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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,