in May of
2003. Following the May hearing, the Commission staff reduced its disallowance
recommendation to approximately $9.3 million. The hearing concluded in November
2003 and the matter 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 $5.9 million, $5.9
million and $4.3 million, respectively, in gas costs incurred during the period
July 1, 1999 through June 30, 2000, July 1, 1998 through June 30, 1999, and July
1, 1997 through June 30, 1998, respectively. The basis of these proposed
disallowances appears to be the same as was rejected by the Commission through
an order dated March 12, 2002, applicable to the period July 1, 1996 through
June 30, 1997. MGE intends to vigorously defend itself in these proceedings. On
November 4, 2002, the Commission adopted a procedural schedule calling for a
hearing in this matter some time after May 2003. No date for this hearing has
been set.
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 Energy's pipelines, with respect to certain
producer contract settlements, may be contractually required to reimburse or, in
some instances, to indemnify producers against such royalty claims. The
potential liability of the producers to the government and of the pipelines to
the producers involves complex issues of law and fact which are likely to take
substantial time to resolve. If required to reimburse or indemnify the
producers, Panhandle Energy's pipelines may file with 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.
Southern Union and its subsidiaries are parties to other legal proceedings that
management considers to be normal actions to which an enterprise of its size and
nature might be subject, and not to be material to the Company's overall
business or financial condition, results of operations or cash flows. (See Note
XVIII - Commitments and Contingencies.)
Inflation. The Company believes that inflation has caused and will continue to
cause increases in certain operating expenses and has required and will continue
to require assets to be replaced at higher costs. The Company continually
reviews the adequacy of its rates in relation to the increasing cost of
providing service and the inherent regulatory lag in adjusting those rates.
Regulatory. The majority of the Company's business activities are subject to
various regulatory authorities. The Company's financial condition and results of
operations have been and will continue to be dependent upon the receipt of
adequate and timely adjustments in rates.
On November 4, 2003, Missouri Gas Energy filed a request with the MPSC to
increase base rates by $44,800,000 and to implement a weather mitigation rate
design that would significantly reduce the impact of weather-related
fluctuations on customer bills. On January 30, 2004, Missouri Gas Energy filed
an updated claim which raised the amount of the base rate increase request to
$54,200,000. As of July 19, 2004, upon the close of the record and reflecting
settlement of a number of issues, MGE's request stood at approximately
$39,000,000 and the MPSC Staff's recommendation stood at approximately
$13,000,000. Statutes require that the MPSC reach a decision in the case within
an eleven-month period from the original filing date. It is not presently
possible to determine what action the MPSC will ultimately take with respect to
this rate increase request.
On May 22, 2003, the RIPUC approved a Settlement Offer filed by New England Gas
Company related to the final calculation of earnings sharing for the 21-month
period covered by the Energize Rhode Island Extension settlement agreement. This
calculation generated excess revenues of $5,277,000. The net result of the
excess revenues and the Energize Rhode Island weather mitigation and non-firm
margin sharing provisions was the crediting to customers of $949,000 over a
twelve-month period starting July 1, 2003.
On May 24, 2002, the RIPUC approved a settlement agreement between the New
England Gas Company and the Rhode Island Division of Public Utilities and
Carriers. The settlement agreement resulted in a $3,900,000 decrease in base
revenues for New England Gas Company's Rhode Island operations, a unified rate
structure ("One State; One Rate") and an integration/merger savings mechanism.
The settlement agreement also allows New England Gas Company to retain
$2,049,000 of merger savings and to share incremental earnings with customers
when the division's Rhode Island operations return on equity exceeds 11.25%.
Included in the settlement agreement was a conversion to therm billing and the
approval of a reconciling Distribution Adjustment Clause (DAC). The DAC allows
New England Gas Company to continue its low income assistance and weatherization
programs, to recover environmental response costs over a 10-year period, puts
into place a new weather normalization clause and allows for the sharing of
nonfirm margins (non-firm margin is margin earned from interruptible customers
with the ability to switch to alternative fuels). The weather normalization
clause is designed to mitigate the impact of weather volatility on customer
billings, which will assist customers in paying bills and stabilize the revenue
stream. New England Gas Company will defer the margin impact of weather that is
greater than 2% colder-than-normal and will recover the margin impact of weather
that is greater than 2% warmer-than-normal. The non-firm margin incentive
mechanism allows New England Gas Company to retain 25% of all non-firm margins
earned in excess of $1,600,000.
In December 2002, FERC approved a Trunkline LNG certificate application to
expand the Lake Charles facility to approximately 1.2 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 by the end of the 2005 calendar
year. In February 2004, Trunkline LNG filed a further incremental LNG expansion
project (Phase II) with FERC and is awaiting commission approval. 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.
In February 2004, Trunkline filed an application with FERC to request approval
of a 30-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal.
The pipeline creates additional transport capacity in association with the
Trunkline LNG expansion and also includes new and expanded delivery points with
major interstate pipelines.
The Company continues to pursue certain changes to rates and rate structures
that are intended to reduce the sensitivity of earnings to weather, including
weather normalization clauses and higher monthly fixed customer charges for its
regulated utility operations. New England Gas Company has a weather
normalization clause in the tariff covering its Rhode Island operations.
Critical Accounting Policies. The Company's consolidated financial statements
have been prepared in accordance with accounting principles generally accepted
in the United States of America. The preparation of these financial statements
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and related disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Estimates and assumptions
about future events and their effects cannot be perceived with certainty. On an
ongoing basis, the Company evaluates its estimates based on historical
experience, current market conditions and on various other assumptions that are
believed to be reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying value of assets and liabilities
that are not readily apparent from other sources. Nevertheless, actual results
may differ from these estimates under different assumptions or conditions. The
following is a summary of the Company's most critical accounting policies, which
are defined as those policies whereby judgments or uncertainties could affect
the application of those policies and materially different amounts could be
reported under different conditions or using different assumptions. For a
summary of all of the Company's significant accounting policies, see Note I -
Summary of Significant Accounting Policies.
Effects of Regulation -- The Company is subject to regulation by certain state
and federal authorities. The Company, in its Distribution segment, has
accounting policies which conform to the FASB Standard, Accounting for the
Effects of Certain Types of Regulation, and which are in accordance with the
accounting requirements and ratemaking practices of the regulatory authorities.
The application of these accounting policies allows the Company to defer
expenses and revenues on the balance sheet as regulatory assets and liabilities
when it is probable that those expenses and income will be allowed in the
ratemaking process in a period different from the period in which they would
have been reflected in the income statement by an unregulated company. These
deferred assets and liabilities are then flowed through the results of
operations in the period in which the same amounts are included in rates and
recovered from or refunded to customers. Management's assessment of the
probability of recovery or pass through of regulatory assets and liabilities
requires judgment and interpretation of laws and regulatory commission orders.
If, for any reason, the Company ceases to meet the criteria for application of
regulatory accounting treatment for all or part of its operations, the
regulatory assets and liabilities related to those portions ceasing to meet such
criteria would be eliminated from the Consolidated Balance Sheet and included in
the Consolidated Statement of Operations for the period in which the
discontinuance of regulatory accounting treatment occurs. The aggregate amount
of regulatory assets and liabilities reflected in the Consolidated Balance
Sheets are $99,314,000 and $11,164,000 at June 30, 2004 and $107,696,000 and
$10,084,000 at June 30, 2003, respectively.
Long-Lived Assets -- Long-lived assets, including property, plant and equipment,
goodwill and intangibles comprise a significant amount of the Company's total
assets. The Company makes judgments and estimates about the carrying value of
these assets, including amounts to be capitalized, depreciation methods and
useful lives. The Company also reviews these assets for impairment on a periodic
basis or whenever events or changes in circumstances indicate that the carrying
amounts may not be recoverable. The impairment test consists of a comparison of
an asset's fair value with its carrying value; if the carrying value of the
asset exceeds its fair value, an impairment loss is recognized in the
Consolidated Statement of Operations in an amount equal to that excess.
Management's determination of an asset's fair value requires it to make
long-term forecasts of future revenues and costs related to the asset, when the
asset's fair value is not readily apparent from other sources. These forecasts
require assumptions about future demand, future market conditions and regulatory
developments. Significant and unanticipated changes to these assumptions could
require a provision for impairment in a future period.
During June 2004, the Company evaluated goodwill for impairment. The
determination of whether an impairment has occurred is based on an estimate of
discounted future cash flows attributable to the Company's reporting units that
have goodwill, as compared to the carrying value of those reporting units' net
assets. As of June 30, 2004, pursuant to the FASB Standard, Goodwill and Other
Intangible Assets, no impairment had been indicated.
In connection with the Company's Cash Flow Improvement Plan announced in July
2001, the Company began the divestiture of certain non-core assets. As a result
of prices of comparable businesses for various non-core properties and pursuant
to the FASB Standard, Impairment of Long-Lived Assets and Assets to be Disposed
Of, a goodwill impairment loss of $1,417,000 was recognized in depreciation and
amortization on the Consolidated Statement of Operations for the quarter ended
September 30, 2001.
Investments in Securities -- As of June 30, 2004, all securities owned by the
Company are accounted for under the cost method. These securities consist of
common and preferred stock in non-public companies whose value is not readily
determinable. A judgmental aspect of accounting for these securities involves
determining whether an other-than-temporary decline in value has been sustained.
Management reviews these 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; financial condition and prospects of the
issuer's region and industry; and Southern Union's intent and ability to retain
the investment. If management determines that a decline in value is
other-than-temporary, a charge will be recorded on the Consolidated Statement of
Operations to reduce the carrying value of the investment security to its
estimated fair value.
In September 2003 and June 2002, Southern Union determined that declines in the
value of its investment in PointServe were other than temporary. Accordingly,
the Company recorded non-cash charges of $1,603,000 and $10,380,000 during the
quarters ended September 30, 2003 and June 30, 2002, respectively, to reduce the
carrying value of this investment to its estimated fair value. The Company
recognized these valuation adjustments to reflect significant lower private
equity valuation metrics and changes in the business outlook of PointServe.
PointServe is a closely held, privately owned company and, as such, has no
published market value. The Company's remaining investment of $2,603,000 at June
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.
Pensions and Other Postretirement Benefits - The Company accounts for pension
costs and other postretirement benefit costs in accordance with the FASB
Standards Employers' Accounting for Pensions and Employers' Accounting for
Postretirement Benefits Other Than Pensions, respectively. These Statements
require liabilities to be recorded on the balance sheet at the present value of
these future obligations to employees net of any plan assets. The calculation of
these liabilities and associated expenses require the expertise of actuaries and
are subject to many assumptions including life expectancies, present value
discount rates, expected long-term rate of return on plan assets, rate of
compensation increase and anticipated health care costs. Any change in these
assumptions can significantly change the liability and associated expenses
recognized in any given year. However, the Company expects to recover
substantially all of its net periodic pension and other post-retirement benefit
costs attributable to employees in its Distribution segment in accordance with
the applicable regulatory commission authorization. For financial reporting
purposes, the difference between the amounts of pension cost and post-retirement
benefit cost recoverable in rates and the amounts of such costs as determined
under applicable accounting principles is recorded as either a regulatory asset
or liability, as appropriate.
Derivatives 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 used to reduce interest rate risks and to
manage interest expense. Commodity swaps have been utilized to manage price risk
associated with certain energy contracts. The Company accounts for its
derivatives in accordance with the FASB Standard, Accounting for Derivative
Instruments and Hedging Activities, as amended. Under this Statement, all
derivatives are recognized on the balance sheet at their fair value. On the date
the derivative contract is entered into, management designates the derivative as
either: (i) a hedge of the fair value of a recognized asset or liability or of
an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a
forecasted transaction or of the variability of cash flows to be received or
paid in connection with a recognized asset or liability (a cash flow hedge), or
(iii) an instrument that is held for trading or non-hedging purposes (a trading
or non-hedging instrument). Changes in the fair value of a derivative that
qualifies as a fair-value hedge, along with the gain or loss on the hedged asset
or liability that is attributable to the hedged risk, are recorded in earnings.
Changes in the fair value of a derivative that qualifies as a cash-flow hedge,
to the extent that the hedge is effective, are recorded in other comprehensive
income, until earnings are affected by the variability of cash flows of the
hedged transaction (e.g., until periodic settlements of a variable-rate asset or
liability are recorded in earnings). Hedge ineffectiveness is recorded through
earnings immediately. Lastly, changes in the fair value of derivative trading
and non-hedging instruments are reported in current-period earnings. Fair value
is determined based upon mathematical models using current and historical data.
The Company formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions have been
highly effective in offsetting changes in the fair value or cash flows of hedged
items and whether those derivatives may be expected to remain highly effective
in future periods. The Company discontinues hedge accounting when: (i) it
determines that the derivative is no longer effective in offsetting changes in
the fair value or cash flows of a hedged item; (ii) the derivative expires or is
sold, terminated, or exercised; (iii) it is no longer probable that the
forecasted transaction will occur; or (iv) management determines that
designating the derivative as a hedging instrument is no longer appropriate. In
all situations in which hedge accounting is discontinued and the derivative
remains outstanding, the Company will carry the derivative at its fair value on
the balance sheet, recognizing changes in the fair value in current-period
earnings. See Note XI -- Derivative Instruments and Hedging Activities.
Commitments and Contingencies -- The Company is subject to proceedings, lawsuits
and other claims related to environmental and other matters. Accounting for
contingencies requires significant judgments by management regarding the
estimated probabilities and ranges of exposure to potential liability. For
further discussion of the Company's commitments and contingencies, see Note
XVIII -- Commitments and Contingencies.
Purchase Accounting -- The Company's acquisition of Panhandle Energy has been
accounted for using the purchase method of accounting in accordance with the
FASB Standard, Business Combinations. Under this Statement, the purchase price
paid by the Company, including transaction costs, was allocated to Panhandle
Energy's net assets as of the acquisition date. The Panhandle Energy assets
acquired and liabilities assumed have been recorded at their estimated fair
value as of the acquisition date based on the results of outside appraisals.
Determining the fair value of certain assets acquired and liabilities assumed is
judgmental in nature and often involves the use of significant estimates and
assumptions. The accounting rules provide a one-year period following the
consummation of an acquisition to finalize the fair value estimates.
Accounting Pronouncements
In April 2003, the FASB issued Amendment of Statement 133 on Derivative
Instruments and Hedging Activities. The Statement is effective for contracts
entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. The Statement (i) clarifies under what
circumstances a contract with an initial net investment meets the characteristic
of a derivative, (ii) clarifies when a derivative contains a financing
component, (iii) amends the definition of an underlying to conform it to
language used in FASB Interpretation Guarantor's Accounting and Disclosure
Requirement for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, and (iv) amends certain other existing pronouncements. The Statement did
not materially change the methods the Company uses to account for and report its
derivatives and hedging activities.
Effective July 1, 2003, the Company adopted the FASB standard, Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity. The Statement establishes guidelines on how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. The Statement further defines and requires that certain instruments
within its scope be classified as liabilities on the financial statements. The
adoption of the Statement did not have a material impact on its financial
position, results of operations or cash flows for the periods presented.
Effective January 1, 2004 the Company adopted the FASB standard, Employers'
Disclosures about Pensions and Other Postretirement Benefits - an amendment of
FASB Statements No. 87, 88, and 106. The Statement revises employers'
disclosures about pension plans and other postretirement benefit plans. It
retains the disclosure requirements contained in FASB Statement No. 132,
Employers' Disclosures about Pensions and Other Postretirement Benefits, which
it replaces, and requires additional disclosure about the assets, obligations,
cash flows and net periodic benefit cost of defined benefit pension plans and
other defined benefit postretirement plans. The Statement does not change the
measurement or recognition of those plans required by FASB Statements No. 87,
Employers' Accounting for Pensions, No. 88, Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits, and No. 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions.
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 June 30, 2004, this Issue did not change the method used by the
Company to calculate its earnings per share for the period ended June 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.
See the Notes to Consolidated Financial Statements for other accounting
pronouncements followed by the Company.
Cautionary Statement Regarding Forward-Looking Information. This Management's
Discussion and Analysis of Results of Operations and Financial Condition and
other sections of this Annual Report on Form 10-K 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 achievement of operating efficiencies and the purchases and
implementation of new technologies for attaining such efficiencies; impact of
relations with labor unions of bargaining-unit employees; the receipt of timely
and adequate rate relief 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.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.
The Company has long-term debt and revolving credit facilities, which subject
the Company to the risk of loss associated with movements in market interest
rates.
At June 30, 2004, the Company had issued fixed-rate long-term debt aggregating
$1,866,308,000 in principal amount (excluding premiums on Panhandle Energy's
debt of $16,199,000) and having a fair value of $1,959,225,000. These
instruments are fixed-rate and, therefore, do not expose the Company to the risk
of earnings loss due to changes in market interest rates. However, the fair
value of these instruments would increase by approximately $84,263,000 if
interest rates were to decline by 10% from their levels at June 30, 2004. In
general, such an increase in fair value would impact earnings and cash flows
only if the Company were to reacquire all or a portion of these instruments in
the open market prior to their maturity.
The Company's floating-rate obligations aggregated $398,066,000 at June 30, 2004
and primarily consisted of the 2002 Term Note, the debt assumed under the
Panhandle Acquisition related to the Trunkline LNG facility, and amounts
borrowed under the Long-Term Facility. The floating-rate obligations under the
2002 Term Note and the Long-Term Facility expose the Company to the risk of
increased interest expense in the event of increases in short-term interest
rates. If the floating rates were to increase by 10% from June 30, 2004 levels,
the Company's consolidated interest expense would increase by a total of
approximately $68,000 each month in which such increase continued.
The risk of an economic loss is reduced at this time as a result of the
Company's regulated status with respect to its Distribution segment operations.
Any unrealized gains or losses are accounted for in accordance with the FASB
Standard, Accounting for the Effects of Certain Types of Regulation, as a
regulatory asset or liability.
The change in exposure to loss in earnings and cash flow related to interest
rate risk from June 30, 2003 to June 30, 2004 is not material to the Company.
See Note XIII - Debt and Capital Lease.
In connection with the acquisition of the Pennsylvania Operations, the Company
assumed a guaranty with a bank whereby the Company unconditionally guaranteed
payment of financing obtained for the development of PEI Power Park. In March
1999, the Borough of Archbald, the County of Lackawanna, and the Valley View
School District (together the Taxing Authorities) approved a Tax Incremental
Financing Plan (TIF Plan) for the development of PEI Power Park. The TIF Plan
requires that: (i) the Redevelopment Authority of Lackawanna County raise
$10,600,000 of funds to be used for infrastructure improvements of the PEI Power
Park; (ii) the Taxing Authorities create a tax increment district and use the
incremental tax revenues generated from new development to service the
$10,600,000 debt; and (iii) PEI Power Corporation, a subsidiary of the Company,
guarantee the debt service payments. In May 1999, the Redevelopment Authority of
Lackawanna County borrowed $10,600,000 from a bank under a promissory note (TIF
Debt), which was refinanced and modified in May 2004. Beginning May 15, 2004 the
TIF Debt bears interest at a variable rate equal to three-quarters percent
(.75%) lower than the National Prime Rate of Interest with no interest rate
floor or ceiling. The TIF Debt matures on June 30, 2011. Interest-only payments
were required until June 30, 2003, and semi-annual interest and principal
payments are required thereafter. As of June 30, 2004, the interest rate on the
TIF Debt was 3.25% and estimated incremental tax revenues are expected to cover
approximately 25% of the fiscal 2005 annual debt service. Based on information
available at this time, the Company believes that the amount provided for the
potential shortfall in estimated future incremental tax revenues is adequate as
of June 30, 2004. The balance outstanding on the TIF Debt was $8,710,000 as of
June 30, 2004.
As a result of the acquisition of Panhandle Energy, the Company is party to
interest rate swap agreements with an aggregate notional amount of $197,947,000
as of June 30, 2004 that fix the interest rate applicable to floating rate
long-term debt and which qualify for hedge accounting. For the year ended June
30, 2004, the amount of swap ineffectiveness was not significant. As of June 30,
2004, floating rate LIBOR-based interest payments are 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 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 June 30, 2004 and 2003,
the fair value liability position of the swaps was $14,445,000 and $26,058,000,
respectively. As of June 30, 2004 and since the acquisition date, an unrealized
gain of $1,776,000, net of tax, was included in accumulated other comprehensive
income related to these swaps, of which approximately $1,068,000, net of tax, is
expected to be reclassified to interest expense during the next twelve months as
the hedged interest payments occur. Current market pricing models were used to
estimate fair values of interest rate swap agreements.
The Company was also party to an interest rate swap agreement with a notional
amount of $8,199,000 at June 30, 2003 that fixed the interest rate applicable to
floating rate long-term debt and which qualified for hedge accounting. The fair
value liability position of the swap was $93,000 at June 30, 2003. In October
2003, the swap expired and $15,000 of unrealized after-tax losses included in
accumulated other comprehensive income relating to this swap was reclassified to
interest expense during the quarter ended December 31, 2003.
In March and April 2003, the Company entered into a series of treasury rate
locks with an aggregate notional amount of $250,000,000 to manage its exposure
against changes in future interest payments attributable to changes in the
benchmark interest rate prior to the anticipated issuance of fixed-rate debt.
These treasury rate locks expired on June 30, 2003, resulting in a $6,862,000
after-tax loss that was recorded in accumulated other comprehensive income and
will be amortized into interest expense over the lives of the associated debt
instruments. As of June 30, 2004, approximately $981,000 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.
In March 2004, Panhandle Energy entered into an interest rate swap 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 agreement 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 June 30, 2004, the fair value liability position of the swap was $4,960,000,
which reduced the carrying value of the underlying debt.
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 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 a liability and a matching adjustment to deferred cost of gas of $1,337,000.
In March 2001, the Company discovered unauthorized financial derivative energy
trading activity by a non-regulated, wholly-owned subsidiary. All unauthorized
trading activity was subsequently closed in March and April of 2001 resulting in
a cumulative cash expense of $191,000, net of taxes, and deferred income of
$7,921,000 at June 30, 2001. For fiscal years 2004, 2003 and 2002, the Company
recorded $605,000, $605,000 and $6,204,000, respectively, through other income
relating to the expiration of contracts resulting from this trading activity.
The remaining deferred liability of $507,000 at June 30, 2004 related to these
derivative instruments will be recognized as income in the Consolidated
Statement of Operations over the next year based on the related contracts. The
Company established new limitations on trading activities, as well as new
compliance controls and procedures that are intended to make it easier to
identify quickly any unauthorized trading activities.
ITEM 8. Financial Statements and Supplementary Data.
The information required here is included in the report as set forth in the
Index to Consolidated Financial Statements on page F-1.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
ITEM 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
We performed an evaluation under the supervision and with the participation of
our management, including our Chief Executive Officer (CEO) and Chief Financial
Officer (CFO), and with the participation of personnel from our Legal, Internal
Audit, Risk Management and Financial Reporting Departments, of the effectiveness
of the design and operation of the Company's disclosure controls and procedures
(as defined in Rule 13a-15(e) 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, our CEO and CFO concluded that our disclosure controls and
procedures were effective as of June 30, 2004 and have communicated that
determination to the Audit Committee of our Board of Directors.
Changes in Internal Controls
There have been no significant changes in our internal controls or other factors
that have materially affected or are reasonably likely to materially affect
internal controls subsequent to June 30, 2004.
ITEM 9B. Other Information.
None.
PART III
ITEM 10. Directors and Executive Officers of the Registrant.
There is incorporated in this Item 10 by reference the information that will
appear in the Company's definitive proxy statement for the 2004 Annual Meeting
of Stockholders under the captions Board of Directors -- Board Size and
Composition, Report of the Audit Committee, and Executive Officers and
Compensation -- Executive Officers Who Are Not Directors and Executive Officers
and Compensation -- Section 16(a) Beneficial Owner Reporting Compliance.
We have adopted a Code of Ethics for Senior Financial Officers, which applies to
our Chief Executive Officer, Chief Financial Officer, controller and other
individuals in our finance department performing similar functions. The Code of
Ethics is available on our website at www.southernunionco.com. If any
substantive amendment to the Code of Ethics is made or any waiver is granted
thereunder, including any implicit waiver, our Chief Executive Officer, Chief
Financial Officer or other authorized officer will disclose the nature of such
amendment or waiver on our website at www.southernunionco.com or in a report on
Form 8-K.
ITEM 11. Executive Compensation.
There is incorporated in this Item 11 by reference the information that will
appear in the Company's definitive proxy statement for the 2004 Annual Meeting
of Stockholders under the captions Executive Officers and Compensation --
Executive Compensation and Certain Relationships.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.
There is incorporated in this Item 12 by reference the information that will
appear in the Company's definitive proxy statement for the 2004 Annual Meeting
of Stockholders under the captions Executive Officers and Compensation - Equity
Compensation Plans and Security Ownership.
ITEM 13. Certain Relationships and Related Transactions.
There is incorporated in this Item 13 by reference the information that will
appear in the Company's definitive proxy statement for the 2004 Annual Meeting
of Stockholders under the caption Certain Relationships.
ITEM 14. Principal Accountants Fee and Services.
There is incorporated in this Item 14 by reference the information that will
appear in the Company's definitive proxy statement for the 2004 Annual Meeting
of Stockholders under the caption Independent Auditors.
PART IV
ITEM 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a)(1) and (2) Financial Statements and Financial Statement Schedules.
See Index to Consolidated Financial Statements set forth on
page F-1.
(a)(3) Exhibits.
Exhibit No. Description
- ----------- -----------
3(a) Restated Certificate of Incorporation of Southern Union Company.
(Filed as Exhibit 3(a) to Southern Union's Transition Report on
Form 10-K for the year ended June 30, 1994 and incorporated herein
by reference.)
3(b) Amendment to Restated Certificate of Incorporation of Southern
Union Company which was filed with the Secretary of State of
Delaware and became effective on October 26, 1999. (Filed as
Exhibit 3(a) to Southern Union's Quarterly Report on Form 10-Q for
the quarter ended December 31, 1999 and incorporated herein by
reference.)
3(c) Southern Union Company Bylaws, as amended. (Filed as Exhibit 3(a)
to Southern Union's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1999 and incorporated herein by reference.)
4(a) Specimen Common Stock Certificate. (Filed as Exhibit 4(a) to
Southern Union's Annual Report on Form 10-K for the year ended
December 31, 1989 and incorporated herein by reference.)
4(b) Indenture between Chase Manhattan Bank, N.A., as trustee, and
Southern Union Company dated January 31, 1994. (Filed as Exhibit
4.1 to Southern Union's Current Report on Form 8-K dated
February 15, 1994 and incorporated herein by reference.)
4(c) Officers' Certificate dated January 31, 1994 setting forth the
terms of the 7.60% Senior Debt Securities due 2024. (Filed as
Exhibit 4.2 to Southern Union's Current Report on Form 8-K dated
February 15, 1994 and incorporated herein by reference.)
4(d) Officer's Certificate of Southern Union Company dated November 3,
1999 with respect to 8.25% Senior Notes due 2029. (Filed as
Exhibit 99.1 to Southern Union's Current Report on Form 8-K filed
on November 19, 1999 and incorporated herein by reference.)
4(e) Certificate of Trust of Southern Union Financing I. (Filed as
Exhibit 4-A to Southern Union's Registration Statement on Form S-3
(No. 33-58297) and incorporated herein by reference.)
4(f) Certificate of Trust of Southern Union Financing II. (Filed as
Exhibit 4-B to Southern Union's Registration Statement on Form S-3
(No. 33-58297) and incorporated herein by reference.)
4(g) Certificate of Trust of Southern Union Financing III. (Filed as
Exhibit 4-C to Southern Union's Registration Statement on Form S-3
(No. 33-58297) and incorporated herein by reference.)
4(h) Form of Amended and Restated Declaration of Trust of Southern
Union Financing I. (Filed as Exhibit 4-D to Southern Union's
Registration Statement on Form S-3 (No. 33-58297) and incorporated
herein by reference.)
4(i) Form of Subordinated Debt Securities Indenture among Southern
Union Company and The Chase Manhattan Bank, N. A., as Trustee.
(Filed as Exhibit 4-G to Southern Union's Registration Statement
on Form S-3 (No. 33-58297) and incorporated herein by reference.)
Exhibit No. Description
- ----------- -----------
4(j) Form of Supplemental Indenture to Subordinated Debt Securities
Indenture with respect to the Subordinated Debt Securities issued
in connection with the Southern Union Financing I Preferred
Securities. (Filed as Exhibit 4-H to Southern Union's
Registration Statement on Form S-3 (No.33-58297) and incorporated
herein by reference.)
4(k) Form of Southern Union Financing I Preferred Security (included in
4(g) above.) (Filed as Exhibit 4-I to Southern Union's
Registration Statement on Form S-3 (No. 33-58297) and incorporated
herein by reference.)
4(l) Form of Subordinated Debt Security (included in 4(i) above.)
(Filed as Exhibit 4-J to Southern Union's Registration Statement
on Form S-3 (No. 33-58297) and incorporated herein by reference.)
4(m) Form of Guarantee with respect to Southern Union Financing I
Preferred Securities. (Filed as Exhibit 4-K to Southern Union's
Registration Statement on Form S-3 (No. 33-58297) and incorporated
herein by reference.)
4(n) First Mortgage Bonds Indenture of Mortgage and Deed of Trust
dated as of March 15, 1946 by Southern Union Company (as
successor to PG Energy, Inc. formerly, Pennsylvania Gas and Water
Company, and originally, Scranton-Spring Brook Water Service
Company) to Guaranty Trust Company of New York. (Filed as Exhibit
4.1 to Southern Union's Current Report on Form 8-K filed on
December 30, 1999 and incorporated herein by reference.)
4(o) Twenty-Third Supplemental Indenture dated as of August 15, 1989
(Supplemental to Indenture dated as of March 15, 1946) between
Southern Union Company and Morgan Guaranty Trust Company of New
York (formerly Guaranty Trust Company of New York). (Filed as
Exhibit 4.2 to Southern Union's Current Report on Form 8-K filed
on December 30, 1999 and incorporated herein by reference.)
4(p) Twenty-Sixth Supplemental Indenture dated as of December 1, 1992
(Supplemental to Indenture dated as of March 15, 1946) between
Southern Union Company and Morgan Guaranty Trust Company of New
York. (Filed as Exhibit 4.3 to Southern Union's Current Report on
Form 8-K filed on December 30, 1999 and incorporated herein by
reference.)
4(q) Thirtieth Supplemental Indenture dated as of December 1, 1995
(Supplemental to Indenture dated as of March 15, 1946) between
Southern Union Company and First Trust of New York, National
Association (as successor trustee to Morgan Guaranty Trust Company
of New York). (Filed as Exhibit 4.4 to Southern Union's Current
Report on Form 8-K filed on December 30, 1999 and incorporated
herein by reference.)
4(r) Thirty-First Supplemental Indenture dated as of November 4, 1999
(Supplemental to Indenture dated as of March 15, 1946) between
Southern Union Company and U. S. Bank Trust, National Association
(formerly, First Trust of New York, National Association). (Filed
as Exhibit 4.5 to Southern Union's Current Report on Form 8-K
filed on December 30, 1999 and incorporated herein by reference.)
4(s) Pennsylvania Gas and Water Company Bond Purchase Agreement dated
September 1, 1989. (Filed as Exhibit 4.6 to Southern Union's
Current Report on Form 8-K filed on December 30, 1999 and
incorporated herein by reference.)
4(t) Letter Agreement dated as of July 26, 2004, between Southern Union
Company and Merrill Lynch International. (Filed as Exhibit 99.1 to
Southern Union's Current Report on Form 8-K filed on August 31,
2004 and incorporated herein by reference.)
4(u) Letter Agreement dated as of July 26, 2004, between Southern
Union Company and JPMorgan Chase Bank, London Branch, acting
through J.P. Morgan Securities Inc. as agent. (Filed as Exhibit
99.2 to Southern Union's Current Report on Form 8-K filed on
August 31, 2004 and incorporated herein by reference.)
4(v) Southern Union is a party to other debt instruments, none of which
authorizes the issuance of debt securities in an amount which
exceeds 10% of the total assets of Southern Union. Southern Union
hereby agrees to furnish a copy of any of these instruments to the
Commission upon request.
10(a) Third Amended and Restated Revolving Credit Agreement between
Southern Union Company and the Banks named therein dated May 28,
2004.
Exhibit No. Description
- ----------- -----------
10(b) Amended and Restated Term Loan Credit Agreement between Southern
Union Company and the Banks named therein dated April 3, 2003.
(Filed as Exhibit 10(c) to Southern Union's Annual Report on Form
10-K for the year ended June 30, 2003 and incorporated herein by
reference.)
10(c) Form of Indemnification Agreement between Southern Union Company
and each of the Directors of Southern Union Company. (Filed as
Exhibit 10(i) to Southern Union's Annual Report on Form 10-K for
the year ended December 31, 1986 and incorporated herein by
reference.)
10(d) Southern Union Company 1992 Long-Term Stock Incentive Plan, as
Amended. (Filed as Exhibit 10(l) to Southern Union's Annual Report
on Form 10-K for the year ended June 30, 1998 and incorporated
herein by reference.)(*)
10(e) Southern Union Company Director's Deferred Compensation Plan.
(Filed as Exhibit 10(g) to Southern Union's Annual Report on Form
10-K for the year ended December 31, 1993 and incorporated herein
by reference.)(*)
10(f) Southern Union Company Amended Supplemental Deferred Compensation
Plan with Amendments. (Filed as Exhibit 4 to Southern Union's Form
S-8 filed May 27, 1999 and incorporated herein by reference.)(*)
10(g) [Reserved].
10(h) Employment agreement between Thomas F. Karam and Southern Union
Company dated December 28, 1999. (Filed as Exhibit 10(a) to
Southern Union's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1999 and incorporated herein by reference.)
10(i) Secured Promissory Note and Security Agreements between Thomas F.
Karam and Southern Union Company dated December 20, 1999. (Filed
as Exhibit 10(b) to Southern Union's Quarterly Report on Form 10-Q
for the quarter ended December 31, 1999 and incorporated herein by
reference.)
10(j) Promissory Note between Dennis K. Morgan and Southern Union
Company dated January 28, 2000. (Filed as Exhibit 10(k) to
Southern Union's Annual Report on Form 10-K for the year ended
June 30, 2002 and incorporated herein by reference.)
10(k) Southern Union Company Pennsylvania Division Stock Incentive
Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36146,
filed on May 3, 2000 and incorporated herein by reference.)(*)
10(l) Southern Union Company Pennsylvania Division 1992 Stock Option
Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36150,
filed on May 3, 2000 and incorporated herein by reference.)(*)
10(m) Employment agreement between David W. Stevens and Southern Union
Company dated October 31, 2002. (Filed as Exhibit 10 to Southern
Union's Quarterly Report on Form 10-Q for the quarter ended
December 31, 2002 and incorporated herein by reference.)
10(n) Southern Union Company 2003 Stock and Incentive Plan. (Filed as
Exhibit 4.1 to Form S-8, SEC File No. 333-112527, filed on
February 5, 2004 and incorporated herein by reference.)(*)
14 Code of Ethics.
21 Subsidiaries of the Company.
23 Consent of Independent Registered Public Accounting Firm.
Exhibit No. Description
- ----------- -----------
24 Power of Attorney.
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.
(b) Reports on Form 8-K. Southern Union filed the following Current
Reports on Form 8-K during the three months ended June 30, 2004.
Date
Filed Description of Filing
- ----- --------------------------------------------------------------
04/30/04 Announcement of operating performance for the quarter- and
nine-months ended March 31, 2004 and 2003 and filing, under
Item 12, summary statements of income of Southern Union
Company for the quarter ended March 31, 2004 and 2003
(unaudited) and notes thereto.
06/23/04 Announcement that CCE Holdings, LLC, a joint venture of
Southern Union and its 50% equity partner GE Commercial
Finance Energy Financial Services, submitted an offer to
acquire 100% of the equity interests of CrossCountry Energy,
LLC from Enron Corp. and its affiliates.
06/25/04 Announcement that CCE Holdings, LLC entered into a Purchase
Agreement to acquire 100% of the equity interests of
CrossCountry Energy, LLC from Enron Corp. and its affiliates;
announcement that the U.S. Bankruptcy Court for the Southern
District of New York issued an Order establishing CCE
Holding's Agreement as the "Stalking Horse" bid; and filing
under Item 7, the Purchase Agreement among CCE Holdings, LLC,
Enron Transportation Services, LLC, EOC Preferred, LLC and
Enron Corp., dated as of June 24, 2004.
- ---------------------
(*) Indicates Management Compensation Plan.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, Southern Union has duly caused this report to be signed by the
undersigned, thereunto duly authorized, on August 31, 2004.
SOUTHERN UNION COMPANY
By THOMAS F. KARAM
--------------------------
Thomas F. Karam
President and Chief
Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed by the following persons on behalf of Southern Union and in the
capacities indicated as of August 31, 2004.
Signature/Name Title
-------------- -----
GEORGE L. LINDEMANN* Chairman of the Board, Chief Executive Officer
and Director
JOHN E. BRENNAN* Director
DAVID BRODSKY* Director
FRANK W. DENIUS* Director
KURT A. GITTER, M.D.* Director
THOMAS F. KARAM Director
---------------------
Thomas F. Karam
ADAM M. LINDEMANN* Director
GEORGE ROUNTREE, III* Director
RONALD W. SIMMS* Director
DAVID J. KVAPIL Executive Vice President and Chief Financial
------------------------
David J. Kvapil Officer (Principal Accounting Officer)
*By THOMAS F. KARAM
-----------------------
Thomas F. Karam
Attorney-in-fact
SOUTHERN UNION COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Financial Statements:
Consolidated statement of operations -- years ended
June 30, 2004, 2003 and 2002.................................. F-2
Consolidated balance sheet -- June 30, 2004 and 2003............ F-3 to F-4
Consolidated statement of cash flows -- years ended June 30,
2004, 2003 and 2002........................................... F-5
Consolidated statement of common stockholders' equity -- years
ended June 30, 2004, 2003 and 2002............................ F-6
Notes to consolidated financial statements...................... F-7 to F-44
Report of independent registered public accounting firm......... F-45
All schedules are omitted as the required information is not applicable or the
information is presented in the consolidated financial statements or related
notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended June 30,
-------------------------------------------
2004 2003 2002
------------- ------------ --------------
(thousands of dollars, except shares and
per share amounts)
Operating revenues:
Gas distribution...................................................... $ 1,304,405 $ 1,158,964 $ 968,933
Gas transportation and storage........................................ 491,083 24,529 --
Other................................................................. 4,486 5,014 11,681
------------- ------------ -------------
Total operating revenues.......................................... 1,799,974 1,188,507 980,614
Cost of gas and other energy............................................... (864,438) (724,611) (573,077)
Revenue-related taxes...................................................... (45,395) (40,485) (33,409)
------------- ------------ -------------
Net operating revenues, excluding depreciation and amortization... 890,141 423,411 374,128
Operating expenses:
Operating, maintenance and general.................................... 411,811 193,745 171,147
Business restructuring charges........................................ -- -- 29,159
Depreciation and amortization......................................... 118,755 60,642 58,989
Taxes, other than on income and revenues.............................. 54,048 26,653 23,708
------------- ------------ -------------
Total operating expenses.......................................... 584,614 281,040 283,003
------------- ------------ -------------
Operating income.................................................. 305,527 142,371 91,125
------------- ------------ -------------
Other income (expenses):
Interest ............................................................. (127,867) (83,343) (90,992)
Dividends on preferred securities of subsidiary trust................. -- (9,480) (9,480)
Other, net............................................................ 5,468 18,394 14,278
------------- ------------ -------------
Total other expenses, net......................................... (122,399) (74,429) (86,194)
------------- ------------ -------------
Earnings from continuing operations before income taxes.................... 183,128 67,942 4,931
Federal and state income taxes ............................................ 69,103 24,273 3,411
------------- ------------ -------------
Net earnings from continuing operations.................................... 114,025 43,669 1,520
------------- ------------ -------------
Discontinued operations:
Earnings from discontinued operations before income taxes............. -- 84,773 29,801
Federal and state income taxes........................................ -- 52,253 11,697
------------- ------------ -------------
Net earnings from discontinued operations.................................. -- 32,520 18,104
------------- ------------ -------------
Net earnings ............................................................. 114,025 76,189 19,624
Preferred stock dividends.................................................. (12,686) -- --
-------------- ------------ -------------
Net earnings available for common shareholders............................. $ 101,339 $ 76,189 $ 19,624
Net earnings available for common shareholders from continuing
operations per share:
Basic................................................................. $ 1.34 $ 0.72 $ 0.03
============= ============= =============
Diluted............................................................... $ 1.30 $ 0.70 $ 0.02
============= ============= =============
Net earnings available for common shareholders per share:
Basic................................................................. $ 1.34 $ 1.26 $ 0.33
============= ============= =============
Diluted............................................................... $ 1.30 $ 1.22 $ 0.31
============= ============= =============
Weighted average shares outstanding:
Basic................................................................. 75,442,238 60,584,293 59,420,048
============= ============= =============
Diluted............................................................... 77,694,532 62,523,107 62,596,874
============= ============= =============
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
ASSETS
June 30,
---------------------------------
2004 2003
---------------------------------
(thousands of dollars)
Property, plant and equipment:
Plant in service................................................................. $ 3,772,616 $ 3,710,541
Construction work in progress.................................................... 169,264 75,484
-------------- --------------
3,941,880 3,786,025
Less accumulated depreciation and amortization............................... (734,367) (641,225)
-------------- --------------
Net property, plant and equipment............................................ 3,207,513 3,144,800
Current assets:
Cash and cash equivalents........................................................ 19,971 86,997
Accounts receivable, billed and unbilled, net.................................... 181,924 192,402
Inventories...................................................................... 200,295 173,757
Deferred gas purchase costs...................................................... 3,933 24,603
Gas imbalances - receivable...................................................... 22,045 34,911
Prepayments and other............................................................ 27,561 18,971
-------------- --------------
Total current assets......................................................... 455,729 531,641
Goodwill, net of accumulated amortization of $27,510.................................. 640,547 642,921
Deferred charges...................................................................... 190,735 188,261
Investment securities, at cost........................................................ 8,038 9,641
Other................................................................................. 69,896 73,674
-------------- --------------
Total assets................................................................. $ 4,572,458 $ 4,590,938
============== ==============
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET (Continued)
STOCKHOLDERS' EQUITY AND LIABILITIES
June 30,
------------------------------
2004 2003
------------------------------
(thousands of dollars)
Stockholders' equity:
Common stock, $1 par value; authorized 200,000,000 shares;
issued 77,140,087 shares at June 30, 2004..................................... $ 77,141 $ 73,074
Preferred stock, no par value; authorized 6,000,000 shares;
issued 920,000 shares at June 30, 2004........................................ 230,000 --
Premium on capital stock.......................................................... 975,104 909,191
Less treasury stock: 404,536 and 282,333 shares, respectively,
at cost....................................................................... (12,870) (10,467)
Less common stock held in trust: 1,089,147 and 1,061,656 shares,
respectively.................................................................. (15,812) (15,617)
Deferred compensation plans....................................................... 11,960 9,960
Accumulated other comprehensive income (loss)..................................... (50,224) (62,579)
Retained earnings................................................................. 46,692 16,856
------------- -------------
Total stockholders' equity........................................................ 1,261,991 920,418
Company-obligated mandatorily redeemable preferred securities of subsidiary
trust holding solely subordinated notes of Southern Union......................... -- 100,000
Long-term debt and capital lease obligation............................................ 2,154,615 1,611,653
------------- -------------
Total capitalization.......................................................... 3,416,606 2,632,071
Current liabilities:
Long-term debt and capital lease obligation due within one year................... 99,997 734,752
Notes payable..................................................................... 21,000 251,500
Accounts payable.................................................................. 122,309 112,840
Federal, state and local taxes.................................................... 32,866 6,743
Accrued interest.................................................................. 36,891 40,871
Customer deposits................................................................. 12,043 12,585
Gas imbalances - payable.......................................................... 72,057 64,519
Other............................................................................. 116,783 130,196
------------- -------------
Total current liabilities..................................................... 513,946 1,354,006
Deferred credits....................................................................... 292,946 322,154
Accumulated deferred income taxes...................................................... 348,960 282,707
Commitments and contingencies..........................................................
------------- -------------
Total stockholders' equity and liabilities.................................... $ 4,572,458 $ 4,590,938
============= =============
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended June 30,
-------------------------------------------
2004 2003 2002
-------------------------------------------
(thousands of dollars)
Cash flows from (used in) operating activities:
Net earnings ........................................................ $ 114,025 $ 76,189 $ 19,624
Adjustments to reconcile net earnings to net cash flows provided by
(used in) operating activities:
Depreciation and amortization.................................... 118,755 60,642 58,989
Amortization of debt premium.............................................. (14,243) (1,307) --
Deferred income taxes............................................ 67,455 78,747 28,397
Provision for bad debts................................................... 21,216 17,873 12,260
Provision for impairment of other assets.................................. 1,603 -- 10,380
Financial derivative trading gains............................... (605) (605) (6,204)
Amortization of debt expense.............................................. 4,143 2,919 2,936
Gain on sale of subsidiaries and other assets............................. -- (62,992) (6,414)
Loss on sale of subsidiaries..................................... 1,150 -- 1,500
Gain on settlement of interest rate swaps........................ -- -- (17,166)
Gain on extinguishment of debt................................... (6,354) -- --
Business restructuring charges................................... -- -- 24,440
Net cash provided (used by) assets held for sale................. -- (23,698) 48,618
Other ........................................................... (470) (707) 355
Changes in operating assets and liabilities, net of
acquisitions:
Accounts receivable, billed and unbilled.................... (6,181) (48,520) 71,932
Gas imbalance receivable.................................... 20,341 6,330 --
Accounts payable............................................ 9,469 22,728 (11,965)
Gas imbalance payable....................................... (1,278) 4,851 --
Customer deposits........................................... (542) 5,013 (53)
Deferred gas purchase costs................................. 20,670 (21,006) 53,436
Inventories................................................. (25,824) (34,583) 1,044
Deferred charges and credits................................ 13,773 (12,561) 16,804
Prepaids and other current assets........................... 8,978 2,541 (3,735)
Taxes and other current liabilities......................... (5,031) (16,158) (31,562)
------------ ----------- -----------
Net cash flows provided by operating activities.................. 341,050 55,696 273,616
------------ ----------- -----------
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment........................... (226,053) (79,730) (70,698)
Acquisition of operations, net of cash received........................... -- (522,316) --
Notes receivable..................................................... (2,000) (6,750) (2,750)
Purchase of investment securities.................................... -- -- (938)
Customer advances ........................................................ (3,600) (9,619) (403)
Proceeds from sale of subsidiaries and other assets.................. 2,175 437,000 40,935
Proceeds from sale of interest rate swaps................................. -- -- 17,166
Net cash used in assets held for sale................................ -- (13,410) (23,215)
Other................................................................ 2,469 3,465 677
------------ ------------ ------------
Net cash flows used in investing activities...................... (227,009) (191,360) (39,226)
------------ ------------ ------------
Cash flows (used in) provided by financing activities:
Issuance of long-term debt........................................... 750,000 311,087 --
Issuance costs of debt.................................................... (8,530) (313) (921)
Issuance of preferred stock.......................................... 230,000 -- --
Issuance costs of preferred stock.................................... (6,590) -- --
Issuance of common stock............................................. -- 168,682 --
Issuance of equity units............................................. -- 125,000 --
Issuance cost of equity units........................................ -- (3,443) --
Purchase of treasury stock........................................... (2,403) (2,181) (41,632)
Dividends paid on preferred stock.................................... (8,393) -- --
Repayment of debt and capital lease obligation....................... (908,773) (500,135) (145,131)
Net (payments) borrowings under revolving credit facilities............... (230,500) 119,700 (58,800)
Proceeds from exercise of stock options................................... 4,122 3,047 8,346
Other................................................................ -- 1,217 2,529
------------ ------------ ------------
Net cash flows (used in) provided by financing activities................. (181,067) 222,661 (235,609)
------------- ------------ ------------
Change in cash and cash equivalents....................................... (67,026) 86,997 (1,219)
Cash and cash equivalents at beginning of year............................ 86,997 -- 1,219
------------ ------------ ------------
Cash and cash equivalents at end of year.................................. $ 19,971 $ 86,997 $ --
============ ============ ============
Cash paid for interest, net of amounts capitalized, in 2004, 2003 and 2002 was
$143,715,000, $90,462,000 and $99,643,000, respectively. Cash refunded for
income taxes in 2004 and 2002 was $10,875,000 and $4,214,000, respectively,
while cash paid for income taxes in 2003 was $2,351,000.
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
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, 2001 $ 54,553 $ -- $ 676,324 $ (15,869) $ (11,697) $ 13,443 $ 5,103 $ 721,857
Comprehensive income:
Net earnings -- -- -- -- -- -- 19,624 19,624
Unrealized loss in investment
securities, net of tax benefit -- -- -- -- -- (18,249) -- (18,249)
Minimum pension liability
adjustment, net of tax benefit -- -- -- -- -- (10,498) -- (10,498)
Unrealized gain on hedging
activities, net of tax -- -- -- -- -- 804 -- 804
---------
Comprehensive income (loss) (8,319)
Payment on note receivable -- -- 202 -- -- -- -- 202
Purchase of treasury stock -- -- -- (41,632) -- -- -- (41,632)
5% stock dividend 2,618 -- 22,091 -- -- -- (24,727) (18)
Stock compensation plan -- -- 1,248 -- 1,257 -- -- 2,505
Sale of common stock held in trust -- -- 26 -- 1,945 -- -- 1,971
Exercise of stock options 884 -- 8,021 (172) 47 -- -- 8,780
-------- ------- --------- --------- --------- --------- --------- ---------
Balance June 30, 2002 58,055 -- 707,912 (57,673) (8,448) (14,500) -- 685,346
Comprehensive income (loss):
Net earnings -- -- -- -- -- -- 76,189 76,189
Unrealized loss in investment
securities, net of tax benefit -- -- -- -- -- (581) -- (581)
Minimum pension liability
adjustment, net of tax benefit -- -- -- -- -- (41,930) -- (41,930)
Unrealized loss on hedging
activities, net of tax benefit -- -- -- -- -- (5,568) -- (5,568)
---------
Comprehensive income 28,110
---------
Payment on note receivable -- -- 305 -- -- -- -- 305
Purchase of treasury stock -- -- -- (2,181) -- -- -- (2,181)
5% stock dividend 3,468 -- 55,832 -- -- -- (59,333) (33)
Stock compensation plan -- -- 480 -- 737 -- -- 1,217
Issuance of stock for acquisition -- -- -- 48,900 -- -- -- 48,900
Issuance of common stock 10,925 -- 157,757 -- -- -- -- 168,682
Issuance costs of equity units -- -- (3,443) -- -- -- -- (3,443)
Contract adjustment payment -- -- (11,713) -- -- -- -- (11,713)
Sale of common stock held in trust -- -- (243) -- 2,424 -- -- 2,181
Exercise of stock options 626 -- 2,304 487 (370) -- -- 3,047
-------- -------- -------- -------- -------- -------- -------- ---------
Balance June 30, 2003 73,074 -- 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
======== ========== ========= ========== ======== =========== ========== ==========
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
I Summary of Significant Accounting Policies
Operations. Southern Union Company (Southern Union and together with its
subsidiaries, the Company) is primarily engaged in the transportation, storage
and distribution of natural gas in the United States. The Company's interstate
natural gas transportation and storage operations are conducted through
Panhandle Energy, which operates more than 10,000 miles of interstate pipelines
that transport natural gas from the Gulf of Mexico, South Texas and the
Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and
Great Lakes regions. 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
customers in Missouri, Pennsylvania, Rhode Island and Massachusetts.
Basis of Presentation. Effective June 11, 2003, the Company acquired Panhandle
Energy from CMS Energy Corporation. The acquisition was accounted for using the
purchase method of accounting in accordance with accounting principles generally
accepted in the United States of America with the purchase price paid and
acquisition costs incurred by the Company allocated to Panhandle Energy's net
assets as of the acquisition date. The Panhandle Energy assets acquired and
liabilities assumed have been recorded at their estimated fair value as of the
acquisition date based on the results of outside appraisals. Panhandle Energy's
results of operations have been included in the Consolidated Statement of
Operations since June 11, 2003. Thus, the Consolidated Statement of Operations
for the periods subsequent to the acquisition is not comparable to the same
periods in prior years.
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas Company natural gas operating division and related assets to ONEOK, Inc.
(ONEOK). In accordance with accounting principles generally accepted in the
United States of America, the results of operations and gain on sale of the
Texas operations have been segregated and reported as "discontinued operations"
in the Consolidated Statement of Operations and as "assets held for sale" in the
Consolidated Statement of Cash Flows for the respective periods. See Note II --
Acquisitions and Sales and Note XIX -- Discontinued Operations.
Principles of Consolidation. The consolidated financial statements include the
accounts of Southern Union and its wholly-owned subsidiaries. Investments, other
than variable interest entities, in which the Company has significant influence
over the operations of the investee are accounted for using the equity method.
Investments that are variable interest entities are consolidated if the Company
is allocated a majority of the entity's gains and/or losses, including fees paid
by the entity. All significant intercompany accounts and transactions are
eliminated in consolidation. All dollar amounts in the tables herein, except per
share amounts, are stated in thousands unless otherwise indicated. Certain
reclassifications have been made to prior years' financial statements to conform
with the current year presentation.
Segment Reporting. The Financial Accounting Standards Board (FASB) Standard,
Disclosures about Segments of an Enterprise and Related Information, requires
disclosure of segment data based on how management makes decisions about
allocating resources to segments and measuring performance. The Company is
principally engaged in the transportation, storage and distribution of natural
gas in the United States and reports these operations under two reportable
segments: the Transportation and Storage segment and the Distribution segment.
Gas Utility Revenues and Gas Purchase Costs. In the Distribution segment, gas
utility customers are billed on a monthly-cycle basis. The related cost of gas
and revenue taxes are matched with cycle-billed revenues through utilization of
purchased gas adjustment provisions in tariffs approved by the regulatory
agencies having jurisdiction. Revenues from gas delivered but not yet billed are
accrued, along with the related gas purchase costs and revenue-related taxes.
The Company's operating revenue and other financial information by segment for
fiscal 2004, 2003 and 2002 are presented in Note XXI -- Reportable Segments.
Transportation and Storage Revenues. In the Transportation and Storage segment,
revenues on transportation, storage and terminalling of natural gas are
recognized as service is provided. Receivables are subject to normal trade terms
and are reported net of an allowance for doubtful accounts. Prior to final
Federal Energy Regulatory Commission (FERC) approval of filed rates, the Company
is exposed to risk that FERC will ultimately approve the rates at a level lower
than those requested. The difference is subject to refund and reserves are
established, where required, for that purpose. The Company's operating revenues
and other financial information by segment for fiscal 2004, 2003 and 2002 are
presented in Note XXI -- Reportable Segments.
Earnings Per Share. The Company's earnings per share presentation conforms to
the FASB Standard, Earnings per Share. All share and per share data have been
appropriately restated for all stock dividends and stock splits distributed
through August 31, 2004 unless otherwise noted.
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 earnings and net earnings
available for 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:
Year Ended June 30,
-----------------------------------
2004 2003 2002
--------- --------- ---------
Net earnings, as reported........................................... $ 114,025 $ 76,189 $ 19,624
Add stock-based employee compensation expense
included in reported net earnings, net of related taxes......... -- -- --
Deduct total stock-based employee compensation
expense determined under fair value based method
for all awards, net of related taxes............................ 1,699 1,373 953
--------- --------- ---------
Pro forma net earnings.............................................. $ 112,326 $ 74,816 $ 18,671
========= ========= =========
Net earnings available for common shareholders per share:
Basic -- as reported................................................ $ 1.34 $ 1.26 $ 0.33
Basic -- pro forma.................................................. 1.32 1.23 0.31
Diluted -- as reported.............................................. 1.30 1.22 0.31
Diluted -- pro forma................................................ 1.29 1.21 0.30
The fair value of each option is estimated on the date of grant using the
Black-Scholes option-pricing model with the following assumptions used for
grants in 2004 and 2002, respectively: dividend yield of nil for all years;
volatility of 36.75% in 2004 and 33.5% for 2002; risk-free interest rate of
2.95% in 2004, and 3.75% in 2002; and expected life outstanding of 6 years for
2004 and 7 years for 2002. The weighted average fair value of options granted at
fair market value at their grant date during 2004 and 2002 were $7.35 and $6.92,
respectively. There were no options granted above fair market value at the grant
date during 2004 and 2002, respectively. No options were granted in 2003.
Accumulated Other 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 available for common shareholders, 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.
The table below gives an overview of comprehensive income for the periods
indicated.
Year Ended June 30,
----------------------------------
2004 2003 2002
----------------------------------
Net earnings ........................................................ $ 114,025 $ 76,189 $ 19,624
Other comprehensive income (loss):
Unrealized loss in investment securities, net of tax benefit ..... (21) (581) (18,249)
Unrealized gain (loss) on hedging activities, net of tax (benefit) 1,608 (5,568) 804
Minimum pension liability adjustment, net of tax (benefit) ...... 10,768 (41,930) (10,498)
--------- --------- ---------
Other comprehensive income (loss) ................................... 12,355 (48,079) (27,943)
--------- --------- ---------
Comprehensive income (loss) ......................................... $ 126,380 $ 28,110 $ (8,319)
========= ========= =========
Accumulated other comprehensive income (loss) reflected in the Consolidated
Balance Sheet at June 30, 2004 and 2003 includes unrealized gains and losses on
hedging activities and investment securities, and minimum pension liability
adjustments.
Significant Customers and Credit Risk. In the Distribution segment,
concentrations of credit risk in trade receivables are limited due to the large
customer base with relatively small individual account balances. In addition,
Company policy requires a deposit from customers who lack a credit history or
whose credit rating is substandard. The Company has recorded an allowance for
doubtful accounts, totaling $13,502,000, $16,823,000, $15,324,000 and
$28,347,000 at June 30, 2004, 2003, 2002 and 2001, respectively, relating to its
Distribution segment trade receivables. The allowance for doubtful accounts is
adjusted for changes in estimated uncollectible accounts and reduced for the
write-off of trade receivables.
In the Transportation and Storage segment, aggregate sales to Panhandle Energy's
top 10 customers accounted for 70% of segment operating revenues and 19% of the
Company's total operating revenues in fiscal 2004. This included sales to
Proliance Energy, LLC, a nonaffiliated local distribution company and gas
marketer, which accounted for 17% of segment operating revenues; sales to BG LNG
Services, a nonaffiliated gas marketer, which accounted for 16% of segment
operating revenues; and sales to CMS Energy Corporation, Panhandle Energy's
former parent, which accounted for 11% of the 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 in 2004. Panhandle Energy manages trade credit risks to minimize
exposure to uncollectible trade receivables. Prospective and existing customers
are reviewed for creditworthiness based upon pre-established standards.
Customers that do not meet minimum standards are required to provide additional
credit support. The Company has recorded an allowance for doubtful accounts
totaling $1,422,000 and $4,138,000 at June 30, 2004 and 2003, respectively,
relating to its Transportation and Storage segment trade receivables.
Inventories. In the Distribution segment, inventories consist of natural gas in
underground storage and materials and supplies, both of which are carried at
weighted average cost. Natural gas in underground storage
at June 30, 2004 and 2003 was $116,292,000 and $117,679,000, respectively, and
consisted of 19,918,000 and 20,853,000 million British thermal units (MMBtu),
respectively.
In the Transportation and Storage segment, inventories consist of gas held for
operations and materials and supplies. All gas held for operations and materials
and supplies purchased are recorded at the lower of weighted average cost or
market, while gas received from or owed back to customers is valued at market.
The gas held for operations that is not expected to be consumed in operations in
the next twelve months is reflected in non-current assets. Gas held for
operations at June 30, 2004 was $94,586,000, or 17,562,000 MMBtu, of which
$28,999,000 is classified as non-current. Gas held for operations at June 30,
2003 was $57,647,000, or 11,657,000 MMBtu, of which $22,769,000 is classified as
non-current.
Goodwill and Other Intangible Assets. The Company accounts for its goodwill and
other intangible assets in accordance with the FASB Standard, Accounting for
Goodwill and Other Intangible Assets. Under this Statement, the Company has
ceased amortization of goodwill. Goodwill, which was previously classified on
the consolidated balance sheet as additional purchase cost assigned to utility
plant and amortized on a straight-line basis over forty years, is now subject to
at least an annual assessment for impairment by applying a fair-value based
test. See Note VII - Goodwill and Intangibles.
Fair Value of Financial Instruments. The carrying amounts reported in the
balance sheet for cash and cash equivalents, accounts receivable, accounts
payable, derivative instruments and notes payable approximate their fair value.
The fair value of the Company's long-term debt is estimated using current market
quotes and other estimation techniques.
Gas Imbalances. In the Transportation and Storage segment, gas imbalances occur
as a result of differences in volumes of gas received and delivered. The Company
records gas imbalance in-kind receivables and payables at cost or market, based
on whether net imbalances have reduced or increased system gas balances,
respectively. Net imbalances which have reduced system gas are valued at the
cost basis of the system gas, while net imbalances which have increased system
gas and are owed back to customers are priced, along with the corresponding
system gas, at market.
Fuel Tracker. Liability accounts are maintained in the Transportation and
Storage segment for net volumes of fuel gas owed to customers collectively.
Trunkline records an asset whenever fuel is due from customers from prior under
recovery based on contractual and specific tariff provisions, which support the
treatment as an asset. Panhandle Energy's other companies that are subject to
fuel tracker provisions record an expense when fuel is under recovered. The
pipelines' fuel reimbursement is in-kind and non-discountable.
Interest Cost Capitalized. The Company capitalizes interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use in accordance with the FASB Standard, Capitalization of Interest
Cost. Interest costs incurred during the construction period are capitalized and
amortized over the life of the assets.
Derivative Instruments and Hedging Activities. The Company accounts for its
derivatives in accordance with the FASB Standard, Accounting for Derivative
Instruments and Hedging Activities, as amended. Under this Statement, all
derivatives are recognized on the balance sheet at their fair value. On the date
the derivative contract is entered into, management designates the derivative as
either: (i) a hedge of the fair value of a recognized asset or liability or of
an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a
forecasted transaction or of the variability of cash flows to be received or
paid in connection with a recognized asset or liability (a cash flow hedge); or
(iii) an instrument that is held for trading or non-hedging purposes (a trading
or non-hedging instrument). Changes in the fair value of a derivative that
qualifies as a fair-value hedge, along with the gain or loss on the hedged asset
or liability that is attributable to the hedged risk are recorded in earnings.
Changes in the fair value of a derivative that qualifies as a cash-flow hedge,
to the extent that the hedge is effective, are recorded in other comprehensive
income, until earnings are affected by the variability of cash flows of the
hedged transaction (e.g., until periodic settlements of a variable-rate asset or
liability are recorded in earnings). Hedge ineffectiveness is recorded through
earnings immediately. Lastly, changes in the fair value of derivative trading
and non-hedging instruments are reported in current-period earnings. Fair value
is determined based upon mathematical models using current and historical data.
The Company formally assesses both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions have been
highly effective in offsetting changes in the fair value or cash flows of hedged
items and whether those derivatives may be expected to remain highly effective
in future periods. The Company discontinues hedge accounting when: (i) it
determines that the derivative is no longer effective in offsetting changes in
the fair value or cash flows of a hedged item; (ii) the derivative expires or is
sold, terminated, or exercised; (iii) it is no longer probable that the
forecasted transaction will occur; or (iv) management determines that
designating the derivative as a hedging instrument is no longer appropriate. In
all situations in which hedge accounting is discontinued and the derivative
remains outstanding, the Company will carry the derivative at its fair value on
the balance sheet, recognizing changes in the fair value in current-period
earnings. See Note XI -- 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 used to reduce
interest rate risks and to manage interest expense. Commodity swaps have been
employed to manage price risk associated with certain energy contracts.
Asset Retirement Obligations.
The Company accounts for its asset retirement obligations in accordance with the
FASB Standard, Accounting for Asset Retirement Obligations (ARO). The Statement
requires legal obligations associated with the retirement of long-lived assets
to be recognized at their fair value at the time the obligations are incurred.
Upon initial recognition of a liability, costs should be capitalized as part of
the related long-lived asset and allocated to expense over the useful life of
the asset. Over time, the liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of the
related long-lived asset. In certain rate jurisdictions, the Company is
permitted to include annual charges for cost of removal in its regulated cost of
service rates charged to customers. The adoption of the Statement did not have a
material impact on the Company's financial position, results of operations or
cash flows for all periods presented.
Panhandle Energy has an ARO liability relating to the retirement of certain of
its offshore lateral lines with an aggregate carrying amount of approximately
$6,407,000 and $6,757,000 as of June 30, 2004 and 2003, respectively. During the
year ended June 30, 2004, changes in the carrying amount of the ARO liability
were attributable to $395,000 of additional liabilities incurred, and $628,000
of accretion expense. Liabilities settled and cash flow revisions were
$1,373,000 for fiscal 2004.
In fiscal 2003, the Company reclassified approximately $27,000,000 of negative
salvage previously included in accumulated depreciation to deferred credits for
amounts collected for asset retirement obligations on certain of the Panhandle
Energy assets acquired which were not liabilities under the Statement but
represented other regulatory obligations.
New Pronouncements.
In April 2003, the FASB issued Amendment of Statement 133 on Derivative
Instruments and Hedging Activities. The Statement is effective for contracts
entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. The Statement (i) clarifies under what
circumstances a contract with an initial net investment meets the characteristic
of a derivative, (ii) clarifies when a derivative contains a financing
component, (iii) amends the definition of an underlying to conform it to
language used in FASB Interpretation Guarantor's Accounting and Disclosure
Requirement for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, and (iv) amends certain other existing pronouncements. The Statement did
not materially change the methods the Company uses to account for and report its
derivatives and hedging activities.
Effective July 1, 2003, the Company adopted the FASB Standard, Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity. The Statement establishes guidelines on how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. The Statement further defines and requires that certain instruments
within its scope be classified as liabilities on the financial statements. The
adoption of the Statement did not have a material impact on the Company's
financial position, results of operations or cash flows for the periods
presented.
Effective January 1, 2004, the Company adopted the FASB Standard, Employers'
Disclosures about Pensions and Other Postretirement Benefits - an amendment of
FASB Statements No. 87, 88, and 106. The Statement revises employers'
disclosures about pension plans and other postretirement benefit plans. It
retains the disclosure requirements contained in FASB Statement No. 132,
Employers' Disclosures about Pensions and Other Postretirement Benefits, which
it replaces, and requires additional disclosure about the assets, obligations,
cash flows and net periodic benefit cost of defined benefit pension plans and
other defined benefit postretirement plans. The Statement does not change the
measurement or recognition of those plans required by FASB Statements No. 87,
Employers' Accounting for Pensions, No. 88, Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits, and No. 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions.
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 June 30, 2004, this Issue did not change the method used by the
Company to calculate its earnings per share for the period ended June 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.
Use of Estimates. The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
II Acquisitions and Sales
On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy
Corporation for approximately $581,729,000 in cash and 3,000,000 shares of
Southern Union common stock (before adjustment for subsequent stock dividends)
valued at approximately $48,900,000 based on market prices at closing of the
Panhandle Energy acquisition and in connection therewith incurred transaction
costs of approximately $31,922,000. At the time of the acquisition, Panhandle
Energy had approximately $1,157,228,000 of debt principal outstanding that it
retained. The Company funded the cash portion of the acquisition with
approximately $437,000,000 in cash proceeds it received for the January 1, 2003
sale of its Texas operations, approximately $121,250,000 of the net proceeds it
received from concurrent common stock and equity unit offerings (see Note X -
Stockholders' Equity) and with working capital available to the Company. The
Company structured the Panhandle Energy acquisition and the sale of its Texas
operations to qualify as a like-kind exchange of property under Section 1031 of
the Internal Revenue Code of 1986, as amended. The acquisition was accounted for
using the purchase method of accounting in accordance with accounting principles
generally accepted within the United States of America with the purchase price
paid and acquisition costs incurred by the Company allocated to Panhandle
Energy's net assets as of the acquisition date. The Panhandle Energy assets
acquired and liabilities assumed have been recorded at their estimated fair
value as of the acquisition date based on the results of outside appraisals.
Panhandle Energy's results of operations have been included in the Consolidated
Statement of Operations since June 11, 2003. Thus, the Consolidated Statement of
Operations for the periods subsequent to the acquisition is not comparable to
the same periods in prior years.
Panhandle Energy is primarily engaged in the interstate transportation and
storage of natural gas and also provides liquefied natural gas (LNG)
terminalling and regasification services and is subject to the rules and
regulations of the Federal Energy Regulatory Commission (FERC). The Panhandle
Energy entities include Panhandle Eastern Pipe Line Company, LP (Panhandle
Eastern Pipe Line), Trunkline Gas Company, LLC (Trunkline), a wholly-owned
subsidiary of Panhandle Eastern Pipe Line, Sea Robin Pipeline Company (Sea
Robin), a Louisiana joint venture and an indirect wholly-owned subsidiary of
Panhandle Eastern Pipe Line, Trunkline LNG Company, LLC (Trunkline LNG) which is
a wholly-owned subsidiary of Trunkline LNG Holdings, LLC (LNG Holdings), an
indirect wholly-owned subsidiary of Panhandle Eastern Pipe Line and Pan Gas
Storage, LLC (d.b.a. Southwest Gas Storage), a wholly-owned subsidiary of
Panhandle Eastern Pipe Line. Collectively, the pipeline assets include more than
10,000 miles of interstate pipelines that transport natural gas from the Gulf of
Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major
U.S. markets in the Midwest and Great Lakes region. The pipelines have a
combined peak day delivery capacity of 5.4 billion cubic feet (Bcf) per day and
72 Bcf of owned underground storage capacity and 6.3 Bcf of above ground LNG
storage capacity. Trunkline LNG, located on Louisiana's Gulf Coast, operates one
of the largest LNG import terminals in North America, based on current send out
capacity.
The following table summarizes the estimated fair values of the Panhandle Energy
assets acquired and liabilities assumed at the date of acquisition. These fair
values were recorded based on the finalization of outside appraisals and reflect
a net reduction of approximately $16,000,000 from the initial purchase price
allocation as a result of purchase accounting adjustments during fiscal 2004.
At June 11, 2003
----------------
(in thousands)
Property, plant and equipment (excluding intangibles) ...... $ 1,904,762
Intangibles ................................................ 9,503
Current assets (1).......................................... 217,645
Other non-current assets.................................... 30,098
----------------
Total assets acquired.................................. 2,162,008
----------------
Long-term debt.............................................. (1,207,617)
Current liabilities......................................... (165,585)
Other non-current liabilities............................... (125,785)
----------------
Total liabilities assumed.............................. (1,498,987)
----------------
Net assets acquired................................ $ 663,021
================
(1) Includes cash and cash equivalents of approximately $60 million.
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK, Inc. (ONEOK) for
approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000.
In accordance with accounting principles generally accepted within the United
States of America, the results of operations and gain on sale of the Texas
operations have been segregated and reported as "discontinued operations" in the
Consolidated Statement of Operations and as "assets held for sale" in the
Consolidated Statement of Cash Flows for the respective periods.
In April 2002, PG Energy Services' (Energy Services) propane operations, which
sold liquid propane to residential, commercial and industrial customers, were
sold for $2,300,000, resulting in a pre-tax gain of $1,200,000. In July 2001,
Energy Services' commercial and industrial gas marketing contracts were sold for
$4,972,000, resulting in a pre-tax gain of $4,653,000.
In October 2001, Morris Merchants, Inc., which served as a manufacturers'
representative agency for franchised plumbing and heating contract supplies
throughout New England, was sold for $1,586,000. In September 2001, Valley
Propane, Inc., which sold liquid propane to residential, commercial and
industrial customers, was sold for $5,301,000. In August 2001, ProvEnergy Oil
Enterprises, Inc., which operated a fuel oil distribution business through its
subsidiary, ProvEnergy Fuels, Inc. for residential and commercial customers, was
sold for $15,776,000. No financial gain or loss was recognized on any of these
sales transactions.
Pro Forma Financial Information
The following unaudited pro forma financial information for the years ended June
30, 2003 and 2002 is presented as though the following events had occurred at
the beginning of the earliest period presented: (i) acquisition of Panhandle
Energy; (ii) the issuance of the common stock and equity units in June 2003; and
(iii) the refinancing of certain short-term and long-term debt at the time of
the Panhandle Energy acquisition. The pro forma financial information is not
necessarily indicative of the results which would have actually been obtained
had the acquisition of Panhandle Energy, the issuance of the common stock and
equity units, or the refinancings been completed as of the assumed date for the
period presented or which may be obtained in the future.
(Unaudited)
Year Ended June 30,
2003 2002
------------- --------------
Operating revenues.......................................... $ 1,671,114 $ 1,467,630
Net earnings from continuing operations..................... 132,458 56,073
Net earnings per share from continuing operations:
Basic.................................................. 1.76 0.75
Diluted................................................ 1.72 0.72
III Other Income (Expense), Net
Other income in 2004 of $5,468,000 includes a gain of $6,354,000 on the early
extinguishment of debt and income of $2,230,000 generated from the sale and/or
rental of gas-fired equipment and appliances from various operating
subsidiaries. These items were partially offset by charges of $1,603,000 and
$1,150,000 to reserve for the impairment of Southern Union's investments in a
technology company and in an energy-related joint venture, respectively, and
$836,000 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 in 2003 of $18,394,000 includes a gain of $22,500,000 on the
settlement of the Southwest litigation and income of $2,016,000 generated from
the sale and/or rental of gas-fired equipment and appliances. These items were
partially offset by $5,949,000 of legal costs related to the Southwest
litigation and $1,298,000 of selling costs related to the Texas operations'
disposition.
Other income in 2002 of $14,278,000 includes gains of $17,166,000 generated
through the settlement of several interest rate swaps, the recognition of
$6,204,000 in previously recorded deferred income related to financial
derivative energy trading activity of a former subsidiary, a gain of $4,653,000
realized through the sale of marketing contracts held by PG Energy Services
Inc., income of $2,234,000 generated from the sale and/or rental of gas-fired
equipment and appliances by various operating subsidiaries, a gain of $1,200,000
realized through the sale of the propane assets of PG Energy Services Inc.,
$1,004,000 of realized gains on the sale of a portion of Southern Union's
holdings in Capstone, and power generation and sales income of $971,000
primarily from PEI Power Corporation. These items were partially offset by a
non-cash charge of $10,380,000 to reserve for the impairment of the Company's
investment in a technology company, $9,100,000 of legal costs associated with
ongoing litigation from the unsuccessful acquisition of Southwest, and a
$1,500,000 loss on the sale of the Florida Operations.
IV Cash Flow Information
The Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents. Short-term investments are highly
liquid investments with maturities of more than three months when purchased, and
are carried at cost, which approximates market. The Company places its temporary
cash investments with a high credit quality financial institution which, in
turn, invests the temporary funds in a variety of high-quality short-term
financial securities.
Under the Company's cash management system, checks issued but not presented to
banks frequently result in overdraft balances for accounting purposes and are
classified in accounts payable in the Consolidated Balance Sheet.
V Earnings Per Share
The following table summarizes the Company's basic and diluted earnings per
share calculations for 2004, 2003, and 2002:
Year Ended June 30,
-------------------------------------
2004 2003 2002
----------- ----------- -----------
Net earnings available for common shareholders
from continuing operations net of dividends on preferred stock ..... $ 101,339 $ 43,669 $ 1,520
Net earnings from discontinued operations ............................... -- 32,520 18,104
----------- ----------- -----------
Net earnings available for common shareholders .......................... $ 101,339 $ 76,189 $ 19,624
=========== =========== ===========
Weighted average shares outstanding -- basic ............................ 75,442,238 60,584,293 59,420,048
========== ========== ==========
Weighted average shares outstanding -- diluted .......................... 77,694,532 62,523,107 62,596,874
========== ========== ==========
Basic earnings per share:
Net earnings available for common shareholders
from continuing operations net of dividends on preferred stock.... $ 1.34 $ 0.72 $ 0.03
Net earnings from discontinued operations............................ -- 0.54 0.30
----------- ---------- -----------
Net earnings available for common shareholders....................... $ 1.34 $ 1.26 $ 0.33
=========== ========== ===========
Diluted earnings per share:
Net earnings available for common shareholders
from continuing operations net of dividends on preferred stock.... $ 1.30 $ 0.70 $ 0.02
Net earnings from discontinued operations............................ -- 0.52 0.29
----------- ---------- -----------
Net earnings available for common shareholders....................... $ 1.30 $ 1.22 $ 0.31
=========== ========== ===========
During the three-year period ended June 30, 2004, no adjustments were required
in net earnings available for common shareholders for the earnings per share
calculations. Diluted earnings per share include average shares outstanding as
well as common stock equivalents from stock options, warrants and mandatory
convertible equity units. Common stock equivalents were 1,095,220, 669,581 and
1,828,993 for the years ended June 30, 2004, 2003 and 2002, respectively. During
2004, 2003 and 2002, the Company repurchased 122,203, 156,340 and 2,115,916
shares of its common stock outstanding, respectively. Substantially all of these
repurchases occurred in private off-market large-block transactions.
Stock options to purchase 290,893 and 2,308,870, shares of common stock were
outstanding during the years ended June 30, 2004 and 2003, respectively but were
not included in the computation of diluted earnings per share because the
options' exercise price was greater than the average market price of the common
shares during the respective period. There were no "anti-dilutive" options
outstanding for the same period in 2002. At June 30, 2004, 1,089,147 shares of
common stock were held by various rabbi trusts for certain of the Company's
benefit plans and 110,996 shares were held in a rabbi trust for certain
employees who deferred receipt of Company shares for stock options exercised.
From time to time, the Company's benefit plans may purchase shares of Southern
Union common stock subject to regular restrictions.
On June 11, 2003, the Company issued 2,500,000 mandatory convertible equity
units at a public offering price of $50.00 per share. Each equity unit consists
of a $50.00 principal amount of the Company's 2.75% Senior Notes due 2006 (see
Note XIII -- Debt and Capital Lease) and a forward stock purchase contract that
obligates the holder to purchase Company common stock on August 16, 2006, at a
price based on the preceding 20-day average closing price (subject to a minimum
and maximum conversion price per share of $14.51 and $17.71, respectively, which
are subject to adjustments for future stock splits or stock dividends). The
Company will issue between 7,060,067 shares and 8,613,281 shares of its common
stock (also subject to adjustments for future stock splits or stock dividends)
upon the consummation of the forward purchase contract. Until the conversion
date, the equity units will have a dilutive effect on earnings per share if the
Company's average common stock price for the period exceeds the maximum
conversion price. See Note X - Stockholder's Equity.
VI Property, Plant and Equipment
Plant. Plant in service and construction work in progress are stated at cost net
of contributions in aid of construction and includes intangible assets and
related amortization. The Company capitalizes all construction-related direct
labor costs, as well as indirect construction costs. The cost of replacements
and betterments that extend the useful life of property, plant and equipment is
also capitalized. The cost of additions includes an allowance for funds used
during construction and applicable overhead charges. Gain or loss is recognized
upon the disposition of significant properties and other property constituting
operating units. The Company capitalizes the cost of significant
internally-developed computer software systems. See Note XIII -- Debt and
Capital Lease.
June 30,
----------------------------
2004 2003
----------------------------
Distribution plant............................................................... $ 1,662,345 $ 1,611,098
Transmission plant............................................................... 1,159,825 1,238,972
General plant.................................................................... 529,599 462,730
Underground storage plant........................................................ 287,005 236,639
Gathering plant.................................................................. 39,746 56,076
Other............................................................................ 96,308 107,444
------------- -------------
Total plant................................................................. 3,774,828 3,712,959
Less contributions in aid of construction........................................ (2,212) (2,418)
------------- -------------
Plant in service............................................................ 3,772,616 3,710,541
Construction work in progress.................................................... 169,264 75,484
------------- -------------
3,941,880 3,786,025
Less accumulated depreciation and amortization................................... (734,367) (641,225)
------------- -------------
Net property, plant and equipment........................................... $ 3,207,513 $ 3,144,800
============= =============
Acquisitions of rate-regulated utilities are recorded at the historical book
carrying value of utility plant.
Depreciation and Amortization. Depreciation and amortization of plant is
generally computed using the straight-line method at an average straight-line
rate of approximately 3% per annum of the cost of such depreciable properties
less applicable salvage. Franchises are amortized over their respective lives.
Depreciation and amortization of other property is provided at straight-line
rates estimated to recover the costs of the properties, after allowance for
salvage, over their respective lives. Internally-developed computer software
system costs are amortized over various periods.
VII Goodwill and Intangibles
Effective July 1, 2001, the Company adopted Goodwill and Other Intangible Assets
which was issued by the FASB in June 2001. In accordance with this Statement,
the Company has ceased amortization of goodwill. Goodwill, which was previously
classified on the Consolidated Balance Sheet as additional purchase cost
assigned to utility plant and amortized on a straight-line basis over forty
years, is now subject to at least an annual assessment for impairment by
applying a fair-value based test.
The following displays changes in the carrying amount of goodwill:
Total
------------
Balance as of July 1, 2001...................................... $ 652,048
Impairment losses............................................ (1,417)
Sale of subsidiaries and other operations.................... (7,710)
------------
Balance as of June 30, 2002..................................... 642,921
Impairment losses............................................ --
Sale of subsidiaries and other operations.................... --
------------
Balance as of June 30, 2003..................................... 642,921
Impairment losses............................................ --
Reversal of income tax reserve............................... (2,374)
------------
Balance as of June 30, 2004..................................... $ 640,547
============
In connection with the Company's Cash Flow Improvement Plan announced in July
2001, the Company began the divestiture of certain non-core assets. As a result
of prices of comparable businesses for various non-core properties, a goodwill
impairment loss of $1,417,000 was recognized in depreciation and amortization on
the Consolidated Statement of Operations for the quarter ended September 30,
2001. As a result of the sale of the Florida Operations, goodwill of $7,710,000
was eliminated during the quarter ended December 31, 2001. As a result of the
sale of the Texas Operations, goodwill of $70,469,000 (See Note XIX-
Discontinued Operations) was also eliminated during the quarter ended March 31,
2003. As a result of the reversal of income tax reserves related to the purchase
of PG Energy, goodwill of $2,347,000 was eliminated during the quarter ended
June 30, 2004. As of June 30, 2004, the Distribution segment has goodwill of
$640,547,000. The Distribution segment is tested annually for impairment in the
fourth quarter, after the annual forecasting process. There was no indication of
impairment at June 30, 2004.
On June 11, 2003, the Company completed its acquisition of Panhandle Energy.
Based on purchase price allocations which rely on estimates and outside
appraisals, the acquisition resulted in no recognition of goodwill as of the
acquisition date. In addition, based on the purchase price allocations and the
outside appraisals, the acquisition resulted in the recognition of intangible
assets relating to customer relationships of approximately $9,503,000. These
intangibles are currently being amortized over a period of twenty years, the
remaining life of the contract for which the value is associated. As of June 30,
2004, the carrying amount of these intangibles was approximately $8,720,000 and
is included in Property, Plant and Equipment on the Consolidated Balance Sheet.
Amortization for fiscal 2004 and 2003 was approximately $583,000 and $200,000,
respectively.
VIII Deferred Charges and Deferred Credits
June 30,
--------
2004 2003
---- ----
Deferred Charges
Pensions...................................................................... $ 45,625 $ 39,088
Unamortized debt expense...................................................... 38,596 34,209
Income taxes.................................................................. 31,441 30,514
Retirement costs other than pensions.......................................... 26,008 29,028
Service Line Replacement program.............................................. 16,722 18,974
Environmental................................................................. 12,220 14,304
Other......................................................................... 20,123 22,144
------------ ----------
Total Deferred Charges..................................................... $ 190,735 $ 188,261
============ ==========
The Company's deferred charges include regulatory assets relating to
Distribution segment operations in the aggregate amount of $99,314,000 and
$107,696,000, respectively, at June 30, 2004 and 2003, of which $63,010,000 and
$74,116,000, respectively, is being recovered through current rates. As of June
30, 2004 and 2003, the remaining recovery period associated with these assets
ranges from 1 month to 208 months and from 6 months to 147 months, respectively.
None of these regulatory assets, which primarily relate to pensions, retirement
costs other than pensions, income taxes, Year 2000 costs, Missouri Gas Energy's
Service Line Replacement program and environmental remediation costs, are
included in rate base. The Company records regulatory assets in accordance with
the FASB standard, Accounting for the Effects of Certain Types of Regulation.
June 30,
-------------------
2004 2003
---- ----
Deferred Credits
Pensions................................................................... $ 97,380 $ 88,016
Retirement costs other than pensions....................................... 60,404 65,144
Cost of Removal............................................................ 28,519 27,286
Environmental.............................................................. 23,082 32,322
Derivative instrument liability............................................ 13,704 26,151
Customer advances for construction......................................... 13,518 12,008
Provision for self-insured claims.......................................... 10,542 12,000
Investment tax credit...................................................... 5,367 5,791
Other...................................................................... 40,430 53,436
------------ --------------
Total Deferred Credits................................................. $ 292,946 $ 322,154
============ ==============
The Company's deferred credits include regulatory liabilities relating to
Distribution segment operations in the aggregate amount of $11,164,000 and
$10,084,000, respectively, at June 30, 2004 and 2003. These regulatory
liabilities primarily relate to retirement benefits other than pensions,
environmental insurance recoveries and income taxes. The Company records
regulatory liabilities with respect to its Distribution segment operations in
accordance with the FASB Standard Accounting for the Effects of Certain Types of
Regulation.
IX Investment Securities
At June 30, 2004, all securities owned by the Company 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.
Realized gains and losses on sales of these investments, as determined on a
specific identification basis, are included in the Consolidated Statement of
Operations when incurred, and dividends are recognized as income when received.
Various Southern Union executive management, 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, it 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 and June 2002, Southern Union determined that declines in the
value of its investment in PointServe were other than temporary. Accordingly,
the Company recorded non-cash charges of $1,603,000 and $10,380,000 during the
quarters ended September 30, 2003 and June 30, 2002, respectively, to reduce the
carrying value of this investment to its estimated fair value. The Company
recognized these valuation adjustments to reflect significant lower private
equity valuation metrics and changes in the business outlook of PointServe.
PointServe is a closely held, privately owned company and, as such, has no
published market value. The Company's remaining investment of $2,603,000 at June
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.
X Stockholders' Equity
Stock Splits and Dividends. On August 31, 2004, July 31, 2003 and July 15, 2002,
Southern Union distributed its annual 5% common stock dividend to stockholders
of record on August 20, 2004, July 17, 2003 and July 1, 2002, respectively. A
portion of the 5% stock dividend distributed on July 15, 2002 was characterized
as a distribution of capital due to the level of the Company's retained earnings
available for distribution as of the declaration date. Unless otherwise stated,
all per share and share data included herein have been restated to give effect
to the dividends.
Common Stock. On November 4, 2003, the stockholders of the Company adopted the
2003 Stock and Incentive Plan (2003 Plan) under which options to purchase
7,350,000 shares were provided to be granted to officers and key employees at
prices not less than fair market value on the date of the grant, until September
28, 2013. The 2003 Plan allows for the granting of stock appreciation rights,
stock awards, performance units, dividend equivalents, incentive options,
non-statutory options, and other equity-based rights. Options granted under the
2003 Plan are exercisable for periods of ten years from the date of the grant or
such lesser period as may be designated for particular options, and become
exercisable after a specified period of time from the date of grant in
cumulative annual installments.
The Company maintains its 1992 Long-Term Stock Incentive Plan (1992 Plan) under
which options to purchase 8,491,540 shares were provided to be granted to
officers and key employees at prices not less than the fair market value on the
date of grant, until July 1, 2002. The 1992 Plan allowed for the granting of
stock appreciation rights, dividend equivalents, performance shares and
restricted stock. Options granted under the 1992 Plan are exercisable for
periods of ten years from the date of grant or such lesser period as may be
designated for particular options, and become exercisable after a specified
period of time from the date of grant in cumulative annual installments. Options
typically vest 20% per year for five years but may be a lesser or greater period
as designated for a particular option grant.
In connection with the acquisition of the Pennsylvania Operations, the Company
adopted the Pennsylvania Division 1992 Stock Option Plan (Pennsylvania Option
Plan) and the Pennsylvania Division Stock Incentive Plan (Pennsylvania Incentive
Plan). Under the terms of the Pennsylvania Option Plan, a total of 459,467
shares were provided to be granted to eligible employees. Stock options awarded
under the Pennsylvania Option Plan may be either Incentive Stock Options or
Nonqualified Stock Options. Upon acquisition, individuals not electing a cash
payment equal to the difference at the date of acquisition between the option
price and the market price of the shares as to which such option related, were
converted to Southern Union options using a conversion rate that maintained the
same aggregate value and the aggregate spread of the pre-acquisition options. No
additional options will be granted under the Pennsylvania Option Plan. During
2004 and 2003, no options and 15,538 options, respectively, were exercised and
443,929 options outstanding and exercisable still remain in the plan. Under the
terms of the Pennsylvania Incentive Plan, a total of 220,635 shares were
provided to be granted to eligible employees, officers and directors. Awards
under the Pennsylvania Incentive Plan may take the form of stock options,
restricted stock, and other awards where the value of the award is based upon
the performance of the Company's stock. Upon acquisition, individuals not
electing a cash payment equal to the difference at the date of acquisition
between the option price and the market price of the shares as to which such
option related, were converted to Southern Union options using a conversion rate
that maintained the same aggregate value and the aggregate spread of the
pre-acquisition options. No additional options will be granted under the
Pennsylvania Incentive Plan. During 2004 and 2003, no options were exercised and
220,635 and 217,571 options outstanding and exercisable still remain in the
plan.
The following table provides information on stock options granted, exercised,
canceled and outstanding under the 2003 Plan and the 1992 Plan for the past
three years:
2003 Plan 1992 Plan
--------- ---------
Weighted Weighted
Shares Under Average Shares Under Average
Option Exercise Price Option Exercise Price
------ -------------- ------ --------------
Outstanding July 1, 2001........................... -- $ -- 4,957,666 $ 11.29
Granted .................................... -- -- 75,249 13.83
Exercised..................................... -- -- (1,020,546) 9.54
Canceled ..................................... -- -- (188,856) 14.45
---------- ----------
Outstanding June 30, 2002.......................... -- -- 3,823,513 11.65
Granted ..................................... -- -- -- --
Exercised..................................... -- -- (662,982) 4.65
Canceled ..................................... -- -- (185,161) 14.67
---------- ----------
Outstanding June 30, 2003.......................... -- -- 2,975,370 13.02
Granted ..................................... 729,227 17.67 -- --
Exercised..................................... -- -- (352,486) 9.91
Canceled ..................................... -- -- (2,190) 15.38
---------- ----------
Outstanding June 30, 2004.......................... 729,227 17.67 2,620,694 13.44
========== ==========
The following table summarizes information about stock options outstanding under
the 1992 Plan at June 30, 2004:
Options Outstanding Options Exercisable
- ----------------------------------------------------------------- ---------------------------------
Weighted Average Weighted Weighted
Range of Number of Remaining Average Number of Average
Exercise Prices Options Contractual Life Exercise Price Options Exercise Price
- --------------- -------- ----------------- -------------- ------- --------------
$ 0.00 - $ 7.99 154,292 1.4 years $ 6.75 124,598 $ 6.75
8.00 - 11.99 291,780 2.9 years 10.22 291,780 10.22
12.00 - 13.99 563,896 4.3 years 13.26 529,595 13.26
14.00 - 17.99 1,610,726 5.9 years 14.72 1,062,093 14.60
--------- -----------
2,620,694 2,008,066
========= ===========
The weighted average remaining contractual life of options outstanding under the
2003 Plan, the Pennsylvania Option Plan and the Pennsylvania Incentive Plan at
June 30, 2004 was 9.6, 2.1 and 3.9 years, respectively. There were no shares
available for future option grants under the 1992 Plan at June 30, 2004.
The shares exercisable under the various plans and corresponding weighted
average exercise price for the past three years are as follows:
Pennsylvania Pennsylvania
1992 Option Incentive
Plan Plan Plan
---- ---- ----
Shares exercisable at:
June 30, 2004......................... 2,008,066 443,929 217,571
June 30, 2003......................... 1,966,753 443,929 214,507
June 30, 2002......................... 2,145,327 459,467 211,442
Weighted average exercise price at:
June 30, 2004......................... $ 13.12 $ 9.21 $ 10.65
June 30, 2003......................... 12.29 9.21 10.60
June 30, 2002......................... 9.51 9.12 10.55
There were no shares exercisable under the 2003 Plan at June 30, 2004.
Warrant. On February 10, 1994, Southern Union granted a warrant to purchase up
to 122,165 shares of its common stock at an exercise price of $5.68 to the
Company's outside legal counsel. On February 10, 2004, the Company's outside
legal counsel exercised the warrant through a non-cash exercise resulting in the
issuance of 84,758 shares of Company common stock.
Retained Earnings. Under the most restrictive provisions in effect, as a result
of the sale of Senior Notes, Southern Union will not declare or pay any cash or
asset dividends on common stock (other than dividends and distributions payable
solely in shares of its common stock or in rights to acquire its common stock)
or acquire or retire any shares of Southern Union's common stock, unless no
event of default exists and the Company meets certain financial ratio
requirements. Currently, the Company is in compliance with the most restrictive
provisions in the indenture governing the Senior Notes.
Fiscal 2005 Equity Issuances. 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.
Fiscal 2003 Equity Issuances. On June 11, 2003, the Company issued 9,500,000
shares of common stock at the public offering price of $16.00 per share. After
underwriting discounts and commissions, the Company realized net proceeds of
$146,700,000. The Company granted the underwriters a 30-day over-allotment
option to purchase up to an additional 1,425,000 shares of the Company's common
stock at the same price, which was exercised on June 11, 2003, resulting in
additional net proceeds to the Company of $22,000,000.
Also on June 11, 2003, the Company issued 3,000,000 shares of common stock from
its treasury stock to CMS Energy Corporation to finance its acquisition of
Panhandle Energy. The shares were valued at $16.30 per share, or $48,900,000,
based on the closing price for the Company's common stock as of June 10, 2003.
On June 11, 2003, the Company also issued 2,500,000 equity units at a public
offering price of $50 per unit, resulting in net proceeds to the Company, after
underwriting discounts and commissions, of $121,300,000. Each equity unit
consists of a stock purchase contract for the purchase of shares of the
Company's common stock and, initially, a senior note due August 16, 2006, issued
pursuant to the Company's existing Indenture. The equity units carry a total
annual coupon of 5.75% (2.75% annual face amount of the senior notes plus 3.0%
annual contract adjustment payments). Each stock purchase contract issued as a
part of the equity units carries a maximum conversion premium of up to 22% over
the $16.00 issuance price (before adjustment for subsequent stock dividends) of
the Company's common shares that were sold on June 11, 2003, as discussed
previously. The present value of the equity units contract adjustment payments
was initially charged to shareholders' equity, with an offsetting credit to
liabilities. The liability is accreted over three years by interest charges to
the Consolidated Statement of Operations. Before the issuance of the Company's
common stock upon settlement of the purchase contracts, the purchase contracts
will be reflected in the Company's diluted earnings per share calculations using
the treasury stock method.
XI Derivative Instruments and Hedging Activities
The Company utilizes derivative instruments on a limited basis to manage certain
business risks. Interest rate swaps and treasury rate locks are employed to
manage the Company's exposure to interest rate risk.
Cash Flow Hedges. As a result of the acquisition of Panhandle Energy, the
Company is party to interest rate swap agreements with an aggregate notional
amount of $197,947,000 as of June 30, 2004 that fix the interest rate applicable
to floating rate long-term debt and which qualify for hedge accounting. For the
year ended June 30, 2004, the amount of swap ineffectiveness was not
significant. As of June 30, 2004, floating rate LIBOR-based interest payments
are 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 June 30, 2004 and 2003, the fair value liability
position of the swaps was $14,445,000 and $26,058,000, respectively. As of June
30, 2004, approximately $1,068,000 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.
The Company was also party to an interest rate swap agreement with a notional
amount of $8,199,000 at June 30, 2003 that fixed the interest rate applicable to
floating rate long-term debt and which qualified for hedge accounting. The fair
value liability position of the swap was $93,000 at June 30, 2003. In October
2003, the swap expired and $15,000 of unrealized after-tax losses included in
accumulated other comprehensive income relating to this swap was reclassified to
interest expense during the quarter ended December 31, 2003.
In March and April 2003, the Company entered into a series of treasury rate
locks with an aggregate notional amount of $250,000,000 to manage its exposure
against changes in future interest payments attributable to changes in the
benchmark interest rate prior to the anticipated issuance of fixed-rate debt.
These treasury rate locks expired on June 30, 2003, resulting in a $6,862,000
after-tax loss that was recorded in accumulated other comprehensive income and
will be amortized into interest expense over the lives of the associated debt
instruments. As of June 30, 2004, approximately $981,000 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 an interest rate
swap 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 agreement 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 June 30, 2004, the fair value liability position of the swap was
$4,960,000, which reduced the carrying value of the underlying debt.
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 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 an asset and a
matching adjustment to deferred cost of gas of $1,337,000.
In March 2001, the Company discovered unauthorized financial derivative energy
trading activity by a non-regulated, wholly-owned subsidiary. All unauthorized
trading activity was subsequently closed in March and April of 2001 resulting in
a cumulative cash expense of $191,000, net of taxes, and deferred income of
$7,921,000 at June 30, 2001. For fiscal years 2004, 2003 and 2002, the Company
recorded $605,000, $605,000 and $6,204,000, respectively, through other income
relating to the expiration of contracts resulting from this trading activity.
The remaining deferred liability of $507,000 at June 30, 2004 related to these
derivative instruments will be recognized as income in the Consolidated
Statement of Operations over the next year based on the related contracts. The
Company established new limitations on trading activities, as well as new
compliance controls and procedures that are intended to make it easier to
identify quickly any unauthorized trading activities.
XII 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.
XIII Debt and Capital Lease
June 30,
--------
2004 2003
---- ----
Southern Union Company
7.60% Senior Notes due 2024...................................... $ 359,765 $ 359,765
8.25% Senior Notes due 2029...................................... 300,000 300,000
2.75% Senior Notes due 2006...................................... 125,000 125,000
Term Note, due 2005.............................................. 111,087 211,087
6.50% to 10.25% First Mortgage Bonds, due 2008 to 2029........... 113,435 115,884
7.70% Debentures, due 2027....................................... -- 6,756
Capital lease and other, due 2004 to 2007........................ 277 9,179
------------ ------------
1,009,564 1,127,671
Panhandle Energy
2.75% Senior Notes due 2007...................................... 200,000 --
4.80% Senior Notes due 2008...................................... 300,000 --
6.05% Senior Notes due 2013...................................... 250,000 --
6.125% Senior Notes due 2004..................................... -- 292,500
7.875% Senior Notes due 2004..................................... 52,455 100,000
6.50% Senior Notes due 2009...................................... 60,623 158,980
8.25% Senior Notes due 2010...................................... 40,500 60,000
7.00% Senior Notes due 2029...................................... 66,305 135,890
Term Loan due 2007............................................... 263,926 275,358
7.95% Debentures due 2023........................................ -- 76,500
7.20% Debentures due 2024........................................ -- 58,000
Net premiums on long-term debt................................... 16,199 61,506
------------ ------------
1,250,008 1,218,734
Total consolidated debt and capital lease........................ 2,259,572 2,346,405
Less current portion......................................... 99,997 734,752
Less fair value swap of Panhandle Energy..................... 4,960 --
------------ ------------
Total consolidated long-term debt and capital lease.............. $ 2,154,615 $ 1,611,653
============ ============
The maturities of long-term debt and capital lease payments for each of the next
five years ending June 30 are: 2005 -- $99,997,000; 2006 -- $90,475,000; 2007 --
$565,718,000; 2008 -- $1,648,000; 2009 -- $301,646,000 and thereafter
$1,183,890,000.
Each note, debenture or bond above is an obligation of Southern Union Company or
a unit of Panhandle Energy, as noted above. The Panhandle Energy Term Loan due
2007 is debt related to Panhandle's Trunkline LNG Holdings subsidiary, and is
non-recourse to other units of Panhandle Energy or Southern Union Company. The
remainder of Panhandle Energy's debt is non-recourse to Southern Union. All
debts that are listed as debt of Southern Union Company are direct obligations
of Southern Union Company, and no debt is cross-collateralized.
Debt issuance costs and premiums or discounts on the early extinguishment of
debt are accounted for in accordance with that required by its various
regulatory bodies having jurisdiction over the Company's operations. The Company
recognizes gains or losses on the early extinguishment of debt to the extent it
is provided for by its regulatory authorities, where applicable, and in some
cases such gains or losses are deferred and amortized over the term of the new
or replacement debt issues.
The 8.25% Notes and the 7.60% Senior Notes traded at $1,166 and $1,079 (per
$1,000 note), respectively on June 30, 2004, as quoted by a major brokerage
firm. The carrying amount of long-term debt at June 30, 2004 and 2003 was
$2,259,573,000 and $2,346,405,000, respectively. The fair value of long-term
debt at June 30, 2004 and 2003 was $2,336,292,000 and $2,408,532,000,
respectively.
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 August 28, 2000, the Company entered into the Term Note to fund
(i) the cash portion of the consideration to be paid to Fall River Gas'
stockholders; (ii) the all cash consideration to be paid to the ProvEnergy and
Valley Resources stockholders, (iii) repayment of approximately $50,000,000 of
long- and short-term debt assumed in the New England mergers, and (iv) related
acquisition costs. The Term Note, which initially expired on August 27, 2001,
was extended through August 26, 2002. On July 16, 2002, the Company repaid the
Term Note with the proceeds from the issuance of a $311,087,000 Term Note dated
July 15, 2002 (the 2002 Term Note) and borrowings under its revolving credit
facilities. The 2002 Term Note is held by a syndicate of sixteen banks, led by
JPMorgan Chase Bank, as Agent. Eleven of the sixteen banks were also among the
lenders of the Term Note. The 2002 Term Note carries a variable interest rate
that is tied to either the LIBOR or prime interest rates at the Company's
option. The interest rate spread over the LIBOR rate varies with the credit
rating of the Senior Notes by Standard and Poor's Rating Information Service
(S&P) and Moody's Investor Service, Inc. (Moody's), and is currently LIBOR plus
105 basis points. As of June 30, 2004, a balance of $111,087,000 was outstanding
on this 2002 Term Note at an effective interest rate of 2.42%. The 2002 Term
Note requires semi-annual principal repayments on February 15th and August 15th
of each year, with payments of $35,000,000 each being due February 15, 2005 and
August 15, 2005. The remaining principal amount of $41,087,000 is due August 26,
2005. No additional draws can be made on the 2002 Term Note.
Additional Debt. In connection with the Panhandle Energy acquisition, the
Company added a principal amount $1,157,228,000 in debt, which had a fair value
of $1,207,617,000 as of the June 11, 2003 acquisition date. The debt included
senior notes and debentures with interest rates ranging from 6.125% to 8.25% and
floating rate debt totaling $275,358,000, all of which is non-recourse to
Southern Union.
Panhandle Refinancing. In July 2003, Panhandle Energy announced a tender offer
for any and all of the $747,370,000 outstanding principal amount of five of its
series of senior notes outstanding at that point in time (the Panhandle Tender
Offer) and also called for redemption all of the outstanding $134,500,000
principal amount of its two series of debentures that were outstanding (the
Panhandle Calls). Panhandle Energy repurchased approximately $378,257,000 of the
principal amount of its outstanding debt through the Panhandle Tender Offer for
total consideration of approximately $396,445,000 plus accrued interest through
the purchase date. Panhandle Energy also redeemed approximately $134,500,000 of
debentures through the Panhandle Calls for total consideration of $139,411,000,
plus accrued interest through the redemption dates. As a result of the Panhandle
Tender Offer, the Company has recorded a pre-tax gain on the extinguishment of
debt of $6,354,000 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, pending
the repayment of the $52,455,000 principal amount of Panhandle Energy's 7.875%
Senior Notes due 2004 that matured on August 15, 2004.
Capital Lease. The Company completed the installation of an Automated Meter
Reading (AMR) system at Missouri Gas Energy during the first quarter of fiscal
year 1999. The installation of the AMR system involved an investment of
approximately $30,000,000, which is accounted for as a capital lease obligation.
As of June 30, 2004 and 2003, the capital lease obligation outstanding was nil
and $8,793,000, respectively. This system has significantly improved meter
reading accuracy and timeliness and provided electronic accessibility to meters
in residential customers' basements, thereby assisting in the reduction of the
number of estimated bills. Depreciation on the AMR system is provided at an
average straight-line rate of approximately 5% per annum of the cost of such
property.
Credit Facilities. 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 Long-Term Facility replaced the Company's
$150,000,000 and $225,000,000 credit facilities that expired on April 1, 2004
and May 29, 2004, respectively. The Company has additional availability under
uncommitted line of credit facilities (Uncommitted Facilities) with various
banks. Borrowings under the Long-Term Facility are available for Southern
Union's working capital, letter of credit requirements and other general
corporate purposes. 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
June 30, 2004, the commitment fees were an annualized 0.15%. The Long-Term
Facility requires the Company to meet certain covenants in order for the Company
to be able to borrow under that agreement. A balance of $21,000,000 and
$251,500,000 was outstanding under the Company's credit facilities at June 30,
2004 and 2003, respectively. As of August 16, 2004, there was a balance of
$79,500,000 outstanding under the Long-Term Facility.
XIV Employee Benefits
Pension and Other Post-Retirement Benefits. In fiscal 2004, the Company adopted
the FASB Standard, Employers' Disclosures about Pensions and Other
Postretirement Benefits - an amendment of FASB Statements No. 87, 88, and 106,
which changed the Company's reporting requirements for its pension and
post-retirement benefit plans. See Note I - Summary of Significant Accounting
Policies (New Pronouncements).
The Company maintains eight trusteed non-contributory defined benefit retirement
plans (Plans) which cover substantially all employees, except Panhandle Energy
employees (see Panhandle Energy, below). The Company funds the Plans' cost in
accordance with federal regulations, not to exceed the amounts deductible for
income tax purposes. The Plans' assets are invested in cash, government
securities, corporate bonds and stock, and various funds. The Company also has
two supplemental non-contributory retirement plans for certain executive
employees and other post-retirement benefit plans for its employees.
The Company uses a March 31 measurement date for the majority of its plans.
Post-retirement medical and other benefit liabilities are accrued on an
actuarial basis during the years an employee provides services. The following
table represents a reconciliation of the Company's retirement and other
post-retirement benefit plans at June 30, 2004 and 2003.
Pension Benefits Post-Retirement Benefits
---------------------------- ---------------------------
2004 2003 2004 2003
------------- ------------ ------------ ------------
Change in Benefit Obligation
Benefit obligation at beginning of year.................. $ 350,860 $ 317,012 $ 90,344 $ 76,596
Service cost............................................. 6,533 5,655 3,993 1,177
Interest cost............................................ 22,591 22,899 8,739 5,579
Benefits paid............................................ (20,649) (20,046) (6,263) (6,676)
Actuarial loss........................................... 21,796 26,350 7,687 13,357
Acquisition............................................ -- -- 42,752 --
Plan amendments.......................................... 7,703 1,095 5,173 311
Settlement recognition................................... (2,341) (2,105) -- --
------------- ------------ ------------ ------------
Benefit obligation at end of year........................ $ 386,493 $ 350,860 $ 152,425 $ 90,344
============= ============ ============ ============
Change in Plan Assets
Fair value of plan assets at beginning of year........... $ 237,376 $ 284,911 $ 21,332 $ 22,408
Return on plan assets.................................... 55,725 (30,900) 3,211 27
Employer contributions................................... 6,043 5,516 15,724 5,572
Benefits paid............................................ (20,649) (20,046) (6,263) (6,675)
Settlement recognition................................... (2,341) (2,105) -- --
------------- ------------ ------------ ------------
Fair value of plan assets at end of year................. $ 276,154 $ 237,376 $ 34,004 $ 21,332
============= ============ ============ ============
Pension Benefits Post-Retirement Benefits
---------------------------- ---------------------------
2004 2003 2004 2003
------------- ------------ ------------ ------------
Funded Status
Funded status at end of year............................. $ (110,339) $ (113,484) $ (118,421) $ (69,012)
Unrecognized net actuarial loss.......................... 114,344 134,752 25,972 20,343
Unrecognized prior service cost.......................... 13,737 7,179 5,038 130
------------- ------------ ------------ ------------
Prepaid/(accrued) prior to contributions for 3 months
ended June 30.......................................... 17,742 28,447 (87,411) (48,539)
Contributions for 3 months ended June 30................. 3,750 4,534 2,151 4,675
------------- ------------ ------------ ------------
Net asset (liability) recognized at June 30.............. $ 21,492 $ 32,981 $ (85,260) $ (43,864)
============= ============ ============ ============
Amounts Recognized in the Consolidated Balance Sheet
Prepaid benefit cost..................................... $ 28,172 $ 27,597 $ -- $ --
Accrued benefit liability................................ (87,448) (89,366) (85,260) (43,864)
Intangible asset......................................... 10,366 3,671 -- --
Accumulated other comprehensive loss..................... 70,402 91,079 -- --
------------- ------------ ------------ ------------
Net asset (liability) recognized......................... $ 21,492 $ 32,981 $ (85,260) $ (43,864)
============= ============ ============ ============
The projected benefit obligation, accumulated benefit obligation and fair value
of plan assets for pension plans with accumulated benefit obligations in excess
of plan assets as of June 30, 2004 were $355,095,000, $319,902,000, and
$228,704,000, respectively, and for those same plans were $323,116,000,
$291,811,000, and $197,911,000 as of June 30, 2003.
The accumulated post-retirement benefit obligation and fair value of plan assets
for post-retirement benefit plans with accumulated post-retirement benefit
obligations in excess of fair value of plan assets as of June 30, 2004 were
$152,425,000 and $34,004,000 respectively, and for those same plans were
$90,344,000 and $21,332,000 respectively as of June 30, 2003.
The minimum pension liability as of June 30, 2004 decreased by $20,677,000 due
primarily to an increase in the fair value of plan assets attributable to higher
than expected investment return. The minimum pension liability as of June 30,
2003 increased by $75,008,000 as a result of the decrease in the discount rate
in 2003, decreases in the fair value of plan assets due to volatility in the
stock markets and increases in liabilities due to early retirement programs.
The weighted-average assumptions used to determine benefit obligations for the
year ended June 30, 2004, 2003 and 2002 were:
Pension Benefits Post-Retirement Benefits
-------------------------------------- --------------------------------------
2004 2003 2002 2004 2003 2002
---------- ----------- ----------- ---------- ---------- ----------
Discount rate
Beginning of year.................. 6.50% 7.50% 7.50% 6.50% 7.50% 7.50%
End of year........................ 6.00% 6.50% 7.50% 6.00% 6.50% 7.50%
Rate of compensation increase (average). 3.60% 4.00% 5.00% N/A N/A N/A
Health care cost trend rate............. N/A N/A N/A 13.00% 13.00% 12.00%
The assumed health care cost trend rate used in measuring the accumulated
post-retirement benefit obligation was 13% during 2004. This rate was assumed to
decrease gradually each year to a rate of 4.75% in 2012 and remain at that level
thereafter. The assumed health care cost trend rate used in measuring the
accumulated post-retirement benefit obligation was 13% during 2003. This rate
was assumed to decrease gradually each year to a rate of 5% in 2011 and remain
at that level thereafter.
Net periodic benefit cost for the year ended June 30, 2004, 2003 and 2002
includes the following components:
Pension Benefits Post-Retirement Benefits
-------------------------------------- --------------------------------------
2004 2003 2002 2004 2003 2002
---------- ----------- ----------- ---------- ---------- ----------
Service cost............................ $ 6,533 $ 5,655 $ 5,707 $ 3,993 $ 1,177 $ 1,136
Interest cost........................... 22,591 22,899 22,570 8,739 5,579 5,362
Expected return on plan assets.......... (21,477) (24,749) (25,868) (1,640) (1,734) (1,701)
Amortization of prior service cost...... 1,145 790 984 266 (65) (100)
Recognized actuarial gain (loss)........ 8,402 2,433 194 485 (234) (737)
Curtailment............................. -- -- 8,905 -- -- 1,200
Special termination benefits............ -- -- 8,957 -- -- 1,309
Settlement recognition.................. (445) (558) (457) -- -- --
---------- ----------- ----------- ---------- ---------- ----------
Net periodic pension cost............... $ 16,749 $ 6,470 $ 20,992 $ 11,843 $ 4,723 $ 6,469
========== =========== =========== ========== ========== ==========
Curtailment and special termination benefit charges were recognized during 2002
in connection with the Company's corporate reorganization and restructuring
initiatives. The Company has deferred, as a regulatory asset, certain of these
charges that have historically been recoverable in rates.
Amortization of unrecognized actuarial gains and losses for Missouri Gas Energy
plans were recognized using a rolling five-year average gain or loss position
with a five-year amortization period pursuant to a stipulation agreement with
the Missouri Public Service Commission (MPSC). The Company has deferred, as a
regulatory asset, the difference in amortization of unrecognized actuarial
losses recognized under such method and that amount determined and reported as
net periodic pension cost in accordance with the applicable FASB Standards.
The weighted-average assumptions used to determine net periodic benefit cost for
the year ended June 30, 2004, 2003 and 2002 were:
Pension Benefits Post-Retirement Benefits
-------------------------------------- --------------------------------------
2004 2003 2002 2004 2003 2002
---------- ----------- ----------- ---------- ---------- ----------
Discount rate
Beginning of year.................. 7.50% 7.50% 8.00% 7.50% 7.50% 7.50%
End of year........................ 6.50% 7.50% 7.50% 6.50% 7.50% 7.50%
Expected return on assets -
tax exempt accounts............... 9.00% 9.00% 9.00% 7.00% 9.00% 9.00%
Expected return on assets - taxable
accounts.............................. N/A N/A N/A 5.00% 5.50% 5.40%
Rate of compensation increase (average). 4.00% 5.00% 5.00% N/A N/A N/A
Health care cost trend rate............. N/A N/A N/A 13.00% 12.00% 12.00%
The assumed health care cost trend rate used in determining the net periodic
benefit cost was 13% during 2004. This rate was assumed to decrease gradually
each year to a rate of 5% in 2011 and remain at that level thereafter. The
assumed health care cost trend rate used in determining the net periodic benefit
cost was 12% during 2003. This rate was assumed to decrease gradually each year
to a rate of 6% in 2006 and remain at that level thereafter.
Assumed health care cost trends rates have a significant effect on the amounts
reported for health care plans. A one-percentage-point change in assumed health
care cost trend rates would have the following effects:
One Percentage Point One Percentage Point
Increase in Health Care Decrease in Health Care
Trend Rate Trend Rate
---------- ----------
Effect on total service and interest cost components.............. $ 1,512 $ (1,227)
Effect on post-retirement benefit obligation...................... $ 14,212 $ (11,628)
Plan Asset Information
Pension Plan Assets. The Pension Plans' assets shall be invested in accordance
with several investment practices that emphasize long-term investment
fundamentals with an investment objective of long-term growth. The investment
practices shall consider risk tolerance and the asset allocation strategy as
described below.
Investment theory and historical capital market return data suggest that, over
long periods of time, there is a relationship between the level of risk assumed
and the level of return that can be expected in an investment program. In
general, higher risk (i.e., volatility of return) is associated with higher
return. Given this relationship between risk and return, a fundamental step in
determining the investment policy is the determination of an appropriate risk
tolerance. The Company examined two important factors that affect the Company's
risk tolerance, including the financial ability to accept risk within the
investment program and willingness to accept return volatility.
Positive factors that contribute to a higher risk tolerance are:(i) the
financial strength of the Company; (ii) the relationship between the market
value of Plan assets and Plan liabilities (a surplus can provide a cushion that
would reduce the probability of making any required contributions in the
short-term in the event of adverse experience versus actuarial assumptions);
(iii) the Company's willingness to accept short-term volatility in the market
value of the Plan for the sake of earning higher long-term returns; (iv) and the
long-term time horizon available for investment provides the opportunity to
benefit from opportunities for growth that may accrue to a patient investment
strategy.
Offsetting these factors are: (i)as a defined benefit pension plan, the risk of
investment losses is borne by the Company and significant investment losses may
require substantial contributions to the Plan to maintain required funding
levels and such contributions may coincide with poor financial results for the
Company; and (ii)cyclical business activity can significantly influence the
finances of the Company and its financial ability to fund required
contributions.
Post-retirement Health and Life Plans' Assets. The Post-retirement Health and
Life Plans' assets shall be invested in accordance with sound investment
practices that emphasize long-term investment fundamentals. The Investment
Committee has adopted an investment objective of income and growth for the Plan.
This investment objective: (i) is a risk-averse balanced approach that
emphasizes a stable and substantial source of current income and some capital
appreciation over the long-term; (ii) implies a willingness to risk some
declines in value over the short-term, so long as the Plan is positioned to
generate current income and exhibits some capital appreciation; (iii) is
expected to earn long-term returns sufficient to keep pace with the rate of
inflation over most market cycles (net of spending and investment and
administrative expenses), but may lag inflation in some environments; (iv)
diversifies the Plan in order to provide opportunities for long-term growth and
to reduce the potential for large losses that could occur from holding
concentrated positions; and (v) recognizes that investment results over the
long-term may lag those of a typical balanced portfolio since a typical balanced
portfolio tends to be more aggressively invested. Nevertheless, this Plan is
expected to earn a long-term return that compares favorably to appropriate
market indices.
It is expected that these objectives can be obtained through a well-diversified
portfolio structure in a manner consistent with the investment policy.
The Company's weighted average asset allocation at June 30, 2004, and 2003, by
asset category is as follows:
Pension Post-Retirement
At June 30, At June 30,
------------ --------------
Asset Category 2004 2003 2004 2003
-------------- ---- ---- ---- ----
Equity securities......................... 68% 51% 21% 26%
Debt securities........................... 26% 45% 50% 64%
Other - cash equivalents.................. 6% 4% 29% 10%
---- ----- ----- ----
Total................................. 100% 100% 100% 100%
==== ===== ===== ====
Equity securities include Company common stock in the amounts of $16,615,000 and
$12,716,000 at June 30, 2004, and 2003, respectively.
Based on the Pension Plan objectives, asset allocations are maintained as
follows: equity of 50% to 75%, fixed income of 25% to 50%, and cash and cash
equivalents of 0% to 10%.
Based on the Post-Retirement Benefit Plan objectives, asset allocations are
maintained as follows: equity of 25% to 35%, fixed income of 65% to 75%, and
cash and cash equivalents of 0% to 10%.
The Company expects to contribute between the estimated amounts of $11,600,000
and $12,608,000 to its pension plans and the estimated amount of $13,553,000 to
its other post-retirement benefit plans in 2005.
The estimated benefit payments, which reflect expected future service, as
appropriate, that are projected to be paid are as follows:
Pension Other
Benefits Benefits
2005................................................. $ 23,547 $ 6,572
2006................................................. 20,579 6,922
2007................................................. 21,161 6,994
2008................................................. 22,205 7,514
2009................................................. 22,543 8,210
Years 2010 - 2014.................................... 136,657 53,149
The Company's eight qualified defined benefit retirement Plans cover: (i) those
employees who are employed by Missouri Gas Energy; (ii) those employees who are
employed by the Pennsylvania Operations; (iii) union employees of ProvEnergy;
(iv) non-union employees of ProvEnergy; (v) union employees of Valley Resources;
(vi) non-union employees of Valley Resources; (vii) union employees of Fall
River Gas; and (viii) non-union employees of Fall River Gas. On December 31,
1998, the Plan covering (i) above, exclusive of Missouri Gas Energy's union
employees, was converted from the traditional defined benefit Plan with benefits
based on years of service and final average compensation to a cash balance
defined benefit plan in which an account is maintained for each employee.
The initial value of the account was determined as the actuarial present value
(as defined in the Plan) of the benefit accrued at transition (December 31,
1998) under the pre-existing traditional defined benefit plan. Future
contribution credits to the accounts are based on a percentage of future
compensation, which varies by individual. Interest credits to the accounts are
based on 30-year Treasury Securities rates.
Defined Contribution Plan. The Company provides a Savings Plan available to all
employees. For Missouri Gas Energy non-union and corporate employees, the
Company contributes 50% and 75% of the first 5% and second 5%, respectively, of
the participant's compensation paid into the Savings Plan. For Missouri Gas
Energy union employees, the Company contributes 50% of the first 7% of the
participant's compensation paid into the Savings Plan. In Pennsylvania, the
Company contributes 55% of the first 4% of the participant's compensation paid
into the Savings Plan. For New England Gas Company's Fall River operations, the
Company contributes 100% of the first 4% of non-union employee compensation paid
into the Savings Plan and 100% of the first 3% of union employee compensation
paid into the Savings Plan. For New England Gas Company's Providence operations,
the Company contributes 50% of the first 10% of the participant's compensation
paid into the Savings Plan. For New England Gas Company's Cumberland operations
(formerly Valley Resources), the Company contributes 50% of the first 4% of the
participant's compensation paid into the Savings Plan. Company contributions are
100% vested after five years of continuous service for all plans other than
Missouri Gas Energy union and New England Gas Company's Cumberland operations,
which are 100% vested after six years of continuous service. Company
contributions to the plan during 2004, 2003 and 2002 were $4,058,000, $2,251,000
and $2,722,000, respectively.
Effective January 1, 1999, the Company amended its defined contribution plan to
provide contributions for certain employees who were employed as of December 31,
1998. These contributions were designed to replace certain benefits previously
provided under defined benefit plans. Employer contributions to these separate
accounts, referred to as Retirement Power Accounts, within the defined
contribution plan were determined based on the employee's age plus years of
service plus accumulated sick leave as of December 31, 1998. The contribution
amounts are determined as a percentage of compensation and range from 3.5% to
8.5%. Company contributions to Retirement Power Accounts during 2004, 2003 and
2002 were $5,149,000, $1,469,000 and $826,000, respectively.
Panhandle Energy. Following the June 11, 2003 acquisition by Southern Union,
Panhandle Energy instituted certain retiree health care and life insurance
benefits under other post employment benefits (OPEB) and added certain benefits
to substantially all of its employees under a defined contribution 401(k) plan
(Savings Plan). Under the Savings Plan, Panhandle Energy provides a matching
contribution of 50% of the first 4% of the participant's compensation paid into
the Savings Plan. In addition, Panhandle Energy makes additional contributions
ranging from 4% to 6% of the employee's eligible pay, depending on the
employee's age and years of service. The adoption of the OPEB plan resulted in
the recording of a $43,000,000 liability as of June 11, 2003 and Panhandle
Energy continues to fund the plan at approximately $8,000,000 per year. Since
Panhandle Energy retirement eligible active employees have primary coverage
through a benefit they are eligible to receive from the former owner of
Panhandle Energy, no liability is currently recognized for these employees under
the OPEB plan.
Following its acquisition by the Company in June 2003, Panhandle Energy
initiated a workforce reduction initiative designed to reduce the workforce by
approximately 5 percent. The workforce reduction initiative was an involuntary
plan with a voluntary component, and was fully implemented by September 30,
2003.
Corporate Restructuring. Business reorganization and restructuring initiatives
were commenced in August 2001 as part of a previously announced Cash Flow
Improvement Plan. Actions taken included (i) the offering of voluntary Early
Retirement Programs (ERPs) in certain of its operating divisions and (ii) a
limited reduction in force (RIF) within its corporate offices. ERPs, providing
for increased benefits for those electing retirement, were offered to
approximately 325 eligible employees across the Company's operating divisions,
with approximately 59% of such eligible employees accepting. The RIF was limited
solely to certain corporate employees in the Company's Austin and Kansas City
offices where forty-eight employees were offered severance packages. In
connection with the corporate reorganization and restructuring efforts, the
Company recorded a charge of $30,553,000 during the quarter ended September 30,
2001. This charge was reduced by $1,394,000 during the quarter ended June 30,
2002, as a result of the Company's ability to negotiate more favorable terms on
certain of its restructuring liabilities. The charge included: $16.4 million of
voluntary and accepted ERP's, primarily through enhanced benefit plan
obligations, and other employee benefit plan obligations; $6.8 million of RIF
within the corporate offices and related employee separation benefits; and $6.0
million connected with various business realignment and restructuring
initiatives. All restructuring actions were completed as of June 30, 2002.
Common Stock Held in Trust. From time to time, the Company purchases outstanding
shares of common stock of Southern Union to fund certain Company employee
stock-based compensation plans. At June 30, 2004 and 2003, 1,089,147 and
1,114,738 shares, respectively, of common stock were held by various rabbi
trusts for certain of those Company's benefit plans. At June 30, 2004, 110,996
shares were held in a rabbi trust for certain employees who deferred receipt of
Company shares for stock options exercised.
XV Taxes on Income
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Income tax expense:
Current:
Federal..................................................... $ 1,497 $ (15,258) $ (8,848)
State....................................................... 151 (6,563) (1,391)
---------- ---------- ---------
1,648 (21,821) (10,239)
---------- ---------- ---------
Deferred:
Federal.................................................... $ 60,380 38,926 13,050
State...................................................... 7,075 7,168 600
---------- ---------- ---------
67,455 46,094 13,650
---------- ---------- ---------
Total income tax expense from continuing operations............. $ 69,103 $ 24,273 $ 3,411
========== ========== =========
Deferred credits include $5,367,000 and $5,791,000 of unamortized deferred
investment tax credit as of June 30, 2004 and 2003.
Deferred income taxes result from temporary differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities.
June 30,
--------
2004 2003
---- ----
Deferred income tax assets:
Alternative minimum tax credit................. $ 24,054 $ 6,263
Insurance accruals............................. 1,601 2,028
Bad debt reserves.............................. 5,721 4,096
Post-retirement benefits....................... 1,346 1,078
Minimum pension liability...................... 33,511 35,159
Other.......................................... 8,442 10,313
------------ ------------
Total deferred income tax assets........... $ 74,675 $ 58,937
------------ ------------
June 30,
--------
2004 2003
---- ----
Deferred income tax liabilities:
Property, plant and equipment................... $ (313,387) $ (261,100)
Unamortized debt expense........................ (21,607) (5,455)
Regulatory liability............................ (13,151) (14,483)
Other........................................... (55,831) (56,510)
------------ ----------
Total deferred income tax liabilities....... (403,976) (337,548)
------------ ----------
Net deferred income tax liability.................... (329,301) (278,611)
Less current income tax assets................... 19,659 4,096
------------ ----------
Accumulated deferred income taxes................... $ (348,960) $ (282,707}
============ ==========
The Company accounts for income taxes utilizing the liability method which bases
the amounts of current and future income tax assets and liabilities on events
recognized in the financial statements and on income tax laws and rates existing
at the time the temporary differences are expected to reverse.
Year Ended June 30,
-------------------
2004 2003 2002
---- ---- ----
Computed statutory income tax expense from continuing operations at 35%......... $ 64,095 $ 23,780 $ 1,726
Changes in income taxes resulting from:
State income taxes, net of federal income tax benefit...................... 4,697 326 695
Amortization/write-down of goodwill........................................ -- -- 3,113
Internal Revenue Service audit settlement.................................. -- -- (1,570)
Investment Tax Credit amortization......................................... (424) (421) (608)
Other...................................................................... 735 588 55
----------- ---------- ---------
Actual income tax expense from continuing operations............................ $ 69,103 $ 24,273 $ 3,411
=========== ========== =========
XVI Regulation and Rates
Missouri Gas Energy. On November 4, 2003, Missouri Gas Energy filed a request
with the MPSC to increase base rates by $44,800,000 and to implement a weather
mitigation rate design that would significantly reduce the impact of
weather-related fluctuations on customer bills. On January 30, 2004, Missouri
Gas Energy filed an updated claim which raised the amount of the base rate
increase request to $54,200,000. As of July 19, 2004, upon the close of the
record and reflecting settlement of a number of issues, MGE's request stood at
approximately $39,000,000 and the MPSC Staff's recommendation stood at
approximately $13,000,000. Statutes require that the MPSC reach a decision in
the case within an eleven-month period from the original filing date. It is not
presently possible to determine what action the MPSC will ultimately take with
respect to this rate increase request.
New England Gas Company. On May 22, 2003, the RIPUC approved a Settlement Offer
filed by New England Gas Company related to the final calculation of earnings
sharing for the 21-month period covered by the Energize Rhode Island Extension
settlement agreement. This calculation generated excess revenues of $5,277,000.
The net result of the excess revenues and the Energize Rhode Island weather
mitigation and non-firm margin sharing provisions was the crediting to customers
of $949,000 over a twelve-month period starting July 1, 2003.
On May 24, 2002, the RIPUC approved a settlement agreement between the New
England Gas Company and the Rhode Island Division of Public Utilities and
Carriers. The settlement agreement resulted in a $3,900,000 decrease in base
revenues for New England Gas Company's Rhode Island operations, a unified rate
structure ("One State; One Rate") and an integration/merger savings mechanism.
The settlement agreement also allows New England Gas Company to retain
$2,049,000 of merger savings and to share incremental earnings with customers
when the division's Rhode Island operations return on equity exceeds 11.25%.
Included in the settlement agreement was a conversion to therm billing and the
approval of a reconciling Distribution Adjustment Clause (DAC). The DAC allows
New England Gas Company to continue its low income assistance and weatherization
programs, to recover environmental response costs over a 10-year period, puts
into place a new weather normalization clause and allows for the sharing of
nonfirm margins (non-firm margin is margin earned from interruptible customers
with the ability to switch to alternative fuels). The weather normalization
clause is designed to mitigate the impact of weather volatility on customer
billings, which will assist customers in paying bills and stabilize the revenue
stream. New England Gas Company will defer the margin impact of weather that is
greater than 2% colder-than-normal and will recover the margin impact of weather
that is greater than 2% warmer-than-normal. The non-firm margin incentive
mechanism allows New England Gas Company to retain 25% of all non-firm margins
earned in excess of $1,600,000.
Panhandle Energy. In December 2002, FERC approved a Trunkline LNG certificate
application to expand the Lake Charles facility to approximately 1.2 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 by the end of the
2005 calendar year. In February 2004, Trunkline LNG filed a further incremental
LNG expansion project (Phase II) with FERC and is awaiting commission approval.
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.
In February 2004, Trunkline filed an application with FERC to request approval
of a 30-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal.
The pipeline creates additional transport capacity in association with the
Trunkline LNG expansion and also includes new and expanded delivery points with
major interstate pipelines.
XVII Leases
The Company leases certain facilities, equipment and office space under
cancelable and non-cancelable operating leases. The minimum annual rentals under
operating leases for the next five years ending June 30 are as follows:
2005--$17,777,000; 2006--$14,708,000; 2007--$13,970,000; 2008--$10,018,000
2009--$6,549,000 and thereafter $8,102,000. Rental expense was $17,821,000,
$4,342,000, and $5,759,000 for the years ended June 30, 2004, 2003 and 2002,
respectively.
XVIII 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 ongoing evaluation of
its operations to identify potential environmental exposures and assure
compliance with regulatory policies and procedures.
The Company follows the provisions of an American Institute of Certified Public
Accountants Statement of Position, Environmental Remediation Liabilities, for
recognition, measurement, display and disclosure of environmental remediation
liabilities.
In certain of the Company's jurisdictions the Company is allowed to recover
environmental remediation expenditures through rates. Although significant
charges to earnings could be required prior to rate recovery for jurisdictions
that do not have rate recovery mechanisms, management does not believe that
environmental expenditures will have a material adverse effect on the Company's
financial position, results of operations or cash flows.
Local Distribution Company Environmental Matters -- The Company is investigating
the possibility that the Company or predecessor companies may have been
associated with Manufactured Gas Plant (MGP) sites in its former gas
distribution service territories, principally in Texas, Arizona and New Mexico,
and present gas distribution service territories in Missouri, Pennsylvania,
Massachusetts and Rhode Island. At the present time, the Company is aware of
certain MGP sites in these areas and is investigating those and certain other
locations. While the Company's evaluation of these Texas, Missouri, Arizona, New
Mexico, Pennsylvania, Massachusetts and Rhode Island MGP sites is in its
preliminary stages, it is likely that some compliance costs may be identified
and become subject to reasonable quantification. Within the Company's gas
distribution service territories certain MGP sites are currently the subject of
governmental actions. These sites are as follows:
Missouri 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 and, subsequently, performed environmental assessments of the
sites. Following the submission of these assessments to MDNR, MGE was required
by MDNR to initiate remediation of Station A. Following the selection of a
qualified contractor in a competitive bidding process, the Company began
remediation of Station A in the first calendar quarter of 2003. The project was
completed in July 2003, at an approximate cost of $4 million. 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. On June 16, 2004, MGE submitted a UST Site Characterization
Work Plan to MDNR for review and approval.
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 million on environmental assessment and remediation at
this MGP site under the supervision of the Rhode Island Department of
Environmental Management (RIDEM). Following the acquisition, environmental
remediation at the site was temporarily suspended. During this suspension, the
Company requested certain modifications to the 1999 Remedial Action Work Plan
from RIDEM. After receiving approval to some of the requested modifications to
the 1999 Remedial Action Work Plan, environmental work was reinitiated on April
17, 2002, by a qualified contractor selected in a competitive bidding process.
Remediation was completed on October 10, 2002, and a Closure Report was filed
with RIDEM in December 2002. The cost of environmental work conducted after
remediation resumed was $4 million. Remediation of the remaining 37.5 acres of
the site (known as the "Phase 2" remediation project) is not scheduled at this
time.
In November 1998, Providence Gas received a letter of responsibility from RIDEM
relating to possible contamination at a site that operated as a MGP in the early
1900s 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 plans. In response, NEG notified RIDEM of
its intent to begin 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 (Action Plan) to the MADEP
on July 26, 2004. The Action Plan proposes an investigation to determine whether
or not coal gasification related material was historically dumped in the State
Avenue Area.
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 gas 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 United States
Environmental Protection Agency (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 million out of the bankruptcy estates. This payment is
payable $1.25 million to the Company for payment of environmental costs
associated with the former Fall River Gas Company, and $3.75 million payable to
the Company and National Grid jointly for payment of future environmental costs
at the Tidewater and Hamlet sites. The settlement further provides an admission
of liability by Stone & Webster that gives National Grid and 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) 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 cleanup 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 systems and has undertaken
clean-up programs at those 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) the 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 and 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. Eight 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 million 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 two rules affect six Company facilities in Texas at an
estimated cost of approximately $12 million for capital improvements through
March 2007, based on current projections.
The EPA promulgated various Maximum Achievable Control Technology (MACT) rules
in August 2003 and 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 million for capital improvements, based on current projections.
Regulatory
On May 31, 2002, the staff of the MPSC recommended that the Commission disallow
approximately $15 million in gas costs incurred during the period July 1, 2000
through June 30, 2001. Missouri Gas Energy filed its response in opposition to
the Staff's recommendation on July 11, 2002, vigorously disputing the Commission
staff's assertions. Missouri Gas Energy intends to vigorously defend itself in
this proceeding. This matter went into recess following a hearing in May of
2003. Following the May hearing, the Commission staff reduced its disallowance
recommendation to approximately $9.3 million. The hearing concluded in November
2003 and the matter 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 $5.9 million, $5.9
million and $4.3 million, respectively, in gas costs incurred during the period
July 1, 1999 through June 30, 2000, July 1, 1998 through June 30, 1999, and July
1, 1997 through June 30, 1998, respectively. The basis of these proposed
disallowances appears to be the same as was rejected by the Commission through
an order dated March 12, 2002, applicable to the period July 1, 1996 through
June 30, 1997. MGE intends to vigorously defend itself in these proceedings. On
November 4, 2002, the Commission adopted a procedural schedule calling for a
hearing in this matter some time after May 2003. No date for this hearing has
been set.
Southwest Gas Litigation
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, 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
material adverse effect on the Company's financial condition, results of
operations or cash flows.
Other
In 1993, the U.S. Department of the Interior announced its intention to seek,
through its Minerals Management Service (MMS) additional royalties from gas
producers as a result of payments received by such producers in connection with
past take-or-pay settlements, buyouts, and buy downs of gas sales contracts with
natural gas pipelines. Panhandle Energy's pipelines, with respect to certain
producer contract settlements, may be contractually required to reimburse or, in
some instances, to indemnify producers against such royalty claims. The
potential liability of the producers to the government and of the pipelines to
the producers involves complex issues of law and fact which are likely to take
substantial time to resolve. If required to reimburse or indemnify the
producers, Panhandle Energy's pipelines may file with 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.
Southern Union and its subsidiaries are parties to other legal proceedings that
management considers to be normal actions to which an enterprise of its size and
nature might be subject, Management does not consider these actions to be
material to Southern Union's overall business or financial condition, results of
operations or cash flows.
Commitments. The Company is committed under various agreements to purchase
certain quantities of gas in the future. At June 30, 2004, the Company's
Distribution segment has purchase commitments for natural gas transportation
services, storage services and certain quantities of natural gas at a
combination of fixed, variable and market-based prices that have an aggregate
value of approximately $1,099,972,000. The Company's purchase commitments may be
extended over several years depending upon when the required quantity is
purchased. The Company has purchase gas tariffs in effect for all its utility
service areas that provide for recovery of its purchase gas costs under defined
methodologies and the Company believes that all costs incurred under such
commitments will be recovered through its purchase gas tariffs.
In connection with the acquisition of the Pennsylvania Operations, the Company
assumed a guaranty with a bank whereby the Company unconditionally guaranteed
payment of financing obtained for the development of PEI Power Park. In March
1999, the Borough of Archbald, the County of Lackawanna, and the Valley View
School District (together the Taxing Authorities) approved a Tax Incremental
Financing Plan (TIF Plan) for the development of PEI Power Park. The TIF Plan
requires that: (i) the Redevelopment Authority of Lackawanna County raise
$10,600,000 of funds to be used for infrastructure improvements of the PEI Power
Park; (ii) the Taxing Authorities create a tax increment district and use the
incremental tax revenues generated from new development to service the
$10,600,000 debt; and (iii) PEI Power Corporation, a subsidiary of the Company,
guarantee the debt service payments. In May 1999, the Redevelopment Authority of
Lackawanna County borrowed $10,600,000 from a bank under a promissory note (TIF
Debt), which was refinanced and modified in May 2004. Beginning May 15, 2004 the
TIF Debt bears interest at a variable rate equal to three-quarters percent
(.75%) lower than the National Prime Rate of Interest with no interest rate
floor or ceiling. The TIF Debt matures on June 30, 2011. Interest-only payments
were required until June 30, 2003, and semi-annual interest and principal
payments are required thereafter. As of June 30, 2004, the interest rate on the
TIF Debt was 3.25% and estimated incremental tax revenues are expected to cover
approximately 25% of the fiscal 2005 annual debt service. Based on information
available at this time, the Company believes that the amount provided for the
potential shortfall in estimated future incremental tax revenues is adequate as
of June 30, 2004. The balance outstanding on the TIF Debt was $8,710,000 as of
June 30, 2004.
Effective May 1, 2004, the Company agreed to five-year contracts with each
bargaining-unit representing Missouri Gas Energy employees.
Effective April 1, 2004, the Company agreed to a three-year contract with a
bargaining unit representing a portion of PG Energy employees. Effective, August
1, 2003, the Company agreed to a three-year contract with another bargaining
unit representing the remaining PG Energy unionized employees.
Effective May 28, 2003, Panhandle Energy agreed to a three-year contract with a
bargaining unit representing Panhandle Energy employees.
During fiscal 2003, the bargaining unit representing certain employees of New
England Gas Company's Cumberland operations (formerly Valley Resources) was
merged with the bargaining unit representing the employees of the Company's Fall
River operations (formerly Fall River Gas). During fiscal 2002, the Company
agreed to five-year contracts with two bargaining units representing employees
of New England Gas Company's Providence operations (formerly ProvEnergy), which
were effective May 2002; a four-year contract with one bargaining unit
representing employees of New England Gas Company's Cumberland operations,
effective May 2002; and a four-year contract with one bargaining unit
representing employees of New England Gas Company's Fall River operations,
effective April 2002; and a one year extension of a bargaining unit representing
certain employees of the Company's Cumberland operations.
Of the Company's employees represented by unions, Missouri Gas Energy employs
36%, New England Gas Company employs 32%, Panhandle Energy employs 18% and PG
Energy employs 14%.
The Company had standby letters of credit outstanding of $58,566,000 at June 30,
2004 and $7,761,000 at June 30, 2003, which guarantee payment of insurance
claims and other various commitments.
The Company has guaranteed a $4,000,000 line of credit between Advent Networks,
Inc. (in which Southern Union has an equity interest) and a bank.
XIX Discontinued Operations
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK for approximately
$437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In accordance
with accounting principles generally accepted in the United States, the results
of operations and gain on sale have been segregated and reported as
"discontinued operations" in the Consolidated Statement of Operations and as
"assets held for sale" in the Consolidated Statement of Cash Flows for the
respective periods.
The following table summarizes the Texas Operations' results of operations that
have been segregated and reported as "discontinued operations" in the
Consolidated Statement of Operations:
Year Ended June 30,
-------------------
2003 2002
------------- -----------
Operating revenues................................ $ 144,490 $ 309,936
============= ===========
Net operating revenues, excluding depreciation
and amortization (a)........................... $ 51,480 $ 105,730
============= ===========
Net earnings from discontinued operations (b)..... $ 32,520 $ 18,104
============= ===========
- ---------------------------------
(a) Net operating revenues consist of operating revenues less gas purchase costs
and revenue-related taxes.
(b) Net earnings from discontinued operations do not include any allocation of
interest expense or other corporate costs, in accordance with generally accepted
accounting principles. All outstanding debt of Southern Union Company and
subsidiaries is maintained at the corporate level, and no debt was assumed by
ONEOK, Inc. in the sale of the Texas Operations.
XX Quarterly Operations (Unaudited)
Year Ended Quarter Ended
June 30, 2004 September 30 December 31 March 31 June 30 Total
------------- --------------- --------------- ------------ ------------ ------------
Operating revenues.......................... $ 231,394 $ 507,113 $ 774,579 $ 286,888 $ 1,799,974
Net operating revenues, excluding
depreciation and amortization............ 169,309 240,097 297,892 182,843 890,141
Net earnings (loss) from continuing
operations............................... (3,707) 38,422 75,367 3,943 114,025
Net earnings (loss) available for common
shareholders............................. (3,707) 34,418 71,026 (398) 101,339
Diluted net earnings (loss) per share
available for common shareholders:(1)
Continuing operations.................... (.05) .45 .91 (.01) 1.30
Available for common shareholders........ (.05) .45 .91 (.01) 1.30
Year Ended Quarter Ended
June 30, 2003 September 30 December 31 March 31 June 30 Total
------------- --------------- -------------- ----------- ------------ ------------
Operating revenues.......................... $ 99,710 $ 346,104 $ 535,663 $ 207,030 $ 1,188,507
Net operating revenues, excluding
depreciation and amortization............ 54,464 118,031 161,400 89,516 423,411
Net earnings (loss) from continuing
operations............................... (9,186) 18,519 46,234 (11,898) 43,669
Net earnings from discontinued operations... 2,691 10,900 17,665 1,264 32,520
Net earnings (loss) available for common
shareholders............................. (6,495) 29,419 63,899 (10,634) 76,189
Diluted net earnings (loss) per share
available for common shareholders:(1)
Continuing operations.................... (.16) .30 .75 (.19) .70
Discontinued operations.................. .05 .18 .29 .02 .52
Available for common shareholders........ (.11) .48 1.04 (.17) 1.22
(1) The sum of earnings per share by quarter may not equal the net earnings per
common and common share equivalents for the year due to variations in the
weighted average common and common share equivalents outstanding used in
computing such amounts.
XXI 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 Transportation
and Storage segment is primarily engaged in the interstate transportation and
storage of natural gas in the Midwest and Southwest, and also provides LNG
terminalling and regasification services. Its operations are conducted through
Panhandle Energy, which the Company acquired on June 11, 2003. The Distribution
segment is primarily engaged in the local distribution of natural gas in
Missouri, Pennsylvania, Rhode Island and Massachusetts. Its operations are
conducted through the Company's three regulated utility divisions: Missouri Gas
Energy, PG Energy and New England Gas Company.
The Company evaluates segment performance based on several factors, of which the
primary financial measure is operating income (which the Company formerly
referred to as net operating revenues). The accounting policies of the segments
are substantially the same as those described in the summary of significant
accounting policies (see Note I - Summary of Significant Accounting Policies).
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 2004, 2003 or 2002.
Prior to the acquisition of Panhandle Energy, the Company was primarily engaged
in the natural gas distribution business and considered its operations to
consist of one reportable segment. As a result of the acquisition of Panhandle
Energy, management assessed the manner in which financial information is
reviewed in making operating decisions and assessing performance, and concluded
that in addition to Panhandle Energy's operations its regulated utility
operations would be treated as one separate and distinct reportable segment.
During fiscal 2003, the Company reported its Southern Union Gas natural gas
operating division as discontinued operations. Accordingly, the Distribution
segment results exclude the results of the Texas operations for all periods
presented.
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., offer 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 following table sets forth certain selected financial information for the
Company's segments for fiscal 2004, 2003 and 2002. Financial information for the
Transportation and Storage segment reflects the operations of Panhandle Energy
beginning on its acquisition date of June 11, 2003.
Year Ended June 30,
------------------------------------------------
2004 2003 2002
---------------- -------------- -------------
Revenues from external customers:
Distribution................................................. $ 1,304,405 $ 1,158,964 $ 968,933
Transportation and Storage................................... 491,083 24,529 --
All Other (a)................................................ 4,486 5,014 11,681
------------- ------------- -------------
Total consolidated operating revenues............................. $ 1,799,974 $ 1,188,507 $ 980,614
============= ============= =============
Depreciation and amortization:
Distribution................................................. $ 57,601 $ 56,396 $ 53,937
Transportation and Storage................................... 59,988 3,197 --
All Other.................................................... 572 590 2,387
------------- ------------- -------------
Total segment depreciation and amortization....................... 118,161 60,183 56,324
Reconciling Item -- Corporate..................................... 594 459 2,665
------------- ------------- -------------
Total consolidated depreciation and amortization.................. $ 118,755 $ 60,642 $ 58,989
============= ============= =============
Operating income:
Distribution................................................. $ 118,894 $ 142,762 $ 135,502
Transportation and Storage................................... 193,702 9,635 --
All Other.................................................... (3,514) 13 --
------------- ------------- -------------
Total segment operating income.................................... 309,082 152,410 135,502
Reconciling Items:
Corporate.................................................... (3,555) (10,039) (15,218)
Business restructuring charges............................... -- -- (29,159)
------------- ------------- -------------
Consolidated operating income..................................... $ 305,527 $ 142,371 $ 91,125
============= ============= =============
Total assets:
Distribution................................................. $ 2,231,970 $ 2,243,257 $ 2,156,106
Transportation and Storage................................... 2,197,289 2,212,467 --
All Other.................................................... 42,133 50,073 53,339
------------- ------------- -------------
Total segment assets.............................................. 4,471,392 4,505,797 2,209,445
Reconciling Items:
Corporate.................................................... 101,066 85,141 75,173
Sale of assets - Texas Operations............................ -- -- 395,446
------------- ------------- -------------
Total consolidated assets......................................... $ 4,572,458 $ 4,590,938 $ 2,680,064
============= ============= =============
Expenditures for long-lived assets:
Distribution................................................. $ 78,791 $ 67,327 $ 68,042
Transportation and Storage................................... 131,378 5,128 --
All Other.................................................... 856 1,653 1,365
------------- ------------- -------------
Total segment expenditures for long-lived assets.................. 211,025 74,108 69,407
Reconciling item - Corporate...................................... 15,028 5,622 1,291
------------- ------------- -------------
Total consolidated expenditures for long-lived assets............. $ 226,053 $ 79,730 $ 70,698
============= ============= =============
Reconciliation of operating income to earnings from continuing
operations before income taxes:
Operating income............................................. $ 305,527 $ 142,371 $ 91,125
Interest..................................................... (127,867) (83,343) (90,992)
Dividends on preferred securities of subsidiary trust........ -- (9,480) (9,480)
Other income, net............................................ 5,468 18,394 14,278
------------- ------------- -------------
Earnings from continuing operations before income taxes. $ 183,128 $ 67,942 $ 4,931
============= ============= =============
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors of
Southern Union Company:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, of cash flows and of stockholders'
equity, present fairly, in all material respects, the financial position of
Southern Union Company and subsidiaries (the "Company") at June 30, 2004 and
2003, and the results of their operations and their cash flows for each of the
three years in the period ended June 30, 2004, in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
These standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Houston, Texas
August 31, 2004
Exhibit 21
SUBSIDIARIES OF THE COMPANY
Name State or Country of Incorporation
---------------------- ---------------------------------
Panhandle Eastern Pipe Line Company, LP Delaware
Trunkline Gas Company, LLC Delaware
Trunkline LNG Holdings, LLC Deleware
Trunkline LNG Company, LLC Delaware
Pan Gas Storage, LLC Deleware
Note: Certain wholly-owned subsidiaries of Southern Union Company are not
named above. Considered in the aggregate as a single subsidiary, these
unnamed entities would not constitute a "significant subsidiary" at the
end of the year covered by this report. Additionally, the Company has
other subsidiaries that conduct no business except to the extent
necessary to maintain their corporate name or existence.
Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 (File No. 333-113757) and Form S-8 (File Nos. 33-37261,
33-69596, 33-69598, 33-61558, 333-79443, 333-08994, 333-42635, 333-89971,
333-36146, 333-36150, 333-47144 and 333-112527) of Southern Union Company of our
report dated August 30, 2004 relating to the consolidated financial statements
which appear in this Form 10-K.
PricewaterhouseCoopers LLP
Houston, Texas
August 31, 2004
Exhibit 24
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS that each person whose signature appears
below constitutes and appoints Thomas F. Karam and David J. Kvapil, or any of
them, acting individually or together, as such person's true and lawful
attorney(s)-in-fact and agent(s), with full power of substitution and
revocation, to act in any capacity for such person and in such person's name,
place and stead in any and all capacities, to sign the Annual Report on Form
10-K for the fiscal year ended June 30, 2004 of Southern Union Company, a
Delaware corporation, and any amendments thereto, and to file the same with all
exhibits thereto, and other documents in connection therewith, with the
Securities and Exchange Commission and the New York Stock Exchange.
Dated: August 30, 2004
GEORGE L. LINDEMANN ADAM M.LINDEMANN
- --------------------------- ----------------------------------------
George L. Lindemann Adam M. Lindemann
JOHN E. BRENNAN DAVID BRODSKY
- --------------------------- ----------------------------------------
John E. Brennan David Brodsky
THOMAS F. KARAM GEORGE ROUNTREE, III
- -------------------------- ----------------------------------------
Thomas F. Karam George Rountree, III
FRANK W. DENIUS RONALD W.SIMMS
- -------------------------- ----------------------------------------
Frank W. Denius Ronald W. Simms
KURT A. GITTER, M.D.
- --------------------------
Kurt A. Gitter, M.D.
Exhibit 31.1
CERTIFICATIONS
I, George L. Lindemann, certify that:
(1) I have reviewed this annual report on Form 10-K 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: August 31, 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 annual report on Form 10-K 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: August 31, 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 Form 10-K of Southern Union Company (the "Company") for
the fiscal year ended June 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
- --------------------------
George L. Lindemann
Chairman of the Board and
Chief Executive Officer
August 31, 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 Form 10-K of Southern Union Company (the "Company") for
the fiscal year ended June 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
August 31, 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.