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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, 2003
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 $1 per share 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 voting stock held by non-affiliates of the
registrant on September 15, 2003 was $911,650,000. The number of shares of the
registrant's Common Stock outstanding on September 15, 2003 was 72,890,475.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's proxy statement for its annual meeting of
stockholders to be held on November 4, 2003, 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, LLC and its subsidiaries (hereafter collectively referred to
as Panhandle Energy), which serve approximately 500 customers in the Midwest and
Southwest. Panhandle Energy was acquired by Southern Union on June 11, 2003. The
Company's local natural gas distribution operations are conducted through its
three regulated utility divisions, Missouri Gas Energy, PG Energy and New
England Gas Company, which collectively serve over 950,000 residential,
commercial and industrial customers in Missouri, Pennsylvania, Rhode Island and
Massachusetts.
Acquisition of Panhandle Eastern Pipe Line Company and Subsidiaries - On June
11, 2003, Southern Union acquired Panhandle Energy from CMS Energy Corporation
for approximately $582 million in cash and in connection therewith incurred
transaction costs estimated at $30 million. Additional consideration was
financed by CMS Energy Corporation through their purchase of 3 million shares
of Southern Union common stock (before adjustment for any subsequent stock
dividends) valued at approximately $49 million based on market prices at
closing. Southern Union also incurred additional deferred state income tax
liabilities estimated at $18 million as a result of the transaction. At the
time of the acquisition, Panhandle Energy had approximately $1.159 billion of
debt outstanding that it retained. The Company funded the cash portion of the
acquisition with approximately $437 million in cash proceeds it received for the
January 1, 2003 sale of its Texas operations (see Sale of Southern Union Gas and
Related Assets), approximately $121 million of the net proceeds it received from
concurrent common stock and equity units 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 in the United States with the purchase price paid by the
Company being allocated to Panhandle Energy's net assets as of the acquisition
date based on preliminary estimates. The Panhandle Energy assets acquired and
liabilities assumed have been recorded in the Consolidated Balance Sheet as of
June 30, 2003 at their estimated fair value and are subject to further
assessment and adjustment pending 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 are 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. The Panhandle Energy entities include
Panhandle Eastern Pipe Line Company, LLC (Panhandle Eastern Pipe Line),
Trunkline Gas Company, LLC (Trunkline), Sea Robin Pipeline Company (Sea Robin),
Trunkline LNG Company, LLC (Trunkline LNG) and Pan Gas Storage Company, LLC (Pan
Gas, also dba Southwest Gas Storage). 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 per day, 72
billion cubic feet of owned underground storage capacity and 6.3 billion cubic
feet of above ground LNG storage facilities. Trunkline LNG, located on
Louisiana's Gulf Coast, operates one of the nation's largest LNG import
terminals.
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, the assets and liabilities sold have
been segregated and reported as "held for sale" in the Consolidated Balance
Sheet as of June 30, 2002, and the related results of operations and gain on
sale have been segregated and reported as "discontinued operations" in the
Consolidated Statement of Operations and Consolidated Statement of Cash Flows
for all periods presented.
Acquisition of Providence Energy Corporation, Fall River Gas Company and Valley
Resources - In September 2000, Southern Union acquired Providence Energy
Corporation (ProvEnergy), Fall River Gas Company (Fall River Gas), and Valley
Resources (Valley Resources). Collectively, these companies (hereafter referred
to as the Company's New England Operations) were acquired for approximately
$422,000,000 in cash and 1,370,629 shares (before adjustment for any subsequent
stock dividends) of Southern Union common stock, as well as the assumption of
approximately $140,000,000 in long-term debt. The results of operations from
ProvEnergy and Fall River Gas have been included in the Consolidated Statement
of Operations since September 28, 2000, and the results of operations from
Valley Resources have been included in the Consolidated Statement of Operations
since September 20, 2000. Thus, the Consolidated Statement of Operations for the
periods subsequent to these acquisitions is not comparable to the same periods
in prior years.
The New England Operations' primary business is the distribution of natural gas
through the New England Gas Company, which serves approximately 298,000
customers throughout Rhode Island and southeastern Massachusetts. Subsidiaries
of the Company acquired with the New England Gas Company and currently operating
include ProvEnergy Power LLC, Fall River Gas Appliance Company, Valley Appliance
Merchandising Company and Alternate Energy Corporation. Subsidiaries acquired
with the New England Gas Company and subsequently sold include Morris Merchants,
Inc., Valley Propane, Inc. and ProvEnergy Oil Enterprises, Inc. (see Other
Sales).
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. The Company's non-core subsidiaries and assets
sold include:
Subsidiary or Asset Sold Date Sold Proceeds Pre-tax Gain (Loss)
- ------------------------------------------ -------------- ----------- -----------
Fiscal Year 2002 Sales--
PG Energy Services' propane operations (a) April 2002 $ 2,300,000 $ 1,200,000
Carrizo Springs Pipeline (b) ............. December 2001 1,000,000 561,000
South Florida Natural Gas and
Atlantic Gas Corporation (c) ........ December 2001 10,000,000 (1,500,000)
Morris Merchants, Inc. (d) ............... October 2001 1,586,000 --
Valley Propane, Inc. (e) ................. September 2001 5,301,000 --
ProvEnergy Oil Enterprises (f) ........... August 2001 15,776,000 --
PG Energy Services' commercial and
industrial gas marketing contracts .. July 2001 4,972,000 4,653,000
Fiscal Year 2001 Sale--
Keystone Pipeline Services, Inc. (g) ..... June 2001 3,300,000 707,000
(a) Sold liquid propane to residential, commercial and industrial customers in
northeastern and central Pennsylvania.
(b) Asset was a 43-mile pipeline operated
by Southern Transmission Company.
(c) South Florida Natural Gas was a natural gas division of Southern Union and
Atlantic Gas Corporation was a propane subsidiary of the Company.
(d) Served as a manufacturers' representative agency for franchised plumbing and
heating contract supplies throughout New England.
(e) Sold liquid propane to residential, commercial and industrial customers in
Rhode Island and Massachusetts.
(f) Operated a fuel oil distribution business through its subsidiary,
ProvEnergy Fuels, Inc. for residential and commercial customers in Rhode Island
and Massachusetts.
(g) Engaged primarily in the construction, maintenance, and rehabilitation of
natural gas distribution pipelines.
Business Segments
The Company's operations include two reportable segments:
o 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;
o 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.
For a further description of the Company's reportable segments, see
Transportation and Storage Segment and Distribution Segment, below. For
information about the revenues, net operating revenues, assets and other
financial information relating to the Company's reportable segments, see ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Business Segment Results and Note XXI - Reportable Segments.
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 (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 17,000 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 17,800 residential and commercial users primarily in central
and northeastern Pennsylvania.
o ProvEnergy Power Company LLC (ProvEnergy Power) provides outsourced energy
management services and owns 50% of Capital Center Energy Company LLC, a
joint venture formed between ProvEnergy and ERI Services, Inc. (an
unrelated party) to provide retail power and conditioned air.
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, Purchasing, Risk Management, Tax and Treasury.
The Company also maintains a venture capital investment portfolio. Certain of
the Company's significant venture capital investments are listed below.
o PointServe, Inc. (PointServe) --The Company has a remaining investment of
$4,206,000 in PointServe, a business-to-business online scheduling
solution, after recording a non-cash charge of $10,380,000 during fiscal
2002 to recognize a decrease in fair value. The Company recognized this
valuation adjustment 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) -- As of June 30, 2003, Southern
Union had a $5,433,000 equity interest in Advent and held
$9,500,000 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 may be due on demand at the request of
Southern Union. Certain Southern Union executive officers,
Directors and employees have invested $1,545,000 and beneficially own in
the aggregate approximately two percent equity ownership
interest in Advent through a partnership unrelated to Southern Union
through which each 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, the Company will
record a charge on its consolidated statement of operations to reduce the
carrying value of the security to its estimated fair value.
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.
Accordingly, in fiscal 2003, during the period owned by the Company this segment
represented only two percent of the Company's total operating revenues but will
represent a significant portion in fiscal 2004.
Panhandle Energy operates a large natural gas pipeline network consisting of
over 10,000 miles of pipeline and a LNG regasification plant. 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 Energy's pipeline
network transports an estimated 6% of the natural gas consumed in the United
States and an estimated 20% of the natural gas consumed in the Midwest.
Panhandle Energy's major customers include 25 utilities located primarily in the
United States Midwest market area, which encompasses large portions of Illinois,
Indiana, Michigan, Missouri, Ohio and Tennessee.
The Panhandle Eastern Pipe Line transmission system consists of a system of four
large diameter parallel pipelines, extending approximately 1,300 miles from
producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through
Missouri, Illinois, Indiana, Ohio and into Michigan. This system is comprised of
approximately 6,500 miles of pipeline.
The Trunkline transmission system consists of a system of two large diameter
parallel pipelines, extending approximately 1,400 miles from the Gulf Coast
areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky,
Illinois and Indiana to a point on the Indiana-Michigan border. This system is
comprised of approximately 3,500 miles of pipeline.
The Sea Robin transmission system consists of two offshore Louisiana natural gas
supply systems. These systems are comprised of approximately 432 miles of
pipeline extending approximately 81 miles into the Gulf of Mexico.
Panhandle Energy has a total of approximately 90 billion cubic feet of total
storage available for use in connection with its gas transmission systems.
Panhandle Energy owns and operates 47 compressor stations and has five
underground gas storage fields located in Illinois, Michigan, Kansas, Oklahoma
and Louisiana with a combined maximum working storage capacity of approximately
72 billion cubic feet. Panhandle Energy also has contracts with third parties
that provide for approximately 18 billion cubic feet of storage.
Panhandle Energy owns an LNG regasification plant and related LNG tanker port,
unloading facilities and LNG storage facilities located at Lake Charles,
Louisiana. This LNG plant is one of the largest operating LNG facilities in
North America, based on its current sustainable sendout capacity of
approximately 630 million cubic feet per day. Panhandle Energy has plans to
expand its sendout capacity to approximately 1.2 billion cubic feet per day.
A majority of Panhandle Energy's revenue comes from long-term service agreements
with local distribution company customers. Panhandle Energy also provides firm
transportation services under contract to gas marketers, producers, other
pipelines, electric power generators, and a variety of end-users. In addition,
Panhandle Energy offers 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 seasonal, with the highest throughput and a higher
portion of annual operating revenues and net earnings occurring in the
traditional winter heating season.
In fiscal 2003, Panhandle Energy's operating revenues and throughput were $24.5
million and 69 TBtu (Billion British thermal unit), respectively. Of this
operating revenue, 75 percent was generated from transportation services, 13
percent from LNG terminalling services, 9 percent from storage services and 3
percent from other services. Aggregate sales to Panhandle Energy's top ten
customers accounted for 73 percent of the segment's operating revenue in fiscal
2003. Panhandle Energy has no single customer, or group of customers under
common control, which accounted for ten percent or more of the Company's
consolidated revenues in fiscal 2003. For additional information, see ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Business Segment Results.
Regulation
Panhandle Energy is subject to regulation by various federal, state and local
governmental agencies, including those specifically described below.
The Federal Energy Regulatory Commission (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. 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, as well as those for gas, sold by a
natural gas company in interstate commerce for resale. 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 the
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.
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 primarily
competes with 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 in the Midwest
market area.
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 more than 950,000 residential,
commercial and industrial customers through local distribution systems
consisting of 14,093 miles of mains, 9,421 miles of service lines and 76 miles
of transmission lines. Each utility division's rates and operations are subject
to regulation by the regulatory commission of any states in which it 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 fiscal
2003, this segment represented 98 percent of the Company's total operating
revenues because the Transportation and Storage segment's assets were acquired
on June 11, 2003.
In fiscal 2003, 2002 and 2001, the Distribution segment's operating revenues
were $1,159.0 million, $968.9 million and $1,304.0 million, respectively;
average customers served totaled 944,657, 935,229 and 935,158, respectively; and
gas volumes sold or transported totaled 188,333 million cubic feet (MMcf),
166,793 MMcf and 185,604 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 consolidated revenues in fiscal 2003. For
additional information, see ITEM 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Business Segment Results.
A description of each of the Company's regulated utility divisions follows.
Missouri Gas Energy - Missouri Gas Energy (MGE), headquartered in Kansas City,
Missouri, serves approximately 502,000 customers in central and western Missouri
(including Kansas City, St. Joseph, Joplin and Monett) through a local
distribution system that consists of approximately 7,954 miles of mains, 4,877
miles of service lines and 47 miles of transmission lines. Its service
territories have a total population of approximately 1.5 million. MGE's natural
gas rates are regulated by the Missouri Public Service Commission (MPSC) (see
Regulation and Rates).
MGE'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,
2003 2002 2001
--------- -------- --------
Average number of gas sales customers:
Residential ............................................ 430,861 428,215 428,971
Commercial ............................................. 60,774 58,749 59,435
Industrial ............................................. 99 95 95
-------- -------- --------
Total average gas sales customers .................. 491,734 487,059 488,501
Average number of transportation customers .................. 461 378 373
-------- -------- --------
Total average gas sales and transportation customers 492,195 487,437 488,874
======== ======== ========
Gas sales in millions of cubic feet (MMcf):
Residential ............................................ 39,821 35,039 44,011
Commercial ............................................. 17,399 15,686 19,828
Industrial ............................................. 391 417 598
-------- -------- --------
Gas sales billed ................................... 57,611 51,142 64,437
Net change in unbilled gas sales ....................... 61 (16) (64)
-------- -------- --------
Total gas sales .................................... 57,672 51,126 64,373
Gas transported in MMcf ..................................... 26,893 27,324 30,921
-------- -------- --------
Total gas sales and gas transported in MMcf ........ 84,565 78,450 95,294
======== ======== ========
Weather:
Degree days (a)...............................................5,105 4,419 5,541
Percent of 10-year measure (b).................................. 98% 85% 107%
Percent of 30-year measure (b)..................................98% 85% 106%
(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 158,000 customers in northeastern and central Pennsylvania
(including Wilkes-Barre, Scranton and Williamsport) through a local distribution
system that consists of approximately 2,504 miles of mains, 1,502 miles of
service lines and 29 miles of transmission lines. Its service territories have a
total population of approximately 745,000. PG Energy's natural gas rates are
regulated by the Pennsylvania Public Utility Commission (PPUC) (see Regulation
and Rates).
PG Energy'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,
2003 2002 2001
-------- -------- --------
Average number of gas sales customers served:
Residential .................................................. 141,769 141,223 140,324
Commercial ................................................... 14,141 13,707 13,480
Industrial ................................................... 120 104 100
Public authorities and other ................................. 337 212 206
-------- -------- --------
Total average customers served ........................... 156,367 155,246 154,110
Average number of transportation customers ........................ 613 624 1,212
-------- -------- --------
Total average gas sales and transportation customers ..... 156,980 155,870 155,322
======== ======== ========
Year Ended June 30,
2003 2002 2001
-------- -------- --------
Gas sales in MMcf:
Residential .................................................... 18,372 15,053 17,965
Commercial ..................................................... 6,732 5,325 6,561
Industrial ..................................................... 376 277 535
Public authorities and other ................................... 334 145 368
-------- -------- --------
Gas sales billed ........................................... 25,814 20,800 25,429
Net change in unbilled gas sales ............................... 4 (22) 40
-------- -------- --------
Total gas sales ............................................ 25,818 20,778 25,469
Gas transported in MMcf ............................................. 28,366 26,976 25,430
-------- -------- --------
Total gas sales and gas transported in MMcf ................ 54,184 47,754 50,899
======== ======== ========
Weather:
Degree days .................................................... 6,654 5,373 6,621
Percent of 10-year measure ..................................... 109% 89% 108%
Percent of 30-year measure ..................................... 106% 86% 105%
New England Gas Company - New England Gas Company (NEG), headquartered in
Providence, Rhode Island, serves approximately 298,000 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 3,635 miles of mains and
3,042 miles of service lines. Its service territories have a total population of
approximately 1.2 million. In Rhode Island and Massachusetts, NEG's natural gas
rates are regulated by the Rhode Island Public Utilities Commission (RIPUC) and
Massachusetts Department of Telecommunications and Energy (MDTE), respectively
(see Regulation and Rates).
NEG's customers served, gas volumes sold or transported and weather-related
information for the past three fiscal years are as follows:
Nine Months
Ended
Year Ended June 30, June 30,
2003 2002 2001 (a)
-------- -------- --------
Average number of gas sales customers served:
Residential ............................................................... 268,312 265,206 264,349
Commercial ................................................................ 25,442 21,696 21,634
Industrial and irrigation ................................................. 225 3,472 3,570
Public authorities and other .............................................. 41 43 45
-------- -------- --------
Total average customers served ........................................ 294,020 290,417 289,598
Average number of transportation customers ..................................... 1,462 1,505 1,364
-------- -------- --------
Total average gas sales and transportation customers .................. 295,482 291,922 290,962
======== ======== ========
Gas sales in MMcf:
Residential ............................................................... 25,481 19,975 21,690
Commercial ................................................................ 9,725 6,196 7,293
Industrial and irrigation ................................................. 2,055 3,271 2,721
Public authorities and other .............................................. 28 23 22
-------- -------- --------
Gas sales billed ...................................................... 37,289 29,465 31,726
Net change in unbilled gas sales .......................................... 1,336 (333) 286
-------- -------- --------
Total gas sales ....................................................... 38,625 29,132 32,012
Gas transported in MMcf ........................................................ 10,959 11,457 7,399
-------- -------- --------
Total gas sales and gas transported in MMcf ........................... 49,584 40,589 39,411
======== ======== ========
Weather:
Degree days ............................................................... 6,143 4,980 5,273
Percent of 10-year measure ................................................ 111% 88% 105%
Percent of 30-year measure ................................................ 107% 85% 102%
(a) Information for the former Fall River Gas and ProvEnergy operations,
acquired September 28, 2000, and the former Valley Resources operations,
acquired September 20, 2000, is included since October 1, 2000. See
Acquisitions and Sales.
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.
The 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 2003 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 2003 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 2004 through 2017. 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 2003 approximated 29% 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 operating margin 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; 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 July 5, 2001, the MPSC issued an order approving a unanimous
settlement of Missouri Gas Energy's rate request. The settlement provides for an
annual $9,892,000 base rate increase, as well as $1,081,000 in added revenue
from new and revised service charges. The majority of the rate increase is
recovered through increased monthly fixed charges to gas sales service
customers. New rates became effective August 6, 2001, two months before the
statutory deadline for resolving the case. The approved settlement resulted in
the dismissal of all pending judicial reviews of prior rate cases. The
settlement also provided for the development of a two-year experimental
low-income program to help certain customers in the Joplin area pay their
natural gas bills.
The MPSC approval of the January 31, 1994 acquisition of Missouri Gas Energy by
the Company was subject to the terms of a stipulation and settlement agreement,
which, among other things, required Missouri Gas Energy to reduce rate base by
$30,000,000 (amortized over a ten-year period on a straight-line basis) to
compensate rate payers for rate base reductions that were eliminated as a result
of the acquisition.
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 $5,227,000. The net
result of the excess revenues and the Energize Rhode Island weather mitigation
and non-firm margin sharing provisions is the crediting to customers of $949,000
over a twelve-month period starting July 1, 2003.
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.
Pennsylvania -- In December 2000, the PPUC approved a settlement agreement that
provided for a rate increase designed to produce $10,800,000 of additional
annual revenue. The new rates became effective on January 1, 2001.
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 on-going 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 contamination at certain sites on its gas transmission systems and
has undertaken cleanup programs at these sites. The contamination resulted from
the past use of lubricants containing polychlorinated bi-phenyls (PCBs) in
compressed air systems; the past use of paints containing PCBs; and the prior
use of wastewater collection facilities and other on-site disposal areas. The
Company 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 Company 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 Management's Discussion and Analysis of Results of Operations and Financial
Condition (MD&A) -- Cautionary Statement Regarding Forward-Looking Information
and Note XVIII - Commitments and Contingencies in the Notes to the Consolidated
Financial Statements.
Real Estate
The Company owns certain real estate that is neither material nor critical to
its operations.
Employees
As of July 31, 2003, the Company had 3,023 employees, of whom 2,138 are paid on
an hourly basis and 885 are paid on a salary basis. Of the 2,138 hourly paid
employees, unions represent 62%. 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--1,844;
Transportation and Storage segment--1,119; All Other segment--20 persons. In
addition, the corporate office of Southern Union employed a total of 40 persons.
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 is expected to be
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.
Effective August 1, 2003, the Company agreed to a three-year contract with a
bargaining unit representing a portion of PG Energy employees. During fiscal
2001, the Company agreed to a three-year contract with another bargaining unit
representing the remaining PG Energy unionized employees, effective April 2001.
Effective May 28, 2003, Panhandle Energy agreed to a three-year contract with a
bargaining unit representing Panhandle Energy employees that will expire on May
27, 2006.
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.
In December 1998, the Company agreed to five-year contracts with each
bargaining-unit representing Missouri Gas Energy employees, which were effective
in May 1999 and will expire in 2004.
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 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 Commitments and Contingencies in the Notes to Consolidated Financial
Statements for a discussion of the Company's legal proceedings. See ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- 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, 2003.
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, 2001 are set forth
below:
$/Share
High Low
July 1 to September 15, 2003..................... $ 17.06 $ 14.80
(Quarter Ended)
June 30, 2003................................ 17.00 11.53
March 31, 2003............................... 16.40 11.50
December 31, 2002............................ 16.18 9.67
September 30, 2002........................... 16.25 9.71
(Quarter Ended)
June 30, 2002................................ 18.00 13.44
March 31, 2002............................... 18.31 15.06
December 31, 2001............................ 20.31 15.06
September 30, 2001........................... 21.93 15.88
Holders
As of September 15, 2003, there were 7,151 holders of record of Southern Union's
common stock and 72,890,475 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.
On September 15, 2003, 54,394,401 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 July 31, 2003, July 15, 2002 and August 30, 2001,
the Company distributed its annual 5% common stock dividend to stockholders of
record on July 17, 2003, July 1, 2002 and August 16, 2001, respectively. A
portion of each of the 5% stock dividends distributed on July 15, 2002 and
August 30, 2001 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.
Plans
There is incorporated herein by reference the information that will appear in
the Company's definitive proxy statement for the 2003 Annual Meeting of
Stockholders under the caption Executive Officers and Compensation - Equity
Compensation Plans.
ITEM 6. Selected Financial Data.
As of and for the year ended June 30,
2003(a) 2002(b) 2001(c) 2000(d) 1999
------------ ----------- ------------ ----------- ------------
(dollars in thousands, except per share amounts)
Total operating revenues .......................... $ 1,188,507$ 980,614 $ 1,461,811 $ 566,833 $ 378,292
Net earnings (loss):
Continuing operations ........................ 43,669 1,520 40,159 (10,251) (8,036)
Discontinued operations (e) .................. 32,520 18,104 16,524 20,096 18,481
Available for common stock ................... 76,189 19,624 57,285 9,845 10,445
Net earnings (loss) per common and common
share equivalents (f):
Continuing operations ........................ .74 .03 .67 (.20) (.21)
Discontinued operations ...................... .55 .30 .28 .39 .48
Available for common stock ................... 1.29 .33 .95 .19 .27
Total assets ...................................... 4,590,938 2,680,064 2,907,299 2,021,460 1,087,348
Common stockholders' equity ....................... 920,418 685,346 721,857 735,455 301,058
Short-term debt and capital lease
obligation ................................... 734,752 108,203 5,913 2,193 2,066
Long-term debt and capital lease
obligation, excluding current portion ........ 1,611,653 1,082,210 1,329,631 733,774 390,931
Company-obligated mandatorily
redeemable preferred securities of
subsidiary trust ............................ 100,000 100,000 100,000 100,000 100,000
Average customers served (g) ...................... 945,705 942,849 970,927 605,000 480,939
(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 results of operations
since June 11, 2003. For these reasons, the consolidated results of
operations of the Company 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
Goodwill and Intangibles and Employee Benefits in the Notes to Consolidated
Financial Statements.
(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 results of operations
since their respective acquisition dates. For these reasons, the
consolidated results of operations of the Company 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
results of operations since November 4, 1999. For these reasons, the
consolidated results of operations of the Company for the periods
subsequent to the acquisition are not comparable to the same periods in
prior years.
(e) 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 for all 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.
(f) 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 (i) the 5% stock
dividends distributed on July 31, 2003, July 15, 2002, August 30, 2001,
June 30, 2000 and August 6, 1999, and (ii) the 50% stock dividend
distributed on July 13, 1998.
(g) 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, as well as 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 serves approximately 500 customers in the Midwest and Southwest. Panhandle
Energy was acquired by Southern Union on June 11, 2003, as further described
below. The Company's local natural gas distribution operations are conducted
through its three regulated utility divisions, Missouri Gas Energy, PG Energy
and New England Gas Company, which collectively serve over 950,000 residential,
commercial and industrial customers in Missouri, Pennsylvania, Rhode Island and
Massachusetts.
On June 11, 2003, Southern Union acquired Panhandle Eastern Pipe Line Company
and its subsidiaries (hereafter collectively referred to as Panhandle Energy)
from CMS Energy Corporation for approximately $582 million in cash and in
connection therewith incurred transaction costs estimated at $30 million.
Additional consideration was financed by CMS Energy Corporation through their
purchase of 3 million shares of Southern Union common stock (before adjustment
for any subsequent stock dividends) valued at approximately $49 million based on
market prices at closing. Southern Union also incurred additional deferred state
income tax liabilities estimated at $18 million as a result of the transaction.
At the time of the acquisition, Panhandle Energy had approximately $1.159
billion of debt outstanding that it retained. The Company funded the cash
portion of the acquisition with approximately $437 million in cash proceeds it
received for the January 1, 2003 sale of its Texas operations, approximately
$121 million of the net proceeds it received from concurrent common stock and
equity units 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 in the
United States with the purchase price paid by the Company being allocated to
Panhandle Energy's net assets as of the acquisition date based on preliminary
estimates. The Panhandle Energy assets acquired and liabilities assumed have
been recorded in the Consolidated Balance Sheet as of June 30, 2003 at their
estimated fair value and are subject to further assessment and adjustment
pending 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 are 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. The Panhandle Energy entities include
Panhandle Eastern Pipe Line Company, LLC (Panhandle Eastern Pipe Line),
Trunkline Gas Company, LLC (Trunkline), Sea Robin Pipeline Company (Sea Robin),
Trunkline LNG Company, LLC (Trunkline LNG) and Pan Gas Storage Company, LLC (Pan
Gas, also dba Southwest Gas Storage). 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 per day, 72
billion cubic feet of owned underground storage capacity and 6.3 billion cubic
feet of above ground LNG storage facilities. Trunkline LNG, located on
Louisiana's Gulf Coast, operates one of the nation's largest LNG import
terminals.
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, the assets and
liabilities sold have been segregated and reported as "held for sale" in the
Consolidated Balance Sheet as of June 30, 2002, and the related results of
operations and gain on sale have been segregated and reported as "discontinued
operations" in the Consolidated Statement of Operations and Consolidated
Statement of Cash Flows for all periods presented.
In September 2000, Southern Union acquired Providence Energy Corporation
(ProvEnergy), Fall River Gas Company (Fall River Gas), and Valley Resources
(Valley Resources). Collectively, these companies (hereafter referred to as the
Company's New England Operations) were acquired for approximately $422,000,000
in cash and 1,370,629 shares (before adjustment for any subsequent stock
dividends) of Southern Union common stock, as well as the assumption of
approximately $140,000,000 in long-term debt. The results of operations from
ProvEnergy and Fall River Gas have been included in the Consolidated Statement
of Operations since September 28, 2000, and the results of operations from
Valley Resources have been included in the Consolidated Statement of Operations
since September 20, 2000. Thus, the Consolidated Statement of Operations for the
periods subsequent to these acquisitions is not comparable to the same periods
in prior years. These acquisitions were accounted for using the purchase method.
The New England Operations' primary business is the distribution of natural gas
through the New England Gas Company. Subsidiaries of the Company acquired with
the New England Gas Company and currently operating include ProvEnergy Power LLC
(ProvEnergy Power), Fall River Gas Appliance Company (Fall River Appliance),
Valley Appliance Merchandising Company (VAMCO) and Alternate Energy Corporation
(AEC). ProvEnergy Power provides outsourced energy management services and owns
50% of Capital Center Energy Company LLC, a joint venture formed between
ProvEnergy and ERI Services, Inc. to provide retail power and conditioned air.
Fall River Appliance rents water heaters and conversion burners, primarily to
residential customers. VAMCO rents natural gas burning appliances and offers
appliance service contract programs to residential customers. AEC is an energy
consulting firm.
Subsidiaries acquired with the New England Gas Company and subsequently sold
include Morris Merchants, Inc. (Morris Merchants), Valley Propane, Inc. (Valley
Propane) and ProvEnergy Oil Enterprises, Inc. (ProvEnergy Oil). In October 2001,
Morris Merchants, which served as a manufacturers' representative agency for
franchised plumbing and heating contract supplies throughout New England, was
sold for $1,586,000. In September 2001, Valley Propane, which sold liquid
propane to residential, commercial and industrial customers, was sold for
$5,301,000. In August 2001, ProvEnergy Oil, which operated a fuel oil
distribution business through its subsidiary, ProvEnergy Fuels, Inc. for
residential and commercial customers, was sold for $15,776,000. No financial
gain or loss was recognized on any of these sales transactions.
In April 2002, PG Energy Services' (Energy Services) propane operations, which
sold liquid propane to residential, commercial and industrial customers, were
sold for $2,300,000, resulting in a pre-tax gain of $1,200,000. In July 2001,
Energy Services' commercial and industrial gas marketing contracts were sold for
$4,972,000, resulting in a pre-tax gain of $4,653,000. In June 2001, the Company
sold Keystone, which engaged primarily in the construction, maintenance, and
rehabilitation of natural gas distribution pipelines, for $3,300,000, resulting
in a pre-tax gain of $707,000.
Results of Operations
In this section the Company's results of operations are discussed on a
consolidated basis and on a segment basis for each of the two reportable
segments. The Company's reportable segments include the Transportation and
Storage segment and the Distribution segment. Segment results of operations are
presented on a net operating revenues basis. Net operating revenues is defined
as operating margin, less operating maintenance and general expenses,
depreciation and amortization, and taxes other than on income and revenues, and
represents one of the financial measures that the Company uses to internally
manage its business. For additional segment reporting information, see Note XXI
- -- Reportable Segments.
Consolidated Results
The following table provides selected financial data regarding the Company's
consolidated results of operations for fiscal 2003, 2002 and 2001:
Years Ended June 30,
------------------------------------------------
2003 2002 2001
------------- ------------- -------------
(thousands of dollars)
Net operating revenues:
Distribution segment.......................................... $ 142,762 $ 135,502 $ 123,484
Transportation and storage segment............................ 9,635 -- --
All other segment............................................. 13 -- (413)
Business restructuring charges.................................... -- (29,159) --
Corporate..................................................... (10,039) (15,218) (21,806)
------------- ------------- -------------
Total net operating revenues............................... 142,371 91,125 101,265
Other income (expenses):
Interest...................................................... (83,343) (90,992) (102,928)
Dividends on preferred securities of subsidiary trust......... (9,480) (9,480) (9,480)
Other, net.................................................... 18,394 14,278 81,401
------------- ------------- -------------
Total other expenses, net.................................. (74,429) (86,194) (31,007)
------------- ------------- -------------
Federal and state income taxes.................................... 24,273 3,411 30,099
------------- ------------- -------------
Net earnings from continuing operations........................... 43,669 1,520 40,159
------------- ------------- -------------
Discontinued operations:
Earnings from discontinued operations before income taxes..... 84,773 29,801 26,425
Federal and state income taxes................................ 52,253 11,697 9,901
------------- ------------- -------------
Net earnings from discontinued operations......................... 32,520 18,104 16,524
------------- ------------- -------------
Cumulative effect of change in accounting principle, net of tax... -- -- 602
------------- ------------- -------------
Net earnings available for common stock........................... $ 76,189 $ 19,624 $ 57,285
============= ============= =============
Net Earnings - 2003 Compared to 2002. Southern Union Company's 2003 (fiscal year
ended June 30) net earnings available for common stock were $76,189,000 ($1.29
per common share, diluted for outstanding options and warrants -- hereafter
referred to as per share), compared with $19,624,000 ($.33 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 $43,669,000 ($.74 per share) in
2003 compared with $1,520,000 ($.03 per share) in 2002. The increase was
primarily due to the following:
o a $7,260,000 increase in net operating revenues from the Distribution
segment (see Business Segment Results - Distribution Segment);
o a $9,635,000 increase in net operating revenues 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 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);
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 $32,520,000 ($.55 per share) in
2003 compared with $18,104,000 ($.30 per share) in 2002. The $14,416,000
increase was primarily due to the recording of an $18,928,000 after-tax gain on
sale of the Texas Operations (see Discontinued Operations).
Net Earnings - 2002 Compared to 2001. Southern Union Company's 2002 net earnings
available for common stock were $19,624,000 ($.33 per share), compared with
$57,285,000 ($.95 per share) in 2001. The $37,661,000 decrease reflects a
$38,639,000 decrease in net earnings from continuing operations and a $1,580,000
increase in net earnings from discontinued operations, as further discussed
below.
Net earnings from continuing operations were $1,520,000 ($.03 per share) in 2002
compared with $40,159,000 ($.67 per share) in 2001. The decrease was primarily
due to the following:
o a total of $29,159,000 in business restructuring charges,
recorded in the first quarter of fiscal 2002 (see Business
Restructuring Charges);
o a $67,123,000 decrease in other income (see Other Income (Expense),
Net).
The above items were partially offset by:
o a $12,018,000 increase in net operating revenues from the Distribution
segment (see Business Segment Results - Distribution Segment);
o a $6,588,000 decrease in corporate costs (see Corporate);
o an $11,936,000 decrease in interest expense (see Interest Expense);
o a $26,688,000 decrease in income tax expense (see Federal and State
Income Taxes).
Net earnings from discontinued operations were $18,104,000 ($.30 per share) in
2002 compared with $16,524,000 ($.27 per share) in 2001, an increase of
$1,580,000 (see Discontinued Operations).
Business Restructuring Charges. Business reorganization and restructuring
initiatives were commenced in August 2001 as part of a previously announced Cash
Flow Improvement Plan designed to increase annualized pre-tax cash flow from
operations by at least $50 million by the end of fiscal 2002. Actions taken by
the Company 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. The Company's Corporate net operating loss in 2003 decreased by
$5,179,000, or 34%, to $10,039,000. The decrease in Corporate loss primarily
reflects the impact of the previously discussed business reorganization and
restructuring initiatives that were commenced in August 2001.
The Company's Corporate net operating loss in 2002 decreased by $6,588,000, or
30%, to $15,218,000. The decrease in Corporate loss primarily reflects the
impact of the previously discussed business reorganization and restructuring
initiatives that were commenced in August 2001, including the limited RIF within
the corporate offices, which resulted in reduced salary and benefit costs and
other corporate operating expenses.
Interest Expense. 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 bank note (the 2002 Term Note) entered into by the Company on July
15, 2002 to refinance a portion of the $485 million Term Note entered into by
the Company on August 28, 2000 to (i) fund the cash consideration paid to
stockholders of Fall River Gas, ProvEnergy and Valley Resources, (ii) refinance
and repay long- and short-term debt assumed in the New England Operations, and
(iii) acquisition costs of the New England Operations. This decrease in the 2002
Term Note interest was due to reductions in LIBOR rates during 2003 and the
principal repayment of $100,000,000 of the note during 2003. The Company
recorded $1,760,000 in interest on long-term debt related to the Panhandle
properties in 2003.
Interest expense on short-term debt in 2003 increased from $7,187,000 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. 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 3.2% to 2.4% in 2003.
Total interest expense in 2002 decreased by $11,936,000, or 12%, to $90,992,000.
Interest expense decreased by $11,299,000 in 2002 on the $485,000,000 Term Note
entered into by the Company on August 28, 2000, previously discussed. This
decrease in Term Note interest was due to significant reductions in LIBOR rates
during 2002 and the principal repayment of $135,000,000 of the Term Note during
2002.
Interest expense on short-term debt in 2002 decreased from $7,913,000 to
$7,187,000, primarily due to the significant decrease in LIBOR rates during
2002, which was partially offset by an increase in the average amount of
short-term debt outstanding from $123,829,000 to $176,600,000 during the year.
The increase in the average amount of short-term debt outstanding during 2002
was primarily due to (i) higher than normal short-term debt outstanding due to
high gas costs and accounts receivable in 2001, (ii) an increase in the
Company's seasonal borrowing requirements due to the acquisition of the New
England Operations, and (iii) the repayment of various principal amounts of the
Term Note with borrowings under the Company's credit facilities. The average
rate of interest on short-term debt decreased from 6.4% to 3.2% in 2002.
Other Income (Expense), Net. Other income, net, in 2003 was $18,394,000,
compared with $14,278,000 in 2002. Other income in 2003 includes a gain of
$22,500,000 on the settlement of the Company's claims against Southwest Gas
Corporation (Southwest) and other parties related to the Southwest litigation,
which was partially offset by $5,949,000 of related legal costs, income of
$2,016,000 generated from the sale and/or rental of gas-fired equipment and
appliances by various operating subsidiaries and $567,000 of realized gains on
the sale of a portion of Southern Union's holdings in Capstone Turbine
Corporation (Capstone).
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 PG Energy Services Inc., 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 PG Energy Services Inc., $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).
Other income, net, in 2001 of $81,401,000 included realized gains on the sale of
investment securities of $74,582,000, a $13,532,000 gain on the sale of non-core
real estate and $6,838,000 of interest and dividend income. These items were
partially offset by $12,855,000 of legal costs associated with Southwest.
Federal and State Income Taxes. Federal and state income tax expense from
continuing operations in 2003, 2002 and 2001 was $24,273,000, $3,411,000 and
$30,099,000, respectively. The Company's consolidated federal and state
effective income tax rate was 36%, 69% and 43% in 2003, 2002 and 2001,
respectively. 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. The fluctuation in the
effective federal and state income tax rate in 2002 compared with 2001 is
primarily the result of the sale of the Florida Operations in 2002 which had
non-tax deductible goodwill on its financial statements, along with the change
in the level of pre-tax earnings.
Discontinued Operations. Net earnings from discontinued operations were
$32,520,000 ($.55 per share) in 2003 compared with $18,104,000 ($.30 per share)
in 2002, an increase of $14,416,000. The Company completed the sale of its Texas
Operations in 2003 resulting in an after-tax gain on sale of $18,928,000 that is
reported in earnings from discontinued operations in accordance with the
Financial Accounting Standards Board (FASB) standard, Accounting for the
Impairment or Disposal of Long-Lived Assets. The after-tax gain on the sale of
the Texas Operations was impacted by the elimination of $70,469,000 of goodwill
related to these operations which was primarily non-tax deductible. The timing
of the Texas Operations' disposition, completed effective January 1, 2003,
resulted in a $15,448,000 decrease in pre-tax earnings from discontinued
operations in 2003 as compared with 2002. This decrease in earnings was
partially offset by a $3,579,000 pre-tax reduction in depreciation expense,
recorded during the quarter ended December 31, 2002. In accordance with the
previously mentioned FASB standard, once the assets of the Texas Operations were
deemed to be "held for sale" in October 2002, depreciation of such assets
ceased. Additionally, during the quarter ended September 30, 2001, the Texas
Operations recorded a charge of $2,153,000 in connection with the previously
discussed reorganization and restructuring efforts under the Cash Flow
Improvement Plan and recognized a goodwill impairment loss of $1,941,000 based
on prices of comparable businesses for certain non-core properties.
Net earnings from discontinued operations were $18,104,000 ($.30 per share) in
2002 compared with $16,524,000 ($.27 per share) in 2001. The increase in
earnings from discontinued operations was impacted by a $4,379,000 pre-tax
reduction in bad debt expense due to a decrease in delinquent customer
receivables resulting from lower gas prices and warmer weather in 2002 as
compared with 2001, and the absence of expense in 2002 relating to financial
derivative energy trading activity of a former subsidiary which generated
$5,685,000 of pre-tax losses in 2001. These items were partially offset by a
$3,286,000 decrease in operating margin primarily due to a reduction in sales
volumes from 54,520 MMcf in 2001 to 49,115 MMcf in 2002 as a result of weather
that was 93% of normal in 2002 as compared with 112% of normal in 2001.
Additionally in 2002, the Texas Operations recorded a pre-tax charge of
$2,153,000 in connection with the previously discussed reorganization and
restructuring efforts under the Cash Flow Improvement Plan.
Employees. The Company's continuing operations employed 3,041, 1,855 and 2,404
individuals as of June 30, 2003, 2002 and 2001, 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 August 1, 2003, the Company agreed to a three-year contract with a
bargaining unit representing a portion of PG Energy employees. During fiscal
2001, the Company agreed to a three-year contract with another bargaining unit
representing the remaining PG Energy unionized employees, effective April 2001.
Effective May 28, 2003, Panhandle Energy agreed to a three-year contract with a
bargaining unit representing the Panhandle Energy employees that will expire on
May 27, 2006.
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 year 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.
In December 1998, the Company agreed to five-year contracts with each
bargaining-unit representing Missouri employees, which were effective in May
1999.
Business Segment Results
Distribution Segment -- The Company's Distribution segment is primarily engaged
in the local distribution of natural gas in Missouri, Pennsylvania, Rhode Island
and Massachusetts. Its operations are conducted through the Company's three
regulated utility divisions: Missouri Gas Energy, PG Energy and New England Gas
Company. Collectively, the utility divisions serve more than 950,000
residential, commercial and industrial customers through local distribution
systems consisting of 14,093 miles of mains, 9,421 miles of service lines and 76
miles of transmission lines. The utility divisions' rates and operations are
subject to regulation 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
fiscal 2003, this segment represented 98 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 service; and (iii) solidify the
Company's relationships with regulatory bodies that oversee the various
operations. 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 2003, 2002 and 2001:
Years Ended June 30,
------------------------------------------------
2003 2002 2001
------------- ------------- -------------
Financial Results (thousands of dollars)
Operating revenues................................................ $ 1,158,964 $ 968,933 $ 1,304,012
Cost of gas and other energy...................................... (723,719) (568,447) (888,760)
Revenue-related taxes............................................. (40,485) (33,410) (49,869)
------------- ------------- -------------
Operating margin.............................................. 394,760 367,076 365,383
Operating expenses:
Operating, maintenance, and general........................... 171,463 154,906 155,929
Depreciation and amortization................................. 56,396 53,937 65,106
Taxes other than on income and revenues....................... 24,139 22,731 20,864
------------- ------------- -------------
Total operating expense.................................... 251,998 231,574 241,899
------------- ------------- -------------
Net operating revenues..................................... $ 142,762 $ 135,502 $ 123,484
============= ============= =============
Operating Information
Gas sales volumes (MMcf).......................................... 122,115 101,036 121,854
Gas transported volumes (MMcf).................................... 66,218 65,757 63,750
Weather:
Degree Days:
Missouri Gas Energy service territories.................... 5,105 4,419 5,541
PG Energy service territories.............................. 6,654 5,373 6,621
New England Gas Company service territories................ 6,143 4,980 5,273
Percent of 30-year measure:
Missouri Gas Energy service territories.................... 98% 85% 106%
PG Energy service territories.............................. 106% 86% 105%
New England Gas Company service territories................ 107% 85% 102%
Operating Revenues. 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-than-normal or near-normal weather in the Company's
utility service territories as compared with warmer-than-normal weather in 2002.
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 current 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. 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, operating margin is 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 2003 increased 461 MMcf to 66,218 MMcf at an
average transportation rate per Mcf of $.56 in 2002 and $.58 in 2003.
Operating revenues in 2002 compared with 2001 decreased by $335,079,000, or 26%,
to $968,933,000 while gas purchase and other energy costs decreased
$320,313,000, or 36%, to $568,447,000. The decrease in both operating revenues
and gas purchase and other energy costs between periods was primarily due to a
17% decrease in gas sales volumes to 101,036 MMcf in 2002 from 121,854 MMcf in
2001 and by a 23% decrease in the average cost of gas from $7.29 per Mcf in 2001
to $5.63 per Mcf in 2002. The decrease in gas sales volumes is primarily due to
warmer-than-normal weather in the Company's utility service territories as
compared to colder-than-normal weather in 2001. The decrease in the average cost
of gas is due to decreases 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 2002 was a
$16,460,000 decrease in gross receipt taxes primarily due to a decrease in gas
purchase and other energy costs. The decrease in operating revenues in 2002 was
partially offset by the timing of the acquisition of the New England Operations
in September 2000, as well as the $10,973,000 annual revenue increase granted to
Missouri Gas Energy effective August 2001 and the $10,800,000 annual revenue
increase granted to PG Energy effective January 2001.
Gas transportation volumes in 2002 increased 2,007 MMcf to 65,757 MMcf at an
average transportation rate per Mcf of $.56 in 2002 and $.53 in 2001.
Operating Margin. Operating margin in 2003 (operating revenues less gas purchase
and other energy costs and revenue-related taxes) increased by $27,684,000,
compared with an increase of $1,693,000 in 2002. Operating margins and earnings
are primarily dependent upon gas sales volumes and gas service rates. The level
of gas sales volumes is sensitive to the variability of the weather as well as
the timing of acquisitions and divestitures. Sales volumes, which benefited from
generally colder-than-normal weather in 2003 and 2001, were negatively impacted
by unusually mild temperatures throughout fiscal 2002. Missouri, Pennsylvania
and New England accounted for 37%, 24% and 39%, respectively, of the segment's
operating margin in 2003 and 37%, 23% and 40%, respectively, in 2002.
Customers. The average number of customers served in 2003, 2002 and 2001 was
944,657, 935,229 and 935,158, respectively. Changes in customer totals between
years primarily reflect the impact of acquisitions and sales not accounted for
as discontinued operations. Missouri Gas Energy served 492,195 customers in
central and western Missouri. PG Energy served 156,980 customers in northeastern
and central Pennsylvania, and New England Gas Company served 295,482 customers
in Rhode Island and Massachusetts during 2003.
Operating Expenses. Operating, maintenance and general expenses in 2003
increased $16,557,000, or 11%, to $171,463,000. The increase is primarily due to
$6,370,000 of increased pension and other postretirement benefit costs primarily
due to volatility in the stock markets, $4,265,000 of increased insurance
expense, and $3,547,000 of increased bad debt expense resulting from higher
customer receivables due to higher gas prices and colder weather in 2003. The
Company also experienced increases in employee payroll and other operating and
maintenance costs as a result of the colder weather in 2003. These items were
partially offset by realized savings in operating costs from the Cash Flow
Improvement Plan (see Business Restructuring Charges).
Depreciation and amortization expense in 2003 increased $2,459,000 to
$56,396,000. The increase was primarily due to normal growth in plant.
Taxes other than on income and revenues, principally consisting of property,
payroll and state franchise taxes increased $1,408,000 to $24,139,000 in 2003,
primarily due to an increase in state franchise taxes.
Operating, maintenance and general expenses in 2002 decreased $1,023,000, or 1%,
to $154,906,000. A decrease in bad debt expense of $11,500,000 resulted from a
decrease in delinquent customer receivables as a result of lower gas prices and
warmer weather in 2002 as compared with 2001. Additionally, in connection with
the Company's Cash Flow Improvement Plan announced in July 2001, the Company
realized savings of approximately $7,722,000 during 2002 primarily due to the
acceptance of voluntary ERPs in certain of its utility operating divisions. The
Company also experienced decreases in employee payroll and other operating and
maintenance costs as a result of the warmer weather in 2002. These items were
partially offset by $18,005,000 of increased operating expenses in 2002 due to
the timing of the acquisition of the New England Operations, and $7,657,000 of
increased pension and other postretirement benefits expense, primarily due to
volatility in the stock markets.
Depreciation and amortization expense in 2002 decreased $11,169,000 to
$53,937,000. The decrease was primarily due to the elimination of goodwill
amortization resulting from the Company's adoption of Goodwill and Other
Intangible Assets effective July 1, 2001. In accordance with this Standard, the
Company has ceased the amortization of goodwill, which generated $14,992,000 of
expense in 2001, and currently accounts for goodwill on an impairment-only
approach. See Other Matters -- Critical Accounting Policies and Goodwill and
Intangibles in the Notes to the Consolidated Financial Statements. The decrease
in 2002 also reflects $5,941,000 of reduced depreciation expense from reduced
depreciation rates in Missouri as a result of changes in the previously
mentioned rate settlement. These items were partially offset by $6,076,000 of
increased depreciation expense in 2002, due to the timing of the acquisition of
the New England Operations, and normal growth in plant.
Taxes other than on income and revenues increased $1,867,000 to $22,731,000 in
2002. The increase was also primarily the result of the acquisition of the New
England Operations.
Transportation and Storage Segment -- The Transportation and Storage segment is
primarily engaged in the interstate transportation and storage of natural gas in
the Midwest and Southwest, and also provides LNG terminalling and regasification
services. Its operations are conducted through Panhandle Energy, which the
Company acquired on June 11, 2003. In fiscal 2003, this segment represented two
percent of the Company's total operating revenues.
Panhandle Energy operates a large natural gas pipeline network, which provides
approximately 500 customers in the Midwest and Southwest with a comprehensive
array of transportation services. Panhandle Energy's major customers include 25
utilities located primarily in the United States Midwest market area, which
encompasses large portions of Illinois, Indiana, Michigan, Missouri, Ohio and
Tennessee.
The results of operations from Panhandle Energy have been included in the
Consolidated Statement of Operations since June 11, 2003. The following table
provides summary data regarding the Transportation and Storage segment's results
of operations for the period owned by Southern Union.
June 12, 2003
to
June 30, 2003
Financial Results (thousands of dollars)
Transportation revenues..................... $ 18,504
Storage revenues............................ 2,097
LNG terminalling revenues................... 3,244
Other revenues.............................. 684
--------------
Total operating revenues................ 24,529
Operating expenses:
Operating, maintenance, and general..... 10,102
Depreciation and amortization........... 3,197
Taxes other than on income and revenues. 1,595
--------------
Total operating expense.............. 14,894
--------------
Net operating revenues............... $ 9,635
==============
Operating Information
Volumes transported (TBtu)................... 69
Customers served ........................... 531
Liquidity and Capital Resources
Operating Activities. The seasonal nature of Southern Union's business results
in a high level of cash flow needs to finance gas purchases and other energy
costs, outstanding customer accounts receivable, and certain tax
payments. Additionally, significant cash flow needs may be required to finance
current debt service obligations. To provide these funds, as well as funds for
its continuing construction and maintenance programs, the Company has
historically used cash flows from operations and its credit facilities. Because
of available credit and the ability to obtain various types of market financing,
combined with anticipated cash flows from operations, management believes it has
adequate financial flexibility and access to the financial markets to meet its
short-term cash needs.
The Company has increased the scale of its natural gas transportation, storage
and distribution operations and the size of its customer base by pursuing and
consummating business acquisitions. On June 11, 2003, the Company acquired
Panhandle Energy. On September 20, 2000, the Company acquired Valley Resources
and on September 28, 2000, the Company acquired both Fall River Gas and
ProvEnergy. See Note II -- Acquisitions and Sales. Acquisitions require a
substantial increase in expenditures that may need to be financed through cash
flow from operations or future debt and equity offerings. The availability and
terms of any such financing sources will depend upon various factors and
conditions such as the Company's combined cash flow and earnings, the Company's
resulting capital structure, and conditions in the financial markets at the time
of such offerings. Acquisitions and financings also affect the Company's
combined results due to factors such as the Company's ability to realize any
anticipated benefits from the acquisitions, successful integration of new and
different operations and businesses, and effects of different regional economic
and weather conditions. Future acquisitions or related acquisition financing or
refinancing may involve the issuance of shares of the Company's common stock,
which could have a dilutive effect on the then-current stockholders of the
Company. See Other Matters -- Cautionary Statement Regarding Forward-Looking
Information.
Cash flows from operating activities before changes in operating assets and
liabilities for 2003 were $147,061,000 compared with $177,715,000 and
$94,465,000 for 2002 and 2001, respectively. After changes in operating assets
and liabilities, cash flows from operating activities were $55,696,000 in 2003
compared with cash flows from operating activities of $273,616,000 in 2002 and
cash flows used in operating activities of $147,099,000 for 2001. Changes in
operating assets and liabilities used cash of $91,365,000 in 2003. Changes in
operating assets and liabilities provided cash of $95,901,000 in 2002 and used
cash of $241,564,000 in 2001. The unusually high accounts receivable balance
that occurred due to high gas costs during 2003, the normal delay in the
recovery of over $21 million in deferred purchased gas costs that the Company
incurred during 2003 due to the regulatory lag in passing along such increased
purchased gas costs to customers and the nearly $35 million in funds expended
for replenishing natural gas stored in inventory in greater volumes and at
higher rates than in 2002, negatively impacted working capital in 2003. The
timing of acquisitions and the timing of natural gas purchases stored in
inventory also impacted operating activities in prior years.
At June 30, 2003, 2002 and 2001, the Company's primary source of liquidity
included borrowings available under the Company's credit facilities. On April 3,
2003, the Company entered into a short-term credit facility in the amount of
$140,000,000 (the Short-Term Facility) that matures April 1, 2004. The
Short-Term Facility was increased to $150,000,000 as of September 25, 2003. On
April 3, 2003, the Company amended the terms and conditions of its $225,000,000
long-term credit facility (the Long-Term Facility), which expires on May 29,
2004. The Company has additional availability under uncommitted line of credit
facilities (Uncommitted Facilities) with various banks. Borrowings under the
Short-Term Facility and Long-Term Facility (together, the Facilities) are
available for Southern Union's working capital, letter of credit requirements
and other general corporate purposes. The Facilities are subject to a commitment
fee based on the rating of the Company's senior unsecured notes (the Senior
Notes). As of June 30, 2003, the commitment fees were an annualized 0.15% on the
Short-Term Facility and 0.15% on the Long-Term Facility. The Facilities require
the Company to meet certain covenants in order for the Company to be able to
borrow under those agreements. A balance of $251,500,000 and $131,800,000 was
outstanding under the Facilities at June 30, 2003 and 2002, respectively. As of
September 15, 2003 there was a balance of $314,000,000 outstanding under these
Facilities.
The Company leases certain facilities, equipment and office space under
cancelable and noncancelable operating leases. The minimum annual rentals under
operating leases for the next five years ending June 30 are as follows:
2004--$18,614,000; 2005--$16,001,000; 2006--$14,345,000; 2007--$7,193,000;
2008--$6,329,000 and thereafter $5,038,000. The Company is also committed under
various agreements to purchase certain quantities of gas in the future. At June
30, 2003, the Company's Distribution segment has purchase commitments for
natural gas transportation services, storage services and certain quantities of
natural gas at a combination of fixed, variable and market-based prices that
have an aggregate value of approximately $1,669,538,000. The Company's purchase
commitments may be extended over several years depending upon when the required
quantity is purchased. The Company has purchase gas tariffs in effect for all
its utility service areas that provide for recovery of its purchase gas costs
under defined methodologies and the Company believes that all costs incurred
under such commitments will be recovered through its purchase gas tariffs.
Investing Activities. Cash flow used in investing activities in 2003 increased
$152,134,000 to $191,360,000. Cash flow used in investing activities decreased
by $395,527,000 to $39,226,000 in 2002. Investing activity cash flow was
primarily affected by additions to property, plant and equipment, acquisition
and sales of operations, sales and purchases of investment securities and the
settlement of interest rate swaps.
During 2003, 2002 and 2001, the Company expended $79,730,000, $70,698,000 and
$100,752,000, respectively, for capital expenditures excluding acquisitions. The
Transportation and Storage segment expended $5,128,000 for capital expenditures
in 2003. The remaining capital expenditures for the last three years primarily
related to Distribution segment system replacement and expansion. Included in
these capital expenditures were $9,094,000, $7,860,000 and $14,040,000 for the
Missouri Gas Energy Safety Program in 2003, 2002 and 2001, respectively. Cash
flow from operations has historically been utilized to finance capital
expenditures and is expected to be the primary source for future capital
expenditures.
In June 2003, Southern Union acquired Panhandle Energy for approximately $582
million in cash plus 3 million shares of Southern Union common stock (before
adjustment for any subsequent stock dividends). On the date of acquisition,
Panhandle Energy had approximately $59 million in cash and cash equivalents. In
September 2000, Southern Union acquired the New England Operations for 1,370,629
pre-stock dividend shares of Southern Union common stock and $414,497,000 in
cash.
In January 2003, the Company completed the sale of its Southern Union Gas
natural gas operating division and related assets for approximately $437,000,000
in cash resulting in a pre-tax gain of $62,992,000. During 2003, 2002 and 2001,
the Company expended $13,410,000, $23,215,000 and $22,012,000, respectively, for
capital expenditures relating to the assets of these operations which have been
classified as held for sale.
During 2002, the Company sold non-core subsidiaries and assets, which generated
proceeds of $40,935,000, resulting in net pre-tax gains of $4,914,000. In 2001,
Southern Union sold its Austin, Texas headquarters building, Lavaca Plaza, for
$20,638,000, resulting in a pre-tax gain of $13,532,000 and also disposed of a
former subsidiary of the Pennsylvania Operations, which generated proceeds of
$3,300,000 resulting in a pre-tax gain of $707,000.
In September 2001, the settlement of three interest rate swaps which the Company
had negotiated in July and August of 2001 and which were not designated as
hedges, resulted in a pre-tax gain and cash flow of $17,166,000.
During 2003, 2002 and 2001, the Company sold a portion of its investment
holdings in Capstone for $782,000, $1,213,000 and $84,762,000, respectively,
resulting in pre-tax gains of $567,000, $1,004,000 and $74,582,000,
respectively. During 2002 and 2001, the Company purchased investment securities
of $938,000 and $12,495,000, respectively.
Trunkline LNG has contractual obligations to complete the planned expansion of
its LNG importing terminal, which is projected to be in service by January 1,
2006. The expansion expenditures are projected to be $123 million over the next
three fiscal years.
Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in a major gas
safety program in its service territories (Missouri Gas Energy Safety Program).
This program includes replacement of company- and customer-owned gas service and
yard lines, the movement and resetting of meters, the replacement of cast iron
mains and the replacement and cathodic protection of bare steel mains. In
recognition of the significant capital expenditures associated with this safety
program, the MPSC permits the deferral, and subsequent recovery through rates,
of depreciation expense, property taxes and associated carrying costs. The
continuation of the Missouri Gas Energy Safety Program will result in
significant levels of future capital expenditures. The Company estimates
incurring capital expenditures of $8.5 million in 2004 related to this program
and approximately $136 million over the remaining life of the program of 16
years.
Financing Activities. Cash flow from financing activities was $222,661,000 in
2003 compared to cash flow used in financing activities of $235,609,000 and cash
flow from financing activities of $555,242,000 in 2002 and 2001, respectively.
Financing activity cash flow changes were primarily due to the net impact of
acquisition financing, repayment and issuance of debt, net activity under the
revolving credit facilities and purchase of treasury stock. As a result of these
financing transactions, the Company's total debt to total capital ratio at June
30, 2003 was 69.7%, compared with 60.3% and 61.9% at June 30, 2002 and 2001,
respectively. The Company's effective debt cost rate under the current debt
structure is 5.45% (which includes interest and the amortization of debt
issuance costs and redemption premiums on refinanced debt).
On June 11, 2003, the Company issued 9,500,000 shares of common stock at the
public offering price of $16.00 per share, resulting in net proceeds to the
Company, after underwriting discounts and commissions, of $15.44 per share, or
$146.7 million in the aggregate. The Company granted the underwriters a 30-day
over-allotment option to purchase up to an additional 1,425,000 shares of the
Company's common stock at the same price, which was exercised on June 11, 2003,
resulting in additional net proceeds to the Company of $22.0 million.
Also on June 11, 2003, the Company issued 2,500,000 equity units at a public
offering price of $50 per unit, resulting in net proceeds to the Company, after
underwriting discounts and commissions, of $48.50 per unit, or $121.3 million in
the aggregate. Each equity unit consists of a stock purchase contract for the
purchase of shares of the Company's common stock and, initially, a senior note
due August 16, 2006, issued pursuant to the Company's existing Indenture. The
equity units carry a total annual coupon of 5.75% (2.75% annual face amount of
the senior notes plus 3.0% annual contract adjustment payments). Each stock
purchase contract issued as a part of the equity units carries a maximum
conversion premium of up to 22% over the $16.00 issuance price of the Company's
common shares that were sold on June 11, 2003, as discussed previously. The
present value of the equity units contract adjustment payments was initially
charged to shareholders' equity, with an offsetting credit to liabilities. The
liability is accreted over three years by interest charges to the Consolidated
Statement of Operations. Before the issuance of the Company's common stock upon
settlement of the purchase contracts, the purchase contracts will be reflected
in the Company's diluted earnings per share calculations using the treasury
stock method.
In connection with the acquisition of the New England Operations, the Company
entered into a $535,000,000 Term Note on August 28, 2000 to fund (i) the cash
portion of the consideration to be paid to Fall River Gas' stockholders; (ii)
the all cash consideration to be paid to the ProvEnergy and Valley Resources
stockholders, (iii) repayment of approximately $50,000,000 of long- and
short-term debt assumed in the New England mergers, and (iv) related acquisition
costs. The Term Note, which initially expired on August 27, 2001, was extended
through August 26, 2002. On July 16, 2002, the Company repaid the Term Note with
the proceeds from the issuance of a $311,087,000 Term Note dated July 15, 2002
(the "2002 Term Note") and borrowings under the Facilities. The 2002 Term Note
is held by a syndicate of sixteen banks, led by JPMorgan Chase Bank, as Agent.
Eleven of the sixteen banks were also among the lenders of the Term Note, and
they are also lenders under at least one of the Facilities. The 2002 Term Note
carries a variable interest rate that is tied to either the LIBOR or prime
interest rates at the Company's option. The interest rate spread over the LIBOR
rate varies with the credit rating of the Senior Notes by Standard and Poor's
Rating Information Service (S&P) and Moody's Investor Service, Inc. (Moody's),
and is currently LIBOR plus 105 basis points. As of June 30, 2003 and September
15, 2003, a balance of $211,087,000 and $186,087,000, respectively, was
outstanding on this 2002 Term Note. The 2002 Term Note requires semi-annual
principal repayments on February 15th and August 15th of each year, with
payments of $25,000,000 each being due August 15, 2003, February 15, 2004, and
August 15, 2004 and payments of $35,000,000 each being due February 15, 2005 and
August 15, 2005. The remaining principal amount of $66,087,000 is due August 26,
2005. No additional draws can be made on the 2002 Term Note. The interest rate
on borrowings under the 2002 Term Note is a floating rate based on LIBOR or
prime interest rates. See Quantitative and Qualitative Disclosures About Market
Risk.
In July 2003, Panhandle Energy announced a tender offer for any and all of the
$747 million outstanding principal amount of five of its series of senior notes
outstanding at that point in time (the Panhandle Tender Offer) and
also called for redemption all of the outstanding $135 million principal amount
of its two series of debentures that were outstanding (the Panhandle Calls).
Panhandle Energy repurchased approximately $378 million of the principal amount
of its outstanding debt through the Panhandle Tender Offer for total
consideration of approximately $396 million plus accrued interest through the
purchase date. Panhandle Energy also redeemed its approximately $135 million of
debentures for total consideration of $139 million, plus accrued interest
through the redemption dates. As a result of these transactions, the Company has
recorded a pre-tax gain on the extinguishment of debt of approximately $6.7
million in August 2003. In August 2003, Panhandle Energy issued $550 million of
new senior notes (five and ten year) principally to refinance the repurchased
notes and redeemed debentures.
The Company has an effective shelf registration statement on file with the
Securities and Exchange Commission for a total principal amount of $800,000,000
in securities of which $326,750,000 in securities is available for issuance as
of September 25, 2003, which may be issued by the Company in the form of debt
securities, common stock, preferred stock, guarantees, warrants to purchase
common stock, preferred stock and debt securities, stock purchase contracts,
stock purchase units and depositary shares in the event that the Company elects
to offer fractional interests in preferred stock, and also trust preferred
securities to be issued by Southern Union Financing II and Southern Union
Financing III. Southern Union may sell such securities up to such amounts from
time to time, at prices determined at the time of any such offering.
The Company's ability to arrange financing, including refinancing, and its cost
of capital are dependent on various factors and conditions, including: general
economic and capital market conditions; maintenance of acceptable credit
ratings; credit availability from banks and other financial institutions;
investor confidence in the Company, its competitors and peer companies in the
energy industry; market expectations regarding the Company's future earnings and
probable cash flows; market perceptions of the Company's ability to access
capital markets on reasonable terms; and provisions of relevant tax and
securities laws.
On July 3, 2003, Moody's changed its credit rating on the Company's senior
unsecured debt to Baa3 with a negative outlook from Baa3 with a stable outlook.
The Company's senior unsecured debt is currently rated BBB by S&P, a rating that
it has held since March 2003 when it was downgraded from BBB+. S&P has
maintained a stable outlook for the Company. Although no further downgrades are
anticipated, such an event would not be expected to have a material impact on
the Company. The Company is not party to any lending agreements that would
accelerate the maturity date of any obligation due to a failure to maintain any
specific credit ratings.
The Company had standby letters of credit outstanding of $7,761,000 at June 30,
2003 and $30,541,000 at June 30, 2002, which guarantee payment of insurance
claims and other various commitments.
Quantitative and Qualitative Disclosures About Market Risk
The Company has long-term debt, Preferred Securities and revolving credit
facilities, which subject the Company to the risk of loss associated with
movements in market interest rates.
At June 30, 2003, the Company had issued fixed-rate long-term debt, capital
lease and Preferred Securities aggregating $2,104,975,000 in principal amount
(excluding premiums on Panhandle Energy's debt of $61,506,000) and having a fair
value of $2,253,994,000. These instruments are fixed-rate and, therefore, do not
expose the Company to the risk of earnings loss due to changes in market
interest rates. However, the fair value of these instruments would increase by
approximately $67,101,000 if interest and dividend rates were to decline by 10%
from their levels at June 30, 2003. In general, such an increase in fair value
would impact earnings and cash flows only if the Company were to reacquire all
or a portion of these instruments in the open market prior to their maturity.
The Company's floating-rate obligations aggregated $531,424,000 at June 30, 2003
and primarily consisted of the 2002 Term Note, the debt assumed under the
Panhandle Acquisition related to the Trunkline LNG facility, and amounts
borrowed under the Facilities of the Company. The floating-rate obligations
under the 2002 Term Note and the Facilities expose the Company to the risk of
increased interest expense in the event of increases in short-term interest
rates. If the floating rates were to increase by 10% from June 30, 2003 levels,
the Company's consolidated interest expense would increase by a total of
approximately $98,000 each month in which such increase continued.
The risk of an economic loss is reduced at this time as a result of the
Company's regulated status with respect to its Distribution segment operations.
Any unrealized gains or losses are accounted for in accordance with the FASB
Standard, Accounting for the Effects of Certain Types of Regulation, as a
regulatory asset/liability.
The change in exposure to loss in earnings and cash flow related to interest
rate risk from June 30, 2002 to June 30, 2003 is not material to the Company.
See Preferred Securities of Subsidiary Trust and Debt and Capital Lease in the
Notes to the Consolidated Financial Statements.
In connection with the acquisition of the Pennsylvania Operations, the Company
assumed a guaranty with a bank whereby the Company unconditionally guaranteed
payment of financing obtained for the development of PEI Power Park. In March
1999, the Borough of Archbald, the County of Lackawanna, and the Valley View
School District (together the Taxing Authorities) approved a Tax Incremental
Financing Plan (TIF Plan) for the development of PEI Power Park. The TIF Plan
requires that: (i) the Redevelopment Authority of Lackawanna County raise
$10,600,000 of funds to be used for infrastructure improvements of the PEI Power
Park; (ii) the Taxing Authorities create a tax increment district and use the
incremental tax revenues generated from new development to service the
$10,600,000 debt; and (iii) PEI Power Corporation, a subsidiary of the Company,
guarantee the debt service payments. In May 1999, the Redevelopment Authority of
Lackawanna County borrowed $10,600,000 from a bank under a promissory note (TIF
Debt), which was refinanced in March 2003. The TIF Debt bears interest at a
floating rate with a floor of 5.0% and a ceiling of 7.75% and matures on June
30, 2011. The loan requires interest-only payments until June 30, 2003, and
semi-annual interest and principal payments thereafter. As of June 30, 2003, the
interest rate on the TIF Debt is 5.0% and estimated incremental tax revenues are
expected to cover approximately 20% of the fiscal 2004 annual debt service. The
balance outstanding on the TIF Debt was $9,710,000 as of June 30, 2003.
In accordance with adoption of FASB, Accounting for Derivative Instruments and
Hedging Activities on July 1, 2000 the Company recorded a net-of-tax
cumulative-effect gain of $602,000 in earnings to recognize the fair value of
the gas derivative contracts at Energy Services that are not designated as
hedges. The Company also recorded $826,000 in accumulated other comprehensive
income which recognizes the fair value of two interest rate swap derivatives
that were designated as cash flow hedges.
As a result of the acquisition of Panhandle Energy, the Company is party to
interest rate swap agreements with an aggregate notional amount of $206,521,000
as of June 30, 2003 that fix the interest rate applicable to floating rate
long-term debt and which qualify for hedge accounting. As of June 30, 2003,
floating rate LIBOR-based interest payments are exchanged for weighted fixed
rate interest payments of 5.08%. Interest rate swaps are carried on the
Consolidated Balance Sheet at fair value with the unrealized gain or loss
adjusted through accumulated other comprehensive income. As such, payments or
receipts on interest rate swap agreements are recognized as adjustments to
interest expense. As of June 11, 2003 (the acquisition date) and June 30, 2003,
the fair value liability position of the swaps was $27,741,000 and $26,058,000,
respectively. As of June 30, 2003, an unrealized gain of $1,033,000, net of tax,
was included in accumulated other comprehensive income related to these swaps,
of which approximately $198,000, net of tax, is expected to be reclassified to
interest expense during the next twelve months as the hedged interest payments
occur.
The Company is also party to an interest rate swap agreement with a notional
amount of $8,199,000 and $22,015,000 as of June 30, 2003 and 2002, respectively,
that fixes the interest rate applicable to floating rate long-term debt and
which qualifies for hedge accounting. As of June 30, 2003, floating rate
LIBOR-based interest payments are exchanged for fixed rate interest payments of
5.79%. The fair value liability position of the swap was $93,000 and $519,000 as
of June 30, 2003 and 2002, respectively. As of June 30, 2003, $57,000 of
unrealized after-tax losses included in accumulated other comprehensive income
related to this swap will be reclassified to interest expense during the next
twelve months as the hedged interest payments occur.
In March and April 2003, the Company entered into a series of treasury rate
locks with an aggregate notional amount of $250,000,000 to manage its exposure
against changes in future interest payments attributable to changes in the
benchmark interest rate prior to the anticipated issuance of fixed-rate debt.
These treasury rate locks expired on June 30, 2003, resulting in a $6,862,000
after-tax loss that was recorded in accumulated other comprehensive income and
will be amortized into interest expense over the lives of the associated debt
instruments. As of June 30, 2003, approximately $846,000 of net after-tax losses
in accumulated other comprehensive income will be amortized into interest
expense during the next twelve months.
The notional amounts of the interest rate swaps are not exchanged and do not
represent exposure to credit loss. In the event of default by a counterparty,
the risk in these transactions is the cost of replacing the agreements at
current market rates.
In March 2001, the Company discovered unauthorized financial derivative energy
trading activity by a non-regulated, wholly-owned subsidiary. All unauthorized
trading activity was subsequently closed in March and April of 2001 resulting in
a cumulative cash expense of $191,000, net of taxes, and deferred income of
$7,921,000 at June 30, 2001. For the fiscal year ended June 30, 2003, the
Company recorded $605,000 through other income relating to the expiration of
contracts resulting from this trading activity, as compared to $6,204,000
recorded for the fiscal year ended June 30, 2002. The majority of the remaining
deferred liability of $1,112,000 at June 30, 2003 related to these derivative
instruments will be recognized as income in the Consolidated Statement of
Operations over the next two years based on the related contracts. The Company
established new limitations on trading activities, as well as new compliance
controls and procedures that are intended to make it easier to identify quickly
any unauthorized trading activities.
Other Matters
Stock Splits and Dividends. On July 31, 2003, July 15, 2002 and August 30, 2001,
Southern Union distributed a 5% common stock dividend to stockholders of record
on July 17, 2003, July 1, 2002 and August 16, 2001, respectively. A portion of
the July 15, 2002 and August 30, 2001 5% stock dividends was characterized as a
distribution of capital due to the level of the Company's retained earnings
available for distribution as of the declaration date. Unless otherwise stated,
all per share data included herein and in the accompanying Consolidated
Financial Statements and Notes thereto have been restated to give effect to the
stock dividends.
Customer Concentrations. In the Transportation and Storage segment, aggregate
sales to Panhandle Energy's top 10 customers accounted for 71% of segment
operating revenues and 1% of consolidated operating revenues for the period
owned by Southern Union in fiscal 2003. This included sales to BG LNG Services,
a nonaffiliated gas marketer, which accounted for 20% of segment operating
revenues; sales to Proliance Energy, LLC, a nonaffiliated local distribution
company and gas marketer, which accounted for 17% of segment operating revenues;
and sales to CMS Energy Corporation, Panhandle Energy's former parent, which
accounted for 13% of segment operating revenues. During 2003, no other customer
accounted for 10% or more of segment or consolidated operating revenues during
the period owned by Southern Union.
Off-Balance Sheet Arrangements and Aggregate Contractual Obligations. As of June
30, 2003, the Company had guarantees related to PEI Power of $9,710,000, letters
of credit related to insurance claims and other commitments of $7,761,000 and
surety bonds related to construction or repair projects of $2,000,000. The
Company believes that the likelihood of having to make payments under the
letters of credit or the surety bonds is remote, and therefore has made no
provisions for making payments under such instruments.
The following table summarizes the Company's expected contractual obligations by
payment due date as of June 30, 2003:
Contractual Obligations (thousands of dollars)
2009 and
Total 2004 2005 2006 2007 2008 thereafter
----------- ---------- -------- --------- --------- -------- -----------
Long-term debt,
including capital leases (1) (2)......... $ 2,284,899 $ 734,752 $125,077 $ 116,092 $ 365,718 $ 1,648 $ 941,612
Short-term borrowing,
including credit facilities (1).......... 251,500 251,500 -- -- -- -- --
Trust preferred securities.................. 100,000 -- -- -- -- -- 100,000
Gas purchases (3) .......................... 1,669,538 557,642 237,645 202,776 159,710 173,773 337,992
Missouri Gas Energy Safety Program.......... 144,500 8,500 8,500 8,500 8,500 8,500 102,000
Storage contracts (4)....................... 101,316 9,977 9,221 9,221 9,221 9,221 54,455
Trunkline LNG facilities expansion.......... 123,021 64,667 49,100 9,254 -- -- --
Operating lease payments.................... 67,520 18,614 16,001 14,345 7,193 6,329 5,038
Non-trading derivative liabilities.......... 26,151 8,513 8,138 6,981 2,519 -- --
----------- ---------- -------- --------- --------- -------- ----------
Total contractual cash obligations....... $ 4,768,445 $1,654,165 $453,682 $ 367,169 $ 552,861 $ 199,471 $1,541,097
=========== ========== ======== ========= ========= ========= ==========
- ---------------------------------
(1) The Company is party to certain debt agreements that contain certain
covenants that if not satisfied would be an event of default that would
cause such debt to become immediately due and payable. Such covenants
require the Company to maintain a certain level of net worth, to meet
certain debt to total capitalization ratios, and to meet certain ratios of
earnings before depreciation, interest and taxes to cash interest expense.
See Note XIII - Debt and Capital Leases.
(2) The long-term debt cash obligations exclude $61,506,000 of unamortized
debt premium as of June 30, 2003.
(3) The Company has purchase gas tariffs in effect for all its utility service
areas that provide for recovery of its purchase gas costs under defined
methodologies.
(4) Charges for third party storage capacity.
Cash Management. In June 2003, FERC issued an Interim Rule, effective in August
2003. Order No. 634 requires all FERC-regulated entities that participate in
cash management programs with corporate affiliates to (i) establish written cash
management procedures including specification of duties and responsibilities of
cash management program participants and administrators, specification of the
methods for calculating interest and allocation of interest income and expenses,
and specification of any restrictions on deposits or borrowings by participants,
and (ii) to document cash management activity in detail. FERC also has made new
proposals that would require FERC-regulated entities to file their written cash
management procedures with FERC for public review. Order No. 634 also requested
industry comments on whether a FERC-regulated entity should be required to
notify FERC within five days when its proprietary capital ratio falls below 30%
or subsequently returns to or exceeds 30%.
New FERC Reporting Requirements. On June 29, 2003, the FERC proposed substantial
new quarterly reporting requirements for each FERC-regulated entity. The Notice
of Proposed Rulemaking (NOPR) is proposed to be effective for reporting third
quarter 2004 results. Panhandle Energy is currently studying the implications of
the NOPR to Panhandle Eastern Pipe Line, Trunkline Gas, Trunkline LNG, Sea Robin
and Southwest Gas Storage.
Contingencies. The Company is investigating the possibility that the Company or
predecessor companies may have been associated with Manufactured Gas Plant (MGP)
sites in its former gas distribution service territories, principally in Texas,
Arizona and New Mexico, and present gas distribution service territories in
Missouri, Pennsylvania, Massachusetts and Rhode Island. At the present time, the
Company is aware of certain MGP sites in these areas and is investigating those
and certain other locations. While the Company's evaluation of these Texas,
Missouri, Arizona, New Mexico, Pennsylvania, Massachusetts and Rhode Island MGP
sites is in its preliminary stages, it is likely that some compliance costs may
be identified and become subject to reasonable quantification. Within the
Company's distribution service territories certain MGP sites are currently the
subject of governmental actions. See Management's Discussion and Analysis of
Results of Operations and Financial Condition (MD&A) -- Cautionary Statement
Regarding Forward-Looking Information and Note XVIII - Commitments and
Contingencies in the Notes to the Consolidated Financial Statements.
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 contamination at certain sites on its gas transmission systems and
has undertaken cleanup programs at these sites. The contamination resulted from
the past use of lubricants containing polychlorinated bi-phenyls (PCBs) in
compressed air systems; the past use of paints containing PCBs; and the prior
use of wastewater collection facilities and other on-site disposal areas. The
Company 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 Company affiliates in accordance with
indemnity agreements that also indemnify against certain future environmental
litigation and claims. The Company is also subject to various federal, state and
local laws and regulations relating to air quality control. These regulations
include rules relating to regional ozone control and hazardous air pollutants.
The regional ozone control rules are known as State Implementation Plans (SIP)
and are designed to control the release of NOx compounds. The rules related to
hazardous air pollutants are known as Maximum Achievable Control Technology
(MACT) rules and are the result of the 1990 Clean Air Act Amendments that
regulate the emission of hazardous air pollutants from internal combustion
engines and turbines. See Management's Discussion and Analysis of Results of
Operations and Financial Condition (MD&A) -- Cautionary Statement Regarding
Forward-Looking Information and Note XVIII - Commitments and Contingencies in
the Notes to the Consolidated Financial Statements.
Several actions were commenced by persons involved in competing efforts to
acquire Southwest Gas Corporation (Southwest) during 1999. All of these actions
eventually were transferred to the District of Arizona (the Court), consolidated
and lodged with Judge Roslyn Silver. As a result of summary judgments granted,
no claims remain against Southern Union. Southern Union's claims against
Southwest were settled on August 6, 2002, by Southwest's payment to Southern
Union of $17,500,000. Southern Union's claims against ONEOK, Inc. (ONEOK) and
the individual defendants associated with ONEOK were settled on January 3, 2003,
following the closing of Southern Union's sale of the Texas assets to ONEOK, by
ONEOK's payment to Southern Union of $5,000,000. Southern Union's claims against
Jack Rose, former aide to Arizona Corporation Commissioner James Irvin, were
settled by Mr. Rose's payment to Southern Union of $75,000, which the Company
donated to charity. The trial of Southern Union's claims against the
sole-remaining defendant, Arizona Corporation Commissioner James Irvin, was
concluded on December 18, 2002, with a jury award to Southern Union of nearly
$400,000 in actual damages and $60,000,000 in punitive damages against
Commissioner Irvin. The Court denied numerous post-trial motions by Commissioner
Irvin, who has filed a notice of appeal. The Company intends to vigorously
pursue collection of the award. With the exception of ongoing legal fees
associated with the collection of damages from Commissioner Irvin, the Company
believes that the results of the above-noted Southwest litigation and any
related appeals will not have a materially adverse effect on the Company's
financial condition, results of operations or cash flows.
On May 31, 2002, the staff of the MPSC recommended that the Commission disallow
approximately $15 million in gas costs incurred during the period July 1, 2000
through June 30, 2001. Missouri Gas Energy filed its response in opposition to
the Staff's recommendation on July 11, 2002, vigorously disputing the Commission
staff's assertions. Missouri Gas Energy intends to vigorously defend itself in
this proceeding. This matter went to hearing in May of 2003, is presently in
recess, and the hearing is set to resume in November 2003.
On November 27, 2001, August 1, 2000 and August 12, 1999, the staff of the MPSC
recommended that the Commission disallow approximately $5.9 million, $5.9
million and $4.3 million, respectively, in gas costs incurred during the period
July 1, 1999 through June 30, 2000, July 1, 1998 through June 30, 1999, and July
1, 1997 through June 30, 1998, respectively. The basis of these proposed
disallowances appears to be the same as was rejected by the Commission through
an order dated March 12, 2002, applicable to the period July 1, 1996 through
June 30, 1997. MGE intends to vigorously defend itself in these proceedings. On
November 4, 2002, the Commission adopted a procedural schedule calling for a
hearing in this matter some time after May 2003. No date for this hearing has
been set.
In conjunction with a FERC Order issued in September 1997, certain natural gas
producers were required to refund previously collected Kansas ad valorem taxes
to interstate natural gas pipelines. These pipelines were ordered to refund
these amounts to their customers. All payments were to be made in compliance
with prescribed FERC requirements. In June 2001, Panhandle Energy filed a
proposed settlement of these proceedings which all the customers and most of the
producers supported. The settlement provides for the producers to refund and the
customers to accept a reduction from the amounts originally billed to the
producers. In September 2001, the FERC approved the settlement without
modification and the settlement became effective on October 15, 2001. On January
2, 2003, FERC established hearing procedures for resolving refunds owed by the
non-settling producers. The hearing is scheduled to commence on October 16,
2003. The amounts have not yet been finally settled with a number of
non-settling producers. Settlement efforts are continuing.
In 1993, the U.S. Department of the Interior announced its intention to seek,
through its Minerals Management Service (MMS), additional royalties from gas
producers as a result of payments received by such producers in connection with
past take-or-pay settlements and buyouts or buy downs of gas sales contracts
with natural gas pipelines. Panhandle Energy's pipelines, with respect to
certain producer contract settlements, may be contractually required to
reimburse or, in some instances, to indemnify producers against such royalty
claims. The potential liability of the producers to the government and of the
pipelines to the producers involves complex issues of law and fact which are
likely to take substantial time to resolve. If required to reimburse or
indemnify the producers, Panhandle Energy's pipelines may file with the FERC to
recover a portion of these costs from pipeline customers. Panhandle Energy does
not believe the outcome of this matter will have a material adverse effect on
its financial position, results of operations or cash flows.
Southern Union and its subsidiaries are parties to other legal proceedings that
management considers to be normal actions to which an enterprise of its size and
nature might be subject, and not to be material to the Company's overall
business or financial condition, results of operations or cash flows. See Note
XVIII - Commitments and Contingencies in the Notes to Consolidated Financial
Statements.
Inflation. The Company believes that inflation has caused and will continue to
cause increases in certain operating expenses and has required and will continue
to require assets to be replaced at higher costs. The Company continually
reviews the adequacy of its rates in relation to the increasing cost of
providing service and the inherent regulatory lag in adjusting those rates.
Regulatory. The majority of the Company's business activities are subject to
various regulatory authorities. The Company's financial condition and results of
operations have been and will continue to be dependent upon the receipt of
adequate and timely adjustments in rates.
On May 22, 2003, the Rhode Island Public Utilities Commission (RIPUC) approved a
Settlement Offer filed by New England Gas Company related to the final
calculation of earnings sharing for the 21-month period covered by the Energize
Rhode Island Extension settlement agreement. This calculation generated excess
revenues of $5,227,000. The net result of the excess revenues and the Energize
Rhode Island weather mitigation and non-firm margin sharing provisions is the
crediting to customers of $949,000 over a twelve-month period starting July 1,
2003.
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 effective July 1, 2002 for New England Gas Company's Rhode Island
operations, a unified rate structure ("One State; One Rate") and an
integration/merger savings mechanism. The settlement agreement also allows New
England Gas Company to retain $2,049,000 of merger savings and to share
incremental earnings with customers when the division's Rhode Island operations
return on equity exceeds 11.25%. Included in the settlement agreement was a
conversion to therm billing and the approval of a reconciling Distribution
Adjustment Clause (DAC). The DAC allows New England Gas Company to continue its
low income assistance and weatherization programs, to recover environmental
response costs over a 10-year period, puts into place a new weather
normalization clause and allows for the sharing of nonfirm margins (non-firm
margin is margin earned from interruptible customers with the ability to switch
to alternative fuels). The weather normalization clause is designed to mitigate
the impact of weather volatility on customer billings, which will assist
customers in paying bills and stabilize the revenue stream. New England Gas
Company will defer the margin impact of weather that is greater than 2%
colder-than-normal and will recover the margin impact of weather that is greater
than 2% warmer-than-normal. The non-firm margin incentive mechanism allows New
England Gas Company to retain 25% of all non-firm margins earned in excess of
$1,600,000.
In December 2001, Trunkline LNG filed with the FERC a certificate application to
expand the Lake Charles LNG facility to approximately 1.2 billion cubic feet per
day of sendout capacity versus the current capacity of 630 million cubic feet
per day. BG LNG Services has contract rights for the 570 million cubic feet per
day of additional capacity. In December 2002, the FERC issued an order approving
the expansion and in March 2003, Trunkline LNG received FERC authorization
to commence construction. On April 17, 2003, Trunkline LNG filed to amend
certain items in the previously mentioned FERC approvals which will not affect
the authorized additional storage capacity and daily sendout capability and
confirms the revised in-service date of January 1, 2006.
On July 5, 2001, the MPSC issued an order approving a unanimous settlement of
Missouri Gas Energy's rate request. The settlement provides for an annual
$9,892,000 base rate increase, as well as $1,081,000 in added revenue from new
and revised service charges. The majority of the rate increase is recovered
through increased monthly fixed charges to gas sales service customers. New
rates became effective August 6, 2001, two months before the statutory deadline
for resolving the case. The approved settlement resulted in the dismissal of all
pending judicial reviews of prior rate cases. The settlement also provided for
the development of a two-year experimental low-income program that will help
certain customers in the Joplin area pay their natural gas bills.
In December 2000, the PPUC approved a settlement agreement that provided for a
rate increase designed to produce $10,800,000 of additional annual revenue. The
new rates became effective on January 1, 2001.
The Company continues to pursue certain changes to rates and rate structures
that are intended to reduce the sensitivity of earnings to weather, including
weather normalization clauses and higher monthly fixed customer charges for its
regulated utility operations. New England Gas Company has a weather
normalization clause in the tariff covering its Rhode Island operations.
Critical Accounting Policies. The Company's consolidated financial statements
have been prepared in accordance with generally accepted accounting principles.
The preparation of these financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and related disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Estimates and assumptions about future
events and their effects cannot be perceived with certainty. On an on-going
basis, the Company evaluates its estimates based on historical experience,
current market conditions and on various other assumptions that are believed to
be reasonable under the circumstances, the results of which form the basis for
making judgments about the carrying value of assets and liabilities that are not
readily apparent from other sources. Nevertheless, actual results may differ
from these estimates under different assumptions or conditions. The following is
a summary of the Company's most critical accounting policies, which are defined
as those policies whereby judgments or uncertainties could affect the
application of those policies and materially different amounts could be reported
under different conditions or using different assumptions. For a summary of all
of the Company's significant accounting policies, see Note I - Summary of
Significant Accounting Policies in Notes to Consolidated Financial Statements.
Effects of Regulation -- The Company is subject to regulation by certain state
and federal authorities. The Company, in its Distribution segment, has
accounting policies which conform to the FASB Standard, Accounting for the
Effects of Certain Types of Regulation, and which are in accordance with the
accounting requirements and ratemaking practices of the regulatory authorities.
The application of these accounting policies allows the Company to defer
expenses and revenues on the balance sheet as regulatory assets and liabilities
when it is probable that those expenses and income will be allowed in the
ratemaking process in a period different from the period in which they would
have been reflected in the income statement by an unregulated company. These
deferred assets and liabilities are then flowed through the results of
operations in the period in which the same amounts are included in rates and
recovered from or refunded to customers. Management's assessment of the
probability of recovery or pass through of regulatory assets and liabilities
requires judgment and interpretation of laws and regulatory commission orders.
If, for any reason, the Company ceases to meet the criteria for application of
regulatory accounting treatment for all or part of its operations, the
regulatory assets and liabilities related to those portions ceasing to meet such
criteria would be eliminated from the Consolidated Balance Sheet and included in
the Consolidated Statement of Operations for the period in which the
discontinuance of regulatory accounting treatment occurs. The aggregate amount
of regulatory assets and liabilities reflected in the Consolidated Balance
Sheets are $84.0 million and $10.1 million at June 30, 2003, and $91.1 million
and $6.4 million at June 30, 2002, respectively.
Long-Lived Assets -- Long-lived assets, including property, plant and equipment,
goodwill, intangibles and equity investments, comprise a significant amount of
the Company's total assets. The Company makes judgments and estimates about the
carrying value of these assets, including amounts to be capitalized,
depreciation methods and useful lives. The Company also reviews these assets for
impairment on a periodic basis or whenever events or changes in circumstances
indicate that the carrying amounts may not be recoverable. The impairment test
consists of a comparison of an asset's fair value with its carrying value; if
the carrying value of the asset exceeds its fair value, an impairment loss is
recognized in the Consolidated Statement of Operations in an amount equal to
that excess. Management's determination of an asset's fair value requires it to
make long-term forecasts of future revenues and costs related to the asset, when
the asset's fair value is not readily apparent from other sources. These
forecasts require assumptions about future demand, future market conditions and
regulatory developments. Significant and unanticipated changes to these
assumptions could require a provision for impairment in a future period.
During June 2003, the Company evaluated goodwill for impairment. The
determination of whether an impairment has occurred is based on an estimate of
discounted future cash flows attributable to the Company's reporting units that
have goodwill, as compared to the carrying value of those reporting units' net
assets. As of June 30, 2003, pursuant to the FASB Standard, Goodwill and Other
Intangible Assets, no impairment had been indicated.
In connection with the Company's Cash Flow Improvement Plan announced in July
2001, the Company began the divestiture of certain non-core assets. As a result
of prices of comparable businesses for various non-core properties and pursuant
to the FASB Standard, Impairment of Long-Lived Assets and Assets to be Disposed
Of, a goodwill impairment loss of $1,417,000 was recognized in depreciation and
amortization on the Consolidated Statement of Operations for the quarter ended
September 30, 2001.
Investments in Securities -- The Company holds securities of Capstone Turbine
Corporation (Capstone), which are classified as "available for sale" under the
FASB Standard Accounting for Certain Investments in Debt and Equity Securities.
Accordingly, these securities are stated at fair value, based on quoted market
price, with unrealized gains and losses recorded in a separate component of
common stockholders' equity. The remaining shares of Capstone held at June 30,
2003 were sold subsequent to year-end. All other securities owned by the Company
are accounted for under the cost method. These securities consist of common and
preferred stock in non-public companies whose value is not readily determinable.
A judgmental aspect of accounting for these securities involves determining
whether an other-than-temporary decline in value has been sustained. Management
reviews these securities on a quarterly basis to determine whether a decline in
value is other-than-temporary. Factors that are considered in assessing whether
a decline in value is other-than-temporary include, but are not limited to:
earnings trends and asset quality; near term prospects and financial condition
of the issuer; financial condition and prospects of the issuer's region and
industry; and Southern Union's intent and ability to retain the investment. If
management determines that a decline in value is other-than-temporary, a charge
will be recorded on the Consolidated Statement of Operations to reduce the
carrying value of the investment security to its estimated fair value.
In June 2002, Southern Union determined that the decline in value of its
investment in PointServe was other than temporary. Accordingly, the Company
recorded a non-cash charge of $10,380,000, to reduce the carrying value of this
investment to its estimated fair value. The Company recognized this valuation
adjustment to reflect significant lower private equity valuation metrics and
changes in the business outlook of PointServe. PointServe is a closely held,
privately owned company and, as such, has no published market value. The
Company's remaining investment of $4,206,000 at June 30, 2003 may be subject to
future market value risk. The Company will continue to monitor the value of its
investment and periodically assess the impact, if any, on reported earnings in
future periods.
Pensions and Other Postretirement Benefits - The Company accounts for pension
costs and other postretirement benefit costs in accordance with the FASB
Standards Employers' Accounting for Pensions and Employers' Accounting for
Postretirement Benefits Other Than Pensions, respectively. These Statements
require liabilities to be recorded on the balance sheet at the present value of
these future obligations to employees net of any plan assets. The calculation of
these liabilities and associated expenses require the expertise of actuaries and
are subject to many assumptions including life expectancies, present value
discount rates, expected long-term rate of return on plan assets, rate of
compensation increase and anticipated health care costs. Any change in these
assumptions can significantly change the liability and associated expenses
recognized in any given year. However, the Company expects to recover
substantially all of its net periodic pension and other post-retirement benefit
costs attributable to employees in its Distribution segment in accordance with
the applicable regulatory commission authorization. For financial reporting
purposes, the difference between the amounts of pension cost and post-retirement
benefit cost recoverable in rates and the amounts of such costs as determined
under applicable accounting principles is recorded as either a regulatory asset
or liability, as appropriate.
Derivatives and Hedging Activities -- The Company utilizes derivative
instruments on a limited basis to manage certain business risks. Interest rate
swaps and treasury rate locks are used to reduce interest rate risks and to
manage interest expense. Commodity swaps have been utilized to manage price risk
associated with certain energy contracts. The Company accounts for its
derivatives in accordance with the FASB Standard, Accounting for Derivative
Instruments and Hedging Activities, as amended. Under this Statement, all
derivatives are recognized on the balance sheet at their fair value. On the date
the derivative contract is entered into, management designates the derivative as
either: (i) a hedge of the fair value of a recognized asset or liability or of
an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a
forecasted transaction or of the variability of cash flows to be received or
paid in connection with a recognized asset or liability (a cash flow hedge), or
(iii) an instrument that is held for trading or non-hedging purposes (a trading
or non-hedging instrument). Changes in the fair value of a derivative that
qualifies as a fair-value hedge, along with the gain or loss on the hedged asset
or liability that is attributable to the hedged risk, are recorded in earnings.
Changes in the fair value of a derivative that qualifies as a cash-flow hedge,
to the extent that the hedge is effective, are recorded in other comprehensive
income, until earnings are affected by the variability of cash flows of the
hedged transaction (e.g., until periodic settlements of a variable-rate asset or
liability are recorded in earnings). Hedge ineffectiveness is recorded through
earnings immediately. Lastly, changes in the fair value of derivative trading
and non-hedging instruments are reported in current-period earnings. Fair value
is determined based upon mathematical models using current and historical data.
The Company formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions have been
highly effective in offsetting changes in the fair value or cash flows of hedged
items and whether those derivatives may be expected to remain highly effective
in future periods. The Company discontinues hedge accounting when: (i) it
determines that the derivative is no longer effective in offsetting changes in
the fair value or cash flows of a hedged item; (ii) the derivative expires or is
sold, terminated, or exercised; (iii) it is no longer probable that the
forecasted transaction will occur; or (iv) management determines that
designating the derivative as a hedging instrument is no longer appropriate. In
all situations in which hedge accounting is discontinued and the derivative
remains outstanding, the Company will carry the derivative at its fair value on
the balance sheet, recognizing changes in the fair value in current-period
earnings. See Note XI -- Derivative Instruments and Hedging Activities in Notes
to Consolidated Financial Statements.
Commitments and Contingencies -- The Company is subject to proceedings, lawsuits
and other claims related to environmental and other matters. Accounting for
contingencies requires significant judgments by management regarding the
estimated probabilities and ranges of exposure to potential liability. For
further discussion of the Company's commitments and contingencies, see Note
XVIII -- Commitments and Contingencies in Notes to Consolidated Financial
Statements.
Purchase Accounting -- The Company's acquisition of Panhandle Energy has been
accounted for using the purchase method of accounting in accordance with the
FASB Standard, Business Combinations. Under this Statement, the purchase price
paid by the Company, including transaction costs, was allocated to Panhandle
Energy's net assets as of the acquisition date based on preliminary estimates of
the fair value of the assets acquired and liabilities assumed. Accordingly, the
Panhandle Energy assets acquired and liabilities assumed have been recorded in
the Consolidated Balance Sheet as of June 30, 2003 at their estimated fair value
and are subject to further assessment and adjustment pending the results of
outside appraisals. Determining the fair value of certain assets acquired and
liabilities assumed is judgmental in nature and often involves the use of
significant estimates and assumptions. The accounting rules provide a one-year
period following the consummation of an acquisition to finalize the fair value
estimates.
Accounting Pronouncements
Effective July 1, 2002, the Company adopted the FASB standard, Accounting for
Asset Retirement Obligations (ARO). The Statement requires legal obligations
associated with the retirement of long-lived assets to be recognized at their
fair value at the time the obligations are incurred. Upon initial recognition of
a liability, costs should be capitalized as part of the related long-lived asset
and allocated to expense over the useful life of the asset. Over time, the
liability is accreted to its present value each period, and the capitalized cost
is depreciated over the useful life of the related long-lived asset. In certain
rate jurisdictions, the Company is permitted to include annual charges for cost
of removal in its regulated cost of service rates charged to customers. The
adoption of the Statement did not have a material impact on the Company's
financial position, results of operations or cash flows for all periods
presented.
As a result of the acquisition of Panhandle Energy, the Company assumed an ARO
liability of approximately $6.8 million as of June 30, 2003, relating to the
retirement of certain of Panhandle Energy's offshore lateral lines. During
fiscal 2003, changes in the carrying amount of the ARO liability attributable to
(i) liabilities incurred, (ii) liabilities settled, (iii) accretion expense, and
(iv) cash flow revisions were immaterial for the period the associated assets
were owned by the Company. In addition, the Company has reclassified
approximately $27 million of negative salvage previously included in accumulated
depreciation to deferred credits for amounts collected for asset retirement
obligations on certain of the Panhandle Energy assets acquired which are not
recordable as liabilities under the Statement but represent other obligations.
Also effective July 1, 2002, the Company adopted the FASB standard, Accounting
for the Impairment or Disposal of Long-Lived Assets. The Statement provides new
guidance on the recognition of impairment losses on long-lived assets to be held
and used or to be disposed of and also broadens the definition of what
constitutes a discontinued operation and how the results of a discontinued
operation are to be measured and presented. Under the Statement, assets held for
sale that are a component of an entity will be included in discontinued
operations if the operations and cash flows will be or have been eliminated from
the ongoing operations of the entity and the entity will not have any
significant continuing involvement in the operations prospectively. The adoption
of this Statement did not materially change the methods the Company uses to
measure impairment losses on long-lived assets, but did result in the Company's
sale of its Texas Operations being reported as discontinued operations. See Note
XIX - Discontinued Operations and Assets Held for Sale in Notes to Consolidated
Financial Statements.
In November 2002, the FASB issued Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Guarantees of Indebtedness of Others. The
Interpretation expands the existing disclosure requirements for guarantees and
requires that companies recognize, at the inception of a guarantee, a liability
for the fair value of the obligations undertaken when issuing the guarantee. The
initial recognition and initial measurement provisions of the Interpretation are
effective for guarantees issued or modified after December 31, 2002.
Implementation of this Statement did not have a material impact on the
Company's financial position, results of operations or cash flows for all
periods presented.
In December 2002, the FASB issued Accounting for Stock-Based Compensation -
Transition and Disclosure. The Statement provides alternative methods of
transition for an entity that voluntarily changes to a fair value based method
of accounting for stock-based employee compensation. In addition, the Statement
amends the previous standard, Accounting for Stock-Based Compensation, to
require more prominent disclosure about the effects on reported net income of
stock-based employee compensation. The Company expects to continue to account
for stock-based compensation in accordance with Accounting Principles Board
opinion, Accounting for Stock Issued to Employees, and will provide the
prominent disclosures required in its annual and future interim financial
statements.
In April 2003, the FASB issued Amendment of Statement 133 on Derivative
Instruments and Hedging Activities. The Statement is effective for contracts
entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. The Statement (i) clarifies under what
circumstances a contract with an initial net investment meets the characteristic
of a derivative, (ii) clarifies when a derivative contains a financing
component, (iii) amends the definition of an underlying to conform it to
language used in FASB Interpretation Guarantor's Accounting and Disclosure
Requirement for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, and (iv) amends certain other existing pronouncements. The Statement is
not expected to materially change the methods the Company uses to account for
and report its derivatives and hedging activities.
In May 2003, the FASB issued Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity. The Statement is effective at
the beginning of the first interim period beginning after June 15, 2003. The
Statement establishes guidelines on how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. The Statement further defines and requires that certain instruments
within its scope be classified as liabilities on the financial statements. The
Company does not expect adoption of this statement to have a material impact
on its financial position, results of operations or cash flows.
See the Notes to Consolidated Financial Statements for other accounting
pronouncements followed by the Company.
Cautionary Statement Regarding Forward-Looking Information. This Management's
Discussion and Analysis of Results of Operations and Financial Condition and
other sections of this Annual Report on Form 10-K contain forward-looking
statements that are based on current expectations, estimates and projections
about the industry in which the Company operates, management's beliefs and
assumptions made by management. Words such as "expects," "anticipates,"
"intends," "plans," "believes," "seeks," "estimates," variations of such words
and similar expressions are intended to identify such forward-looking
statements. Similarly, statements that describe our objectives, plans or goals
are or may be forward-looking statements. These statements are not guarantees of
future performance and involve certain risks, uncertainties and assumptions,
which are difficult to predict and many of which are outside the Company's
control. Therefore, actual results, performance and achievements may differ
materially from what is expressed or forecasted in such forward-looking
statements. The Company undertakes no obligation to publicly update any
forward-looking statements, whether as a result of new information, future
events or otherwise. Readers are cautioned not to put undue reliance on such
forward-looking statements. Stockholders may review the Company's reports filed
in the future with the Securities and Exchange Commission for more current
descriptions of developments that could cause actual results to differ
materially from such forward-looking statements.
Factors that could cause actual results to differ materially from those
expressed in our forward-looking statements include, but are not limited to, the
following: cost of gas; gas sales volumes; gas throughput volumes and available
sources of natural gas; discounting of transportation rates due to competition,
which could adversely affect our results of operation; customer growth; abnormal
weather conditions in our service territories; the impact of relations with
labor unions of bargaining-unit union employees; the receipt of timely and
adequate rate relief and the impact of future rate cases or regulatory rulings;
the outcome of pending and future litigation; the speed and degree to which
competition is introduced to our gas distribution business; new legislation and
government regulations affecting or involving the Company; unanticipated
environmental liabilities; the Company's ability to comply with or to challenge
successfully existing or new environmental regulations; changes in business
strategy and the success of new business ventures; the nature and impact of any
extraordinary transactions, such as any acquisition or divestiture of a business
unit or any assets; the economic climate and growth in our industry and service
territories and competitive conditions of energy markets in general;
inflationary trends; changes in gas or other energy market commodity prices and
interest rates; the current market conditions causing more customer contracts to
be of shorter duration, which may increase revenue volatility; exposure to
customer concentration with a significant portion of revenues realized from a
relatively small number of customers and any credit risks associated with the
financial position of those customers; our or any of our subsidiaries' debt
securities ratings; factors affecting operations such as maintenance or repairs,
environmental incidents or gas pipeline system constraints; the possibility of
war or terrorist attacks; and other risks and unforeseen events. In light of
these risks, uncertainties and assumptions, the results reflected in our
forward-looking statements might not occur. In addition, we could be affected by
general industry and market conditions, and general economic conditions,
including interest rate fluctuations, federal, state and local laws and
regulations affecting the retail gas industry or the energy industry generally.
ITEM 8. Financial Statements and Supplementary Data.
The information required here is included in the report as set forth in the
Index to Consolidated Financial Statements on page F-1.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
ITEM 9A. Controls and Procedures.
We performed an evaluation under the supervision and with the participation of
our management, including our Chief Executive Officer ("CEO") and Chief
Financial Officer ("CFO"), and with the participation of personnel from our
Legal, Internal Audit, Risk Management and Financial Reporting Departments, of
the effectiveness of the design and operation of the Company's disclosure
controls and procedures (as defined in Rule 13a-15(e) under the Securities
Exchange Act of 1934) as of the end of the period covered by this report. Based
on that evaluation, our CEO and CFO concluded that our disclosure controls and
procedures were effective as of June 30, 2003 and have communicated that
determination to the Audit Committee of our Board of Directors. There have been
no significant changes in our internal controls or other factors that have
materially affected or are reasonably likely to materially affect internal
controls subsequent to June 30, 2003.
PART III
ITEM 10. Directors and Executive Officers of the Registrant.
There is incorporated in this Item 10 by reference the information that will
appear in the Company's definitive proxy statement for the 2003 Annual Meeting
of Stockholders under the captions Board of Directors -- Board Size and
Composition and Executive Officers and Compensation -- Executive Officers Who
Are Not Directors and Executive Officers and Compensation -- Section 16(a)
Beneficial Owner Reporting Compliance.
ITEM 11. Executive Compensation.
There is incorporated in this Item 11 by reference the information that will
appear in the Company's definitive proxy statement for the 2003 Annual Meeting
of Stockholders under the captions Executive Officers and Compensation --
Executive Compensation and Certain Relationships.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.
There is incorporated in this Item 12 by reference the information that will
appear in the Company's definitive proxy statement for the 2003 Annual Meeting
of Stockholders under the caption Security Ownership.
ITEM 13. Certain Relationships and Related Transactions.
There is incorporated in this Item 13 by reference the information that will
appear in the Company's definitive proxy statement for the 2003 Annual Meeting
of Stockholders under the caption Certain Relationships.
ITEM 14. Principal Accountants Fees and Services.
There is incorporated in this Item 14 by reference the information that will
appear in the Company's definitive proxy statement for the 2003 Annual Meeting
of Stockholders under the caption Independent Auditors.
PART IV
ITEM 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a)(1) and (2) Financial Statements and Financial Statement Schedules.
-------------------------------------------------------
See Index to Consolidated Financial Statements set forth on
page F-1.
(a)(3) Exhibits.
Exhibit No. Description
- ----------- -----------------------------------------------------------------
3(a) Restated Certificate of Incorporation of Southern Union Company.
(Filed as Exhibit 3(a) to Southern Union's Transition Report on
Form 10-K for the year ended June 30, 1994 and incorporated herein
by reference.)
3(b) Amendment to Restated Certificate of Incorporation of Southern
Union Company which was filed with the Secretary of State of
Delaware and became effective on October 26, 1999. (Filed as
Exhibit 3(a) to Southern Union's Quarterly Report on Form 10-Q for
the quarter ended December 31, 1999 and incorporated herein by
reference.)
3(c) Southern Union Company Bylaws, as amended. (Filed as Exhibit 3(a)
to Southern Union's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1999 and incorporated herein by reference.)
4(a) Specimen Common Stock Certificate. (Filed as Exhibit 4(a) to
Southern Union's Annual Report on Form 10-K for the year ended
December 31, 1989 and incorporated herein by reference.)
4(b) Indenture between Chase Manhattan Bank, N.A., as trustee, and
Southern Union Company dated January 31, 1994. (Filed as Exhibit
4.1 to Southern Union's Current Report on Form 8-K dated February
15, 1994 and incorporated herein by reference.)
4(c) Officers' Certificate dated January 31, 1994 setting forth the
terms of the 7.60% Senior Debt Securities due 2024. (Filed as
Exhibit 4.2 to Southern Union's Current Report on Form 8-K dated
February 15, 1994 and incorporated herein by reference.)
4(d) Officer's Certificate of Southern Union Company dated November 3,
1999 with respect to 8.25% Senior Notes due 2029. (Filed as
Exhibit 99.1 to Southern Union's Current Report on Form 8-K filed
on November 19, 1999 and incorporated herein by reference.)
4(e) Certificate of Trust of Southern Union Financing I. (Filed as
Exhibit 4-A to Southern Union's Registration Statement on Form S-3
(No. 33-58297) and incorporated herein by reference.)
4(f) Certificate of Trust of Southern Union Financing II. (Filed as
Exhibit 4-B to Southern Union's Registration Statement on Form S-3
(No. 33-58297) and incorporated herein by reference.)
4(g) Certificate of Trust of Southern Union Financing III. (Filed as
Exhibit 4-C to Southern Union's Registration Statement on Form S-3
(No. 33-58297) and incorporated herein by reference.)
4(h) Form of Amended and Restated Declaration of Trust of Southern
Union Financing I. (Filed as Exhibit 4-D to Southern Union's
Registration Statement on Form S-3 (No. 33-58297) and incorporated
herein by reference.)
4(i) Form of Subordinated Debt Securities Indenture among Southern
Union Company and The Chase Manhattan Bank, N. A., as Trustee.
(Filed as Exhibit 4-G to Southern Union's Registration Statement
on Form S-3 (No. 33-58297) and incorporated
herein by reference.)
4(j) Form of Supplemental Indenture to Subordinated Debt Securities
Indenture with respect to the Subordinated Debt Securities issued
in connection with the Southern Union Financing I Preferred
Securities. (Filed as Exhibit 4-H to Southern Union's Registration
Statement on Form S-3 (No. 33-58297) and incorporated herein by
reference.)
4(k) Form of Southern Union Financing I Preferred Security (included in
4(g) above.) (Filed as Exhibit 4-I to Southern Union's
Registration Statement on Form S-3 (No. 33-58297) and incorporated
herein by reference.)
4(l) Form of Subordinated Debt Security (included in 4(i) above.)
(Filed as Exhibit 4-J to Southern Union's Registration Statement
on Form S-3 (No. 33-58297) and incorporated herein by reference.)
4(m) Form of Guarantee with respect to Southern Union Financing I
Preferred Securities. (Filed as Exhibit 4-K to Southern Union's
Registration Statement on Form S-3 (No. 33-58297) and incorporated
herein by reference.)
4(n) First Mortgage Bonds Indenture of Mortgage and Deed of Trust dated
as of March 15, 1946 by Southern Union Company (as successor to PG
Energy, Inc. formerly, Pennsylvania Gas and Water Company, and
originally, Scranton-Spring Brook Water Service Company to
Guaranty Trust Company of New York. (Filed as Exhibit 4.1 to
Southern Union's Current Report on Form 8-K filed on December 30,
1999 and incorporated herein by reference.)
4(o) Twenty-Third Supplemental Indenture dated as of August 15, 1989
(Supplemental to Indenture dated as of March 15, 1946) between
Southern Union Company and Morgan Guaranty Trust Company of New
York (formerly Guaranty Trust Company of New York). (Filed as
Exhibit 4.2 to Southern Union's Current Report on Form 8-K filed
on December 30, 1999 and incorporated herein by reference.)
4(p) Twenty-Sixth Supplemental Indenture dated as of December 1, 1992
(Supplemental to Indenture dated as of March 15, 1946) between
Southern Union Company and Morgan Guaranty Trust Company of New
York. (Filed as Exhibit 4.3 to Southern Union's Current Report on
Form 8-K filed on December 30, 1999 and incorporated herein by
reference.)
4(q) Thirtieth Supplemental Indenture dated as of December 1, 1995
(Supplemental to Indenture dated as of March 15, 1946) between
Southern Union Company and First Trust of New York, National
Association (as successor trustee to Morgan Guaranty Trust Company
of New York). (Filed as Exhibit 4.4 to Southern Union's Current
Report on Form 8-K filed on December 30, 1999 and incorporated
herein by reference.)
4(r) Thirty-First Supplemental Indenture dated as of November 4, 1999
(Supplemental to Indenture dated as of March 15, 1946) between
Southern Union Company and U. S. Bank Trust, National Association
(formerly, First Trust of New York, National Association). (Filed
as Exhibit 4.5 to Southern Union's Current Report on Form 8-K
filed on December 30, 1999 and incorporated herein by reference.)
4(s) Pennsylvania Gas and Water Company Bond Purchase Agreement dated
September 1, 1989. (Filed as Exhibit 4.6 to Southern Union's
Current Report on Form 8-K filed on December 30, 1999 and
incorporated herein by reference.)
4(t) Southern Union is a party to other debt instruments, none of which
authorizes the issuance of debt securities in an amount which
exceeds 10% of the total assets of Southern Union. Southern Union
hereby agrees to furnish a copy of any of these instruments to the
Commission upon request.
10(a) Amended and Restated Revolving Credit Agreement (Long-Term Credit
Facility) between Southern Union Company and the Banks named
therein dated April 3, 2003.
10(b) Revolving Credit Agreement (Short-Term Credit Facility) between
Southern Union Company and the Banks named therein dated
April 3, 2003.
10(c) Amended and Restated Term Loan Credit Agreement between
Southern Union Company and the Banks named therein dated
April 3, 2003.
10(d) Form of Indemnification Agreement between Southern Union Company
and each of the Directors of Southern Union Company. (Filed as
Exhibit 10(i) to Southern Union's Annual Report on Form 10-K for
the year ended December 31, 1986 and incorporated herein by
reference.)
10(e) Southern Union Company 1992 Long-Term Stock Incentive Plan, As
Amended. (Filed as Exhibit 10(l) to Southern Union's Annual Report
on Form 10-K for the year ended June 30, 1998 and incorporated
herein by reference.)(*)
10(f) Southern Union Company Director's Deferred Compensation Plan.
(Filed as Exhibit 10(g) to Southern Union's Annual Report on Form
10-K for the year ended December 31, 1993 and incorporated herein
by reference.)(*)
10(g) Southern Union Company Amended Supplemental Deferred Compensation
Plan with Amendments. (Filed as Exhibit 4 to Southern
Union's Form S-8 filed May 27, 1999 and incorporated herein
by reference.)(*)
10(h) Form of warrant granted to Fleischman and Walsh L.L.P. (Filed as
Exhibit 10(j) to Southern Union's Transition Report on Form 10-K
for the year ended June 30, 1994 and incorporated herein by
reference.)
10(i) Employment agreement between Thomas F. Karam and Southern Union
Company dated December 28, 1999. (Filed as Exhibit 10(a) to
Southern Union's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1999 and incorporated herein by reference.)
10(j) Secured Promissory Note and Security Agreements between Thomas F.
Karam and Southern Union Company dated December 20, 1999. (Filed
as Exhibit 10(b) to Southern Union's Quarterly Report on Form 10-Q
for the quarter ended December 31, 1999 and incorporated herein by
reference.)
10(k) Promissory Note between Dennis K. Morgan and Southern Union
Company dated January 28, 2000. (Filed as Exhibit 10(k) to
Southern Union's Annual Report on Form 10-K for the year ended
June 30, 2002 and incorporated herein by reference.)
10(l) Southern Union Company Pennsylvania Division Stock Incentive
Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36146,
filed on May 3, 2000 and incorporated herein by reference.)(*)
10(m) Southern Union Company Pennsylvania Division 1992 Stock
Option Plan. (Filed as Exhibit 4 to Form S-8, SEC File No.
333-36150, filed on May 3, 2000 and incorporated herein by
reference.)(*)
10(n) Employment agreement between David W. Stevens and Southern Union
Company dated October 31, 2002. (Filed as Exhibit 10 to Southern
Union's Quarterly Report on Form 10-Q for the quarter ended
December 31, 2002 and incorporated herein by reference.)
21 Subsidiaries of the Company.
23 Consent of Independent Accountants.
24 Power of Attorney.
Exhibit No. Description
---------- ------------------------------------------------------------------
31.1 Certificate by Chief Executive Officer pursuant to Rule 13a-14(a)
or Rule 15d-14(a) promulgated under the Securities Exchange Act of
1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2 Certificate by Chief Financial Officer pursuant to Rule 13a-14(a)
or Rule 15d-14(a) promulgated under the Securities Exchange Act of
1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
32.1 Certificate by Chief Executive Officer pursuant to Rule 13a-14(b)
or Rule 15d-14(b) promulgated under the Securities Exchange Act of
1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C.
Section 1350.
32.2 Certificate by Chief Financial Officer pursuant to Rule 13a-14(b)
or Rule 15d-14(b) promulgated under the Securities Exchange Act of
1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C.
Section 1350.
(b) Reports on Form 8-K. Southern Union filed the following Current Reports
on Form 8-K during the three months ended June 30, 2003.
Date
Filed Description of Filing
--------- -----------------------------------------------------
04/30/03 Announcement of operating performance for the three-
and nine month periods ended March 31, 2003 and 2002
and filing, under Item 9, summary statements of
income of the Company for the three- and nine month
periods ended March 31, 2003 and 2002 (unaudited) and
notes thereto.
05/27/03 Announcement that Southern Union Company and CMS
Energy Corporation entered into an amendment to their
definitive Stock Purchase Agreement for Southern
Union's purchase of Panhandle Eastern Pipe Line
Company and its subsidiaries, and filing under Item
7, the Amended and Restated Stock Purchase Agreement
and Shareholder Agreement, both dated May 12, 2003.
05/30/03 Announcement of the termination of the
Hart-Scott-Rodino Act waiting period for Southern
Union's acquisition of Panhandle Eastern Pipe Line
Company and its subsidiaries; announcement of
Southern Union's plans for concurrent offerings of
common stock and equity units; and announcement
regarding the Company's earnings guidance for the
remainder of fiscal 2003 and for fiscal 2004.
05/30/03 Filing under Item 7, the audited historical financial
statements and related notes of Panhandle Eastern
Pipe Line Company and its subsidiaries for the three
years ended December 31, 2002, and the unaudited
historical financial statements and related notes of
Panhandle Eastern Pipe Line Company for the three
months ended March 31, 2003.
05/30/03 Filing under Item 7, the Unaudited Pro Forma Combined
Condensed Financial Statements of Southern Union
Company and Panhandle Eastern Pipe Line Company,
including their respective subsidiaries, and related
notes thereto.
06/06/03 Filing under Item 7, Consent of Independent Public
Accountants, Ernst & Young LLP, relating to certain
historical financial statements of Panhandle Eastern
Pipe Line Company attached to a Current Report on
Form 8-K filed by the Company on May 30, 2003.
06/10/03 Filing under Item 7, Consent of Independent Public
Accountants Ernst & Young LLP, relating to certain
historical financial statements of Panhandle Eastern
Pipe Line Company attached to a Current Report on
Form 8-K filed by the Company on May 30, 2003.
06/16/03 Announcement of Southern Union Company's completion
of the acquisition of Panhandle Eastern Pipe Line
Company and its subsidiaries on June 11, 2003;
announcement of exercise of over-allotment option on
Southern Union common stock offering; and filing
under Item 7, the following financial information:
audited historical financial statements of Panhandle
Eastern Pipe Line Company and its subsidiaries for
the three years ended December 31, 2002 and the
unaudited historical financial statements for the
three months ended March 31, 2003; unaudited pro
forma combined condensed balance sheet as of March
31, 2003 and the unaudited pro forma combined
condensed statements of operations for the year ended
June 30, 2002 and the nine months ended March 31,
2003 of Southern Union and Panhandle Eastern Pipe
Line company and its subsidiaries.
(*) Indicates Management Compensation Plan.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, Southern Union has duly caused this report to be signed by the
undersigned, thereunto duly authorized, on September 26, 2003.
SOUTHERN UNION COMPANY
By THOMAS F. KARAM
--------------------------
Thomas F. Karam
President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed by the following persons on behalf of Southern Union and in the
capacities indicated as of September 26, 2003.
Signature/Name Title
-------------- -----
GEORGE L. LINDEMANN* Chairman of the Board, Chief Executive
Officer and Director
JOHN E. BRENNAN* Director
DAVID BRODSKY* Director
FRANK W. DENIUS* Director
KURT A. GITTER, M.D.* Director
THOMAS F. KARAM Director
---------------------
Thomas F. Karam
ADAM M. LINDEMANN* Director
ROGER J. PEARSON* Director
GEORGE ROUNTREE, III* Director
RONALD W. SIMMS* Director
DAVID J. KVAPIL Executive Vice President and Chief
------------------------ Financial Officer
David J. Kvapil (Principal Accounting Officer)
*By THOMAS F. KARAM
-----------------------
Thomas F. Karam
Attorney-in-fact
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SOUTHERN UNION COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Financial Statements:
Consolidated statement of operations -- years ended
June 30, 2003, 2002 and 2001..................... F-2
Consolidated balance sheet --
June 30, 2003 and 2002........................... F-3 to F-4
Consolidated statement of cash flows -- years ended
June 30, 2003, 2002 and 2001..................... F-5
Consolidated statement of common stockholders' equity --
years ended June 30, 2003, 2002 and 2001.......... F-6
Notes to consolidated financial statements................ F-7 to F-42
Report of independent auditors............................ F-43
All schedules are omitted as the required information is not applicable or the
information is presented in the consolidated financial statements or related
notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended June 30,
2003 2002 2001
------------- ------------ -------------
(thousands of dollars, except shares and
per share amounts)
Operating revenues......................................................... $ 1,188,507 $ 980,614 $ 1,461,811
Cost of gas and other energy............................................... (724,611) (573,077) (1,031,696)
Revenue-related taxes...................................................... (40,485) (33,409) (49,869)
------------- ------------ -------------
Operating margin...................................................... 423,411 374,128 380,246
Operating expenses:
Operating, maintenance and general.................................... 193,745 171,147 186,468
Business restructuring charges........................................ -- 29,159 --
Depreciation and amortization......................................... 60,642 58,989 69,161
Taxes, other than on income and revenues.............................. 26,653 23,708 23,352
------------- ------------ -------------
Total operating expenses.......................................... 281,040 283,003 278,981
------------- ------------ -------------
Net operating revenues............................................ 142,371 91,125 101,265
------------- ------------ -------------
Other income (expenses):
Interest ............................................................. (83,343) (90,992) (102,928)
Dividends on preferred securities of subsidiary trust................. (9,480) (9,480) (9,480)
Other, net............................................................ 18,394 14,278 81,401
------------- ------------- -------------
Total other expenses, net......................................... (74,429) (86,194) (31,007)
------------- ------------ -------------
Earnings from continuing operations before income taxes.................... 67,942 4,931 70,258
Federal and state income taxes ............................................ 24,273 3,411 30,099
------------- ------------ -------------
Net earnings from continuing operations.................................... 43,669 1,520 40,159
------------- ------------ -------------
Discontinued operations:
Earnings from discontinued operations before income taxes............. 84,773 29,801 26,425
Federal and state income taxes........................................ 52,253 11,697 9,901
------------- ------------ -------------
Net earnings from discontinued operations.................................. 32,520 18,104 16,524
------------- ------------ -------------
Net earnings before cumulative effect of change in accounting
principle............................................................. 76,189 19,624 56,683
Cumulative effect of change in accounting principle, net of tax............ -- -- 602
------------- ------------ -------------
Net earnings available for common stock.................................... $ 76,189 $ 19,624 $ 57,285
============= ============ =============
Net earnings from continuing operations per share:
Basic................................................................. $ .76 $ .03 $ .71
============= ============ =============
Diluted............................................................... $ .74 $ .03 $ .67
============= ============ =============
Net earnings available for common stock per share:
Basic................................................................. $ 1.33 $ .35 $ 1.01
============= ============ =============
Diluted............................................................... $ 1.29 $ .33 $ .95
============= ============ =============
Weighted average shares outstanding:
Basic................................................................. 57,176,843 56,060,425 56,893,218
============= ============ =============
Diluted............................................................... 59,017,861 59,132,567 60,081,146
============= ============ =============
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
ASSETS
June 30,
2003 2002
------------- --------------
(thousands of dollars)
Property, plant and equipment:
Plant in service................................................................. $ 3,710,541 $ 1,767,349
Construction work in progress.................................................... 75,484 6,535
-------------- --------------
3,786,025 1,773,884
Less accumulated depreciation and amortization (641,225) (604,114)
-------------- --------------
Net property, plant and equipment............................................ 3,144,800 1,169,770
Current assets:
Cash and cash equivalents........................................................ 86,997 --
Accounts receivable, billed and unbilled, net.................................... 192,402 95,036
Inventories...................................................................... 173,757 101,076
Deferred gas purchase costs...................................................... 24,603 3,597
Investment securities available for sale......................................... 53 1,163
Gas imbalances - receivable...................................................... 34,911 --
Prepayments and other............................................................ 18,918 13,527
Assets held for sale............................................................. -- 395,446
-------------- --------------
Total current assets......................................................... 531,641 609,845
Goodwill, net of accumulated amortization of $27,510.................................. 642,921 642,921
Deferred charges...................................................................... 188,261 206,130
Investment securities, at cost........................................................ 9,641 9,786
Other................................................................................. 73,674 41,612
Total assets................................................................. $ 4,590,938 $ 2,680,064
============== =============
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET (Continued)
STOCKHOLDERS' EQUITY AND LIABILITIES
June 30,
2003 2002
------------- ------------
(thousands of dollars)
Common stockholders' equity:
Common stock, $1 par value; authorized 200,000,000 shares; issued
73,073,967 shares at June 30, 2003............................................ $ 73,074 $ 58,055
Premium on capital stock.......................................................... 901,701 707,912
Less treasury stock: 282,333 and 3,125,993 shares, respectively,
at cost....................................................................... (10,467) (57,673)
Less common stock held in Trust: 1,061,656 and 1,138,821 shares,
respectively.................................................................. (15,617) (17,821)
Deferred compensation plans....................................................... 9,960 9,373
Accumulated other comprehensive income (loss)..................................... (62,579) (14,500)
Retained earnings................................................................. 24,346 --
------------- -------------
920,418 685,346
Company-obligated mandatorily redeemable preferred securities of subsidiary
trust holding solely subordinated notes of Southern Union......................... 100,000 100,000
Long-term debt and capital lease obligation............................................ 1,611,653 1,082,210
------------- -------------
Total capitalization.......................................................... 2,632,071 1,867,556
Current liabilities:
Long-term debt and capital lease obligation due within one year................... 734,752 108,203
Notes payable..................................................................... 251,500 131,800
Accounts payable.................................................................. 112,840 71,343
Federal, state and local taxes.................................................... 6,743 9,212
Accrued interest.................................................................. 40,871 17,019
Accrued dividends on preferred securities of subsidiary trust..................... -- 2,370
Customer deposits................................................................. 12,585 7,572
Gas imbalances - payable.......................................................... 64,519 --
Other............................................................................. 130,196 38,167
Liabilities related to assets held for sale....................................... -- 67,718
------------- -------------
Total current liabilities..................................................... 1,354,006 453,404
Deferred credits....................................................................... 322,154 142,452
Accumulated deferred income taxes...................................................... 282,707 216,652
Total stockholders' equity and liabilities.................................... $ 4,590,938 $ 2,680,064
============= =============
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended June 30,
2003 2002 2001
------------ ------------ ------------
(thousands of dollars)
Cash flows from (used in) operating activities:
Net earnings ........................................................ $ 76,189 $ 19,624 $ 57,285
Adjustments to reconcile net earnings to net cash flows from
(used in) operating activities:
Depreciation and amortization.................................... 60,642 58,989 69,161
Deferred income taxes............................................ 78,747 28,397 27,778
Provision for bad debts.......................................... 17,873 12,260 27,260
Provision for investment impairment.............................. -- 10,380 --
Financial derivative trading gains............................... (605) (6,204) --
Amortization of debt expense..................................... 2,919 2,936 3,118
Gain on sale of investment securities............................ (567) (1,004) (74,582)
Gain on sale of subsidiaries and other assets.................... (62,992) (6,414) (14,239)
Loss on sale of subsidiaries..................................... -- 1,500 --
Gain on settlement of interest rate swaps........................ -- (17,166) --
Cumulative effect of change in accounting principle.............. -- -- (602)
Business restructuring charges................................... -- 24,440 --
Net cash provided (used by) assets held for sale................. (23,698) 48,618 320
Other ........................................................... (1,447) 1,359 (1,034)
Changes in operating assets and liabilities, net of
acquisitions:
Accounts receivable, billed and unbilled.................... (48,520) 71,932 (111,732)
Gas imbalance receivable.................................... 6,330 -- --
Accounts payable............................................ 22,728 (11,965) (13,134)
Gas imbalance payable....................................... 4,851 -- --
Customer deposits........................................... 5,013 (53) (2,136)
Deferred gas purchase costs................................. (21,006) 53,436 (59,054)
Inventories................................................. (34,583) 1,044 (32,125)
Deferred charges and credits................................ (12,561) 16,804 (9,316)
Prepaids and other current assets........................... 2,541 (3,735) (7,802)
Taxes and other current liabilities......................... (16,158) (31,562) (6,265)
------------ ------------ ------------
Net cash flows from (used in) operating activities............... 55,696 273,616 (147,099)
------------ ------------ ------------
Cash flows (used in) from investing activities:
Additions to property, plant and equipment........................... (79,730) (70,698) (100,752)
Acquisition of operations, net of cash received...................... (522,316) -- (414,497)
Notes receivable..................................................... (6,750) (2,750) --
Purchase of investment securities.................................... -- (938) (12,495)
Customer advances ................................................... (9,619) (403) 717
Proceeds from sale of investment securities.......................... 782 1,213 85,761
Proceeds from sale of subsidiaries and other assets.................. 437,000 40,935 23,938
Proceeds from sale of interest rate swaps............................ -- 17,166 --
Net cash used in assets held for sale................................ (13,410) (23,215) (22,012)
Other................................................................ 2,683 (536) 4,587
------------ ------------ ------------
Net cash flows used in investing activities...................... (191,360) (39,226) (434,753)
------------ ------------ ------------
Cash flows (used in) from financing activities:
Issuance of long-term debt........................................... 311,087 -- 535,000
Issuance cost of debt................................................ (313) (921) (3,474)
Issuance of common stock............................................. 168,682 -- --
Issuance of equity units............................................. 125,000 -- --
Issuance cost of equity units........................................ (3,443) -- --
Purchase of treasury stock........................................... (2,181) (41,632) --
Repayment of debt and capital lease obligation....................... (500,135) (145,131) (167,270)
Net (payments) borrowings under revolving credit facilities.......... 119,700 (58,800) 190,597
Proceeds from exercise of stock options.............................. 3,047 8,346 707
Other................................................................ 1,217 2,529 (318)
------------ ------------ ------------
Net cash flows (used in) from financing activities........................ 222,661 (235,609) 555,242
------------ ------------ ------------
Change in cash and cash equivalents....................................... 86,997 (1,219) (26,610)
Cash and cash equivalents at beginning of year............................ -- 1,219 27,829
------------ ------------ ------------
Cash and cash equivalents at end of year.................................. $ 86,997 $ -- $ 1,219
============ ============ ============
Cash paid for interest, net of amounts capitalized, in 2003, 2002 and 2001 was
$90,462,000, $99,643,000 and $107,295,000, respectively. Cash paid for income
taxes in 2003 and 2001 was $2,351,000 and $17,753,000, respectively, while cash
refunded for income taxes in 2002 was $4,214,000.
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Common Accumulated
Common Premium Treasury Stock Other
Stock, $1 on Capital Stock, at Held in Comprehensive Retained
Par Value Stock Cost Trust Income (Loss) Earnings Total
---------- ----------- ----------- ----------- ---------- ------------ -----------
(thousands of dollars)
Balance July 1, 2000................... $ 50,521 $ 599,835 $ (15,554) $ (14,522) $ 115,175 $ -- $ 735,455
Comprehensive income:
Net earnings ..................... -- -- -- -- -- 57,285 57,285
Unrealized loss in investment
securities, net of tax benefit . -- -- -- -- (96,323) -- (96,323)
Minimum pension liability
adjustment, net of tax benefit . -- -- -- -- (4,324) -- (4,324)
Cumulative effect of change in
accounting principle, net of tax -- -- -- -- 826 -- 826
Unrealized loss on hedging
activities, net of tax benefit . -- -- -- -- (1,911) -- (1,911)
---------
Comprehensive income (loss) ...... (44,447)
---------
Payment on note receivable ......... -- 290 -- -- -- -- 290
Purchase of common stock held
in trust ......................... -- -- -- (4,009) -- -- (4,009)
5% stock dividend .................. 2,556 49,626 -- -- -- (52,182) --
Benefit plan modification .......... -- -- -- 6,560 -- -- 6,560
Issuance of stock for acquisition .. 1,371 25,930 -- -- -- -- 27,301
Exercise of stock options .......... 105 643 (315) 274 -- -- 707
--------- --------- --------- --------- --------- --------- ---------
Balance June 30, 2001 ................. 54,553 676,324 (15,869) (11,697) 13,443 5,103 721,857
Comprehensive income:
Net earnings ..................... -- -- -- -- -- 19,624 19,624
Unrealized loss in investment
securities, net of tax benefit . -- -- -- -- (18,249) -- (18,249)
Minimum pension liability
adjustment, net of tax benefit . -- -- -- -- (10,498) -- (10,498)
Unrealized gain on hedging
activities, net of tax ......... -- -- -- -- 804 -- 804
---------
Comprehensive income (loss) ...... (8,319)
---------
Payment on note receivable ......... -- 202 -- -- -- -- 202
Purchase of treasury stock ......... -- -- (41,632) -- -- -- (41,632)
5% stock dividend .................. 2,618 22,091 -- -- -- (24,727) (18)
Stock compensation plan ............ -- 1,248 -- 1,257 -- -- 2,505
Sale of common stock held
in trust ......................... -- 26 -- 1,945 -- -- 1,971
Exercise of stock options .......... 884 8,021 (172) 47 -- -- 8,780
--------- --------- --------- --------- --------- --------- ---------
Balance June 30, 2002 ................. 58,055 707,912 (57,673) (8,448) (14,500) -- 685,346
Comprehensive income:
Net earnings ..................... -- -- -- -- -- 76,189 76,189
Unrealized loss in investment
securities, net of tax benefit . -- -- -- -- (581) -- (581)
Minimum pension liability
adjustment, net of tax benefit . -- -- -- -- (41,930) -- (41,930)
Unrealized loss on hedging
activities, net of tax benefit . -- -- -- -- (5,568) -- (5,568)
---------
Comprehensive income (loss) ...... 28,110
---------
Payment on note receivable ......... -- 305 -- -- -- -- 305
Purchase of treasury stock ......... -- -- (2,181) -- -- -- (2,181)
5% stock dividend .................. 3,468 48,342 -- -- -- (51,843) (33)
Stock compensation plan ............ -- 480 -- 737 -- -- 1,217
Issuance of stock for acquisition .. -- -- 48,900 -- -- -- 48,900
Issuance of common stock ........... 10,925 157,757 -- -- -- -- 168,682
Issuance costs of equity units ..... -- (3,443) -- -- -- -- (3,443)
Contract adjustment payment ........ -- (11,713) -- -- -- -- (11,713)
Sale of common stock held in trust . -- (243) -- 2,424 -- -- 2,181
Exercise of stock options .......... 626 2,304 487 (370) -- -- 3,047
--------- --------- --------- --------- --------- --------- ---------
Balance June 30, 2003 ................. $ 73,074 $ 901,701 $ (10,467) $ (5,657) $ (62,579) $ 24,346 $ 920,418
========= ========= ========= ========= ========= ========= =========
The Company's common stock is $1 par value. Therefore, the change in Common
Stock, $1 Par Value is equivalent to the change in the number of shares of
common stock outstanding.
See accompanying notes.
SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
I Summary of Significant Accounting Policies
Operations. Southern Union Company (Southern Union and together with its
subsidiaries, the Company) is primarily engaged in the transportation, storage
and distribution of natural gas in the United States. The Company's interstate
natural gas transportation and storage operations are conducted through
Panhandle Eastern Pipe Line Company, LLC and its subsidiaries (hereafter
referred to as Panhandle Energy), which serve approximately 500 customers in the
Midwest and Southwest. Panhandle Energy was acquired by Southern Union on June
11, 2003 (see Note II - Acquisitions and Sales). The Company's local natural gas
distribution operations are conducted through its three regulated utility
divisions, Missouri Gas Energy, PG Energy and New England Gas Company, which
collectively serve over 950,000 residential, commercial and industrial customers
in Missouri, Pennsylvania, Rhode Island and Massachusetts.
Basis of Presentation. Effective June 11, 2003, the Company acquired Panhandle
Energy from CMS Energy Corporation. The acquisition was accounted for using the
purchase method of accounting in accordance with accounting principles generally
accepted in the United States with the purchase price paid by the Company being
allocated to Panhandle Energy's net assets as of the acquisition date based on
preliminary estimates. The Panhandle Energy assets acquired and liabilities
assumed have been recorded in the Consolidated Balance Sheet as of June 30, 2003
at their estimated fair value and are subject to further assessment and
adjustment pending 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. See Note II -- Acquisitions and Sales.
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas Company natural gas operating division and related assets (the Texas
Operations) to ONEOK, Inc. In accordance with accounting principles generally
accepted in the United States, the assets and liabilities sold have been
segregated and reported as "held for sale" in the Consolidated Balance Sheet as
of June 30, 2002, and the related results of operations and gain on sale have
been segregated and reported as "discontinued operations" in the Consolidated
Statement of Operations and Consolidated Statement of Cash Flows for all periods
presented. See Note II -- Acquisitions and Sales and Note XIX -- Discontinued
Operations and Assets Held for Sale.
Principles of Consolidation. The consolidated financial statements include the
accounts of Southern Union and its wholly-owned subsidiaries. Investments in
which the Company has significant influence over the operations of the investee
and the Company owns a 20% to 50% interest are accounted for using the equity
method. All significant intercompany accounts and transactions are eliminated in
consolidation. All dollar amounts in the tables herein, except per share
amounts, are stated in thousands unless otherwise indicated. Certain
reclassifications have been made to prior years' financial statements to conform
with the current year presentation.
Segment Reporting. The Financial Accounting Standards Board (FASB) Standard,
Disclosures about Segments of an Enterprise and Related Information, requires
disclosure of segment data based on how management makes decisions about
allocating resources to segments and measuring performance. The Company is
principally engaged in the transportation, storage and distribution of natural
gas in the United States and reports these operations under two reportable
segments: the Transportation and Storage segment and the Distribution segment.
Gas Utility Revenues and Gas Purchase Costs. In the Distribution segment, gas
utility customers are billed on a monthly-cycle basis. The related cost of gas
and revenue taxes are matched with cycle-billed revenues through utilization of
purchased gas adjustment provisions in tariffs approved by the regulatory
agencies having jurisdiction. Revenues from gas delivered but not yet billed are
accrued, along with the related gas purchase costs and revenue-related taxes.
Unbilled revenues, net of related gas purchase costs and revenue-related taxes,
were $7,864,000 and $7,450,000 at June 30, 2003 and 2002, respectively. The
Company's operating revenues and other financial information by segment for
fiscal 2003, 2002 and 2001 are presented in Note XXI -- Reportable Segments.
Transportation and Storage Revenues. In the Transportation and Storage segment,
revenues on transportation, storage and terminalling of natural gas are
recognized as service is provided. Receivables are subject to normal trade terms
and are carried net of an allowance for doubtful accounts. Prior to final
Federal Energy Regulatory Commission (FERC) approval of filed rates, the Company
is exposed to risk that the FERC will ultimately approve the rates at a level
lower than those requested. The difference is subject to refund and reserves are
established, where required, for that purpose. The Company's operating revenues
and other financial information by segment for fiscal 2003, 2002 and 2001 are
presented in Note XXI -- Reportable Segments.
Earnings Per Share. The Company's earnings per share presentation conforms to
the FASB Standard, Earnings per Share. All share and per share data have been
appropriately restated for all stock dividends and stock splits distributed
through July 31, 2003 unless otherwise noted.
Accumulated Other Comprehensive Income. The Company reports comprehensive income
and its components in accordance with the FASB Standard, Reporting Comprehensive
Income. The main components of comprehensive income that relate to the Company
are net earnings, unrealized holding gains and losses on investment securities,
minimum pension liability adjustments, unrealized loss on hedging activities and
cumulative effect of change in accounting principle, all of which are presented
in the Consolidated Statement of Stockholders' Equity.
Unrealized holding gains on investment securities were $21,000, $603,000 and
$18,852,000 in 2003, 2002 and 2001, respectively. The reclassification
adjustment for gains included in net income, net of tax, for reporting other
comprehensive income was $364,000, $567,000 and $43,726,000 in 2003, 2002 and
2001, respectively. The unrealized holding gains or losses on investment
securities and the reclassification adjustment for gains are combined and
reflected on the Consolidated Statement of Stockholders' Equity.
Significant Customers and Credit Risk. In the Distribution segment,
concentrations of credit risk in trade receivables are limited due to the large
customer base with relatively small individual account balances. In addition,
Company policy requires a deposit from certain customers. The Company has
recorded an allowance for doubtful accounts totaling $16,823,000, $15,324,000,
$28,347,000 and $6,675,000 at June 30, 2003, 2002, 2001 and 2000, respectively,
relating to its Distribution segment trade receivables. The allowance for
doubtful accounts is adjusted for changes in estimated uncollectible accounts
and reduced for the write-off of trade receivables.
In the Transportation and Storage segment, aggregate sales to Panhandle Energy's
top 10 customers accounted for 71% of segment operating revenues and 1% of
consolidated operating revenues for the period owned by Southern Union in fiscal
2003. This included sales to BG LNG Services, a nonaffiliated gas marketer,
which accounted for 20% of segment operating revenues; sales to Proliance
Energy, LLC, a nonaffiliated local distribution company and gas marketer, which
accounted for 17% of segment operating revenues; and sales to CMS Energy
Corporation, Panhandle Energy's former parent, which accounted for 13% of
segment operating revenues. During 2003, no other customer accounted for 10% or
more of segment operating revenues during the period owned by Southern Union.
Panhandle Energy manages trade credit risks to minimize exposure to
uncollectible trade receivables. Prospective and existing customers are reviewed
for creditworthiness based upon pre-established standards. Customers that do not
meet minimum standards are required to provide additional credit support. The
Company has recorded an allowance for doubtful accounts totaling $4,138,000 at
June 30, 2003, relating to its Transportation and Storage segment trade
receivables.
Inventories. In the Distribution segment, inventories consist of natural gas in
underground storage and materials and supplies, both of which are carried at
weighted average cost. Natural gas in underground storage at June 30, 2003 and
2002 was $117,679,000 and $92,448,000, respectively, and consisted of 20,853,000
and 23,166,000 million British thermal units (MMBtu), respectively.
In the Transportation and Storage segment, inventories consist of gas held for
operations and materials and supplies. All gas held for operations and materials
and supplies purchased are recorded at the lower of weighted average cost or
market, while gas received from or owed back to customers is valued at market.
The gas held for operations that is not expected to be consumed in operations in
the next twelve months is reflected in non-current assets. Gas held for
operations at June 30, 2003 was $57,647,000, of which $22,769,000 is classified
as non-current, and consisted of 11,657,000 MMBtu.
Goodwill and Other Intangible Assets. The Company accounts for its goodwill and
other intangible assets in accordance with the FASB Standard, Accounting for
Goodwill and Other Intangible Assets. Under this Statement, the Company has
ceased amortization of goodwill. Goodwill, which was previously classified on
the consolidated balance sheet as additional purchase cost assigned to utility
plant and amortized on a straight-line basis over forty years, is now subject to
at least an annual assessment for impairment by applying a fair-value based
test. See Note VII - Goodwill and Intangibles.
Fair Value of Financial Instruments. The carrying amounts reported in the
balance sheet for cash and cash equivalents, accounts receivable, accounts
payable and notes payable approximate their fair value. The fair value of the
Company's preferred securities of subsidiary trust and long-term debt is
estimated using current market quotes and other estimation techniques.
Gas Imbalances. In the Transportation and Storage segment, gas imbalances occur
as a result of differences in volumes of gas received and delivered. The Company
records gas imbalance in-kind receivables and payables at cost or market, based
on whether net imbalances have reduced or increased system gas balances,
respectively.
Fuel Tracker. Liability accounts are maintained in the Transportation and
Storage segment for net volumes of fuel gas owed to customers collectively.
Trunkline records an asset whenever fuel is due from customers from prior under
recovery based on contractual and specific tariff provisions, which support the
treatment as an asset. Panhandle's other companies that are subject to fuel
tracker provisions record an expense when fuel is under recovered. The
pipelines' fuel reimbursement is in-kind and non-discountable.
Interest Cost Capitalized. The Company capitalizes interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use in accordance with the FASB Standard, Capitalization of Interest
Cost. Interest costs incurred during the construction period are capitalized and
amortized over the life of the assets.
Derivative Instruments and Hedging Activities. The Company accounts for its
derivatives in accordance with the FASB Standard, Accounting for Derivative
Instruments and Hedging Activities, as amended. Under this Statement, all
derivatives are recognized on the balance sheet at their fair value. On the date
the derivative contract is entered into, management designates the derivative as
either: (i) a hedge of the fair value of a recognized asset or liability or of
an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a
forecasted transaction or of the variability of cash flows to be received or
paid in connection with a recognized asset or liability (a cash flow hedge), or
(iii) an instrument that is held for trading or non-hedging purposes (a trading
or non-hedging instrument). Changes in the fair value of a derivative that
qualifies as a fair-value hedge, along with the gain or loss on the hedged asset
or liability that is attributable to the hedged risk, are recorded in earnings.
Changes in the fair value of a derivative that qualifies as a cash-flow hedge,
to the extent that the hedge is effective, are recorded in other comprehensive
income, until earnings are affected by the variability of cash flows of the
hedged transaction (e.g., until periodic settlements of a variable-rate asset or
liability are recorded in earnings). Hedge ineffectiveness is recorded through
earnings immediately. Lastly, changes in the fair value of derivative trading
and non-hedging instruments are reported in current-period earnings. Fair value
is determined based upon mathematical models using current and historical data.
The Company formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions have been
highly effective in offsetting changes in the fair value or cash flows of hedged
items and whether those derivatives may be expected to remain highly effective
in future periods. The Company discontinues hedge accounting when: (i) it
determines that the derivative is no longer effective in offsetting changes in
the fair value or cash flows of a hedged item; (ii) the derivative expires or is
sold, terminated, or exercised; (iii) it is no longer probable that the
forecasted transaction will occur; or (iv) management determines that
designating the derivative as a hedging instrument is no longer appropriate. In
all situations in which hedge accounting is discontinued and the derivative
remains outstanding, the Company will carry the derivative at its fair value on
the balance sheet, recognizing changes in the fair value in current-period
earnings. See Note XI -- Derivative Instruments and Hedging Activities.
The Company utilizes derivative instruments on a limited basis to manage certain
business risks. Interest rate swaps and treasury rate locks are used to reduce
interest rate risks and to manage interest expense. Commodity swaps have been
employed to manage price risk associated with certain energy contracts.
In accordance with adoption of this Statement on July 1, 2000, the Company
recorded a net-of-tax cumulative-effect gain of $602,000 in earnings to
recognize the fair value of the gas derivative contracts at PG Energy Services,
Inc., a wholly-owned subsidiary, that are not designated as hedges.
New Pronouncements. Effective July 1, 2002, the Company adopted the FASB
standard, Accounting for Asset Retirement Obligations (ARO). The Statement
requires legal obligations associated with the retirement of long-lived assets
to be recognized at their fair value at the time the obligations are incurred.
Upon initial recognition of a liability, costs should be capitalized as part of
the related long-lived asset and allocated to expense over the useful life of
the asset. Over time, the liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of the
related long-lived asset. In certain rate jurisdictions, the Company is
permitted to include annual charges for cost of removal in its regulated cost of
service rates charged to customers. The adoption of the Statement did not have a
material impact on the Company's financial position, results of operations or
cash flows for all periods presented.
As a result of the acquisition of Panhandle Energy, the Company assumed an ARO
liability of approximately $6.8 million as of June 30, 2003, relating to the
retirement of certain of Panhandle Energy's offshore lateral lines. During
fiscal 2003, changes in the carrying amount of the ARO liability attributable to
(i) liabilities incurred, (ii) liabilities settled, (iii) accretion expense, and
(iv) cash flow revisions were immaterial for the period the associated assets
were owned by the Company. In addition, the Company has reclassified
approximately $27 million of negative salvage previously included in accumulated
depreciation to deferred credits for amounts collected for asset retirement
obligations on certain of the Panhandle Energy assets acquired which are not
recordable as liabilities under the Statement but represent other obligations.
Also effective July 1, 2002, the Company adopted the FASB standard, Accounting
for the Impairment or Disposal of Long-Lived Assets. The Statement provides new
guidance on the recognition of impairment losses on long-lived assets to be held
and used or to be disposed of and also broadens the definition of what
constitutes a discontinued operation and how the results of a discontinued
operation are to be measured and presented. Under the Statement, assets held for
sale that are a component of an entity will be included in discontinued
operations if the operations and cash flows will be or have been eliminated from
the ongoing operations of the entity and the entity will not have any
significant continuing involvement in the operations prospectively. The adoption
of this Statement did not materially change the methods the Company uses to
measure impairment losses on long-lived assets, but did result in the Company's
sale of its Texas Operations being reported as discontinued operations. See Note
XIX - Discontinued Operations and Assets Held for Sale.
In November 2002, the FASB issued Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Guarantees of Indebtedness of Others. The
Interpretation expands the existing disclosure requirements for guarantees and
requires that companies recognize, at the inception of a guarantee, a liability
for the fair value of the obligations undertaken when issuing the guarantee. The
initial recognition and initial measurement provisions of the Interpretation are
effective for guarantees issued or modified after December 31, 2002.
Implementation of this Statement did not have a material impact on the
Company's financial position, results of operations or cash flows for all
periods presented.
In December 2002, the FASB issued Accounting for Stock-Based Compensation -
Transition and Disclosure. The Statement provides alternative methods of
transition for an entity that voluntarily changes to a fair value based method
of accounting for stock-based employee compensation. In addition, the Statement
amends the previous standard, Accounting for Stock-Based Compensation, to
require more prominent disclosure about the effects on reported net income of
stock-based employee compensation. The Company expects to continue to account
for stock-based compensation in accordance with Accounting Principles Board
opinion, Accounting for Stock Issued to Employees, and will provide the
prominent disclosures required in its annual and future interim financial
statements.
In April 2003, the FASB issued Amendment of Statement 133 on Derivative
Instruments and Hedging Activities. The Statement is effective for contracts
entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. The Statement (i) clarifies under what
circumstances a contract with an initial net investment meets the characteristic
of a derivative, (ii) clarifies when a derivative contains a financing
component, (iii) amend the definition of an underlying to conform it to language
used in FASB Interpretation Guarantor's Accounting and Disclosure Requirement
for Guarantees, Including Indirect Guarantees of Indebtedness of Others, and
(iv) amends certain other existing pronouncements. The Statement is not expected
to materially change the methods the Company uses to account for and report its
derivatives and hedging activities.
In May 2003, the FASB issued Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity. The Statement is effective at
the beginning of the first interim period beginning after June 15, 2003. The
Statement establishes guidelines on how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. The Statement further defines and requires that certain instruments
within its scope be classified as liabilities on the financial statements. The
Company does not expect adoption of this statement to have a material impact on
its financial position, results of operations or cash flows.
Use of Estimates. The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
II Acquisitions and Sales
On June 11, 2003, Southern Union acquired Panhandle Energy from CMS Energy
Corporation for approximately $582 million in cash and in connection therewith
incurred transaction costs estimated at $30 million. Additional consideration
was financed by CMS Energy Corporation through their purchase of 3 million
shares of Southern Union common stock (before adjustment for any subsequent
stock dividends) valued at approximately $49 million based on market prices at
closing. Southern Union also incurred additional deferred state income tax
liabilities estimated at $18 million as a result of the transaction. At the
time of the acquisition, Panhandle Energy had approximately $1.159 billion of
debt outstanding that it retained. The Company funded the cash portion of the
acquisition with approximately $437 million in cash proceeds it received for the
January 1, 2003 sale of its Texas operations, approximately $121 million of the
net proceeds it received from concurrent common stock and equity units 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 in the United States with the purchase
price paid by the Company being allocated to Panhandle Energy's net assets as of
the acquisition date based on preliminary estimates. The Panhandle Energy assets
acquired and liabilities assumed have been recorded in the Consolidated Balance
Sheet as of June 30, 2003 at their estimated fair value and are subject to
further assessment and adjustment pending 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 are 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. The Panhandle Energy entities include
Panhandle Eastern Pipe Line Company, LLC (Panhandle Eastern Pipe Line),
Trunkline Gas Company, LLC (Trunkline), Sea Robin Pipeline Company (Sea Robin),
Trunkline LNG Company, LLC (Trunkline LNG) and Pan Gas Storage Company, LLC (Pan
Gas, also dba Southwest Gas Storage). 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 per day, 72
billion cubic feet of owned underground storage capacity and 6.3 billion cubic
feet of above ground LNG storage facilities. Trunkline LNG, located on
Louisiana's Gulf Coast, operates one of the nation's largest LNG import
terminals.
The following table summarizes the estimated fair values of the Panhandle Energy
assets acquired and liabilities assumed at the date of acquisition.
At
June 11, 2003
--------------
(in thousands)
Property, plant and equipment (excluding intangibles) ....... $ 1,910,000
Intangibles.................................................. 20,000
Current assets (1)........................................... 206,000
Other non-current assets..................................... 29,000
-------------
Total assets acquired................................... 2,165,000
-------------
Long-term debt............................................... (1,220,000)
Current liabilities.......................................... (153,000)
Other non-current liabilities................................ (113,000)
-------------
Total liabilities assumed............................... (1,486,000)
-------------
Net assets acquired................................. $ 679,000
=============
(1) Includes cash and cash equivalents of approximately $59 million.
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK, Inc. (ONEOK) for
approximately $437,000,000 in cash resulting in a pre-tax gain of $62,992,000.
In 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 September 2000, Southern Union acquired Providence Energy Corporation
(ProvEnergy), Fall River Gas Company (Fall River Gas), and Valley Resources
(Valley Resources). Collectively, these companies (hereafter referred to as the
Company's New England Operations) were acquired for approximately $422,000,000
in cash and 1,370,629 shares (before adjustment for any subsequent stock
dividends) of Southern Union common stock, as well as the assumption of
approximately $140,000,000 in long-term debt. The results of operations from
ProvEnergy and Fall River Gas have been included in the Company's Consolidated
Statement of Operations since September 28, 2000, and the results of operations
from Valley Resources have been included in the Company's Consolidated Statement
of Operations since September 20, 2000. Thus, the Company's Consolidated
Statement of Operations for the periods subsequent to these acquisitions is not
comparable to the same periods in prior years. These acquisitions were accounted
for using the purchase method.
The New England Operations' primary business is the distribution of natural gas
through the New England Gas Company. Subsidiaries of the Company acquired with
the New England Gas Company and currently operating include ProvEnergy Power LLC
(ProvEnergy Power), Fall River Gas Appliance Company (Fall River Appliance),
Valley Appliance Merchandising Company (VAMCO) and Alternate Energy Corporation
(AEC). ProvEnergy Power provides outsourced energy management services and owns
50% of Capital Center Energy Company LLC, a joint venture formed between
ProvEnergy and ERI Services, Inc. to provide retail power and conditioned air.
Fall River Appliance rents water heaters and conversion burners, primarily to
residential customers. VAMCO rents natural gas burning appliances and offers
appliance service contract programs to residential customers. AEC is an energy
consulting firm.
Subsidiaries acquired with the New England Gas Company and subsequently sold
include Morris Merchants, Inc. (Morris Merchants), Valley Propane, Inc. (Valley
Propane) and ProvEnergy Oil Enterprises, Inc. (ProvEnergy Oil). In October 2001,
Morris Merchants, which served as a manufacturers' representative agency for
franchised plumbing and heating contract supplies throughout New England, was
sold for $1,586,000. In September 2001, Valley Propane, which sold liquid
propane to residential, commercial and industrial customers, was sold for
$5,301,000. In August 2001, ProvEnergy Oil, which operated a fuel oil
distribution business through its subsidiary, ProvEnergy Fuels, Inc. for
residential and commercial customers, was sold for $15,776,000. No financial
gain or loss was recognized on any of these sales transactions.
In April 2002, PG Energy Services' (Energy Services) propane operations, which
sold liquid propane to residential, commercial and industrial customers, were
sold for $2,300,000, resulting in a pre-tax gain of $1,200,000. In July 2001,
Energy Services' commercial and industrial gas marketing contracts were sold for
$4,972,000, resulting in a pre-tax gain of $4,653,000. In June 2001, the Company
sold Keystone, which engaged primarily in the construction, maintenance, and
rehabilitation of natural gas distribution pipelines, for $3,300,000, resulting
in a pre-tax gain of $707,000.
Pro Forma Financial Information
The following unaudited pro forma financial information for the years ended June
30, 2003, 2002 and 2001 is presented as though the following events had occurred
at the beginning of the earliest period presented: (i) acquisition of Panhandle
Energy and the New England Operations; (ii) the issuance of the common stock and
equity units in June 2003; (iii) the issuance of the Term Note; and (iv) the
refinancing of certain short-term and long-term debt at the time of the
respective acquisitions. The pro forma financial information is not necessarily
indicative of the results which would have actually been obtained had the
acquisition of Panhandle Energy and the New England Operations, the issuance of
the common stock and equity units, the issuance of the Term Note, or the
refinancings been completed as of the assumed date for the period presented or
which may be obtained in the future.
(Unaudited)
Year Ended June 30,
2003 2002 2001
------------- ------------- ---------------
Operating revenue...................................................... $ 1,671,114 $ 1,467,630 $ 2,017,679
Income from continuing operations before extraordinary item............ 129,705 53,453 93,576
Net earnings from continuing operations................................ 129,705 53,453 93,576
Net earnings per share from continuing operations:
Basic............................................................. 1.83 .76 1.31
Diluted........................................................... 1.78 .72 1.25
III Other Income (Expense), Net
Other income in 2003 of $18,394,000 includes a gain of $22,500,000 on the
settlement of the Company's claims against Southwest Gas Corporation (Southwest)
and other parties related to the Southwest litigation, which was partially
offset by $5,949,000 of related legal costs, income of $2,016,000 generated from
the sale and/or rental of gas-fired equipment and appliances by various
operating subsidiaries and $567,000 of realized gains on the sale of a portion
of Southern Union's holdings in Capstone Turbine Corporation (Capstone).
Other income in 2002 of $14,278,000 includes gains of $17,166,000 generated
through the settlement of several interest rate swaps, the recognition of
$6,204,000 in previously recorded deferred income related to financial
derivative energy trading activity of a former subsidiary, a gain of $4,653,000
realized through the sale of marketing contracts held by PG Energy Services
Inc., income of $2,234,000 generated from the sale and/or rental of gas-fired
equipment and appliances by various operating subsidiaries, a gain of $1,200,000
realized through the sale of the propane assets of PG Energy Services Inc.,
$1,004,000 of realized gains on the sale of a portion of Southern Union's
holdings in Capstone, and power generation and sales income of $971,000
primarily from PEI Power Corporation. These items were partially offset by a
non-cash charge of $10,380,000 to reserve for the impairment of the Company's
investment in a technology company, $9,100,000 of legal costs associated with
ongoing litigation from the unsuccessful acquisition of Southwest, and a
$1,500,000 loss on the sale of the Florida Operations.
Other income of $81,401,000 in 2001 included realized gains on the sale of
Capstone of $74,582,000, a $13,532,000 gain on the sale of non-core real estate
and $6,838,000 of interest and dividend income. These items were partially
offset by $12,855,000 of legal costs associated with Southwest.
IV Cash Flow Information
The Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents. Short-term investments are highly
liquid investments with maturities of more than three months when purchased, and
are carried at cost, which approximates market. The Company places its temporary
cash investments with a high credit quality financial institution which, in
turn, invests the temporary funds in a variety of high-quality short-term
financial securities.
Under the Company's cash management system, checks issued but not presented to
banks frequently result in overdraft balances for accounting purposes and are
classified in accounts payable in the consolidated balance sheet.
V Earnings Per Share
The following table summarizes the Company's basic and diluted earnings per
share calculations for 2003, 2002, and 2001:
Year Ended June 30,
2003 2002 2001
------------- ------------- -------------
Net earnings from continuing operations ................................. $ 43,669 $ 1,520 $ 40,159
Net earnings from discontinued operations................................ 32,520 18,104 16,524
Cumulative effect of change in accounting principle, net of tax.......... -- -- 602
------------- ------------- -------------
Net earnings available for common stock.................................. $ 76,189 $ 19,624 $ 57,285
============= ============= =============
Weighted average shares outstanding -- basic............................. 57,176,843 56,060,425 56,893,218
============= ============= =============
Weighted average shares outstanding -- diluted........................... 59,017,861 59,132,567 60,081,146
============= ============= =============
Basic earnings per share:
Net earnings from continuing operations.............................. $ 0.76 $ 0.03 $ 0.71
Net earnings from discontinued operations............................ 0.57 0.32 0.29
Cumulative effect of change in accounting principle, net of tax...... -- -- 0.01
------------- ------------- -------------
Net earnings available for common stock.............................. $ 1.33 $ 0.35 $ 1.01
============= ============= =============
Diluted earnings per share:
Net earnings from continuing operations.............................. $ 0.74 $ 0.03 $ 0.67
Net earnings from discontinued operations............................ 0.55 0.30 0.27
Cumulative effect of change in accounting principle, net of tax...... -- -- 0.01
------------- ------------- -------------
Net earnings available for common stock.............................. $ 1.29 $ 0.33 $ 0.95
============= ============= =============
During the three-year period ended June 30, 2003, no adjustments were required
in net earnings available for common stock for the earnings per share
calculations. Diluted earnings per share include average shares outstanding as
well as common stock equivalents from stock options and warrants. Common stock
equivalents were 637,676, 1,788,491 and 2,003,946 for the years ended June 30,
2003, 2002 and 2001, respectively. During 2003, the Company repurchased 156,340
shares of its common stock outstanding at a price of $13.95 per share. These
repurchases occurred in private off-market large-block transactions.
Stock options to purchase 2,197,765, shares of common stock were outstanding
during the year ended June 30, 2003, but were not included in the computation of
diluted earnings per share because the options' exercise price was greater than
the average market price of the common shares during the respective period.
There were no "antidilutive" options outstanding for the same period in 2002 and
2001. At June 30, 2003, 1,061,656 shares of common stock were held by various
rabbi trusts for certain of the Company's benefit plans and 105,710 shares were
held in a rabbi trust for certain employees who deferred receipt of Company
shares for stock options exercised. From time to time, the Company's benefit
plans may purchase shares of Southern Union common stock subject to regular
restrictions.
VI Property, Plant and Equipment
Plant. Plant in service and construction work in progress are stated at cost net
of contributions in aid of construction and includes intangible assets and
related amortization. The Company capitalizes all construction-related direct
labor costs, as well as indirect construction costs. The cost of replacements
and betterments that extend the useful life of property, plant and equipment is
also capitalized. The cost of additions includes an allowance for funds used
during construction and applicable overhead charges. Gain or loss is recognized
upon the disposition of significant properties and other property constituting
operating units. The Company capitalizes the cost of significant
internally-developed computer software systems. See Note XIII -- Debt and
Capital Lease.
June 30,
2003 2002
------------- -------------
Distribution plant............................. $ 1,611,098 $ 1,551,459
Transmission plant............................. 1,238,972 --
General plant.................................. 462,730 161,054
Underground storage plant...................... 236,639 --
Gathering plant................................ 56,076 --
Other.......................................... 107,444 56,012
------------ -------------
Total plant............................... 3,712,959 1,768,525
Less contributions in aid of construction...... (2,418) (1,176)
------------- -------------
Plant in service.......................... 3,710,541 1,767,349
Construction work in progress.................. 75,484 6,535
------------- -------------
3,786,025 1,773,884
Less accumulated depreciation and amortization. (641,225) (604,114)
------------- -------------
Net property, plant and equipment......... $ 3,144,800 $ 1,169,770
============= =============
Acquisitions of rate-regulated utilities are recorded at the historical book
carrying value of utility plant. On September 28, 2000, ProvEnergy and Fall
River Gas were acquired in which historical utility plant and equipment had a
cost of $357,822,000 and $64,384,000, respectively, and accumulated depreciation
and amortization of $138,857,000 and $24,401,000, respectively. On September 20,
2000, Valley Resources was acquired in which historical utility plant and
equipment had a cost and accumulated depreciation and amortization of
$105,888,000 and $47,010,000, respectively.
On June 11, 2003, Southern Union acquired Panhandle Energy. The acquisition was
accounted for using the purchase method of accounting in accordance with
accounting principles generally accepted in the United States with the purchase
price paid by the Company being allocated to Panhandle Energy's net assets as of
the acquisition date based on preliminary estimates. The Panhandle Energy assets
acquired and liabilities assumed have been recorded in the Consolidated Balance
Sheet as of June 30, 2003 at their estimated fair value and are subject to
further assessment and adjustment pending the results of outside appraisals.
Depreciation and Amortization. Depreciation and amortization of plant is
generally computed using the straight-line method at an average straight-line
rate of approximately 3% per annum of the cost of such depreciable properties
less applicable salvage. Franchises are amortized over their respective lives.
Depreciation and amortization of other property is provided at straight-line
rates estimated to recover the costs of the properties, after allowance for
salvage, over their respective lives. Internally-developed computer software
system costs are amortized over various periods.
Depreciation of property, plant and equipment in 2003, 2002 and 2001 was
$60,642,000, $57,572,000 and $54,169,000, respectively.
VII Goodwill and Intangibles
Effective July 1, 2001, the Company adopted Goodwill and Other Intangible Assets
which was issued by the FASB in June 2001. In accordance with this Statement,
the Company has ceased amortization of goodwill. Goodwill, which was previously
classified on the Consolidated Balance Sheet as additional purchase cost
assigned to utility plant and amortized on a straight-line basis over forty
years, is now subject to at least an annual assessment for impairment by
applying a fair-value based test.
The following table reflects the Company's comparative net earnings from
continuing operations and net earnings, both before the change in accounting
principle and goodwill amortization under Goodwill and Other Intangible Assets:
Year Ended June 30,
2003 2002 2001
----------- ----------- -----------
Reported net earnings from continuing operations............................... $ 43,669 $ 1,520 $ 40,159
Goodwill amortization, net of taxes........................................ -- -- 14,992
----------- ----------- -----------
Adjusted net earnings from continuing operations............................... $ 43,669 $ 1,520 $ 55,151
=========== =========== ===========
Basic earnings per share from continuing operations:
Reported net earnings from continuing operations ........................... $ .76 $ .03 $ .71
Goodwill amortization.................................................... -- -- .26
----------- ----------- -----------
Adjusted net earnings from continuing operations............................ $ .76 $ .03 $ .97
=========== =========== ===========
Diluted earnings per share from continuing operations:
Reported net earnings from continuing operations............................ $ .74 $ .03 $ .67
Goodwill amortization.................................................... -- -- .25
----------- ----------- -----------
Adjusted net earnings from continuing operations............................ $ .74 $ .03 $ .92
=========== =========== ===========
Year Ended June 30,
2003 2002 2001
----------- ----------- -----------
Reported net earnings........................................................... $ 76,189 $ 19,624 $ 56,683
Goodwill amortization, net of taxes........................................ -- -- 17,463
----------- ----------- -----------
Adjusted net earnings.......................................................... $ 76,189 $ 19,624 $ 74,146
=========== =========== ===========
Basic earnings per share:
Reported net earnings....................................................... $ 1.33 $ .35 $ 1.00
Goodwill amortization.................................................... -- -- .31
----------- ----------- -----------
Adjusted net earnings....................................................... $ 1.33 $ .35 $ 1.31
=========== =========== ===========
Diluted earnings per share:
Reported net earnings....................................................... $ 1.29 $ .33 $ .94
Goodwill amortization.................................................... -- -- .29
----------- ----------- -----------
Adjusted net earnings....................................................... $ 1.29 $ .33 $ 1.23
=========== ============ ===========
The following displays changes in the carrying amount of goodwill:
Total
Balance as of July 1, 2001...................... $ 652,048
Impairment losses............................ (1,417)
Sale of subsidiaries and other operations.... (7,710)
------------
Balance as of June 30, 2002..................... 642,921
Impairment losses............................ --
Sale of subsidiaries and other operations.... --
------------
Balance as of June 30, 2003..................... $ 642,921
============
In connection with the Company's Cash Flow Improvement Plan announced in July
2001, the Company began the divestiture of certain non-core assets. As a result
of prices of comparable businesses for various non-core properties, a goodwill
impairment loss of $1,417,000 was recognized in depreciation and amortization on
the Consolidated Statement of Operations for the quarter ended September 30,
2001. As a result of the sale of the Florida Operations, goodwill of $7,710,000
was eliminated during the quarter ended December 31, 2001 and as a result of the
sale of the Texas Operations, goodwill of $70,469,000 (which was classified as
Assets Held for Sale in the Consolidated Balance Sheet) was eliminated during
the quarter ended March 31, 2003. As of June 30, 2003, the Distribution segment
has goodwill of $642,921,000.
On June 11, 2003, the Company completed its acquisition of Panhandle Energy.
Based on the preliminary purchase price allocations, which rely on estimates and
are subject to change based on final outside appraisal, the acquisition resulted
in no recognition of goodwill as of the acquisition date. The final appraisal
may result in some of the purchase price being allocated to goodwill. In
addition, based on the preliminary purchase price allocations which are subject
to change, the acquisition resulted in the recognition of intangible assets
relating to customer relationships of approximately $20 million as of the
acquisition date. These intangibles are currently being amortized over a period
of five years, pending final determination of estimated remaining useful life.
As of June 30, 2003, the carrying amount of these intangibles was approximately
$19.8 million and is included in Property, Plant and Equipment on the
Consolidated Balance Sheet. Amortization for fiscal 2003 was approximately
$200,000. Estimated annual amortization is expected to be approximately $4
million for each fiscal year through June 30, 2008.
VIII Deferred Charges and Deferred Credits
June 30,
2003 2002
------------- --------------
Deferred Charges
Pensions................................ $ 39,088 $ 52,481
Unamortized debt expense................ 34,209 33,897
Income taxes............................ 30,514 24,000
Retirement costs other than pensions.... 29,028 33,032
Service Line Replacement program........ 18,974 21,360
Environmental........................... 14,304 16,646
Other................................... 22,144 24,714
----------- -------------
Total Deferred Charges.............. $ 188,261 $ 206,130
=========== =============
The Company's deferred charges include regulatory assets relating to
Distribution segment operations in the aggregate amount of $84,023,000 and
$91,116,000, respectively, at June 30, 2003 and 2002, of which $50,244,000 and
$66,301,000, respectively, is being recovered through current rates. As of June
30, 2003 and 2002, the remaining recovery period associated with these assets
ranges from 6 months to 147 months and from 10 months to 159 months,
respectively. None of these regulatory assets, which primarily relate to
pensions, retirement costs other than pensions, income taxes, Year 2000 costs,
Missouri Gas Energy's Service Line Replacement program and environmental
remediation costs, are included in rate base. The Company records regulatory
assets in accordance with the FASB standard, Accounting for the Effects of
Certain Types of Regulation.
June 30,
2003 2002
------------- -----------
Deferred Credits
Pensions.................................. $ 88,016 $ 45,645
Retirement costs other than pensions...... 65,144 37,669
Environmental............................. 32,322 7,206
Cost of Removal........................... 27,286 --
Derivative liability...................... 26,151 519
Customer advances for construction........ 12,008 11,119
Self-insurance............................ 12,000 6,208
Investment tax credit..................... 5,791 6,212
Other..................................... 53,436 27,874
------------ -----------
Total Deferred Credits.............. $ 322,154 $ 142,452
============ ===========
The Company's deferred credits include regulatory liabilities relating to
Distribution segment operations in the aggregate amount of $10,084,000 and
$6,389,000, respectively, at June 30, 2003 and 2002. These regulatory
liabilities primarily relate to retirement benefits other than pensions,
environmental insurance recoveries and income taxes. The Company records
regulatory liabilities with respect to its Distribution segment operations in
accordance with the FASB Standard Accounting for the Effects of Certain Types of
Regulation.
IX Investment Securities
At June 30, 2003, the Company held securities of Capstone Turbine Corporation
(Capstone). This investment is classified as "available for sale" under the FASB
Standard Accounting for Certain Investments in Debt and Equity Securities;
accordingly, these securities are stated at fair value, with unrealized gains
and losses recorded in a separate component of common stockholders' equity.
Realized gains and losses on sales of investments, as determined on a specific
identification basis, are included in the Consolidated Statement of Operations
when incurred. As of June 30, 2003 and 2002, the Company's investment in
Capstone had a fair value of $53,000 and $1,163,000, respectively, and an
unrealized holding gain, net of tax, of $21,000 and $603,000, respectively. The
Company has classified this investment as current, as the remaining shares of
Capstone held at June 30, 2003 were sold subsequent to year-end.
At June 30, 2003 and 2002, all other securities owned by the Company are
accounted for under the cost method. The Company's other investments in
securities consist of common and preferred stock in non-public companies whose
value is not readily determinable. Realized gains and losses on sales of these
investments, as determined on a specific identification basis, are included in
the Consolidated Statement of Operations when incurred, and dividends are
recognized as income when received. Various Southern Union executive management,
Board of Directors and employees also have an equity ownership in certain of
these investments.
The Company reviews its portfolio of investment securities on a quarterly basis
to determine whether a decline in value is other than temporary. Factors that
are considered in assessing whether a decline in value is other than temporary
include, but are not limited to: earnings trends and asset quality; near term
prospects and financial condition of the issuer, including the availability and
terms of any additional financing requirements; financial condition and
prospects of the issuer's region and industry, customers and markets and
Southern Union's intent and ability to retain the investment. If Southern Union
determines that the decline in value of an investment security is other than
temporary, the Company will record a charge on its consolidated statement of
operations to reduce the carrying value of the security to its estimated fair
value.
In June 2002, Southern Union determined that the decline in value of its
investment in PointServe was other than temporary. Accordingly, the Company
recorded a non-cash charge of $10,380,000 to reduce the carrying value of this
investment to its estimated fair value. The Company recognized this valuation
adjustment to reflect significant lower private equity valuation metrics and
changes in the business outlook of PointServe. PointServe is a closely held,
privately owned company and, as such, has no published market value. The
Company's remaining investment of $4,206,000 at June 30, 2003 may be subject to
future market value risk. The Company will continue to monitor the value of its
investment and periodically assess the impact, if any, on reported earnings in
future periods.
X Stockholders' Equity
Stock Splits and Dividends. On July 31, 2003, July 15, 2002 and August 30, 2001
Southern Union distributed its annual 5% common stock dividend to stockholders
of record on July 17, 2003, July 1, 2002 and August 16, 2001, respectively. A
portion of the 5% stock dividends distributed on July 15, 2002 and August 30,
2001 was characterized as a distribution of capital due to the level of the
Company's retained earnings available for distribution as of the declaration
date. Unless otherwise stated, all per share and share data included herein have
been restated to give effect to the dividends.
Common Stock. The Company maintains its 1992 Long-Term Stock Incentive Plan
(1992 Plan) under which options to purchase 8,087,181 shares were provided to be
granted to officers and key employees at prices not less than the fair market
value on the date of grant, until July 1, 2002. The 1992 Plan allowed for the
granting of stock appreciation rights, dividend equivalents, performance shares
and restricted stock. The Company also had an incentive stock option plan (1982
Plan) that provided for the granting of 787,500 options, until December 31,
1991. Options granted under both the 1992 Plan and the 1982 Plan are exercisable
for periods of ten years from the date of grant or such lesser period as may be
designated for particular options, and become exercisable after a specified
period of time from the date of grant in cumulative annual installments. Options
typically vest 20% per year for five years but may be a lesser or greater period
as designated for a particular option grant.
In connection with the acquisition of the Pennsylvania Operations, the Company
adopted the Pennsylvania Division 1992 Stock Option Plan (Pennsylvania Option
Plan) and the Pennsylvania Division Stock Incentive Plan (Pennsylvania Incentive
Plan). Under the terms of the Pennsylvania Option Plan, a total of 437,588
shares were provided to be granted to eligible employees. Stock options awarded
under the Pennsylvania Option Plan may be either Incentive Stock Options or
Nonqualified Stock Options. Upon acquisition, individuals not electing a cash
payment equal to the difference at the date of acquisition between the option
price and the market price of the shares as to which such option related, were
converted to Southern Union options using a conversion rate that maintained the
same aggregate value and the aggregate spread of the pre-acquisition options. No
additional options will be granted under the Pennsylvania Option Plan. During
2003, 14,799 options were exercised at a weighted average exercise price of
$7.10 with 422,789 options outstanding and exercisable remaining in the plan.
Under the terms of the Pennsylvania Incentive Plan, a total of 210,126 shares
were provided to be granted to eligible employees, officers and directors.
Awards under the Pennsylvania Incentive Plan may take the form of stock options,
restricted stock, and other awards where the value of the award is based upon
the performance of the Company's stock. Upon acquisition, individuals not
electing a cash payment equal to the difference at the date of acquisition
between the option price and the market price of the shares as to which such
option related, were converted to Southern Union options using a conversion rate
that maintained the same aggregate value and the aggregate spread of the
pre-acquisition options. No additional options will be granted under the
Pennsylvania Incentive Plan.
The Company accounts for its incentive plans under the Accounting Principles
Board opinion, Accounting for Stock Issued to Employees and related
authoritative interpretations. The Company recorded no compensation expense for
2003, 2002 and 2001. During 1997, the Company adopted the FASB Standard,
Accounting for Stock-Based Compensation, for footnote disclosure purposes only.
Had compensation cost for these incentive plans been determined consistent with
this Statement, the Company's net earnings from continuing operations and
diluted earnings per share would have been $42,296,000 and $.72 respectively, in
2003, $567,000 and $.01, respectively, in 2002 and $38,559,000 and $.64,
respectively, in 2001. Had compensation cost for these incentive plans been
determined consistent with this Statement, the Company's net earnings available
for common stock and diluted earnings per share would have been $75,123,000 and
$1.27 respectively, in 2003, $17,877,000 and $.30, respectively, in 2002 and
$55,043,000 and $.93, respectively, in 2001. Because this Statement has not been
applied to options granted prior to July 1, 1995, the resulting pro forma
compensation cost may not be representative of that to be expected in future
years.
The fair value of each option is estimated on the date of grant using the
Black-Scholes option-pricing model with the following assumptions used for
grants in 2002 and 2001, respectively: dividend yield of nil for all years;
volatility of 33.5% in 2002 and 27.5% for 2001; risk-free interest rate of 3.75%
in 2002, and 5% in 2001; and expected life outstanding of 7 years for 2002 and
5.5 years for 2001. The weighted average fair value of options granted at fair
market value at their grant date during 2002 and 2001 were $6.92 and $6.45,
respectively. There were no options granted above fair market value at the grant
date during 2002 and 2001. No options were granted in 2003.
The following table provides information on stock options granted, exercised,
canceled and outstanding under the 1992 Plan and the 1982 Plan for the past
three years:
1992 Plan 1982 Plan
------------------------------ ------------------------------
Weighted Weighted
Shares Under Average Shares Under Average
Option Exercise Price Option Exercise Price
Outstanding July 1, 2000........................... 3,972,122 $ 10.83 142,137 $ 2.50
Granted ..................................... 886,288 16.16 -- --
Exercised..................................... (94,646) 8.04 (142,137) 2.50
Canceled ..................................... (42,177) 14.13 -- --
------------- -----------
Outstanding June 30, 2001.......................... 4,721,587 11.85 -- --
===========
Granted ..................................... 71,666 14.52
Exercised..................................... (971,949) 10.02
Canceled ..................................... (179,863) 15.17
-------------
Outstanding June 30, 2002.......................... 3,641,441 12.23
Granted ..................................... -- --
Exercised..................................... (631,411) 4.88
Canceled ..................................... (176,342) 15.39
-------------
Outstanding June 30, 2003.......................... 2,833,688 13.67
=============
The following table summarizes information about stock options outstanding under
the 1992 Plan at June 30, 2003:
Options Outstanding Options Exercisable
------------------------------------------------------------------------------- ----------------------------------
Weighted
Average Weighted Number
Range of Number of Remaining Average of Weighted Average
Exercise Prices Options Contractual Life Exercise Price Options Exercise Price
$ 0.00 - $ 5.99 122,965 .8 years $ 5.68 122,965 $ 5.68
6.00 - 9.99 148,203 2.4 years 7.09 105,781 7.10
10.00 - 10.99 325,988 4.0 years 10.69 325,988 10.69
11.00 - 11.99 33,060 3.6 years 11.07 33,060 11.07
12.00 - 13.99 619,749 5.3 years 13.92 578,607 13.93
14.00 - 14.99 846,283 6.4 years 14.89 478,865 14.89
15.00 - 16.99 737,440 7.3 years 16.16 227,832 16.16
----------- ---------
2,833,688 1,873,098
========= =========
The shares exercisable under the various plans and corresponding weighted
average exercise price for the past three years are as follows:
Pennsylvania Pennsylvania
1992 Option Incentive
Plan Plan Plan
--------- -------------- -------------
Shares exercisable at:
June 30, 2003............................................. 1,873,098 422,789 204,292
June 30, 2002............................................. 2,043,169 437,588 201,373
June 30, 2001............................................. 2,509,900 437,588 198,454
Weighted average exercise price at:
June 30, 2003............................................. $ 12.90 $ 9.67 $ 11.13
June 30, 2002............................................. 9.99 9.58 11.08
June 30, 2001............................................. 9.19 9.58 11.02
The weighted average remaining contractual life of options outstanding under the
Pennsylvania Option Plan and the Pennsylvania Incentive Plan at June 30, 2003
was 3.0 and 4.9 years, respectively. There were no shares available for future
option grants under the 1992 Plan or the 1982 Plan at June 30, 2003.
Warrant. On February 10, 1994, Southern Union granted a warrant, which expires
on February 10, 2004, to purchase up to 122,165 shares of Common Stock at an
exercise price of $5.68 to the Company's outside legal counsel.
Retained Earnings. Under the most restrictive provisions in effect, as a result
of the sale of Senior Notes, Southern Union will not declare or pay any cash or
asset dividends on common stock (other than dividends and distributions payable
solely in shares of its common stock or in rights to acquire its common stock)
or acquire or retire any shares of Southern Union's common stock, unless no
event of default exists and the Company meets certain financial ratio
requirements. Currently, the Company is in compliance with the most restrictive
provisions in the indenture governing the Senior Notes.
2003 Equity Issuances. On June 11, 2003, the Company issued 9,500,000 shares of
common stock at the public offering price of $16.00 per share, resulting in net
proceeds to the Company, after underwriting discounts and commissions, of $15.44
per share, or $146.7 million in the aggregate. The Company granted the
underwriters a 30-day over-allotment option to purchase up to an additional
1,425,000 shares of the Company's common stock at the same price, which was
exercised on June 11, 2003, resulting in additional net proceeds to the Company
of $22.0 million.
Also on June 11, 2003, the Company issued 3,000,000 shares of common stock from
its treasury stock to CMS Energy Corporation to finance its acquisition of
Panhandle Energy. The shares were valued at $16.30 per share, or $48.9 million
in the aggregate, based on the closing price for the Company's common stock as
of June 10, 2003.
On June 11, 2003, the Company also issued 2,500,000 equity units at a public
offering price of $50 per unit, resulting in net proceeds to the Company, after
underwriting discounts and commissions, of $48.50 per unit, or $121.3 million in
the aggregate. Each equity unit consists of a stock purchase contract for the
purchase of shares of the Company's common stock and, initially, a senior note
due August 16, 2006, issued pursuant to the Company's existing Indenture. The
equity units carry a total annual coupon of 5.75% (2.75% annual face amount of
the senior notes plus 3.0% annual contract adjustment payments). Each stock
purchase contract issued as a part of the equity units carries a maximum
conversion premium of up to 22% over the $16.00 issuance price of the Company's
common shares that were sold on June 11, 2003, as discussed previously. The
present value of the equity units contract adjustment payments was initially
charged to shareholders' equity, with an offsetting credit to liabilities. The
liability is accreted over three years by interest charges to the Consolidated
Statement of Operations. Before the issuance of the Company's common stock upon
settlement of the purchase contracts, the purchase contracts will be reflected
in the Company's diluted earnings per share calculations using the treasury
stock method.
XI Derivative Instruments and Hedging Activities
The Company may from time to time enter into derivative instruments including,
but not limited to, interest rate swaps and treasury rate locks to manage its
exposure to interest rate risk.
Cash Flow Hedges. As a result of the acquisition of Panhandle Energy, the
Company is party to interest rate swap agreements with an aggregate notional
amount of $206,521,000 as of June 30, 2003 that fix the interest rate applicable
to floating rate long-term debt and which qualify for hedge accounting. As of
June 30, 2003, floating rate LIBOR-based interest payments are exchanged for
weighted fixed rate interest payments of 5.08%. Interest rate swaps are carried
on the Consolidated Balance Sheet at fair value with the unrealized gain or loss
adjusted through accumulated other comprehensive income. As such, payments or
receipts on interest rate swap agreements are recognized as adjustments to
interest expense. As of June 11, 2003 (the acquisition date) and June 30, 2003,
the fair value liability position of the swaps was $27,741,000 and $26,058,000,
respectively. As of June 30, 2003, an unrealized gain of $1,033,000, net of tax,
was included in accumulated other comprehensive income related to these swaps,
of which approximately $198,000, net of tax, is expected to be reclassified to
interest expense during the next twelve months as the hedged interest payments
occur.
The Company is also party to an interest rate swap agreement with a notional
amount of $8,199,000 and $22,015,000 as of June 30, 2003 and 2002, respectively,
that fixes the interest rate applicable to floating rate long-term debt and
which qualifies for hedge accounting. As of June 30, 2003, floating rate
LIBOR-based interest payments are exchanged for fixed rate interest payments of
5.79%. The fair value liability position of the swap was $93,000 and $519,000 as
of June 30, 2003 and 2002, respectively. As of June 30, 2003, $57,000 of
unrealized after-tax losses included in accumulated other comprehensive income
related to this swap will be reclassified to interest expense during the next
twelve months as the hedged interest payments occur.
In March and April 2003, the Company entered into a series of treasury rate
locks with an aggregate notional amount of $250,000,000 to manage its exposure
against changes in future interest payments attributable to changes in the
benchmark interest rate prior to the anticipated issuance of fixed-rate debt.
These treasury rate locks expired on June 30, 2003, resulting in a $6,862,000
after-tax loss that was recorded in accumulated other comprehensive income and
will be amortized into interest expense over the lives of the associated debt
instruments. As of June 30, 2003, approximately $846,000 of net after-tax losses
in accumulated other comprehensive income will be amortized into interest
expense during the next twelve months.
The notional amounts of the interest rate swaps are not exchanged and do not
represent exposure to credit loss. In the event of default by a counterparty,
the risk in these transactions is the cost of replacing the agreements at
current market rates.
Trading and Non-Hedging Activities. In March 2001, the Company discovered
unauthorized financial derivative energy trading activity by a non-regulated,
wholly-owned subsidiary. All unauthorized trading activity was subsequently
closed in March and April of 2001 resulting in a cumulative cash expense of
$191,000, net of taxes, and deferred income of $7,921,000 at June 30, 2001. For
the fiscal year ended June 30, 2003, the Company recorded $605,000 through other
income relating to the expiration of contracts resulting from this trading
activity, as compared to $6,204,000 recorded for the fiscal year ended June 30,
2002. The majority of the remaining deferred liability of $1,112,000 at June 30,
2003 related to these derivative instruments will be recognized as income in the
Consolidated Statement of Operations over the next two years based on the
related contracts.
XII Preferred Securities of Subsidiary Trust
On May 17, 1995, Southern Union Financing I (Subsidiary Trust), a consolidated
wholly-owned subsidiary of Southern Union, issued $100,000,000 of 9.48% Trust
Originated Preferred Securities (Preferred Securities). In connection with the
Subsidiary Trust's issuance of the Preferred Securities and the related purchase
by Southern Union of all of the Subsidiary Trust's common securities (Common
Securities), Southern Union issued to the Subsidiary Trust $103,092,800
principal amount of its 9.48% Subordinated Deferrable Interest Notes, due 2025
(Subordinated Notes). The sole assets of the Subsidiary Trust are the
Subordinated Notes. The interest and other payment dates on the Subordinated
Notes correspond to the distribution and other payment dates on the Preferred
Securities and the Common Securities. Under certain circumstances, the
Subordinated Notes may be distributed to holders of the Preferred Securities and
holders of the Common Securities in liquidation of the Subsidiary Trust. The
Subordinated Notes were redeemable at the option of the Company on or after May
17, 2000, at a redemption price of $25 per Subordinated Note plus accrued and
unpaid interest. The Preferred Securities and the Common Securities will be
redeemed on a pro rata basis to the same extent as the Subordinated Notes are
repaid, at $25 per Preferred Security and Common Security plus accumulated and
unpaid distributions. Southern Union's obligations under the Subordinated Notes
and related agreements, taken together, constitute a full and unconditional
guarantee by Southern Union of payments due on the Preferred Securities. As of
June 30, 2003, the quoted market price per Preferred Security was $25.84. As of
June 30, 2003 and 2002, 4,000,000 shares of Preferred Securities were
outstanding.
XIII Debt and Capital Lease
June 30,
2003 2002
------------- --------------
Southern Union Company
7.60% Senior Notes due 2024............................................................. $ 359,765 $ 362,515
8.25% Senior Notes due 2029............................................................. 300,000 300,000
2.75% Senior Notes due 2006............................................................. 125,000 --
Term Note, due 2005..................................................................... 211,087 350,000
8.375% First Mortgage Bonds, due 2002................................................... -- 30,000
5.62% First Mortgage Bonds, due 2003.................................................... 1,482 3,082
10.25% First Mortgage Bonds, due 2008................................................... 1,636 1,909
6.82% First Mortgage Bonds, due 2018.................................................... 14,464 14,464
9.34% First Mortgage Bonds, due 2019.................................................... 15,000 15,000
9.63% First Mortgage Bonds, due 2020.................................................... 10,000 10,000
9.44% First Mortgage Bonds, due 2020.................................................... 6,500 6,500
8.09% First Mortgage Bonds, due 2022.................................................... 12,500 12,500
8.46% First Mortgage Bonds, due 2022.................................................... 12,500 12,500
7.50% First Mortgage Bonds, due 2025.................................................... 15,000 15,000
7.99% First Mortgage Bonds, due 2026.................................................... 7,000 7,000
7.24% First Mortgage Bonds, due 2027.................................................... 6,000 6,000
6.50% First Mortgage Bonds, due 2029.................................................... 13,802 13,933
7.70% Debentures, due 2022.............................................................. 6,756 6,776
Capital lease and other, due 2003 to 2007............................................... 9,179 23,234
------------ ------------
1,127,671 1,190,413
Panhandle Energy
6.125% Senior Notes due 2004............................................................ 292,500 --
7.875% Senior Notes due 2004............................................................ 100,000 --
6.50% Senior Notes due 2009............................................................. 158,980 --
8.25% Senior Notes due 2010............................................................. 60,000 --
7.00% Senior Notes due 2029............................................................. 135,890 --
Term Loan due 2007...................................................................... 275,358 --
7.95% Debentures due 2023............................................................... 76,500 --
7.20% Debentures due 2024............................................................... 58,000 --
Net premiums on long-term debt.......................................................... 61,506 --
------------ ------------
1,218,734 --
------------ ------------
Total consolidated debt and capital lease............................................... 2,346,405 1,190,413
Less current portion................................................................ 734,752 108,203
------------ ------------
Total consolidated long-term debt and capital lease..................................... $ 1,611,653 $ 1,082,210
============ ============
The maturities of long-term debt and capital lease payments for each of the next
five years ending June 30 are: 2004 -- $734,752,000; 2005 -- $125,077,000; 2006
- -- $116,092,000; 2007 -- $365,718,000; 2008 -- $1,648,000 and thereafter
$1,003,118,000.
Each note, debenture or bond above is an obligation of Southern Union Company or
a unit of Panhandle Energy, as noted above. The Panhandle Energy Term Loan due
2007 is debt related to Panhandle's Trunkline LNG Holdings subsidiary, and is
non-recourse to other units of Panhandle Energy or Southern Union Company. The
remainder of Panhandle Energy's debt is non-recourse to Southern Union. All
debts that are listed as debt of Southern Union Company are direct obligations
of Southern Union Company, and no debt is cross-collateralized.
Debt issuance costs and premiums or discounts on the early extinguishment of
debt are accounted for in accordance with that required by its various
regulatory bodies having jurisdiction over the Company's operations. The Company
recognizes gains or losses on the early extinguishment of debt to the extent it
is provided for by its regulatory authorities, where applicable, and in some
cases such gains or losses are deferred and amortized over the term of the new
or replacement debt issues.
The 8.25% Notes and the 7.60% Senior Notes traded at $1,177 and $1,094 (per
$1,000 note), respectively on June 30, 2003, as quoted by a major brokerage
firm. The carrying amount of long-term debt at June 30, 2003 and 2002 was
$2,346,405,000 and $1,190,413,000, respectively. The fair value of long-term
debt at June 30, 2003 and 2002 was $2,408,532,000 and $1,174,647,000,
respectively.
The Company is not party to any lending agreement that would accelerate the
maturity date of any obligation due to a failure to maintain any specific credit
rating. Certain covenants exist in certain of the Company's debt agreements that
require the Company to maintain a certain level of net worth, to meet certain
debt to total capitalization ratios, and to meet certain ratios of earnings
before depreciations, interest and taxes to cash interest expense. A failure by
the Company to satisfy any such covenant would be considered an event of default
under the associated debt, which could become immediately due and payable if the
Company did not cure such default within any permitted cure period or if the
Company did not obtain amendments, consents or waivers from its lenders with
respect to such covenants.
Term Note. On August 28, 2000 the Company entered into the Term Note to fund (i)
the cash portion of the consideration to be paid to the Fall River Gas'
stockholders; (ii) the all cash consideration to be paid to the ProvEnergy and
Valley Resources stockholders, (iii) repayment of approximately $50,000,000 of
long- and short-term debt assumed in the mergers, and (iv) all related
acquisition costs. The Term Note, which initially expired on August 27, 2001,
was extended through August 26, 2002. On July 16, 2002, the Company repaid the
Term Note with the proceeds from the issuance of a $311,087,000 Term Note dated
July 15, 2002 (the 2002 Term Note) and borrowings under the Company's lines of
credit. The 2002 Term Note is held by a syndicate of sixteen banks, led by
JPMorgan Chase Bank, as Agent. Eleven of the sixteen banks were also among the
lenders of the Term Note, and they are also lenders under at least one of the
Facilities. The 2002 Term Note carries a variable interest rate that is tied to
either the LIBOR or prime interest rates at the Company's option. The interest
rate spread over the LIBOR rate varies with the credit rating of the Senior
Notes by S&P and Moody's, and is currently LIBOR plus 105 basis points. As of
June 30, 2003, a balance of $211,087,000 was outstanding under this 2002 Term
Note. The 2002 Term Note requires semi-annual principal repayments on February
15th and August 15th of each year, with payments of $25,000,000 each being due
August 15, 2003, February 15, 2004, and August 15, 2004 and payments of
$35,000,000 each being due February 15, 2005 and August 15, 2005. The remaining
principal amount of $66,087,000 is due August 26, 2005. No additional draws can
be made on the Term Note.
Additional Debt. In connection with the Panhandle Energy acquisition, the
Company added a principal amount $1.159 billion in debt, which had a fair value
of $1.220 billion as of June 30, 2003. The debt included senior notes and
debentures with interest rates ranging from 6.125% to 8.25% and floating rate
debt totaling $275.4 million, all of which is non-recourse to Southern Union.
In connection with the acquisition of ProvEnergy, the Company assumed
$86,916,000 of First Mortgage Bonds bearing interest between
5.62% and 10.25%. In connection with the acquisition of Fall River Gas, the
Company assumed $19,500,000 of First Mortgage Bonds bearing interest between
7.24% and 9.44%. In connection with the acquisition of Valley Resources, the
Company assumed $6,905,000 of 7.70% Debentures.
In July 2003, Panhandle Energy announced a tender offer for any and all of the
$747 million outstanding principal amount of five of its series of senior notes
outstanding at that point in time (the Panhandle Tender Offer) and
also called for redemption all of the outstanding $135 million principal amount
of its two series of debentures that were outstanding (the Panhandle Calls).
Panhandle Energy repurchased approximately $378 million of the principal amount
of its outstanding debt through the Panhandle Tender Offer for total
consideration of approximately $396 million plus accrued interest through the
purchase date. Panhandle Energy also redeemed its approximately $135 million of
debentures for total consideration of $139 million, plus accrued interest
through the redemption dates. As a result of these transactions, the Company has
recorded a pre-tax gain on the extinguishment of debt of approximately $6.7
million in August 2003. In August 2003, Panhandle Energy issued $550 million of
new senior notes (five and ten year) principally to refinance the repurchased
notes and redeemed debentures.
Capital Lease. The Company completed the installation of an Automated Meter
Reading (AMR) system at Missouri Gas Energy during the first quarter of fiscal
year 1999. The installation of the AMR system involved an investment of
approximately $30,000,000 which is accounted for as a capital lease obligation.
As of June 30, 2003, the capital lease obligation outstanding was $8,793,000
with a fixed rate of 5.79%. This system has significantly improved meter reading
accuracy and timeliness and provided electronic accessibility to meters in
residential customers' basements, thereby assisting in the reduction of the
number of estimated bills. Depreciation on the AMR system is provided at an
average straight-line rate of approximately 5% per annum of the cost of such
property.
Credit Facilities. On April 3, 2003, the Company entered into a short-term
credit facility in the amount of $140,000,000 (the Short Term Facility), that
matures April 1, 2004. The Short-Term Facility was increased to $150,000,000 as
of September 25, 2003. Also on April 3, 2003, the Company amended the terms and
conditions of its $225,000,000 long-term credit facility (the Long-Term
Facility), which expires on May 29, 2004. The Company has additional
availability under uncommitted line of credit facilities (Uncommitted
Facilities) with various banks. Borrowings under the facilities are available
for Southern Union's working capital, letter of credit requirements and other
general corporate purposes. The Short-Term Facility and the Long-Term Facility
(together, the Facilities) are subject to a commitment fee based on the rating
of the Senior Notes. As of June 30, 2003, the commitment fees were an annualized
0.15% on the Facilities. The interest rate on borrowings on the Facilities is
calculated based upon a formula using the LIBOR or prime interest rates. The
average interest rate under the Facilities was 2.4% for the year ended June 30,
2003 and 3.2% for the year ended June 30, 2002. A $251,500,000 and $131,800,000
balance was outstanding under the Facilities at June 30, 2003 and 2002,
respectively. A balance of $314,000,000 was outstanding under the Facilities at
September 15, 2003.
XIV Employee Benefits
Pension and Other Post-Retirement Benefits. The Company adopted in 1999,
Employers Disclosures About Pensions and Other Post-Retirement Benefits, a FASB
Standard which changed the Company's reporting requirements for its pension and
post-retirement benefit plans.
The Company maintains eight trusteed non-contributory defined benefit retirement
plans (Plans) which cover substantially all employees, except Panhandle Energy
employees (see Panhandle Energy, below). The Company funds the Plans' cost in
accordance with federal regulations, not to exceed the amounts deductible for
income tax purposes. The Plans' assets are invested in cash, government
securities, corporate bonds and stock, and various funds. The Company also has
two supplemental non-contributory retirement plans for certain executive
employees and other post-retirement benefit plans for its employees.
Post-retirement medical and other benefit liabilities are accrued on an
actuarial basis during the years an employee provides services. The following
table represents a reconciliation of the Company's retirement and other
post-retirement benefit plans at June 30, 2003 and 2002.
Pension Benefits Post-Retirement Benefits
---------------------------- ---------------------------
2003 2002 2003 2002
------------- ------------ ------------ ------------
Change in Benefit Obligation
Benefit obligation at beginning of year.................. $ 317,012 $ 302,454 $ 76,596 $ 70,061
Service cost............................................. 5,655 5,707 1,177 1,136
Interest cost............................................ 22,899 22,570 5,579 5,362
Benefits paid............................................ (20,046) (21,695) (6,676) (4,889)
Actuarial loss........................................... 26,350 1,993 13,357 2,413
Plan amendments.......................................... 1,095 (1,362) 311 22
Curtailments............................................. -- 313 -- 1,182
Special termination benefits............................. -- 8,957 -- 1,309
Settlement recognition................................... (2,105) (1,925) -- --
------------- ------------ ------------ ------------
Benefit obligation at end of year........................ $ 350,860 $ 317,012 $ 90,344 $ 76,596
============= ============ ============ ============
Change in Plan Assets
Fair value of plan assets at beginning of year........... $ 284,911 $ 304,580 $ 22,408 $ 20,309
Return on plan assets.................................... (30,900) 1,560 -- 489
Employer contributions................................... 5,516 2,380 5,572 6,499
Benefits paid............................................ (20,046) (21,695) (6,675) (4,889)
Settlement recognition................................... (2,105) (1,914) -- --
------------- ------------ ------------ ------------
Fair value of plan assets at end of year................. $ 237,376 $ 284,911 $ 21,305 $ 22,408
============= ============ ============ ============
Pension Benefits Post-Retirement Benefits
---------------------------- ---------------------------
2003 2002 2003 2002
------------- ------------ ------------ ------------
Funded Status
Funded status at end of year............................. $ (113,484) $ (32,101) $ (69,039) $ (54,188)
Unrecognized net actuarial loss.......................... 136,560 56,167 21,511 5,985
Unrecognized prior service cost.......................... 7,179 6,875 130 (244)
------------- ------------ ------------ ------------
Net asset (liability) recognized......................... $ 30,255 $ 30,941 $ (47,398) $ (48,447)
============= ============ ============ ============
Amounts Recognized in the Consolidated Balance Sheet
Prepaid benefit cost..................................... $ 27,174 $ 38,439 $ -- $ --
Accrued benefit liability................................ (91,669) (27,240) (47,398) (48,447)
Intangible asset......................................... 3,671 2,779 -- --
Accumulated other comprehensive loss..................... 91,079 16,963 -- --
------------- ------------ ------------ ------------
Net asset (liability) recognized......................... $ 30,255 $ 30,941 $ (47,398) $ (48,447)
============= ============ ============ ============
The projected benefit obligation, accumulated benefit obligation and fair value
of plan assets for pension plans with accumulated benefit obligations in excess
of plan assets as of June 30, 2003 were $324,504,000, $293,199,000, and
$197,911,000, respectively, and for those same plans were $196,333,000,
$179,915,000, and $151,403,000 as of June 30, 2002.
The accumulated post-retirement benefit obligation and fair value of plan assets
for post-retirement benefit plans with accumulated post-retirement benefit
obligations in excess of fair value of plan assets as of June 30, 2003 were
$90,344,000 and $21,305,000 respectively, and for those same plans were
$76,596,000 and $22,408,000 respectively as of June 30, 2002.
An additional minimum pension liability of $75,008,000 and $6,851,000 was
recorded as of June 30, 2003 and 2002, respectively, as a result of the decrease
in the discount rate in 2003, decreases in the fair value of plan assets due to
volatility in the stock markets and increases in liabilities due to early
retirement programs.
The weighted-average assumptions used for the year ended June 30, 2003, 2002 and
2001 were:
Pension Benefits Post-Retirement Benefits
-------------------------------------- --------------------------------------
2003 2002 2001 2003 2002 2001
---------- ----------- ----------- ---------- ---------- ----------
Discount rate...........................
Beginning of year.................. 7.50% 7.50% 8.00% 7.50% 7.50% 7.50%
End of year............................. 6.50% 7.50% 7.50% 6.50% 7.50% 7.50%
Expected return on assets -
tax exempt accounts............... 9.00% 9.00% 9.00% 9.00% 9.00% 9.00%
Expected return on assets - taxable accounts N/A N/A N/A 5.50% 5.50% 5.40%
Rate of compensation increase (average). 4.00% 5.00% 5.00% N/A N/A N/A
Health care cost trend rate............. N/A N/A N/A 13.00% 12.00% 12.00%
Net periodic benefit cost for the year ended June 30, 2003, 2002 and 2001
includes the following components:
Pension Benefits Post-Retirement Benefits
-------------------------------------- --------------------------------------
2003 2002 2001 2003 2002 2001
---------- ----------- ----------- ---------- ---------- ----------
Service cost............................ $ 5,655 $ 5,707 $ 3,791 $ 1,177 $ 1,136 $ 708
Interest cost........................... 22,899 22,570 17,587 5,579 5,362 4,276
Expected return on plan assets.......... (24,749) (25,868) (21,957) (1,734) (1,701) (1,010)
Amortization of prior service cost...... 790 984 1,769 (65) (100) (114)
Recognized actuarial gain (loss)........ 2,433 194 (2,482) (234) (737) (982)
Curtailment............................. -- 8,905 -- -- 1,200 --
Special termination benefits............ -- 8,957 -- -- 1,309 --
Settlement recognition.................. (558) (457) 611 -- -- (788)
---------- ----------- ----------- ---------- ---------- ----------
Net periodic pension cost (benefit)..... $ 6,470 $ 20,992 $ (681) $ 4,723 $ 6,469 $ 2,090
========== =========== =========== ========== ========== ==========
Curtailment and special termination benefit charges were recognized during 2002
in connection with the Company's corporate reorganization and restructuring
initiatives (see Corporate Restructuring). The Company has deferred, as a
regulatory asset, certain of these charges that have historically been
recoverable in rates.
The assumed rate of compensation increase of 4.00% (average) used in measuring
the accumulated post-retirement benefit obligation during 2003 consisted of a
rate of 4.00% for the plans of Missouri Gas Energy, PG Energy and ProvEnergy,
and rates of 4.50% and 3.75%, respectively, for the plans of Valley Resources,
and Fall River Gas.
The assumed health care cost trend rate used in measuring the accumulated
post-retirement benefit obligation was 13% during 2003. This rate was assumed to
decrease gradually each year to a rate of 5.0% in 2011 and remain at that level
thereafter. The assumed health care cost trend rate used in measuring the
accumulated post-retirement benefit obligation was 12% during 2002. This rate
was assumed to decrease gradually each year to a rate of 6.0% in 2006 and remain
at that level thereafter.
Amortization of unrecognized actuarial gains and losses for Missouri Gas Energy
plans were recognized using a rolling five-year average gain or loss position
with a five-year amortization period pursuant to a stipulation agreement with
the Missouri Public Service Commission (MPSC). The Company has deferred, as a
regulatory asset, the difference in amortization of unrecognized actuarial
losses recognized under such method and that amount determined and reported as
net periodic pension cost in accordance with the applicable FASB Standards.
Effect of assumed health care trend rate changes on health care plans:
One Percentage Point One Percentage Point
Increase in Health Care Decrease in Health Care
Trend Rate Trend Rate
Effect on total service and interest cost components.............. $ 284 $ (247)
Effect on post-retirement benefit obligation...................... 3,028 (2,671)
The Company's eight qualified defined benefit retirement Plans cover: (i) those
employees who are employed by Missouri Gas Energy; (ii) those employees who are
employed by the Pennsylvania Operations; (iii) union employees of ProvEnergy;
(iv) non-union employees of ProvEnergy; (v) union employees of Valley Resources;
(vi) non-union employees of Valley Resources; (vii) union employees of Fall
River Gas; and (viii) non-union employees of Fall River Gas. On December 31,
1998, the Plan covering (i) above, exclusive of Missouri Gas Energy's union
employees, was converted from the traditional defined benefit Plan with benefits
based on years of service and final average compensation to a cash balance
defined benefit plan in which an account is maintained for each employee.
The initial value of the account was determined as the actuarial present value
(as defined in the Plan) of the benefit accrued at transition (December 31,
1998) under the pre-existing traditional defined benefit plan. Future
contribution credits to the accounts are based on a percentage of future
compensation, which varies by individual. Interest credits to the accounts are
based on 30-year Treasury Securities rates.
Defined Contribution Plan. The Company provides a Savings Plan available to all
employees. For Missouri Gas Energy non-union and corporate employees, the
Company contributes 50% and 75% of the first 5% and second 5%, respectively, of
the participant's compensation paid into the Savings Plan. For Missouri Gas
Energy union employees, the Company contributes 50% of the first 7% of the
participant's compensation paid into the Savings Plan. In Pennsylvania, the
Company contributes 50% of the first 4% of the participant's compensation paid
into the Savings Plan. For New England Gas Company's Fall River operations, the
Company contributes 100% of the first 4% of non-union employee compensation paid
into the Savings Plan and 100% of the first 3% of union employee compensation
paid into the Savings Plan. For New England Gas Company's Providence operations,
the Company contributes 50% of the first 10% of the participant's compensation
paid into the Savings Plan. For New England Gas Company's Cumberland operations
(formerly Valley Resources), the Company contributes 50% of the first 4% of the
participant's compensation paid into the Savings Plan. Company contributions are
100% vested after five years of continuous service for all plans other than
Missouri Gas Energy union and New England Gas Company's Cumberland operations,
which are 100% vested after six years of continuous service. Company
contributions to the plan during 2003, 2002 and 2001 were $2,251,000, $2,722,000
and $2,673,000, respectively.
Effective January 1, 1999 the Company amended its defined contribution plan to
provide contributions for certain employees who were employed as of December 31,
1998. These contributions were designed to replace certain benefits previously
provided under defined benefit plans. Employer contributions to these separate
accounts, referred to as Retirement Power Accounts, within the defined
contribution plan were determined based on the employee's age plus years of
service plus accumulated sick leave as of December 31, 1998. The contribution
amounts are determined as a percentage of compensation and range from 3.5% to
8.5%. Company contributions to Retirement Power Accounts during 2003, 2002 and
2001 were $1,469,000, $826,000 and $983,000, respectively.
Panhandle Energy. Following the June 11, 2003 acquisition by Southern Union,
Panhandle Energy instituted certain retiree health care and life insurance
benefits under other post employment benefits (OPEB) and added certain benefits
to substantially all of its employees under a defined contribution 401(k) plan
(Savings Plan). Under the Savings Plan, Panhandle Energy provides a matching
contribution of 50% of the first 4% of the participant's compensation paid into
the Savings Plan. In addition, Panhandle Energy makes additional contributions
ranging from 4% to 6% of the employee's eligible pay, depending on the
employee's age and years of service. The adoption of the OPEB plan resulted in
the recording of a $43 million liability as of June 11, 2003 and Panhandle
Energy continues to fund the plan at approximately $8 million per year. Since
Panhandle Energy retirement eligible active employees have primary coverage
through a benefit they are eligible to receive from the former owner of
Panhandle Energy, no liability is currently recognized for these employees under
the OPEB plan.
Following its acquisition by the Company in June 2003, Panhandle Energy
initiated a workforce reduction initiative designed to reduce the workforce by
approximately 5 percent. The workforce reduction initiative is expected to be
fully implemented by September 30, 2003.
Corporate Restructuring. In August 2001, the Company implemented a corporate
reorganization and restructuring which was initially announced in July 2001 as
part of a Cash Flow Improvement Plan designed to increase annualized pre-tax
cash flow from operations by at least $50 million by the end of fiscal year
2002. Actions taken included (i) the offering of voluntary Early Retirement
Programs (ERPs) in certain of its operating divisions and (ii) a limited
reduction in force (RIF) within its corporate offices. ERPs, providing for
increased benefits for those electing retirement, were offered to approximately
325 eligible employees across the Company's operating divisions, with
approximately 59% of such eligible employees accepting. The RIF was limited
solely to certain corporate employees in the Company's Austin and Kansas City
offices where forty-eight employees were offered severance packages. In
connection with the corporate reorganization and restructuring efforts, the
Company recorded a charge of $30,553,000 during the quarter ended September 30,
2001. This charge was reduced by $1,394,000 during the quarter ended June 30,
2002, as a result of the Company's ability to negotiate more favorable terms on
certain of its restructuring liabilities. The charge included: $16.4 million of
voluntary and accepted ERP's, primarily through enhanced benefit plan
obligations, and other employee benefit plan obligations; $6.8 million of RIF
within the corporate offices and related employee separation benefits; and $6.0
million connected with various business realignment and restructuring
initiatives. All restructuring actions were completed as of June 30, 2002.
Common Stock Held in Trust. From time to time, the Company purchases outstanding
shares of common stock of Southern Union to fund certain Company employee
stock-based compensation plans. At June 30, 2003 and 2002, 955,946 and 989,143
shares, respectively, of common stock were held by various rabbi trusts for
certain of those Company's benefit plans. Effective March 22, 2001, the Company
amended a benefit plan holding common stock in a rabbi trust eliminating the
non-cash income and expense volatility associated with the accounting treatment
for such plan. During 2002 and 2001, certain employees deferred receipt of
Company shares for stock options exercised. At June 30, 2003, 105,710 shares
were held in a rabbi trust for these employees.
XV Taxes on Income
Year Ended June 30,
2003 2002 2001
----------- ----------- ---------
Current:
Federal..................................................................... $ (15,258) $ (8,848) $ 15,936
State....................................................................... (6,563) (1,391) 545
---------- ---------- ---------
(21,821) (10,239) 16,481
---------- ---------- ---------
Deferred:
Federal.................................................................... 38,926 13,050 13,249
State...................................................................... 7,168 600 369
---------- ---------- ---------
46,094 13,650 13,618
---------- ---------- ---------
Total continuing operations provision........................................... $ 24,273 $ 3,411 $ 30,099
========== ========== =========
Deferred credits and other liabilities from continuing operations also include
$5,791,000 and $6,212,000 of unamortized deferred investment tax credit as of
June 30, 2003 and 2002.
Deferred income taxes result from temporary differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities.
June 30,
2003 2002
------------ ------------
Deferred tax assets:
Estimated alternative minimum tax credit................................................ $ 6,263 $ 3,764
Insurance accruals...................................................................... 2,028 1,995
Bad debt reserves....................................................................... 4,096 4,229
Post-retirement benefits................................................................ 1,078 1,506
Restructuring charges................................................................... -- 8,287
Minimum pension liability............................................................... 35,159 8,799
Other................................................................................... 10,313 8,655
------------ ------------
Total deferred tax assets........................................................... 58,937 37,235
------------ ------------
Deferred tax liabilities:
Property, plant and equipment........................................................... (261,100) (178,089)
Unamortized debt expense................................................................ (5,455) (5,489)
Regulatory liability.................................................................... (14,483) (14,746)
Other................................................................................... (56,510) (51,334)
------------ ------------
Total deferred tax liabilities...................................................... (337,548) (249,658)
------------ ------------
Net deferred tax liability .................................................................. (278,611) (212,423)
Less current tax assets...................................................................... 4,096 4,229
------------ ------------
Accumulated deferred income taxes............................................................ $ (282,707) $ (216,652)
============ ============
The Company accounts for income taxes utilizing the liability method which bases
the amounts of current and future tax assets and liabilities on events
recognized in the financial statements and on income tax laws and rates existing
at the time the temporary differences are expected to reverse.
Year Ended June 30,
2003 2002 2001
----------- ---------- ---------
Computed statutory tax expense from continuing operations at 35%................ $ 23,780 $ 1,726 $ 24,590
Changes in taxes resulting from:
State income taxes, net of federal income tax benefit...................... 326 695 670
Amortization/write-down of goodwill........................................ -- 3,113 4,770
Internal Revenue Service audit settlement.................................. -- (1,570) --
Investment Tax Credit amortization......................................... (421) (608) --
Other...................................................................... 588 55 69
----------- ---------- ---------
Actual tax expense from continuing operations................................... $ 24,273 $ 3,411 $ 30,099
=========== ========== =========
XVI Regulation and Rates
Missouri Gas Energy. On July 5, 2001, the MPSC issued an order approving a
unanimous settlement of Missouri Gas Energy's rate request. The settlement
provides for an annual $9,892,000 base rate increase, as well as $1,081,000 in
added revenue from new and revised service charges. The majority of the rate
increase is recovered through increased customer service charges to gas sales
service customers. New rates became effective August 6, 2001, two months before
the statutory deadline for resolving the case. The approved settlement resulted
in the dismissal of all pending judicial reviews of prior rate cases. The
settlement also provided for the development of a two-year experimental
low-income program that will help certain customers in the Joplin area pay their
natural gas bills.
The approval of the January 31, 1994 acquisition of the Missouri properties by
the MPSC was subject to the terms of a stipulation and settlement agreement,
which, among other things, requires Missouri Gas Energy to reduce rate base by
$30,000,000 (amortized over a ten-year period on a straight-line basis) to
compensate rate payers for rate base reductions that were eliminated as a result
of the acquisition.
New England Gas Company. On May 22, 2003, the RIPUC approved a Settlement Offer
filed by New England Gas Company related to the final calculation of earnings
sharing for the 21-month period covered by the Energize Rhode Island Extension
settlement agreement. This calculation generated excess revenues of $5,227,000.
The net result of the excess revenues and the Energize Rhode Island weather
mitigation and non-firm margin sharing provisions is the crediting to customers
of $949,000 over a twelve-month period starting July 1, 2003.
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.
PG Energy. In December 2000, the Pennsylvania Public Utility Commission approved
a settlement agreement that provided for a rate increase designed to produce
$10,800,000 of additional annual revenue. The new rates became effective on
January 1, 2001.
Panhandle Energy. In December 2001, Trunkline LNG filed with the FERC a
certificate application to expand the Lake Charles LNG facility to approximately
1.2 billion cubic feet per day of sendout capacity versus the current capacity
of 630 million cubic feet per day. BG LNG Services has contract rights for the
570 million cubic feet per day of additional capacity. In December 2002, the
FERC issued an order approving the expansion and in March 2003,
Trunkline LNG received FERC authorization to commence construction. On April 17,
2003, Trunkline LNG filed to amend certain items in the previously mentioned
FERC approvals which will not affect the authorized additional storage capacity
and daily sendout capability and confirms the revised in-service date of
January 1, 2006.
XVII Leases
The Company leases certain facilities, equipment and office space under
cancelable and noncancelable operating leases. The minimum annual rentals under
operating leases for the next five years ending June 30 are as follows:
2004--$18,614,000; 2005--$16,001,000; 2006--$14,345,000; 2007--$7,193,000;
2008--$6,329,000 and thereafter $5,038,000. Rental expense from continuing
operations was $4,342,000, $5,759,000 and $7,652,000 for the years ended June
30, 2003, 2002 and 2001, respectively.
XVIII Commitments and Contingencies
Environmental
The Company is subject to federal, state and local laws and regulations relating
to the protection of the environment. These evolving laws and regulations may
require expenditures over a long period of time to control environmental
impacts. The Company has established procedures for the on-going evaluation of
its operations to identify potential environmental exposures and assure
compliance with regulatory policies and procedures.
The Company follows the provisions of an American Institute of Certified Public
Accountants Statement of Position, Environmental Remediation Liabilities, for
recognition, measurement, display and disclosure of environmental remediation
liabilities.
In certain of the Company's jurisdictions the Company is allowed to recover
environmental remediation expenditures through rates. Although significant
charges to earnings could be required prior to rate recovery for jurisdictions
that do not have rate recovery mechanisms, management does not believe that
environmental expenditures will have a material adverse effect on the Company's
financial position, results of operations or cash flows.
MGP Sites -- The Company is investigating the possibility that the Company or
predecessor companies may have been associated with Manufactured Gas Plant (MGP)
sites in its former gas distribution service territories, principally in Texas,
Arizona and New Mexico, and present gas distribution service territories in
Missouri, Pennsylvania, Massachusetts and Rhode Island. At the present time, the
Company is aware of certain MGP sites in these areas and is investigating those
and certain other locations. While the Company's evaluation of these Texas,
Missouri, Arizona, New Mexico, Pennsylvania, Massachusetts and Rhode Island MGP
sites is in its preliminary stages, it is likely that some compliance costs may
be identified and become subject to reasonable quantification. Within the
Company's gas distribution service territories certain MGP sites are currently
the subject of governmental actions. These sites are as follows:
Missouri Sites. In a letter dated May 10, 1999, the Missouri Department of
Natural Resources ("MDNR") sent notice of a planned Site Inspection/Removal Site
Evaluation of the Kansas City Coal Gas Former MGP site. This site (comprised of
two adjacent MGP operations previously owned by two separate companies and
hereafter referred to as Station A and Station B) is located at East 1st Street
and Campbell in Kansas City, Missouri and is owned by Missouri Gas Energy (MGE).
During July 1999, the Company submitted the two sites to MDNR's Voluntary
Cleanup Program (VCP) and, subsequently, performed environmental assessments of
the sites. Following the submission of these assessments to MDNR, MGE was
required by MDNR to initiate remediation of Station A. Following the selection
of a qualified contractor in a competitive bidding process, the Company began
remediation of Station A in the first calendar quarter of 2003. The project was
completed in July 2003, at an approximate cost of $4 million. The remediation of
Station B has not been required by MDNR.
In a letter dated July 24, 2002, the Port Authority demanded that the Company
assume full financial responsibility for the design and implementation of a
remedial action plan at property owned by the Port Authority adjacent to MGE's
Station A and B (the Riverfront Redevelopment Site) allowing the Port Authority
to obtain an "unrestricted" clearance for redevelopment of the site. On June 24,
2003, the U.S. District Court approved a settlement agreement among the Port
Authority, the City of Kansas City, MDNR and MGE, whereby the claims related to
the Riverfront Redevelopment Site were resolved, and MGE obtained a release
therefrom, on the basis of payment by MGE of $3.5 million.
Rhode Island and Massachusetts Sites. Prior to its acquisition by the Company,
Providence Gas performed environmental studies and initiated an environmental
remediation project at Providence Gas' primary gas distribution facility located
at 642 Allens Avenue in Providence, Rhode Island. Providence Gas spent more than
$13 million on environmental assessment and remediation at this MGP site under
the supervision of the Rhode Island Department of Environmental Management
(RIDEM). Following the acquisition, environmental remediation at the site was
temporarily suspended. During this suspension, the Company requested certain
modifications to the 1999 Remedial Action Work Plan from RIDEM. After receiving
approval to some of the requested modifications to the 1999 Remedial Action Work
Plan, environmental work was reinitiated on April 17, 2002, by a qualified
contractor selected in a competitive bidding process. Remediation was completed
on October 10, 2002, and a Closure Report was filed with RIDEM in December 2002.
The approximate cost of the environmental work conducted after environmental
work resumed was $4 million. Remediation of the remaining 37.5 acres of the site
(known as the "Phase 2" remediation project) is not scheduled at this time.
In November 1998, Providence Gas received a letter of responsibility from RIDEM
relating to possible contamination at a site that operated as a MGP in the early
1900's in Providence, Rhode Island. Subsequent to its use as a MGP, this site
was operated for over eighty years as a bulk fuel oil storage yard by a
succession of companies including Cargill, Inc. (Cargill). Cargill has also
received a letter of responsibility from RIDEM for the site. An investigation
has begun to determine the extent of contamination, as well as the extent of the
Company's responsibility. Providence Gas entered into a cost-sharing agreement
with Cargill, under which Providence Gas is responsible for approximately twenty
percent (20%) of the costs related to the investigation. To date, approximately
$300,000 has been spent on environmental assessment work at this site. Until
RIDEM provides its final response to the investigation, and the Company knows
it's ultimate responsibility respective to other potentially responsible parties
with respect to the site, the Company cannot offer any conclusions as to its
ultimate financial responsibility with respect to the site.
Fall River Gas Company was a defendant in a civil action seeking to recover
anticipated remediation costs associated with contamination found at property
owned by the plaintiffs (the Cory Lane Site) in Tiverton, Rhode Island. This
claim was based on alleged dumping of material by Fall River Gas Company trucks
at the site in the 1930s and 1940s. In a settlement agreement effective December
3, 2001, the Company agreed to perform all assessment, remediation and
monitoring activities at the Cory Lane Site sufficient to obtain a final letter
of compliance from the RIDEM.
In a letter dated March 17, 2003, RIDEM sent the New England Gas Company
division of Southern Union (NEGC) a letter of responsibility pertaining to
alleged historical MGP impacted soils in a residential neighborhood along Bay
Street, Judson Street, Canonicus Street, Hooper Street, Hilton Street, Chase
Street and Foote Street (collectively the Bay Street Area) in Tiverton, Rhode
Island. The letter requested that NEGC prepare a draft Site Investigation Work
Plan for submittal to RIDEM by April 10, 2003, and subsequently perform a Site
Investigation of the Bay Street Area. Without admitting responsibility or
accepting liability, NEGC responded to RIDEM in a letter dated March 19, 2003,
and agreed to perform the activities requested by the State within the period
specified by RIDEM. After receiving approval from RIDEM on a Site Investigation
Work Plan and upon obtaining access agreements from a number of property owners,
NEGC began assessment work on June 2, 2003. Assessment fieldwork is now complete
at approximately half of the 68 residential lots within the Bay Street Area. As
additional access agreements are received, environmental assessment work will
continue through September 2003. Upon the validation of the assessment data,
assessment results will be communicated to RIDEM and to the residents. As the
Bay Street Area is built on a historic dumpsite, research is underway to
identify other potentially responsible parties associated with the area.
Valley Gas Company is a party to an action in which Blackstone Valley Electric
Company (Blackstone) brought suit for contribution to its expenses of cleanup of
a site on Mendon Road in Attleboro, Massachusetts, to which coal manufacturing
waste was transported from a former MGP site in Pawtucket, Rhode Island (the
Blackstone Litigation). Blackstone Valley Electric Company v. Stone & Webster,
Inc., Stone & Webster Engineering Corporation, Stone & Webster Management
Consultants, Inc. and Valley Gas Company, C. A. No. 94-10178JLT, United States
District Court, District of Massachusetts. Valley Gas Company takes the position
in that litigation that it is indemnified for any cleanup expenses by Blackstone
pursuant to a 1961 agreement signed at the time of Valley Gas Company's
creation. This suit was stayed in 1995 pending the issuance of rulemaking at the
United States Environmental Protection Agency (EPA) (Commonwealth of
Massachusetts v. Blackstone Valley Electric Company, 67 F.3d 981 (1995)). In
January 2001, the EPA issued a Preliminary Administrative Decision on this issue
and announced that it was soliciting comments on the Decision. While the public
comment period has now closed, the EPA has yet to reissue its decision. While
this suit has been stayed, Valley Gas Company and Blackstone (merged with
Narragansett Electric Company in May 2000) have received letters of
responsibility from the RIDEM with respect to releases from two MGP sites in
Rhode Island. RIDEM issued letters of responsibility to Valley Gas Company and
Blackstone in September 1995 for the Tidewater MGP in Pawtucket, Rhode Island,
and in February 1997 for the Hamlet Avenue MGP in Woonsocket, Rhode Island.
Valley Gas Company entered into an agreement with Blackstone (now Narragansett)
in which Valley Gas Company and Blackstone agreed to share equally the expenses
for the costs associated with the Tidewater site subject to reallocation upon
final determination of the legal issues that exist between the companies with
respect to responsibility for expenses for the Tidewater site and otherwise. No
such agreement has been reached with respect to the Hamlet site.
In a letter dated March 11, 2003, the Commonwealth of Massachusetts Department
of Environmental Protection provided New England Gas Company a Notice of
Responsibility for 60 and 82 Hartwell Street in Fall River, Massachusetts. This
Notice of Responsibility requested that site assessment activities be conducted
with respect to the listed properties and with respect to the adjacent former
MGP property owned by NEGC at 66 5th Street, Fall River.
Pennsylvania Sites. During 2002, PG Energy received inquiries from the
Pennsylvania Department of Environmental Protection (PADEP) pertaining to three
Pennsylvania former MGP sites. Of these three sites, PG Energy is currently
performing environmental assessment work at the Scranton MGP at the request of
PADEP. PG Energy has participated financially in PPL Electric Utilities
Corporation's (PPL's) environmental and health assessment of a MGP site located
in Sunbury, Pennsylvania. In May 2003, PPL commenced a remediation project at
the Sunbury site that was completed in August 2003. PG Energy has contributed to
PPL's remediation project by removing and relocating gas utility lines located
in the path of the remediation. The Company does not believe the outcome of
these matters will have a material adverse effect on its financial position,
results of operations or cash flows.
To the extent that potential costs associated with former MGPs are quantified,
the Company expects to provide any appropriate accruals and seek recovery for
such remediation costs through all appropriate means, including in rates charged
to gas distribution customers, insurance and regulatory relief. At the time of
the closing of the acquisition of the Company's Missouri service territories,
the Company entered into an Environmental Liability Agreement that provides that
Western Resources retains financial responsibility for certain liabilities under
environmental laws that may exist or arise with respect to Missouri Gas Energy.
In addition, the New England Division has reached agreement with its Rhode
Island rate regulators on a regulatory plan that creates a mechanism for the
recovery of environmental costs over a 10-year period. This plan, effective July
1, 2002, establishes an environmental fund for the recovery of evaluation,
remedial and clean-up costs arising out of the Company's MGPs and sites
associated with the operation and disposal activities from MGPs. Similarly,
environmental costs associated with Massachusetts' facilities are recoverable in
rates over a seven-year period.
PCB Sites -- Panhandle Energy has identified environmental impacts at certain
sites on its systems and has undertaken clean-up programs at those sites. These
impacts resulted from (i) the past use of lubricants containing polychlorinated
bi-phenyls (PCBs) in compressed air systems; (ii) the prior use of wastewater
collection facilities; and (iii) other on-site disposal areas. The Panhandle
Energy companies communicated with the EPA and appropriate state regulatory
agencies on these matters. Under the terms of the sale of Panhandle Eastern Pipe
Line Company, LLC and Trunkline Gas Company, LLC to CMS Energy, a subsidiary of
Duke Energy is obligated to complete the Panhandle Energy clean-up programs at
certain agreed-upon sites and to indemnify against certain future environmental
litigation and claims. Duke Energy's cleanup activities have been completed on
all but one of the agreed-upon sites. Should additional information be requested
regarding sites where compliance information has been submitted, the Company
would be obligated to respond to the request. Further, Panhandle Energy is
currently managing the assessment and remediation of one site in Kansas, one in
Indiana and one in Texas.
At some locations, PCBs have been identified in paint that was applied to
facilities many years ago. In accordance with EPA regulations, Panhandle Energy
is implementing a program to remediate sites where such issues have been
identified during painting activities. If PCBs are identified above acceptable
levels, the paint is removed and disposed of in an EPA-approved manner.
As part of the clean-up program resulting from contamination due to the use of
lubricants in compressed air systems containing PCBs, Panhandle Energy has
identified PCB levels above acceptable levels inside the auxiliary buildings
that houses air compressor equipment at thirty-two compressor station sites.
Panhandle Energy has developed and is implementing an EPA-approved process to
remediate this PCB contamination.
Based on information available at this time, it would appear the amount reserved
for all of the above is adequate to cover the potential exposure for clean-up
costs.
Waste Oil Sites -- The Illinois Environmental Protection Agency (IEPA) has
initiated a voluntary cleanup of one of three former waste oil disposal sites
(the Pierce Waste Oil Sites) in Illinois. This cleanup involves numerous
defendants who were allegedly contributors to this site. In 1993, the United
States EPA completed a partial cleanup effort at this site. Prior to the U.S.
EPA partial cleanup, a preliminary study estimated the cleanup costs related to
this site to be between $5 million and $15 million. Panhandle Energy estimates
that it's share of the cost of assessment and remediation at the site, based on
the volume of waste sent to the site, is 17.32%. If a voluntary cleanup effort
is not successful, the IEPA may choose to designate the site as a Superfund site
or to initiate a Federal Court proceeding. The State of Illinois has not
initiated any efforts to begin an investigation to remediate the other two
Pierce sites. Based on information available at this time, it would appear the
amount reserved is adequate to cover the potential exposure for clean-up costs.
Air Quality Control
In 1998, the EPA issued a final rule on regional ozone control that requires
Panhandle Energy to place controls on engines in five Midwestern states. The
part of the rule that affects Panhandle Energy was challenged in court by
various states, industry and other interests, including Interstate Natural Gas
Association of America (INGAA), an industry group to which Panhandle Energy
belongs. In March 2000, the court upheld most aspects of the EPA's rule, but
agreed with INGAA's position and remanded to the EPA the sections of the rule
that affected Panhandle Energy. The final rule is expected no earlier than early
2004. Based on an EPA guidance document negotiated with gas industry
representatives in 2002, it is believed that Panhandle Energy will be required
to reduce NOx emissions by 82% on the identified large internal combustion (IC)
engines and will be able to trade off engines within a company and State in an
effort to create a cost effective NOx reduction solution. The implementation
date is expected to be May 2007. The rule impacts 20 large internal combustion
engines on the Panhandle Energy system in Illinois and Indiana at an approximate
cost of $17 million for capital improvements, consistent with budget
projections.
EPA proposed various Maximum Achievable Control Technology (MACT) rules in late
2002 and early 2003. The rules require that Panhandle and Trunkline control
Hazardous Air Pollutants (HAPS) emitted from Major sources by 90% of carbon
monoxide (CO)emissions. Most Panhandle Eastern Pipe Line and Trunkline
compressor stations are major sources. The HAP's pollutant of concern for
Panhandle Eastern Pipe Line and Trunkline is formaldehyde. As proposed, the rule
seeks to reduce CO emissions as a surrogate for formaldehyde. For IC engines,
the control technology would be the use of non-selective catalytic reduction
(NSCR) catalysts and the expected implementation date is February 2007. For
Turbines, the control technology would be the use of oxidation catalysts and the
expected implementation date is December 2007. Panhandle Eastern Pipe Line and
Trunkline have 28 IC engines and two turbines subject to the rules. It is
expected to cost approximately $8.4 million, consistent with budget projections.
The Illinois Environmental Protection Agency issued a permit in February of
2002, requiring the installation of certain capital improvements at the Glenarm
compressor station facility at a cost of approximately $3 million. Controls were
installed on two engines in 2002 and controls will be installed in 2003 on two
additional engines in accordance with the 2002 permit.
Beginning in 2002, the Texas Commission on Environmental Quality enacted the
Houston/Galveston State Implementation Plan (SIP) regulations requiring
reductions in nitrogen oxide emissions in an eight county area surrounding
Houston. Trunkline's Cypress compressor station is affected and may require the
installation of emission controls. In 2003, the new regulations will also
require all "grandfathered" facilities to enter into the new source permit
program which may require the installation of emission controls at five
additional facilities.
Regulatory
On May 31, 2002, the staff of the MPSC recommended that the Commission disallow
approximately $15 million in gas costs incurred during the period July 1, 2000
through June 30, 2001. Missouri Gas Energy filed its response in opposition to
the Staff's recommendation on July 11, 2002, vigorously disputing the Commission
staff's assertions. Missouri Gas Energy intends to vigorously defend itself in
this proceeding. This matter went to hearing in May of 2003, is presently in
recess, and the hearing is set to resume in November 2003.
On November 27, 2001, August 1, 2000 and August 12, 1999, the staff of the MPSC
recommended that the Commission disallow approximately $5.9 million, $5.9
million and $4.3 million, respectively, in gas costs incurred during the period
July 1, 1999 through June 30, 2000, July 1, 1998 through June 30, 1999, and July
1, 1997 through June 30, 1998, respectively. The basis of these proposed
disallowances appears to be the same as was rejected by the Commission through
an order dated March 12, 2002, applicable to the period July 1, 1996 through
June 30, 1997. MGE intends to vigorously defend itself in these proceedings. On
November 4, 2002, the Commission adopted a procedural schedule calling for a
hearing in this matter some time after May 2003. No date for this hearing has
been set.
Southwest Gas Litigation
Several actions were commenced by persons involved in competing efforts to
acquire Southwest Gas Corporation (Southwest) during 1999. All of these actions
eventually were transferred to the District of Arizona (the Court), consolidated
and lodged with Judge Roslyn Silver. As a result of summary judgments granted,
no claims remain against Southern Union. Southern Union's claims against
Southwest were settled on August 6, 2002, by Southwest's payment to Southern
Union of $17,500,000. Southern Union's claims against ONEOK, Inc. (ONEOK) and
the individual defendants associated with ONEOK were settled on January 3, 2003,
following the closing of Southern Union's sale of the Texas assets to ONEOK, by
ONEOK's payment to Southern Union of $5,000,000. Southern Union's claims against
Jack Rose, former aide to Arizona Corporation Commissioner James Irvin, were
settled by Mr. Rose's payment to Southern Union of $75,000, which the Company
donated to charity. The trial of Southern Union's claims against the
sole-remaining defendant, Arizona Corporation Commissioner James Irvin, was
concluded on December 18, 2002, with a jury award to Southern Union of nearly
$400,000 in actual damages and $60,000,000 in punitive damages against
Commissioner Irvin. The Court denied numerous post-trial motions by Commissioner
Irvin, who has filed a notice of appeal. The Company intends to vigorously
pursue collection of the award. With the exception of ongoing legal fees
associated with the collection of damages from Commissioner Irvin, the Company
believes that the results of the above-noted Southwest litigation and any
related appeals will not have a materially adverse effect on the Company's
financial condition, results of operations or cash flows.
Other
In conjunction with a FERC Order issued in September 1997, certain natural gas
producers were required to refund previously collected Kansas ad valorem taxes
to interstate natural gas pipelines. These pipelines were ordered to refund
these amounts to their customers. All payments were to be made in compliance
with prescribed FERC requirements. In June 2001, Panhandle Energy filed a
proposed settlement of these proceedings which all the customers and most of the
producers supported. The settlement provides for the producers to refund and the
customers to accept a reduction from the amounts originally billed to the
producers. In September 2001, the FERC approved the settlement without
modification and the settlement became effective on October 15, 2001. On January
2, 2003, FERC established hearing procedures for resolving refunds owed by the
non-settling producers. The hearing is scheduled to commence on October 16,
2003. The amounts have not yet been finally settled with a number of
non-settling producers. Settlement efforts are continuing.
In 1993, the U.S. Department of the Interior announced its intention to seek,
through its Minerals Management Service (MMS) additional royalties from gas
producers as a result of payments received by such producers in connection with
past take-or-pay settlements and buyouts or buy downs of gas sales contracts
with natural gas pipelines. Panhandle Energy's pipelines, with respect to
certain producer contract settlements, may be contractually required to
reimburse or, in some instances, to indemnify producers against such royalty
claims. The potential liability of the producers to the government and of the
pipelines to the producers involves complex issues of law and fact which are
likely to take substantial time to resolve. If required to reimburse or
indemnify the producers, Panhandle Energy's pipelines may file with the FERC to
recover a portion of these costs from pipeline customers. Panhandle Energy does
not believe the outcome of this matter will have a material adverse effect on
its financial position, results of operations or cash flows.
Southern Union and its subsidiaries are parties to other legal proceedings that
management considers to be normal actions to which an enterprise of its size and
nature might be subject, Management does not consider these actions to be
material to Southern Union's overall business or financial condition, results of
operations or cash flows.
Commitments. The Company is committed under various agreements to purchase
certain quantities of gas in the future. At June 30, 2003, the Company's
Distribution segment has purchase commitments for natural gas transportation
services, storage services and certain quantities of natural gas at a
combination of fixed, variable and market-based prices that have an aggregate
value of approximately $1,669,538,000. The Company's purchase commitments may
extend over a period of several years depending upon when the required quantity
is purchased. The Company has purchase gas tariffs in effect for all its utility
service areas that provide for recovery of its purchase gas costs under defined
methodologies.
In connection with the acquisition of the Pennsylvania Operations, the Company
assumed a guaranty with a bank whereby the Company unconditionally guaranteed
payment of financing obtained for the development of PEI Power Park. In March
1999, the Borough of Archibald, the County of Lackawanna, and the Valley View
School District (together the Taxing Authorities) approved a Tax Incremental
Financing Plan (TIF Plan) for the development of PEI Power Park. The TIF Plan
requires that: (i) the Redevelopment Authority of Lackawanna County raise
$10,600,000 of funds to be used for infrastructure improvements of the PEI Power
Park; (ii) the Taxing Authorities create a tax increment district and use the
incremental tax revenues generated from new development to service the
$10,600,000 debt; and (iii) PEI Power Corporation, a subsidiary of the Company,
guarantee the debt service payments. In May 1999, the Redevelopment Authority of
Lackawanna County borrowed $10,600,000 from a bank under a promissory note (TIF
Debt), which was refinanced in March 2003. The TIF Debt bears interest at a
floating rate with a floor of 5.0% and a ceiling of 7.75% and matures on June
30, 2011. The loan requires interest-only payments until June 30, 2003, and
semi-annual interest and principal payments thereafter. As of June 30, 2003, the
interest rate on the TIF Debt is 5.0% and estimated incremental tax revenues are
expected to cover approximately 20% of the fiscal year 2004 annual debt service.
The balance outstanding on the TIF Debt was $9,710,000 as of June 30, 2003.
Effective August 1, 2003, the Company agreed to a three-year contract with a
bargaining unit representing a portion of PG Energy employees. During fiscal
2001, the Company agreed to a three-year contract with another bargaining unit
representing the remaining PG Energy unionized employees, effective April 2001.
Effective May 28, 2003, Panhandle Energy agreed to a three-year contract with a
bargaining unit representing the Panhandle Energy employees that will expire on
May 27, 2006.
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 year 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.
In December 1998, the Company agreed to five-year contracts with each
bargaining-unit representing Missouri employees, which were effective in May
1999.
Of the Company's employees represented by unions, 36% are employed by Missouri
Gas Energy, 32% are employed by the New England Division, 18% are employed by
Panhandle Energy and 14% are employed by PG Energy.
The Company had standby letters of credit outstanding of $7,761,000 at June 30,
2003 and $30,541,000 at June 30, 2002, which guarantee payment of insurance
claims and other various commitments.
XIX Discontinued Operations and Assets Held for Sale
Effective January 1, 2003, the Company completed the sale of its Southern Union
Gas natural gas operating division and related assets to ONEOK for approximately
$437,000,000 in cash resulting in a pre-tax gain of $62,992,000. In accordance
with accounting principles generally accepted in the United States, the assets
and liabilities sold have been segregated and reported as "held for sale" in the
Consolidated Balance Sheet as of June 30, 2002, and the related results of
operations and gain on sale have been segregated and reported as "discontinued
operations" in the Consolidated Statement of Operations and Consolidated
Statement of Cash Flows for all periods presented.
The following table summarizes the major classes of the Texas Operations' assets
and liabilities that have been segregated and reported as "held for sale" in the
Consolidated Balance Sheet at June 30, 2002:
ASSETS: June 30, 2002
-------------
Property, plant and equipment:
Utility plant, at cost............................................ $ 504,015
Accumulated depreciation and amortization......................... (217,425)
-------------
Net property, plant and equipment............................. 286,590
Current assets......................................................... 29,677
Goodwill, net ......................................................... 70,469
Deferred charges and other assets...................................... 8,710
-------------
Total assets held for sale.................................... $ 395,446
=============
LIABILITIES:
Current liabilities.................................................... $ 43,762
Deferred credits and other liabilities................................. 23,956
-------------
Total liabilities related to assets held for sale............. $ 67,718
=============
The following table summarizes the Texas Operations' results of operations that
have been segregated and reported as "discontinued operations" in the
Consolidated Statement of Operations:
Year Ended June 30,
2003 2002 2001
------------- ------------- -------------
Operating revenues..................................................... $ 144,490 $ 309,936 $ 471,002
============= ============= =============
Net operating margin (a)............................................... $ 51,480 $ 105,730 $ 109,016
============= ============= =============
Net earnings from discontinued operations (b).......................... $ 32,520 $ 18,104 $ 16,524
============= ============= =============
- ---------------------------------
(a) Net operating margin consists of operating revenues less gas purchase costs
and revenue-related taxes.
(b) Net earnings from discontinued operations do not include any allocation of
interest expense or other corporate costs, in accordance with generally
accepted accounting principles. All outstanding debt of Southern Union
Company and subsidiaries is maintained at the corporate level, and no debt
was assumed by ONEOK, Inc. in the sale of the Texas Operations.
XX Quarterly Operations (Unaudited)
Year Ended Quarter Ended
June 30, 2003 September 30 December 31 March 31 June 30 Total
-------------- ------------ ----------- --------- --------- --------------
Total operating revenues ....................... $ 99,710 $ 346,104 $ 535,663 $ 207,030 $ 1,188,507
Operating margin ............................... 54,464 118,031 161,400 89,516 423,411
Net earnings (loss) from continuing operations . (9,186) 18,519 46,234 (11,898) 43,669
Net earnings (loss) from discontinued operations 2,691 10,900 17,665 1,264 32,520
Net earnings (loss) available for common stock . (6,495) 29,419 63,899 (10,634) 76,189
Diluted net earnings (loss) per share:(1)
Continuing operations ....................... (.17) .31 .79 (.20) .74
Discontinued operations ..................... .05 .19 .30 .02 .55
Available for common stock .................. (.12) .50 1.09 (.18) 1.29
Year Ended Quarter Ended
June 30, 2002 September 30 December 31 March 31 June 30 Total
------------- -------------- --------------- ------------ ------------ -------------
Total operating revenues.................... $ 120,676 $ 286,622 $ 419,599 $ 153,717 $ 980,614
Operating margin............................ 55,576 104,455 143,630 70,467 374,128
Net earnings (loss) from continuing operations (29,906) 7,554 38,899 (15,027) 1,520
Net earnings (loss) from discontinued operations (497) 12,196 4,889 1,516 18,104
Net earnings (loss) available for common stock (30,403) 19,750 43,788 (13,511) 19,624
Diluted net earnings (loss) per share:(1)
Continuing operations.................... (.51) .14 .67 (.27) .03
Discontinued operations.................. (.01) .21 .07 .03 .30
Available for common stock............... (.52) .35 .74 (.24) .33
(1) The sum of earnings per share by quarter may not equal the net earnings per
common and common share equivalents for the year due to variations in the
weighted average common and common share equivalents outstanding used in
computing such amounts.
XXI Reportable Segments
The Company's operations include two reportable segments. The Transportation and
Storage segment is primarily engaged in the interstate transportation and
storage of natural gas in the Midwest and Southwest, and also provides LNG
terminalling and regasification services. Its operations are conducted through
Panhandle Energy, which the Company acquired on June 11, 2003. The Distribution
segment is primarily engaged in the local distribution of natural gas in
Missouri, Pennsylvania, Rhode Island and Massachusetts. Its operations are
conducted through the Company's three regulated utility divisions: Missouri Gas
Energy, PG Energy and New England Gas Company. The determination of reportable
business segments is based on similarities in economic characteristics, products
and services, types of customers, methods of distribution and regulatory
environment.
The Company evaluates segment performance based on several factors, of which the
primary financial measure is net operating revenues. Net Operating Revenues is
defined as operating margin, less operating, maintenance and general expenses,
depreciation and amortization, and taxes other than on income and revenues. The
accounting policies of the segments are substantially the same as those
described in the summary of significant accounting policies (see Note I -
Summary of Significant Accounting Policies). Sales of products or services
between segments are billed at regulated rates or at market rates, as
applicable. There were no material inter segment revenues during 2003, 2002 or
2001.
Prior to the acquisition of Panhandle Energy, the Company was primarily engaged
in the natural gas distribution business and considered its operations to
consist of one reportable segment. As a result of the acquisition of Panhandle
Energy, management assessed the manner in which financial information is
reviewed in making operating decisions and assessing performance, and concluded
that in addition to Panhandle Energy's operations its regulated utility
operations would be treated as one separate and distinct reportable segment. All
historical segment financial and statistical information has been adjusted to
reflect the current segment presentation.
Revenue from segments in the All Other category is attributable to several
operating subsidiaries of the Company: PEI Power Corporation generates and sells
electricity; Fall River Gas Appliance Company, Inc. and Valley Appliance and
Merchandising Company rent gas burning appliances and/or equipment and, along
with PG Energy Services Inc., offer appliance service contracts; ProvEnergy
Power Company LLC (ProvEnergy Power) provides outsourced energy management
services and owns 50% of Capital Center Energy Company LLC, a joint venture
formed between ProvEnergy and ERI Services, Inc. to provide retail power and
conditioned air; and Alternate Energy Corporation provides energy consulting
services. None of these segments have ever met the quantitative thresholds for
determining reportable segments. The Company also has corporate operations that
do not generate any revenues.
The following table sets forth certain selected financial information for the
Company's segments for fiscal 2003, 2002 and 2001. Financial information for the
Transportation and Storage segment reflects the operations of Panhandle Energy
beginning on its acquisition date of June 11, 2003.
Year Ended June 30,
------------------------------------------------
2003 2002 2001
------------- ------------- -------------
Revenues from external customers:
Distribution................................................. $ 1,158,964 $ 968,933 $ 1,304,012
Transportation and Storage................................... 24,529 -- --
All Other (a)............................................... 5,014 11,681 157,799
------------- ------------- -------------
Total consolidated operating revenues............................. $ 1,188,507 $ 980,614 $ 1,461,811
============= ============= =============
Operating Margin:
Distribution................................................. $ 394,760 $ 367,076 $ 365,383
Transportation and Storage................................... 24,529 -- --
All Other.................................................... 4,122 7,052 14,863
------------- ------------- -------------
Total consolidated operating margin............................... $ 423,411 $ 374,128 $ 380,246
============= ============= =============
Depreciation and amortization:
Distribution................................................. $ 56,396 $ 53,937 $ $65,106
Transportation and Storage................................... 3,197 -- --
All Other.................................................... 590 2,387 1,624
------------- ------------- -------------
Total segment depreciation and amortization....................... 60,183 56,324 66,730
Reconciling Item -- Corporate..................................... 459 2,665 2,431
------------- ------------- -------------
Total consolidated depreciation and amortization.................. $ 60,642 $ 58,989 $ 69,161
============= ============= =============
Net operating revenues:
Distribution................................................. $ 142,762 $ 135,502 $ 123,484
Transportation and Storage................................... 9,635 -- --
All Other.................................................... 13 -- (413)
------------- ------------- -------------
Total segment net operating revenues.............................. 152,410 135,502 123,071
Reconciling Items:
Corporate.................................................... (10,039) (15,218) (21,806)
Business restructuring charges............................... -- (29,159) --
------------- ------------- -------------
.............................................................
Consolidated net operating revenues............................... $ 142,371 $ 91,125 $ 101,265
============= ============= =============
Total assets:
Distribution................................................. $ 2,243,257 $ 2,156,106 $ 2,235,011
Transportation and Storage................................... 2,212,467 -- --
All Other.................................................... 50,073 53,339 134,575
------------- ------------- -------------
Total segment assets.............................................. 4,505,797 2,209,445 2,369,586
Reconciling Items:
Corporate.................................................... 85,141 75,173 126,589
Sale of assets - Texas Operations............................ -- 395,446 411,124
------------- ------------- -------------
Total consolidated assets......................................... $ 4,590,938 $ 2,680,064 $ 2,907,299
============= ============= =============
Expenditures for long-lived assets:
Distribution................................................. $ 67,327 $ 68,042 $ 67,329
Transportation and Storage................................... 5,128 -- --
All Other.................................................... 1,653 1,365 6,978
------------- ------------- -------------
Total segment expenditures for long-lived assets.................. 74,108 69,407 74,307
Reconciling item - Corporate...................................... 5,622 1,291 26,445
------------- ------------- -------------
Total consolidated expenditures for long-lived assets............. $ 79,730 $ 70,698 $ 100,752
============= ============= =============
- -----------------------
(a) For the year ended June 30, 2001, the All Other segment included revenues
of approximately $107 million from Energy Services' former non-regulated
gas and electricity businesses and approximately $35 million from the
Company's former subsidiary, ProvEnergy Oil Enterprises, Inc.
Year Ended June 30,
------------------------------------------------
2003 2002 2001
---------------- ------------- ---------------
Reconciliation of net operating revenues to earnings from continuing operations
before income taxes:
Net operating revenues....................................... $ 142,371 $ 91,125 $ 101,265
Interest..................................................... (83,343) (90,992) (102,928)
Dividends on preferred securities of subsidiary trust........ (9,480) (9,480) (9,480)
Other income, net............................................ 18,394 14,278 81,401
------------- ------------- -------------
Earnings from continuing operations before income taxes. $ 67,942 $ 4,931 $ 70,258
============= ============= =============
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors of
Southern Union Company:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, of cash flows and of stockholders'
equity, present fairly, in all material respects, the financial position of
Southern Union Company and subsidiaries at June 30, 2003 and 2002, and the
results of their operations and their cash flows for each of the three years in
the period ended June 30, 2003, in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note I, the Company adopted FASB Standard No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets" for reporting discontinued
operations for each of the three years in the period ended June 30, 2003. As
further discussed in Note I, the Company has completed its purchase of Panhandle
Eastern Pipe Line Company effective June 11, 2003.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
September 25, 2003
SUBSIDIARIES OF THE COMPANY Exhibit 21
Name State or Country of Incorporation
- ---------------------------------------- ---------------------------------
Panhandle Eastern Pipe Line Company, LLC Delaware
Trunkline Gas Company, LLC Delaware
- ----------------------
Note: Certain wholly-owned subsidiaries of Southern Union Company are not
named above. Considered in the aggregate as a single subsidiary, these
unnamed entities would not constitute a "significant subsidiary" at the
end of the year covered by this report. Additionally, the Company has
other subsidiaries that conduct no business except to the extent
necessary to maintain their corporate name or existence.
CONSENT OF INDEPENDENT ACCOUNTANTS Exhibit 23
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 (File No. 333-102388) and Form S-8 (File Nos. 33-37261,
33-69596, 33-69598, 33-61558, 333-79443, 333-08994, 333-42635, 333-89971,
333-36146, 333-36150, and 333-47144) of Southern Union Company of our report
dated September 25, 2003 relating to the consolidated financial statements,
which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
September 25, 2003
POWER OF ATTORNEY Exhibit 24
KNOW ALL PERSONS BY THESE PRESENTS that each person whose signature appears
below constitutes and appoints Thomas F. Karam and David J. Kvapil, or any of
them, acting individually or together, as such person's true and lawful
attorney(s)-in-fact and agent(s), with full power of substitution and
revocation, to act in any capacity for such person and in such person's name,
place and stead in any and all capacities, to sign the Annual Report on Form
10-K for the fiscal year ended June 30, 2003 of Southern Union Company, a
Delaware corporation, and any amendments thereto, and to file the same with all
exhibits thereto, and other documents in connection therewith, with the
Securities and Exchange Commission and the New York Stock Exchange.
Dated: September 26, 2003
GEORGE L. LINDEMANN ADAM M. LINDEMANN
- ------------------------ ------------------------------------------
George L. Lindemann Adam M. Lindemann
JOHN E. BRENNAN DAVID BRODSKY
- ------------------------ ------------------------------------------
John E. Brennan David Brodsky
THOMAS F. KARAM GEORGE ROUNTREE, III
- ------------------------ ------------------------------------------
Thomas F. Karam George Rountree, III
FRANK W. DENIUS RONALD W. SIMMS
- ------------------------ ------------------------------------------
Frank W. Denius Ronald W. Simms
KURT A. GITTER, M.D. ROGER J. PEARSON
- ------------------------ ------------------------------------------
Kurt A. Gitter, M.D. Roger J. Pearson
Exhibit 31.1
CERTIFICATE PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
I, George L. Lindemann, certify that:
1. I have reviewed this annual report on Form 10-K of Southern
Union Company.
2. Based on my knowledge, this report does not contain any
untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made
not misleading with respect to the period covered by this
report.
3. Based on my knowledge, the financial statements, and other
financial information included in this report, fairly present
in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for,
the periods presented in this report.
4. The registrant's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-15(e) and 15d-15(e) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities,
particularly during the period in which this report is being
prepared; and
(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure
controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
(c) Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred
during the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting.
5. The registrant's other certifying officer and I have
disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's
auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the
design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
(b) Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal control over financial reporting.
Date: September 26, 2003 /s/ George L. Lindemann
-----------------------------------
Name: George L. Lindemann
Title: Chairman of the Board and
Chief Executive Officer
Exhibit 31.2
CERTIFICATE PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
I, David J. Kvapil, certify that:
1. I have reviewed this annual report on Form 10-K of Southern
Union Company.
2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the
circumstances under which such statements were made not
misleading with respect to the period covered by this report.
3. Based on my knowledge, the financial statements, and other
financial information included in this report, fairly present
in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for,
the periods presented in this report.
4. The registrant's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-15(e) and 15d-15(e) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly
during the period in which this report is being prepared; and
(b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this
report based on such evaluation; and
(c) Disclosed in this report any change in the registrant's
internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter that has
materially affected, or is reasonably likely to materially
affect, the registrant's internal control over financial
reporting.
5. The registrant's other certifying officer and I have
disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors
and the audit committee of the registrant's board of directors
(or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the
design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report
financial information; and
(b) Any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal control over financial reporting.
Date: September 26, 2003 /s/ David J. Kvapil
---------------------------------------
Name: David J. Kvapil
Title: Executive Vice President and
Chief Financial Officer
Exhibit 32.1
CERTIFICATE PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
18 U.S.C. SECTION 1350
In connection with the Annual Report of Southern Union Company (the
"Company") on Form 10-K for the fiscal year ended June 30, 2003 as filed with
the Securities and Exchange Commission on the date hereof (the "Report"), I,
George L. Lindemann, Chairman of the Board and Chief Executive Officer of the
Company, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18
U.S.C. Section 1350 that, to my knowledge:
1. The Report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended; and
2. The information contained in the Report fairly presents, in all
material respects, the financial condition and result of
operations of the Company.
Date: September 26, 2003 /s/ George L. Lindemann
----------------------------
Name: George L. Lindemann
Title: Chairman of the Board and
Chief Executive Officer
Exhibit 32.2
CERTIFICATE PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
18 U.S.C. SECTION 1350
In connection with the Annual Report of Southern Union Company (the
"Company") on Form 10-K for the fiscal year ended June 30, 2003 as filed with
the Securities and Exchange Commission on the date hereof (the "Report"), I,
David J. Kvapil, Executive Vice President and Chief Financial Officer of the
Company, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18
U.S.C. Section 1350 that, to my knowledge:
1. The Report fully complies with the requirements of Section 13(a)
or 15(d) of the Securities Exchange Act of 1934, as amended; and
2. The information contained in the Report fairly presents, in all
material respects, the financial condition and result of
operations of the Company.
Date: September 26, 2003 /s/ David J. Kvapil
-----------------------------------------
Name: David J. Kvapil
Title: Executive Vice President and
Chief Financial Officer
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