10-K 1 suform10k_123107.htm SOUTHERN UNION COMPANY FORM 10-K, DECEMBER 31, 2007 suform10k_123107.htm





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 December 31, 2007

OR

 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM

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 incorporation or organization)
(I.R.S. Employer Identification No.)

5444 Westheimer Road
77056-5306
Houston, Texas
(Zip Code)
(Address of principal executive offices)
 

Registrant's telephone number, including area code:  (713) 989-2000

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
7.55% Depositary Shares
New York Stock Exchange
5.00% Corporate Units
New York Stock Exchange
   

Securities Registered Pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes  P  No ____

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ____  No  P

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  P    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. P  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  P    Accelerated filer _____   Non-accelerated filer _____  Smaller reporting company _____   

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes ____    No  P 

The aggregate market value of the Common Stock held by non-affiliates of the Registrant as of June 30, 2007 was $3,537,812,559 (based on the closing sales price of Common Stock on the New York Stock Exchange on June 30, 2007).  For purposes of this calculation, shares held by non-affiliates exclude only those shares beneficially owned by executive officers, directors and stockholders of more than 10% of the Common Stock of the Company.

The number of shares of the registrant's Common Stock outstanding on February 22, 2008 was 123,772,513.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its annual meeting of stockholders that is scheduled to be held on May 13, 2008 are incorporated by reference into Part III.


 
 

 

FORM 10-K
DECEMBER 31, 2007

Table of Contents


   
Page
 
PART I
 
1
15
23
24
24
24
 
PART II
 
25
28
29
51
53
53
53
55
 
PART III
 
55
55
55
55
55
 
PART IV
 
56
60
F-1




PART I


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 owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States.  The Company operates in three reportable segments:  Transportation and Storage, Gathering and Processing, and Distribution.
 
BUSINESS SEGMENTS

Reportable Segments

The Company’s operations, as reported, include three reportable segments:

·
The Transportation and Storage segment, which is primarily engaged in the interstate transportation and storage of natural gas from gas producing areas in Texas, Oklahoma, Colorado, the Gulf of Mexico and the Gulf Coast to markets throughout the Midwest and from the Gulf Coast to Florida, and liquefied natural gas (LNG) terminalling and regasification services.  Its operations are currently conducted through Panhandle Eastern Pipe Line Company, LP (PEPL) and its subsidiaries (collectively Panhandle) and its 50 percent equity ownership interest in Florida Gas Transmission Company, LLC (Florida Gas) through Citrus Corp. (Citrus);

·
The Gathering and Processing segment, which is primarily engaged in the gathering, treating, processing and redelivery of natural gas and natural gas liquids (NGLs) in Texas and New Mexico.  Its operations are conducted through Southern Union Gas Services (SUGS); and

·
The Distribution segment, which is primarily engaged in the local distribution of natural gas in Missouri and  Massachusetts.  Its operations are conducted through Missouri Gas Energy and New England Gas Company.

The Company has other operations that support and expand its natural gas and other energy sales, which are not included in its reportable segments.  These operations do not meet the quantitative thresholds for determining reportable segments and have been combined for disclosure purposes in the Corporate and Other category.  For information about the revenues, operating income, assets and other financial information relating to the  Corporate and Other category, see Item 8.  Financial Statements and Supplementary Data, Note 21 – Reportable Segments.

The Company also provides various corporate services to support its operating businesses, including executive management, accounting, communications, human resources, information technology, insurance, internal audit, investor relations, environmental, legal, payroll, purchasing, risk management, tax and treasury.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.  There were no material intersegment revenues during the years ended December 31, 2007, 2006 or 2005.
 
Transportation and Storage Segment

Services

The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas to the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services.  The Transportation and Storage segment’s operations are conducted through Panhandle and Florida Gas.

For the years ended December 31, 2007, 2006 and 2005, the Transportation and Storage segment’s operating revenues were $658.4 million, $577.2 million and $505.2 million, respectively.  Earnings from unconsolidated investments related to Citrus were $98.9 million for the year ended December 31, 2007.  For the years ended December 31, 2006 and 2005, Earnings from unconsolidated investments contributed through CCE Holdings,


LLC (CCE Holdings) were $141.1 million and $70.4 million, respectively.  See discussion below in Citrus and CCE Holdings related to the Company’s increased ownership interest in Florida Gas through Citrus effective December 1, 2006.

For information about operating revenues, earnings before interest and taxes (EBIT), earnings from unconsolidated investments, assets and other financial information relating to the Transportation and Storage segment, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Business Segment Results – Transportation and Storage and Item 8. Financial Statements and Supplementary Data, Note 21 – Reportable Segments.

Panhandle.  Panhandle owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the PEPL transmission system, the Trunkline Gas Company, LLC (Trunkline) transmission system and the Sea Robin Pipeline Company, LLC (Sea Robin) transmission system, serves customers in the Midwest with a comprehensive array of transportation and storage services.  PEPL’s transmission system consists of four large diameter 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.  Trunkline’s transmission system consists of two large diameter 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.  Sea Robin’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 81 miles into the Gulf of Mexico. In connection with its gas transmission and storage systems, Panhandle has five gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma.  Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage) operates four of these fields and Trunkline operates one.  Through Trunkline LNG Company, LLC (Trunkline LNG), Panhandle owns and operates an LNG terminal in Lake Charles, Louisiana.  The Trunkline LNG terminal is one of the largest operating LNG facilities in North America based on its current sustainable send out capacity of approximately 1.8 billion cubic feet per day (Bcf/d).

Panhandle earns most of its revenue by entering into firm transportation and storage contracts, reserving capacity for customers to transport or store natural gas or LNG, in its facilities.  Approximately 34 percent of Panhandle’s total operating revenue comes from long-term service agreements with local distribution company customers and their affiliates.  Panhandle also provides firm transportation services under contract to gas marketers, producers, other pipelines, electric power generators and a variety of end-users.  Panhandle’s pipelines offer both firm and interruptible transportation to customers on a short-term or seasonal basis.  Demand for gas transmission on Panhandle’s pipeline systems is seasonal, with the highest throughput and a higher portion of annual total operating revenues and net earnings occurring in the traditional winter heating season in the first and fourth calendar quarters.

Citrus and CCE Holdings.  On December 1, 2006, the Company completed a series of transactions that resulted in it increasing its effective ownership interest in Florida Gas from 25 percent to 50 percent and eliminating its effective 50 percent ownership interest in Transwestern Pipeline Company, LLC (Transwestern).  On September 14, 2006, Energy Transfer Partners, LP. (Energy Transfer) entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings, LLC (CCE Holdings) held by GE Energy Financial Services and other investors.  At the same time, Energy Transfer and CCE Holdings entered into a definitive redemption agreement (Redemption Agreement), pursuant to which Energy Transfer’s 50 percent ownership interest in CCE Holdings would be redeemed in exchange for 100 percent of the equity interests in Transwestern.  Upon closing of the Redemption Agreement on December 1, 2006, the Company became the sole owner of 100 percent of CCE Holdings, whose principal remaining asset was its 50 percent interest in Citrus which, in turn, owns 100 percent of Florida Gas.

Florida Gas is an open-access interstate pipeline system with a mainline capacity of 2.1 Bcf/d extending approximately 5,000 miles from south Texas through the Gulf Coast region of the United States to south Florida. Florida Gas’ pipeline system primarily receives natural gas from natural gas producing basins along the Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico.  Florida Gas is the principal transporter of natural gas to the Florida energy market, delivering over 70 percent of the natural gas consumed in the state.  In addition, Florida Gas’ pipeline system operates and maintains 60 interconnects with major interstate and intrastate natural gas pipelines, which provide Florida Gas’ customers access to diverse natural gas producing regions.



Florida Gas earns the majority of its revenue by entering into firm transportation contracts, providing capacity for customers to transport natural gas in their pipelines.   Florida Gas also earns variable revenue from charges assessed on each unit of transportation provided.

Demand for gas transmission service on the Florida Gas pipeline system is somewhat seasonal, with the highest throughput and related net earnings occurring in the summer period due to gas-fired generation loads in the second and third calendar quarters.  The Company’s share of net earnings of Florida Gas and, until its transfer on December 1, 2006, Transwestern have been reported in Earnings from unconsolidated investments in the Consolidated Statement of Operations.

The following table provides a summary of transportation volumes (in trillion British thermal units) associated with the reported results of operations for the periods presented:

   
Year Ended
   
Year Ended
 
Year Ended
 
   
December 31, 2007
   
December 31, 2006
 
December 31, 2005
 
                 
Panhandle
               
PEPL
    662       579     609  
Trunkline
    648       486     459  
Sea Robin
    144       115     146  
Trunkline LNG Usage Volumes
    261       149     108  
                       
Citrus and CCE Holdings (1)
                     
Florida Gas
    751       737     699  
Transwestern
    N/A       572  (2)   589  
                       
_______________________
(1)
Represents 100 percent of Transwestern and Florida Gas versus the Company's effective equity ownership interest.
The Company's effective equity ownership interests in Transwestern and Florida Gas were 50 percent and 25 percent,
respectively, until December 1, 2006, when the Company's interest in Transwestern was transferred to Energy
Transfer, increasing the Company's effective interest in Florida Gas to 50 percent.
(2)
Represents transportation volumes for Transwestern for the eleven-month period ended November 30, 2006.







 









The following table provides a summary of certain statistical information associated with Panhandle and Florida Gas at December 31, 2007:

   
As of
 
   
December 31, 2007
 
Panhandle
     
Approximate Miles of Pipelines
     
PEPL
    6,000  
Trunkline
    3,500  
Sea Robin
    400  
Peak Day Delivery Capacity (Bcf/d)
       
PEPL
    2.8  
Trunkline
    1.7  
Sea Robin
    1.0  
Trunkline LNG
    2.1  
Trunkline LNG Sustainable Send Out Capacity (Bcf/d)
    1.8  
Underground Storage Capacity-Owned (Bcf)
    74.4  
Underground Storage Capacity-Leased (Bcf)
    19.9  
Trunkline LNG Terminal Storage Capacity (Bcf)
    9.0  
Average Number of Transportation Customers
    500  
Weighted Average Remaining Life in Years of Firm Transportation Contracts
       
PEPL
    4.6  
Trunkline
    9.0  
Sea Robin (1)
    N/A  
Weighted Average Remaining Life in Years of Firm Storage Contracts
       
PEPL
    5.9  
Trunkline
    3.1  
         
Florida Gas (2)
       
Approximate Total Miles of Pipelines
    5,000  
Peak Day Delivery Capacity (Bcf/d)
    2.3  
Average Number of Transportation Customers
    125  
Weighted Average Remaining Life of Firm Transportation Contracts
    8.7  
         
___________________
(1)    Sea Robin’s contracts are primarily interruptible, with only one firm contract in place.
(2)    Represents 100 percent of Florida Gas versus the Company's effective equity ownership interest of
        50 percent at December 31, 2007.

Recent System Enhancements – Completed or Under Construction

LNG Terminal Enhancement.  The Company has commenced construction of an enhancement at its Trunkline LNG terminal.  This infrastructure enhancement project, which was originally expected to cost approximately $250 million, plus capitalized interest, will increase send out flexibility at the terminal and lower fuel costs.  Recent cost projections indicate the construction costs will likely be approximately $365 million, plus capitalized interest.  The revised costs reflect increases in the quantities and cost of materials required, higher contract labor costs and an allowance for additional contingency funds, if needed.  The negotiated rate with the project’s customer, BG LNG Services, will be adjusted based on final capital costs pursuant to a contract-based formula. The project is now expected to be in operation in the second quarter of 2009.  In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements through 2028, representing a five-year extension.  Approximately $178.3 million and $40.8 million of costs are included in the line item Construction work-in-progress at December 31, 2007 and 2006, respectively.



Compression Modernization.  The Company has received approval from FERC to modernize and replace various compression facilities on PEPL.  Such replacements are ultimately expected to be made at eleven compressor stations, with three stations completed as of December 31, 2007.  Three additional stations are in progress and planned to be completed by the end of 2009, with the remaining cost for these stations estimated at approximately $100 million, plus capitalized interest.  Planning for the other five compressor stations on which construction has not yet begun is continuing, with the timing and scope of the work on these stations being evaluated on an individual station basis.  The Company is also replacing approximately 32 miles of existing pipeline on the east end of the PEPL system at a current estimated cost of approximately $125 million, plus capitalized interest, which will further improve system integrity and reliability.  The revised higher cost relates to various construction issues and delays which have resulted in current estimated in-service dates for the related facilities around the end of the first quarter of 2008 or in the second quarter of 2008.  Approximately $124.7 million and $57.9 million of costs related to these projects are included in the line item Construction work-in-progress at December 31, 2007 and December 31, 2006, respectively.  

Trunkline Field Zone Expansion Project.  Trunkline has completed construction on its field zone expansion project.  The expansion project included the north Texas expansion and creation of additional capacity on Trunkline’s pipeline system in Texas and Louisiana to increase deliveries to Henry Hub.  Trunkline has increased the capacity along existing rights-of-way from Kountze, Texas to Longville, Louisiana by approximately 625 million cubic feet per day (MMcf/d) with the construction of approximately 45 miles of 36-inch diameter pipeline.  The project included horsepower additions and modifications at existing compressor stations.  Trunkline has also created additional capacity to Henry Hub with the construction of a 13.5-mile, 36-inch diameter pipeline loop from Kaplan, Louisiana directly into Henry Hub.  The Henry Hub lateral provides capacity of 1 Bcf/d from Kaplan, Louisiana to Henry Hub.  The majority of the project was put into service in late December 2007 with the remainder placed in-service in February 2008.  The Company currently estimates the final project costs will total approximately $250 million, plus capitalized interest.  The estimated costs include a $40 million contribution in aid of construction (CIAC) to a subsidiary of Energy Transfer, which was paid in January 2008 and is expected to be amortized over the life of the facilities.  Approximately $26.4 million and $12.5 million of costs for this project are included in the line item Construction work-in-progress at December 31, 2007 and 2006, respectively, with $178.3 million closed to Plant in service in December 2007.

Significant Customers

The following table provides the percentage of Transportation and Storage segment Operating revenues and related weighted average contract lives of Panhandle’s significant customers at December 31, 2007:
 
   
Percent of
 
Weighted
 
   
Segment Revenues
 
Average Life
 
   
For Year Ended
 
of Contracts at
 
Customer
 
December 31, 2007 (1)
 
December 31, 2007
 
               
BG LNG Services
    28 %  
16 years (LNG, transportation)
 
ProLiance
    11    
   5.2 years (transportation) 6.9 years (storage)
 
Other top 10 customers
    26    
 N/A
 
Remaining customers
    35    
 N/A
 
  Total percentage
    100 %      
               
____________________
(1)
Panhandle has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s total consolidated operating revenues.



Panhandle’s customers are subject to change during the year as a result of capacity release provisions that allow current customers to release all or part of their capacity, which generally occurs for a limited time period.  Under the terms of Panhandle’s tariffs, a temporary capacity release does not relieve the original customer from its payment obligations if the replacement customer fails to pay.

The following table provides information related to Florida Gas’ significant customers at December 31, 2007:
 
   
Percent of
     
   
Florida Gas'
     
   
Total Operating
 
Weighted
 
   
Revenues
 
Average Life
 
   
For Year Ended
 
of Contracts at
 
Customer
 
December 31, 2007 (1)
 
December 31, 2007
 
               
Florida Power & Light
    40 %     7.3   Years
 
Tampa Electric/Peoples Gas
    16       9.6   Years
 
Other top 10 customers
    28       N/A    
Remaining customers
    16       N/A    
Total percentage
    100 %          
                   
____________________
(1)
The Company accounts for its investment in Florida Gas through its equity investment in Citrus using the equity method.  Accordingly, it reports its share of Florida Gas’ net earnings within Earnings from unconsolidated investments in the Consolidated Statement of Operations.

Regulation and Rates

Panhandle and Florida Gas are subject to regulation by various federal, state and local governmental agencies, including those specifically described below.   See also Item 1A.  Risk Factors – Risks That Relate to the Company’s Transportation and Storage Segment and Item 8.  Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.

FERC has comprehensive jurisdiction over PEPL, Trunkline, Sea Robin, Trunkline LNG, Southwest Gas Storage and Florida Gas as natural gas companies within the meaning of the Natural Gas Act of 1938.  For natural gas companies, FERC’s jurisdiction relates, among other things, to the acquisition, operation and disposition of assets and facilities and to the service provided and rates charged.

FERC has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce.  FERC also has authority over the construction and operation of pipeline and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of service using such facilities.  PEPL, Trunkline, Sea Robin, Trunkline LNG, Southwest Gas Storage and Florida Gas hold certificates of public convenience and necessity issued by FERC, authorizing them to construct and operate the pipelines, facilities and properties now in operation for which such certificates are required, and to transport and store natural gas in interstate commerce.



The following table summarizes the status of the rate proceedings applicable to the Transportation and Storage segment as of December 31, 2007:
 
   
Date of Last
   
Company
 
Rate Filing
 
Status
         
PEPL
 
May 1992
 
Settlement effective April 1997
Trunkline
 
January 1996
 
Settlement effective May 2001
Sea Robin
 
June 2007
 
Ongoing; procedural schedule currently suspended (1)
Trunkline LNG
 
June 2001
 
Settlement effective January 2002 (2)
Southwest Gas Storage
 
August 2007
 
Settlement approved February 2008
Florida Gas
 
October 2003
 
Settlement effective March 2005; rate moratorium in effect until October 2007; required to file by October 2009
         
____________________
(1)
Filed rates put into effect January 1, 2008, subject to refund.
(2)
Settlement provides for a rate moratorium through 2015.

Panhandle and Florida Gas are 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.

For a discussion of the effect of certain FERC orders on Panhandle, see Item 8.  Financial Statements and Supplementary Data, Note 16 – Regulation and Rates – Panhandle.

Competition

The interstate pipeline systems of Panhandle and Florida Gas compete with those of 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, flexibility and reliability of service.

Natural gas competes with other forms of energy available to the Company’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 regulation, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the ongoing demand for natural gas in the areas served by Panhandle and Florida Gas.

Federal and state regulation of natural gas interstate pipelines has changed dramatically in the last two decades and could continue to change over the next several years.  These regulatory changes have resulted, and will likely continue to result, in increased competition in the pipeline business. In order to meet competitive challenges, Panhandle and Florida Gas will need to adapt their marketing strategies, the type of transportation and storage services provided and their pricing and rate responses to competitive forces.  Panhandle and Florida Gas will also need to respond to changes in state regulation in their market areas that allow direct sales to all retail end-user customers or, at a minimum, broader customer classes than now allowed.

FERC may authorize the construction of new interstate pipelines that are competitive with existing pipelines.  A number of new pipeline and pipeline expansion projects are under development to transport large additional volumes of natural gas to the Midwest from the Rockies.  These pipelines, which include Kinder Morgan’s Rockies Express Pipeline project, could potentially compete with the Company.

The Company’s direct competitors include Alliance Pipeline LP, ANR Pipeline Company, Natural Gas Pipeline Company of America, ONEOK Partners, Texas Gas Transmission Corporation, Northern Natural Gas Company, Vector Pipeline, Columbia Gulf Transmission and Midwestern Gas Transmission.

Florida Gas competes in peninsular Florida with Gulfstream, a joint venture of Spectra Energy Corporation and The Williams Companies. Florida Gas also serves the Florida panhandle, where it competes with Gulf South Pipeline Company and the natural gas transportation business of Southern Natural Gas. Florida Gas faces competition, to a lesser degree, from alternate fuels, including residual fuel oil, in the Florida market, as well as from proposed LNG regasification facilities.


Gathering and Processing Segment

Services

SUGS’ operations consist of a network of approximately 4,800 miles of natural gas and NGLs pipelines, four active cryogenic processing plants with a combined capacity of 410 MMcf/d and five active natural gas treating plants with a combined capacity of 470 MMcf/d.  The principal assets of SUGS are located in the Permian Basin of Texas and New Mexico.

SUGS is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGLs, and redelivering natural gas and NGLs to a variety of markets.  SUGS gathers and processes natural gas for approximately 240 customers.  Its primary sales customers include producers, power generating companies, utilities, energy marketers, and industrial users located primarily in the southwestern United States.  SUGS receives natural gas for purchase or gathering and redelivery to market from more than 240 producers and suppliers.  SUGS’ business is not generally seasonal in nature.

As a result of the operational flexibility built into SUGS’ gathering system and plants, it is able to offer a broad array of services to producers, including:

 
·
field gathering and compression of natural gas for delivery to its plants;
 
·
treating, dehydration, sulfur recovery and other conditioning; and
 
·
natural gas processing and marketing of products.

For the year 2007 and the 2006 period subsequent to the March 1, 2006 acquisition, SUGS’ gross margin (Operating revenues net of Cost of gas and other energy) were $210.8 million and $172.2 million, respectively.  For information about operating revenues, EBIT, assets and other financial information relating to the Gathering and Processing segment, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Business Segment Results – Gathering and Processing and Item 8. Financial Statements and Supplementary Data, Note 21 – Reportable Segments.

Significant Customers

The following table provides the percentage of Gathering and Processing segment Operating revenues and related weighted average contract lives of SUGS’ significant customers at December 31, 2007:

   
Percent of
 
Weighted
 
   
Segment Revenues
 
Average Life
 
   
For Year Ended
 
of Firm Contracts at
 
Customer
 
December 31, 2007
 
December 31, 2007
 
             
ConocoPhillips Company  (1)
    16 %  
Month-to-Month
 
Other top 10 customers
    47    
N/A
 
Remaining customers
    37    
N/A
 
Total percentage
    100 %      
               
_______________
(1)
SUGS has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s total consolidated operating revenues.



Natural Gas Connections

SUGS’ major natural gas pipeline interconnects are with ATMOS Pipeline Texas, El Paso Natural Gas Company, Energy Transfer Fuel, LP, DCP Guadalupe Pipeline, LP, Enterprise Texas Pipeline, Northern Natural Gas Company, Oasis Pipeline, LP, ONEOK Westex Transmission, LP, Public Service Company of New Mexico and Transwestern.  Its major NGLs pipeline interconnects are with Chapparal, Louis Dreyfus and Chevron.

Natural Gas Supply Contracts

SUGS’s gas supply contracts primarily include fee-based, percent-of-proceeds, conditioning fee and wellhead contracts, which as of December 31, 2007, comprised 50 percent, 39 percent, 9 percent and 2 percent by volume of its gas supply contracts, respectively.  These gas supply contracts vary in length from month-to-month to a number of years, with many of the contracts having a term of three to five years.

Following is a summary description of the gas supply contracts utilized by SUGS:
 
 
·
Fee-Based.  Under fee-based arrangements, SUGS receives a fee or fees for one or more of the following services:  gathering, compressing, treating or processing natural gas.  The fee or fees are usually based on the volume or level of service provided to gather, compress, treat or process natural gas.  While fee-based arrangements are generally not subject to commodity risk, certain operating conditions as well as provisions of these arrangements, including fuel recovery mechanisms, may subject SUGS to a limited amount of commodity risk.

 
·
Percent-of-Proceeds,  Percent-of-Value or Percent-of-Liquids.  Under percent-of-proceeds arrangements, SUGS generally gathers and processes natural gas from producers for an agreed percentage of the proceeds from the sales of the resulting residue gas and NGLs.  The percent-of-value and percent-of-liquids are variations on this arrangement.  These types of arrangements expose SUGS to some commodity price risk as the costs and revenues from the contracts are directly correlated with the price of natural gas and NGLs.

 
·
Conditioning Fee.  Conditioning fee arrangements provide a guaranteed minimum margin or fee on gas that must be processed for liquid hydrocarbon extraction in order to meet the quality specifications of the transmission pipelines.  In addition to the minimum margin or fee, SUGS keeps all or a large percentage of the value of the NGLs.  The revenue earned is directly related to the processing value of the gas, however, SUGS is kept whole on a minimum value or fee in low processing spread environments.

 
·
Keep-Whole and Wellhead.  A keep-whole arrangement allows SUGS to keep 100 percent of the NGLs produced and requires the return of the processed natural gas, or value of the gas, to the producer or owner.  Since some of the gas is used during processing, SUGS must compensate the producer or owner for the gas shrink entailed in processing by supplying additional gas or by paying an agreed value for the gas utilized.  These arrangements have the highest commodity price exposure for SUGS because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.  As a result, SUGS benefits from these types of arrangements when the value of the NGLs is high relative to the cost of the natural gas and is disadvantaged when the cost of the natural gas is high relative to the value of NGLs.  SUGS has the ability to eliminate its exposure to negative processing spreads by treating, dehydrating and blending the wellhead gas with leaner gas in order to meet downstream transmission pipeline specifications rather than processing the gas.  In situations where the negative processing spread is eliminated, such contracts are referred to as wellhead contracts.

For information related to SUGS use of various derivative financial instruments to manage its commodity price risk and related operating cash flows, see Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment.



Regulation

SUGS’ facilities are not currently regulated by FERC but are subject to oversight by various other governmental agencies, including matters of asset integrity, safety and environmental protection.  The relevant agencies include the U.S. Environmental Protection Agency and its state counterparts, the Occupational Safety and Health Administration and the U.S. Department of Transportation’s Office of Pipeline Safety and its state counterparts.  The Company believes that its gathering and processing operations are in material compliance with applicable safety and environmental statutes and regulations.

Competition

SUGS competes with other midstream service providers and producer-owned midstream facilities in the Permian basin.  The Company’s direct competitors include Targa Resources Partners LP, DCP Midstream Partners, LP (formerly Duke Energy Field Services), Enterprise Texas Field Services, Anadarko Petroleum, Atlas Pipeline Partners, LP and Regency Gas Services.  Industry factors that typically affect the Company’s ability to compete in this segment are:

 
·
contract fees charged,
 
·
pressures maintained on the gathering systems,
 
·
location of the gathering systems relative to competitors and producer drilling activity,
 
·
efficiency and reliability of the operations, and
 
·
delivery capabilities in each system and plant location.

Commodity prices for natural gas and NGLs also play a major role in drilling activity on or near the Company’s gathering and processing systems.  Generally, lower commodity prices will result in less producer drilling activity and conversely, higher commodity prices will result in increased producer drilling activity.

SUGS has responded to these industry conditions by positioning and configuring its gathering and processing facilities to offer a broad range of services to accommodate the types and quality of natural gas produced in the region, while many competing systems provide only a single level of service.

Distribution Segment
Services

The Company’s Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, through Missouri Gas Energy, and Massachusetts, through New England Gas Company.  The utilities serve over 550,000 residential, commercial and industrial customers through local distribution systems consisting of 9,068 miles of mains, 6,096 miles of service lines and 45 miles of transmission lines.  The utilities’ natural gas rates and operations in Missouri and Massachusetts are regulated by the Missouri Public Service Commission (MPSC) and the Massachusetts Department of Public Utilities (MDPU), respectively.

The utilities operations have historically been sensitive to weather and are seasonal in nature, with a significant percentage of annual operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters.  However, the MPSC approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 87 percent of its total customers and approximately 67 percent of its operating revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

For the years ended December 31, 2007, 2006 and 2005, the Distribution segment’s Operating revenues were $732.1 million, $668.7 million and $752.7 million, respectively; average customers served totaled 552,023, 551,604 and 548,514, respectively; and gas volumes sold or transported totaled 83,107 million cubic feet (MMcf), 77,890 MMcf and 84,112 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 Distribution segment or the Company’s total consolidated operating revenues for the years ended December 31, 2007, 2006 and 2005.




For information about operating revenues, EBIT, assets and other financial information relating to the Distribution segment, see Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Business Segment Results – Distribution Segment and Item 8. Financial Statements and Supplementary Data, Note 21 – Reportable Segments.

The Distribution segment customers served, gas volumes sold or transported and weather-related information for the years ended December 31, 2007, 2006 and 2005 are as follows:  

   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
Average number of customers:
                 
Residential
    483,753       482,882       480,381  
Commercial
    66,631       67,120       66,608  
Industrial
    122       129       142  
Total average customers served
    550,506       550,131       547,131  
Transportation customers
    1,517       1,473       1,383  
Total average gas sales and transportation customers
    552,023       551,604       548,514  
                         
Gas sales (MMcf):
                       
Residential
    37,916       34,946       39,160  
Commercial
    15,988       14,938       16,633  
Industrial
    504       517       525  
    Gas sales billed
    54,408       50,401       56,318  
Net change in unbilled gas sales
    1,788       (1,025 )     185  
    Total gas sales
    56,196       49,376       56,503  
Gas transported
    26,911       26,340       27,609  
    Total gas sales and gas transported
    83,107       75,716       84,112  
                         
Gas sales revenues ($ in thousands):
                       
Residential
  $ 495,464     $ 472,926     $ 500,874  
Commercial
    186,987       189,837       201,122  
Industrial
    10,900       11,140       10,499  
    Gas revenues billed
    693,351       673,903       712,495  
Net change in unbilled gas sales revenues
    9,491       (25,681 )     19,561  
    Total gas sales revenues
    702,842       648,222       732,056  
Gas transportation revenues
    12,669       12,253       12,885  
Other revenues
    16,598       8,246       7,758  
    Total operating revenues
  $ 732,109     $ 668,721     $ 752,699  
                         
                         
Weather:
                       
Massachusetts Utility Operations:
                       
Degree days (1)
    5,371       4,901       5,801  
Percent of 10-year measure (2)
    86 %     90 %     106 %
Percent of 30-year measure (2)
    89 %     85 %     101 %
                         
Missouri Utility Operations:
                       
Degree days (1)
    4,776       3,996       4,621  
Percent of 10-year measure (2)
    92 %     77 %     89 %
Percent of 30-year measure (2)
    92 %     77 %     89 %
                         
 ___________________                                             
(1)   "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.
(2)   Information with respect to weather conditions is provided by the National Oceanic and Atmospheric Administration. Percentages of 10-
       and 30-year measures are computed based on the weighted average volumes of gas sales billed.  The 10- and 30-year measures are
       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.




Gas Supply

The cost and reliability of natural gas service are dependent upon the Company's ability to achieve favorable mixes of long-term and short-term gas supply agreements and fixed and variable trans­portation con­tracts.  The Com­pany has been acquiring its gas supplies directly since the mid-1980s when inter­state pipeline sys­tems opened their systems for trans­portation service.  The Company sought to ensure reliable service to customers by developing the ability to dispatch and moni­tor gas volumes on a daily, hourly or real-time basis.

For the year ended December 31, 2007, the majority of the gas requirements for the utility operations of Missouri Gas Energy were delivered under short- and long-term trans­portation contracts through five major pipeline companies and more than 22 commodity suppliers.  For this same period, the majority of the gas requirements for the Massachusetts utility operations of New England Gas Company were delivered under long-term contracts through five major pipeline companies and contracts with four commodity suppliers.  Collectively, these con­tracts have various expira­tion dates ranging from 2009 through 2036.  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.  Missouri Gas Energy and New England Gas Company hold contract rights to over 17 billion cubic feet (Bcf) and 1 Bcf of storage capacity, respectively, to assist in meeting peak demands.

Like the gas industry as a whole, Southern Union utilizes gas sales and/or transportation contracts with interruption provisions, by which 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 by higher priority customers for load management.  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.

Regulation and Rates

The Company’s utilities are regulated as to rates, operations and other matters by the regulatory commissions of the states in which each operates.  In Missouri, natural gas rates are established by the MPSC on a system-wide basis.  In Massachusetts, natural gas rates for New England Gas Company are subject to the regulatory authority of the MDPU.  For additional information concerning recent state and federal regulatory developments, see Item 8.  Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.

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.  Fall River, Massachusetts; Kansas City, Missouri; and St. Joseph, Missouri are the 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 prior to its expiration.  The franchises in Fall River, Massachusetts and St. Joseph, Missouri are perpetual.  Regulatory authorities establish gas service rates so as 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 purchased gas adjustment 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.  The MPSC and MDPU allow such adjustments up to three and two times per year, respectively.

The Company supports any service rate changes that it proposes 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 in these jurisdictions may not reflect the operating costs at the time new rates are put into effect.

Except for Missouri Gas Energy’s residential customers, that are billed a fixed monthly charge for services provided, the Company’s monthly customer bills contain a fixed service charge, a usage charge for service to deliver gas, and a charge for the amount of natural gas used.  Although 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.



In addition to public service commission regu­la­tion of its utility businesses, the Distribution segment is affected by other regula­tions, including pipe­line safety regulations under the Natural Gas Pipeline Safety Act of 1968, the Pipeline Safety Improvement Act of 2002, 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.

The following table summarizes the rate proceedings applicable to the Distribution segment:
 
   
Date of Last
     
Utility Operations
 
Rate Filing
 
Status (1)
 
           
Missouri
 
May 2006
 
MPSC rate order effective April 2007.
 
           
Massachusetts
 
June 2007
 
Settlement effective August 2007.
 
           
_______________
(1)
For more information related to these rate filings, see Item 8.  Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.

Competition

As energy providers, Missouri Gas Energy and New England Gas Company have historic­ally competed with alterna­tive energy sources available to end-users in their service areas, particularly electri­city, propane, fuel oil, coal, NGLs and other refined products.  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 increased due to the volatility of natural gas prices and increased marketing efforts from various energy companies.  Competition among the use of fuel oils, natural gas and propane is generally greater in the Company’s Massachusetts service area than in its Missouri service area. Nevertheless, 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.

OTHER MATTERS

Environmental

The Company is subject to federal, state and local laws and regulations relating to the protection of the environment.  These evolving laws and regulations may require expenditures over a long period of time to con­trol environmental impacts.  The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures.  These procedures are designed to achieve compliance with such laws and regulations.  For additional information concerning the impact of environmental regulation on the Company, see Item 8.  Financial Statements and Supplementary Data, Note 18 – Commitments and Contingencies.

Insurance

The Company maintains insurance coverage provided under its policies similar to other comparable companies in the same lines of business.  The insurance policies are subject to terms, conditions, limitations and exclusions that do not fully compensate the Company for all losses.  Insurance deductibles range from $100,000 to $10 million for the various policies utilized by the Company.


Employees

As of December 31, 2007, the Company had 2,337 employees, of whom 1,513 are paid on an hourly basis and 824 are paid on a salary basis.  Unions represent approximately 50 percent of the 1,513 hourly paid employees.  The table below sets forth the number of employees represented by unions for each division, as well as the expiration dates of the current contracts with the respective bargaining units.

   
Number of employees
 
Expiration of
Company
 
Represented by Unions
 
Current Contract
         
PEPL
       
USW Local 348
 
 215
 
May 27, 2009
   
 
   
Missouri Gas Energy
       
Gas Workers 781
 
 195
 
April 30, 2009
IBEW Local 53
 
 98
 
April 30, 2009
USW Local 5-267
 
 27
 
April 30, 2009
USW Local 12561, 14228
 
 142
 
April 30, 2009
         
New England Gas Company
       
UWUA Local 431
 
 72
 
April 30, 2010
         

As of December 31, 2007, the number of persons employed by each segment was as follows:  Transportation and Storage segment –1,121 persons; Gathering and Processing segment – 317 persons; Distribution segment – 792 persons; All Other subsidiary operations – 12 persons.  In addition, the corporate employees of Southern Union totaled 95 persons.

The employees of Florida Gas are not employees of Southern Union or its segments and, therefore, were not considered in the employee statistics noted above.  As of December 31, 2007, Florida Gas had 301 non-union employees.

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 the years ended December 31, 2007, 2006 or 2005.

Available Information

Southern Union files annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (SEC) as required.  Any document that Southern Union files with the SEC may be read or copied at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549.  Please call the SEC at 1-800-SEC-0330 for information on the public reference room.  Southern Union’s SEC filings are also available at the SEC’s website at http://www.sec.gov and through Southern Union’s website at http://www.sug.com.  The information on Southern Union’s website is not incorporated by reference into and is not made a part of this report.

Southern Union, by and through the audit committee of its board of directors, has adopted a Code of Ethics and Business Conduct (Code) designed to reflect requirements of the Sarbanes-Oxley Act of 2002, New York Stock Exchange rules and other applicable laws, rules and regulations.  The Code applies to all of the Company’s directors, officers and employees. Any amendment to the Code will be posted promptly on Southern Union’s website.



Southern Union, by and through the corporate governance committee of its board of directors, also has adopted Corporate Governance Guidelines (Guidelines).  The Guidelines set forth the responsibilities and standards under which the major board committees and management shall function.  The Code of Ethics and Business Conduct (Code), the Guidelines and the charters of the audit, corporate governance, compensation and finance committees are posted on the Corporate Governance section of Southern Union’s website under “Governance Documents” and are available free of charge by calling Southern Union at (713) 989-2000 or by writing to:

Southern Union Company
Attn: Corporate Secretary
5444 Westheimer Road
Houston, TX 77056


The risks and uncertainties described below are not the only ones faced by the Company. Additional risks and uncertainties that it is unaware of, or that it currently deems immaterial, may become important factors that affect it. If any of the following risks occur, the Company’s business, financial condition, results of operations or cash flows could be materially and adversely affected.
 
RISKS THAT RELATE TO SOUTHERN UNION
 
Southern Union has substantial debt and depends on its ability to access the capital markets.
 
Southern Union has a significant amount of debt outstanding.  As of December 31, 2007, consolidated debt on the Consolidated Balance Sheet totaled $3.5 billion outstanding, compared to total capitalization (long and short-term debt plus stockholders' equity) of $5.7 billion.
 
Some of the Company’s debt obligations contain financial covenants concerning debt-to-capital ratios and interest coverage ratios.  The Company’s failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations or render the Company unable to borrow under certain credit agreements. Any such acceleration or inability to borrow could cause a material adverse change in the Company’s financial condition.
 
The Company relies on access to both short-term and long-term credit as a significant source of liquidity for capital requirements not satisfied by the cash flow from its operations.  Any worsening of the Company’s financial condition or a material decrease in its common stock price could hamper its ability to access the capital markets. External events could also increase the Company’s cost of borrowing or adversely affect its ability to access the capital markets.

Further, because of the need for certain state regulatory approvals in order to incur debt and issue capital stock, the Company may not be able to access the capital markets on a timely basis. Restrictions on the Company’s ability to access capital markets could affect its ability to execute its business plan or limit its ability to pursue improvements or acquisitions on which it may otherwise rely for future growth.

The Company plans to refinance its $425 million of debt maturing in August 2008 with new capital market debt or bank financings.  Alternatively, should the Company not be successful in its refinancing efforts, the Company may choose to retire such debt upon maturity by utilizing some combination of cash flows from operations, draw downs under existing credit facilities, and altering the timing of controllable expenditures, among other things.  The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets, current economic and capital market conditions and market expectations regarding the Company's future earnings and cash flows, that it will be able to refinance and/or retire these obligations under acceptable terms prior to their maturity.  There can be no assurance, however, that the Company will be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings.  Moreover, there can be no assurance the Company will be successful in its implementation of these refinancing and/or retirement plans and the Company's inability to do so would cause a material adverse effect on the Company's financial condition and liquidity.


Credit ratings downgrades could increase the Company’s financing costs and limit its ability to access the capital markets.

As of December 31, 2007, both Southern Union’s and Panhandle’s debt is rated Baa3 by Moody's Investor Services, Inc., BBB- by Standard & Poor's and BBB by Fitch Ratings. If the Company’s credit ratings are downgraded below investment grade or if there are times when it is placed on "credit watch," both borrowing costs and the costs of maintaining certain contractual relationships could increase. Lower credit ratings could also adversely affect the Distribution segment’s relationships with state regulators, who may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

The Company’s growth strategy entails risk for investors.

The Company intends to actively pursue acquisitions in the energy industry to complement and diversify its existing businesses. As part of its growth strategy, Southern Union may:

 
·
examine and potentially acquire regulated or unregulated businesses, including transportation and storage assets and gathering and processing businesses within the natural gas industry;
 
·
enter into joint venture agreements and/or other transactions with other industry participants or financial investors;
 
·
selectively divest parts of its business, including parts of its core operations; and
 
·
continue expanding its existing operations.

The Company’s ability to acquire new businesses will depend upon the extent to which opportunities become available, as well as, among other things:

 
·
its success in bidding for the opportunities;
 
·
its ability to assess the risks of the opportunities;
 
·
its ability to obtain regulatory approvals on favorable terms; and
 
·
its access to financing on acceptable terms.

Once acquired, the Company’s ability to integrate a new business into its existing operations successfully will depend on the adequacy of implementation plans, including the ability to identify and retain employees to manage the acquired business, and the ability to achieve desired operating efficiencies. The successful integration of any businesses acquired in the future may entail numerous risks, including, among others:

 
·
the risk of diverting management's attention from day-to-day operations;
 
·
the risk that the acquired businesses will require substantial capital and financial investments;
 
·
the risk that the investments will fail to perform in accordance with expectations; and
 
·
the risk of substantial difficulties in the transition and integration process.

These factors could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows, particularly in the case of a larger acquisition or multiple acquisitions in a short period of time.

Additionally, if the Company expands its existing operations, the success of any such expansion is subject to substantial risk and may expose the Company to significant costs. The Company cannot assure that its development or construction efforts will be successful.

The consideration paid in connection with an investment or acquisition also affects the Company’s financial results. To the extent it issues shares of capital stock or other rights to purchase capital stock, including options or other rights, existing stockholders may be diluted and earnings per share may decrease. In addition, acquisitions or expansions may result in the incurrence of additional debt.



The Company depends on distributions from its subsidiaries and joint ventures to meet its needs.

The Company is dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from, its subsidiaries and joint ventures (including Citrus) to generate the funds necessary to meet its obligations.  The availability of distributions from such entities is subject to their earnings and capital requirements, the satisfaction of various covenants and conditions contained in financing documents by which they are bound or in their organizational documents, and in the case of the regulated subsidiaries, regulatory restrictions that limit their ability to distribute profits to Southern Union.

The Company owns 50 percent of Citrus, the holding company for Florida Gas.  As such, the Company cannot control or guarantee the receipt of distributions from Florida Gas through Citrus.

The Company is subject to operating risks.

The Company’s operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with natural gas or NGLs, including explosions, pollution, release of toxic substances, fires and other hazards, each of which could result in damage to or destruction of its facilities or damage to persons and property. If any of these events were to occur, the Company could suffer substantial losses. Moreover, as a result, the Company has been, and likely will be, a defendant in legal proceedings and litigation arising in the ordinary course of business. Although the Company maintains insurance coverage, such coverage may be inadequate to protect the Company from all expenses related to these risks.

The Company is subject to extensive federal, state and local laws and regulations regulating the environmental aspects of its business that may increase its costs of operation, expose it to environmental liabilities and require it to make material unbudgeted expenditures.

The Company is subject to extensive federal, state and local laws and regulations regulating the environmental aspects of its business (including air emissions), which are complex and have tended to become increasingly strict over time. These laws and regulations have necessitated, and in the future may necessitate, increased capital expenditures and operating costs. In addition, certain environmental laws may result in liability without regard to fault concerning contamination at a broad range of properties, including those currently or formerly owned, leased or operated properties and properties where the Company disposed of, or arranged for the disposal of, waste.

The Company is currently monitoring or remediating contamination at a number of its facilities and at third party waste disposal sites pursuant to environmental laws and regulations and indemnification agreements.  The Company cannot predict with certainty the sites for which it may be responsible, the amount of resulting cleanup obligations that may be imposed on it or the amount and timing of future expenditures related to environmental remediation because of the difficulty of estimating cleanup costs and the uncertainty of payment by other potentially responsible parties.

Costs and obligations also can arise from claims for toxic torts and natural resource damages or from releases of hazardous materials on other properties as a result of ongoing operations or disposal of waste. Compliance with amended, new or more stringently enforced existing environmental requirements, or the future discovery of contamination, may require material unbudgeted expenditures. These costs or expenditures could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows, particularly if such costs or expenditures are not fully recoverable from insurance or through the rates charged to customers or if they exceed any amounts that have been reserved.

Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and the consequences of the War on Terror and the Iraq conflict may adversely impact the Company’s results of operations.

The impact that terrorist attacks, such as the attacks of September 11, 2001, may have on the energy industry in general, and on the Company in particular, is not known at this time. Uncertainty surrounding military activity may affect the Company’s operations in unpredictable ways, including disruptions of fuel supplies and markets and the possibility that infrastructure facilities, including pipelines, LNG facilities, gathering facilities and processing plants,


could be direct targets of, or indirect casualties of, an act of terror or a retaliatory strike. The Company may have to incur significant additional costs in the future to safeguard its physical assets.

Federal, state and local jurisdictions may challenge the Company’s tax return positions

The positions taken by the Company in its tax return filings require significant judgment, use of estimates, and the interpretation and application of complex tax laws.  Significant judgment is also required in assessing the timing and amounts of deductible and taxable items.  Despite management’s belief that the Company’s tax return positions are fully supportable, certain positions may be successfully challenged by federal, state and local jurisdictions.

The success of the pipeline and gathering and processing businesses depends, in part, on factors beyond the Company’s control.

Third parties own most of the natural gas transported and stored through the pipeline systems operated by Panhandle and Florida Gas.  Additionally, third parties produce all the natural gas or NGLs gathered and processed by SUGS.  As a result, the volume of natural gas transported, stored, gathered or processed depends on the actions of those third parties and is beyond the Company’s control.  Further, other factors beyond the Company’s control may unfavorably impact its ability to maintain or increase current transmission, storage, gathering or processing rates, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity.

The success of the pipeline and gathering and processing businesses depends on the continued development of additional natural gas reserves in the vicinity of their facilities and their ability to access additional reserves to offset the natural decline from existing wells connected to their systems.

The amount of revenue generated by Panhandle and Florida Gas ultimately depends upon their access to reserves of available natural gas. Additionally, the amount of revenue generated by SUGS depends substantially upon the volume of natural gas or NGLs gathered and processed.  As the reserves available through the supply basins connected to these systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission, gathering or processing. Investments by third parties in the development of new natural gas reserves connected to the Company’s facilities depend on many factors beyond the Company’s control.

The pipeline and gathering and processing business revenues are generated under contracts that must be renegotiated periodically.

The revenues of Panhandle, Florida Gas and SUGS are generated under contracts that expire periodically.  Although the Company will actively pursue the renegotiation, extension and/or replacement of all of its contracts, it cannot assure that it will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts.  If the Company is unable to renew, extend or replace these contracts, or if the Company renews them on less favorable terms, it may suffer a material reduction in revenues and earnings.

The expansion of the Company’s pipeline and gathering and processing systems by constructing new facilities subjects the Company to construction and other risks that may adversely affect the financial results of the pipeline and gathering and processing businesses.
 
During 2007, the domestic energy industry experienced an unprecedented level of expansion activity, including new natural gas and LNG pipelines and compression infrastructure projects.  This level of activity is expected to continue for a period of three to four years.  As a result, requirements for material, equipment and construction resources are straining supply and causing significant industry-wide cost increases.  While the Company’s project cost estimates include provisions for cost escalation, future costs are uncertain.  Further, the Company’s construction productivity was adversely affected in 2007 by contractor employee turnover and shortages of experienced contractor staff, as well as other factors beyond the Company’s control, such as weather conditions.  These factors may continue to affect ultimate cost and timing of the Company’s expansion projects through the current construction boom-cycle.


RISKS THAT RELATE TO THE COMPANY’S TRANSPORTATION AND STORAGE BUSINESS

The Company’s transportation and storage business is highly regulated.

The Company’s transportation and storage business is subject to regulation by federal, state and local regulatory authorities. FERC, the U.S. Department of Transportation and various state and local regulatory agencies regulate the interstate pipeline business. In particular, FERC regulates services provided and rates charged by Panhandle and Florida Gas. In addition, the U.S. Coast Guard has oversight over certain issues related to the importation of LNG.

The Company’s rates and operations are subject to regulation by federal regulators as well as the actions of Congress and state legislatures and, in some respects, state regulators. The Company cannot predict or control what effect future actions of regulatory agencies may have on its business or its access to the capital markets. Furthermore, the nature and degree of regulation of natural gas companies has changed significantly during the past 25 years and there is no assurance that further substantial changes will not occur or that existing policies and rules will not be applied in a new or different manner.

Should new regulatory requirements regarding the security of its pipeline system or new accounting requirements for certain entities be imposed, the Company could be subject to additional costs that could adversely affect its business, financial condition or results of operations if these costs are deemed unrecoverable in rates.

The pipeline businesses are subject to competition.

The interstate pipeline businesses of Panhandle and Florida Gas compete with those of 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 the flexibility and reliability of service.  Natural gas competes with other forms of energy available to the Company’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 and Florida Gas.

Substantial risks are involved in operating a natural gas pipeline system.

Numerous operational risks are associated with the operation of a complex pipeline system. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline facilities below expected levels of capacity and efficiency, the collision of equipment with pipeline facilities (such as may occur if a third party were to perform excavation or construction work near the facilities) and other catastrophic events beyond the Company’s control.  In particular, the Company’s pipeline system, especially those portions that are located offshore, may be subject to adverse weather conditions including hurricanes, earthquakes, tornadoes, extreme temperatures and other natural phenomena, making it more difficult for the Company to realize the historic rates of return associated with these assets and operations.  It is also possible that infrastructure facilities could be direct targets or indirect casualties of an act of terror. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.

Fluctuations in energy commodity prices could adversely affect the pipeline businesses.

If natural gas prices in the supply basins connected to the pipeline systems of Panhandle and Florida Gas are higher than prices in other natural gas producing regions, especially Canada, the volume of gas transported by the Company may be negatively impacted.



The pipeline businesses are dependent on a small number of customers for a significant percentage of their sales.

Panhandle’s top three customers accounted for 48 percent of its 2007 revenue.  Florida Gas’ top two customers accounted for 56 percent of its 2007 revenue.  The loss of any one or more of these customers could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.

The Company is exposed to the credit risk of its transportation and storage customers in the ordinary course of business.

Transportation service contracts obligate customers to pay charges for reservation of capacity, or reservation charges, regardless of whether they transport natural gas on the pipeline system. As a result, the Company’s profitability will depend upon the continued financial performance and creditworthiness of its customers rather than just upon the amount of capacity provided under service contracts.

Generally, customers are rated investment grade or, as permitted by the Company’s tariff, are required to make pre-payments or deposits, or to provide collateral, if their creditworthiness does not meet certain criteria.  Nevertheless, the Company cannot predict to what extent future declines in customers' creditworthiness may negatively impact its business.

RISKS THAT RELATE TO THE COMPANY’S NATURAL GAS GATHERING AND PROCESSING BUSINESS

The Company’s natural gas gathering and processing business is unregulated.

Unlike the Company’s returns on its regulated transportation and distribution businesses, the natural gas and NGLs gathering and processing operations conducted at SUGS are not regulated and may potentially have a higher level of risk than the Company’s regulated operations.

Although SUGS operates in an unregulated market, the business is subject to certain regulatory risks, most notably environmental and safety regulations.  Moreover, the Company cannot predict when additional legislation or regulation might affect the gathering and processing industry, nor the impact of any such changes on the Company’s business, financial position, results of operations or cash flows.

The Company’s natural gas gathering and processing business is subject to competition.

The natural gas gathering and processing industry is expected to remain highly competitive.  Most customers of SUGS have access to more than one gathering and/or processing system.  The Company’s ability to compete depends on a number of factors, including the infrastructure and contracting strategy of competitors in the Company’s gathering region; the efficiency, quality and reliability of the Company’s system; and the Company’s ability to maintain a reliable low-cost pipeline operating system.

In addition to SUGS’ current competitive position in the natural gas gathering and processing industry, its business is subject to pricing risks associated with changes in the supply of, and the demand for, natural gas and NGL byproducts.  If natural gas or NGL prices in the supply basins connected to the Company’s gathering system are comparatively higher than prices in other natural gas producing regions, the volume of gas that SUGS chooses to process may be reduced to maximize returns to the Company.  Similarly, since the demand for natural gas or NGLs is primarily a function of commodity prices (including prices for alternative energy sources), customer usage rates, weather, economic conditions and service costs, the volume processed by SUGS may be reduced based on these market conditions on a daily basis after analysis by the Company.

The Company’s profit margin in the natural gas gathering and processing business is highly dependent on energy commodity prices.

SUGS’ gross margin is largely derived from (a) percentage of proceeds arrangements based on the volume of gas gathered and/or NGLs processed through its facilities or (b) specified fee arrangements for a range of services provided.   Under percent-of-proceeds arrangements, SUGS generally gathers and processes natural gas from producers for an agreed percentage of the proceeds from the sales of the resulting residue gas and

 
NGLs. The percent-of-proceeds arrangements, in particular, expose SUGS’ revenues and cash flows to risks associated with the fluctuation of the price of natural gas, NGLs, crude oil and their relationship to each other. 
 
The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:
 
·
the impact of seasonality and weather;
·
general economic conditions;
·
the level of domestic crude oil and natural gas production and consumption;
·
the availability of imported natural gas, NGLs and crude oil;
·
actions taken by foreign oil and gas producing nations;
·
the availability of local, intrastate and interstate transportation systems;
·
the availability of natural gas liquids transportation and fractionation capacity;
·
the availability and marketing of competitive fuels;
·
the impact of energy conservation efforts; and
·
the extent of governmental regulation and taxation.

The Company employs various derivative financial instruments to manage commodity price risk.  The Company uses a combination of fixed price physical forward contracts, exchange-traded futures and options and fixed for floating index and basis swaps to manage commodity price risk.  These derivative financial instruments allow the Company to preserve value and protect margins because changes in the value of the derivative financial instruments are effective in offsetting changes in the physical market and reducing basis risk.  However, these financial derivative instrument contracts do not entirely eliminate pricing risks and, to the extent certain elements of these financial derivative instruments are speculative in nature, may expose the Company to losses or unprotected margins and value diminution.  Moreover, the Company is subject to other risks including un-hedged commodity price changes, market supply shortages and customer defaults.   For information related to derivative financial instruments, see Item 8.  Financial Statements and Supplementary Data – Note 11 Derivative Instruments and Hedging Activities – Gathering and Processing Segment.
 
Operational risks are involved in operating a natural gas gathering and processing business.

Numerous operational risks are associated with the operation of a natural gas gathering and processing business. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of processing facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. It is also possible that infrastructure facilities could be direct targets or indirect casualties of an act of terror. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.

The Company’s natural gas gathering and processing business accepts some credit risk in dealing with customers.

SUGS derives its revenues from customers engaged primarily in the natural gas and utilities industries and extends payment credit to these customers.  SUGS’ accounts receivable primarily consist of mid- to large-size domestic customers with credit ratings of investment grade or better.  Moreover, SUGS maintains trading relationships with counterparties that include reputable U.S. broker-dealers and other financial institutions and evaluates the ability of each counterparty to perform under the terms of the derivative agreements.  Nevertheless, the Company cannot predict to what extent future declines in customers’ creditworthiness may negatively impact its business.

The inability to continue to access independently owned and publicly owned lands could adversely affect the Company’s ability to operate and/or expand its natural gas gathering and processing business.

SUGS’ ability to operate within its operating region will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way. Securing additional rights-of-way is also critical to SUGS’ ability to pursue expansion projects.  SUGS cannot assure that it will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants. The Company’s financial position could be adversely affected if the costs of new or extended rights-of-way grants exceed the margin within a gathering region.

RISKS THAT RELATE TO THE COMPANY’S DISTRIBUTION BUSINESS

The distribution business is highly regulated and the Company’s revenues, operating results and financial condition may fluctuate with the distribution business’ ability to achieve timely and effective rate relief from state regulators.

The Company’s distribution business is subject to regulation by the MPSC and the MDPU. These authorities regulate many aspects of the Company’s distribution operations, including construction and maintenance of facilities, operations, safety, the rates that can be charged to customers and the maximum rates of return that the Company is allowed to realize. The ability to obtain rate increases and rate supplements to maintain the current rate of return depends upon regulatory discretion.
 
 
 
The distribution business is influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, changes in the provision for the allowance for doubtful accounts associated with volatile natural gas costs and other operating costs. The profitability of regulated operations depends on the business’ ability to pass through to its customers costs related to providing them service. To the extent that such operating costs increase in an amount greater than that for which rate recovery is allowed, this differential could impact operating results until the business files for and is allowed an increase in rates. The lag between an increase in costs and the rate relief obtained from the regulators can have a direct negative impact on operating results. As with any request for an increase in rates in a regulatory filing, once granted, the rate increase may not be adequate. In addition, regulators may prevent the business from passing along some costs in the form of higher rates.

The distribution business’ operating results and liquidity needs are seasonal in nature and may fluctuate based on weather conditions and natural gas prices.

The gas distribution business is a seasonal business and is subject to weather conditions. The utilities’ operations have historically been sensitive to weather and are seasonal in nature, with a significant percentage of annual operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters.  However, the MPSC approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 87 percent of its total customers and approximately 67 percent of its operating revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

The business is also subject to seasonal and other variations in working capital due to changes in natural gas prices and the fact that customers pay for the natural gas delivered to them after they use it, whereas the business is required to pay for the natural gas before delivery.  As a result, fluctuations in weather between years may have a significant effect on results of operations and cash flows. In years with warm winters, revenues may be adversely affected.

Operational risks are involved in operating a natural gas distribution business.

Numerous risks are associated with the operations of a natural gas distribution business.  These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of suppliers’ processing facilities below expected levels of capacity or efficiency, the collision of equipment with facilities and catastrophic events such as explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events beyond the Company’s control. It is also possible that infrastructure facilities could be direct targets or indirect casualties of an act of terror. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may be inadequate to cover all liabilities or expenses incurred or revenues lost.

CAUTIONARY FACTORS THAT MAY AFFECT FUTURE RESULTS

The disclosure and analysis in this Form 10-K contains forward-looking statements that set forth anticipated results based on management’s plans and assumptions.  From time to time, Southern Union also provides forward-looking statements in other materials it releases to the public as well as oral forward-looking statements.  Such statements give the Company’s current expectations or forecasts of future events; they do not relate strictly to historical or current facts.  Southern Union has tried, wherever possible, to identify such statements by using words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “will” and similar expressions in connection with any discussion of future operating or financial performance.  In particular, these include statements relating to future actions, future performance or results of current and anticipated services, expenses, interest rates, the outcome of contingencies, such as legal proceedings, and financial results.

Southern Union cannot guarantee that any forward-looking statement will be realized, although management believes that the Company has been prudent in its plans and assumptions.  Achievement of future results is subject to risks, uncertainties and potentially inaccurate assumptions.  If known or unknown risks or uncertainties should materialize, or if underlying assumptions should prove inaccurate, actual results could differ materially from past results and those anticipated, estimated or projected.  Readers should bear this in mind as they consider forward-looking statements.
 
 

Southern Union undertakes no obligation to update publicly forward-looking statements, whether as a result of new information, future events or otherwise. Readers are advised, however, to consult any further disclosures the Company makes on related subjects in its Form 10-K, Form 10-Q and Form 8-K reports to the SEC.  Also note that Southern Union provides the following cautionary discussion of risks, uncertainties and possibly inaccurate assumptions relevant to its businesses.  These are factors that, individually or in the aggregate, management believes could cause the Company’s actual results to differ materially from expected and historical results.  Southern Union notes these factors for investors as permitted by the Private Securities Litigation Reform Act of 1995.  Readers should understand that it is not possible to predict or identify all such factors. Consequently, readers should not consider the following to be a complete discussion of all potential risks or uncertainties.

Factors that could cause actual results to differ materially from those expressed in the Company’s forward-looking statements include, but are not limited to, the following:

 
·
changes in demand for natural gas by the Company’s customers, the composition of the Company’s customer base and in the sources of natural gas available to the Company;
 
·
the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas or natural gas liquid products as well as electricity, oil, coal and other bulk materials and chemicals;
 
·
adverse weather conditions, such as warmer than normal weather in the Company’s service territories, and the operational impact of natural disasters;
 
·
changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies affecting or involving Southern Union, including deregulation initiatives and the impact of rate and tariff proceedings before FERC and various state regulatory commissions;
 
·
the speed and degree to which additional competition is introduced to Southern Union’s business and the resulting effect on revenues;
 
·
the outcome of pending and future litigation;
 
·
the Company’s ability to comply with or to challenge successfully existing or new environmental regulations;
 
·
unanticipated environmental liabilities;
 
·
The Company’s increased exposure to highly competitive commodity businesses through its Gathering and Processing segment;
 
·
the Company’s ability to acquire new businesses and assets and integrate those operations into its existing operations, as well as its ability to expand its existing businesses and facilities;
 
·
the Company’s ability to control costs successfully and achieve operating efficiencies, including the purchase and implementation of new technologies for achieving such efficiencies;
 
·
the impact of factors affecting operations such as maintenance or repairs, environmental incidents, gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;
 
·
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;
 
·
changes in the ratings of the debt securities of Southern Union or any of its subsidiaries;
 
·
changes in interest rates and other general capital markets conditions, and in the Company’s ability to continue to access the capital markets;
 
·
acts of nature, sabotage, terrorism or other acts causing damage greater than the Company’s insurance coverage limits;
 
·
market risks beyond the Company’s control affecting its risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness; and
 
·
other risks and unforeseen events.


N/A




TRANSPORTATION AND STORAGE

See Item 1. Business – Business Segments – 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.

GATHERING AND PROCESSING

See Item 1. Business – Business Segments – Gathering and Processing Segment for information concerning the general location and characteristics of the important physical properties and assets of the Gathering and Processing segment.

DISTRIBUTION

See Item 1. Business – Business Segments – Distribution Segment for information concerning the general location and characteristics of the important physical properties and assets of the Distribution segment.

OTHER

The Company’s other businesses primarily consist of PEI Power Corporation, a wholly-owned subsidiary of the Company, which has ownership interests in two electric power plants that share a site in Archbald, Pennsylvania.  PEI Power Corporation wholly owns one plant, a 25 megawatt electric cogeneration facility fueled by a combination of natural gas and methane, and owns 49.9 percent of the second plant, a 45 megawatt natural gas-fired electric generation facility, through a joint venture with Cayuga Energy.


Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in Item 8.  Financial Statements and Supplementary Data, Note 18 – Commitments and Contingencies.  Also see Item 1A. Risk Factors Cautionary Factors That May Affect Future Results.


N/A




PART II


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 for shares of Southern Union common stock and the cash dividends per share declared in each quarter since January 1, 2006 are set forth below:

   
Dollars per share
 
   
High
   
Low
   
Dividends
 
                   
(Quarter Ended)
                 
December 31, 2007
  $ 33.01     $ 28.46     $ 0.15  
September 30, 2007
    35.05       27.20       0.10  
June 30, 2007
    35.50       30.35       0.10  
March 31, 2007
    30.50       26.81       0.10  
                         
(Quarter Ended)
                       
December 31, 2006
  $ 29.76     $ 26.19     $ 0.10  
September 30, 2006
    27.75       25.83       0.10  
June 30, 2006
    27.22       22.76       0.10  
March 31, 2006
    25.55       22.90       0.10  
                         

Provisions in certain of Southern Union’s long-term debt and bank credit facilities limit the issuance of divi­dends on capital stock.  Under the most restrictive provisions in effect, Southern Union may not declare or issue any 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 and Citrus that could limit Southern Union’s access to funds from Panhandle and Citrus for debt service or dividends.  See Item 8.  Financial Statements and Supplementary Data, Note 13 – Debt Obligations.



COMMON STOCK PERFORMANCE GRAPH
 
The following performance graph compares the performance of Southern Union’s common stock to the Standard & Poor’s 500 Stock Index (S&P 500 Index) and the Bloomberg U.S. Pipeline Index.  The comparison assumes $100 was invested on December 31, 2002 in Southern Union common stock, the S&P 500 Index and in the Bloomberg U.S. Pipeline Index.  Each case assumes reinvestment of dividends.
 
Five Stock Performance Graph
 
 
2002
2003
2004
2005
2006
2007
 
Southern Union
100
117
160
166
199
212
 
S&P 500 Index
100
129
143
150
173
183
 
Bloomberg U.S. Pipeline Index
100
164
209
270
305
353
 
               

The following companies are included in the Bloomberg U.S. Pipeline Index used in the graph:  El Paso Corp., Enbridge, Inc., Equitable Resources, Inc., ONEOK, Inc., Questar Corp., Spectra Energy Corp., TransCanada Corp., and Williams Cos, Inc.

HOLDERS

As of February 22, 2008, there were 5,996 holders of record of Southern Union’s common stock, and 123,772,513 shares of Southern Union’s common stock were issued and outstanding.  The holders of record do not include persons whose shares are held of record by a bank, brokerage house or clearing agency, but do include any such bank, brokerage house or clearing agency that is a holder of record.


EQUITY COMPENSATION PLANS

Equity compensation plans approved by stockholders include the Southern Union Company Second Amended and Restated 2003 Stock and Incentive Plan and the 1992 Long-Term Stock Incentive Plan (1992 Plan).  While Southern Union options are still outstanding under the 1992 Plan, the 1992 Plan expired on July 1, 2002 and no shares are available for future grant thereunder.  Under both plans, stock options are issued having an exercise price equal to the fair market value of the common stock on the date of grant and typically vest ratably over three, four or five years.

The following table sets forth the number of outstanding options and stock appreciation rights (SARs), the weighted-average exercise price of outstanding options and the number of shares remaining available for issuance as of December 31, 2007:

             
   
Number of Securities
     
Number of Securities
   
to Be issued Upon
 
Weighted-Average
 
Remaining Available for
   
Exercise of
 
Exercise Price of
 
Future Issuance Under
Plan Category
 
Outstanding Options/SARs
 
Outstanding Options/SARs
 
Equity Compensation Plans
 
Plans approved by stockholders
 
 
2,076,836     
 
(1)
 
$22.87
 
  
6,304,479
__________________
(1)  Excludes 201,170 shares of restricted stock that were outstanding at December 31, 2007.





                     
For the
               
   
For the years ended
 
 
six months ended
   
For the years ended
   
         
December 31,
         
December 31,
   
June 30,
   
   
2007
   
2006 (1)
   
2005
   
2004 (2)
   
2004
   
2003 (3)
   
   
(In thousands of dollars, except per share amounts)
   
                                       
Total operating revenues
  $ 2,616,665     $ 2,340,144     $ 1,266,882     $ 517,849     $ 1,149,268     $ 596,330    
Earnings from unconsolidated
                                                 
     investments
    100,914       141,370       70,742       4,745       200       422    
Net earnings (loss):
                                                 
Continuing operations (4)
    211,346       199,718       135,731       (1,635 )     51,729       (12,425 )  
Discontinued operations (5)
    -       (152,952 )     (132,413 )     7,723       49,610       88,614    
Available for common stockholders
    211,346       46,766       3,318       6,088       101,339       76,189    
Net earnings (loss) per diluted
                                                 
common share (6):
                                                 
Continuing operations
    1.75       1.70       1.20       (0.02 )     0.63       (0.19 )
 
Discontinued operations
    -       (1.30 )     (1.17 )     0.09       0.61       1.36  
 
Available for common stockholders
    1.75       0.40       0.03       0.07       1.24       1.17    
Total assets
    7,397,913       6,782,790       5,836,819       5,568,289       4,572,458       4,590,938    
Stockholders’ equity
    2,205,806       2,050,408       1,854,069       1,497,557       1,261,991       920,418    
Current portion of long-term debt and
                                                 
capital lease obligation
    434,680       461,011       126,648       89,650       99,997       734,752    
Long-term debt and capital lease
                                                 
obligation, excluding current portion
    2,960,326       2,689,656       2,049,141       2,070,353       2,154,615       1,611,653    
Company-obligated mandatorily
                                                 
redeemable preferred securities
                                                 
of subsidiary trust
    -       -       -       -       -       100,000    
Cash dividends declared on common
                                                 
stock (7)
    53,968       46,289       -       -       -       -    
                                                   
___________________                         
(1)
Includes the impact of significant acquisitions and sales of assets.  See Item 8.  Financial Statements and Supplementary Data, Note 3 – Acquisitions and Sales and Item 8.  Financial Statements and Supplementary Data, Note 19 – Discontinued Operations for information related to the acquisitions and sales.
(2)
The Company’s investment in CCE Holdings, which was accounted for using the equity method, was included in the Company’s Consolidated Balance Sheet at December 31, 2004.  The Company’s share of net income from CCE Holdings was recorded as Earnings from unconsolidated investments in the Company’s Consolidated Statement of Operations since its acquisition on November 17, 2004.  For these reasons, the Consolidated Statement of Operations for the periods subsequent to such acquisition is not comparable to the year of acquisition.
(3)
Panhandle was acquired on June 11, 2003 and was accounted for as a purchase.  The Panhandle assets were included in the Company's Consolidated Balance Sheet at June 30, 2003 and its results of operations have been included in the Company's Consolidated Statement of Operations since its acquisition on June 11, 2003.  For these reasons, the Consolidated Statement of Operations for the periods subsequent to such acquisition is not comparable to the year of acquisition.
(4)
Net earnings from continuing operations are net of dividends on preferred stock of $17.4 million, $17.4 million, $17.4 million, $8.7 million and $12.7 million for the years ended December 31, 2007, 2006 and
  2005, the six months ended December 31, 2004 and the year ended June 30, 2004, respectively.  For additional related information, see Item 8. Financial Statements and Supplementary Data, Note12 – Preferred Securities.
(5)
On August 24, 2006, the Company completed the sales of the assets of its PG Energy natural gas distribution division to UGI Corporation and the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA.  On January 1, 2003, ONEOK acquired the Company’s Southern Union Gas natural gas operating division and related assets.  These dispositions  were accounted for as discontinued operations in the Consolidated Statement of Operations.  For additional related information, see Item 8. Financial Statements and Supplementary Data, Note 19 – Discontinued Operations.
(6)
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 period, adjusted for the five percent stock dividends distributed on September 1, 2005, August 31, 2004, July 31, 2003 and July 15, 2002.
(7)
No cash dividends on common stock were paid during the reporting periods prior to 2006.  See Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities and Item 8.  Financial Statements and Supplementary Data, Note 10 – Stockholders’ Equity – Dividends.




INTRODUCTION

This Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying consolidated financial statements and notes 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 the Company’s business as well as recent developments that the Company believes are important in understanding its results of operations, and to anticipate future trends in those operations.  Subsequent sections include an analysis of the Company’s results of operations on a consolidated basis and on a segment basis for each reportable segment, and information relating to the Company’s liquidity and capital resources, quantitative and qualitative disclosures about market risk and other matters.

The Company’s business purpose is to provide gathering, processing, transportation, storage and distribution of natural gas and NGLs in a safe, efficient and dependable manner.  The Company’s reportable business segments are determined based on the way internal managerial reporting presents the results of the Company’s various businesses to its executive management for use in determining the performance of the businesses and in allocating resources to the businesses as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment.  The Company operates in three reportable segments.

BUSINESS STRATEGY

The Company’s strategy is focused on achieving profitable growth and enhancing stockholder value.  The Company seeks to balance its entrepreneurial focus with respect to maximizing cash and capital appreciation return to shareholders with preservation of its investment grade credit ratings.  The key elements of its strategy include the following:

·
Expanding through development of the Company’s existing businesses.  The Company will continue to pursue growth opportunities through the expansion of its existing asset base, while maintaining its focus on providing safe and reliable service to its customers.  In each of its business segments, the Company identifies opportunities for organic growth through incremental volumes and system enhancements to generate operating efficiencies.  In its interstate transmission and distribution businesses, the Company seeks rate increases and/or improved rate design as appropriate to achieve a fair return on its investment.  See Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Investing Activities for information related to the Company’s principal capital expenditure projects.  See Item 8.  Financial Statements and Supplementary Data, Note 16 – Regulation and Rates for information related to ratemaking activities.
 
·
New initiatives.  The Company regularly assesses strategies to enhance stockholder value, including diversification of earning sources through strategic acquisitions or joint ventures in the diversified natural gas industry.

·
Disciplined capital expenditures and cost containment programs.  The Company will continue to focus on system optimization and cost savings while making prudent capital expenditures across its base of energy infrastructure assets.



RESULTS OF OPERATIONS

Overview

The Company believes that its completed and ongoing expansion of Panhandle’s asset base, its acquisition of Sid Richardson Energy Services on March 1, 2006, its investment in CCE Holdings on November 17, 2004 and the related CCE Holdings redemption transaction with Energy Transfer more fully described below, and the sale of the assets of its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division represent significant steps undertaken by the Company in its transformation into a higher return business with significant growth opportunities.

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is EBIT, which is a non-GAAP measure.  The Company defines EBIT as Net earnings available for common stockholders, adjusted for the following:

 
·
items that do not impact net earnings from continuing operations, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;
 
·
income taxes;
 
·
interest; and
 
·
dividends on preferred stock.

EBIT may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or operating cash flow.

The following table provides a reconciliation of EBIT (by segment) to Net earnings available for common stockholders.  

   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
EBIT:
                 
Transportation and storage segment
  $ 391,029     $ 417,536     $ 281,344  
Gathering and processing segment
    65,368       62,630       -  
Distribution segment
    70,568       41,883       61,698  
Corporate and other
    151       14,324       (11,424 )
Total EBIT
    527,116       536,373       331,618  
Interest expense
    203,146       210,043       128,470  
Earnings from continuing operations before
                       
income taxes
    323,970       326,330       203,148  
Federal and state income taxes
    95,259       109,247       50,052  
Earnings from continuing operations
    228,711       217,083       153,096  
                         
Discontinued operations:
                       
Loss from discontinued operations
                       
before income taxes
    -       (2,369 )     (111,588 )
Federal and state income taxes
    -       150,583       20,825  
Loss from discontinued operations
    -       (152,952 )     (132,413 )
                         
Preferred stock dividends
    17,365       17,365       17,365  
                         
Net earnings available for common stockholders
  $ 211,346     $ 46,766     $ 3,318  
                         

Year ended December 31, 2007 versus the year ended December 31, 2006.  The Company’s $164.6 million increase in Net earnings available for common stockholders was primarily due to:

 
·
Impact of the $153 million loss from discontinued operations in the 2006 period associated with the August 2006 sales of the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division;


 
·
Higher EBIT contributions of $28.7 million from the Distribution segment primarily due to higher net operating revenue resulting from the Missouri Gas Energy rate increase effective April 3, 2007 eliminating the impact of weather and conservation for residential margin revenues;
 
·
Lower interest expense of $6.9 million primarily due to the retirement of debt in 2006 associated with the bridge loan facility entered into to finance the acquisition of the Sid Richardson Energy Services business, partially offset by increased interest expense related to the $600 million Junior Subordinated Notes issued in October 2006 and higher interest expense on Panhandle debt primarily due to higher debt balances; and
 
·
Lower income tax expense from continuing operations of $14 million primarily due to the lower  federal and state effective income tax rate (EITR) of 29 percent in the 2007 period versus 33 percent in the 2006 period primarily due to the tax benefit associated with the increase in the dividends received deduction as a result of increased dividends from the Company’s unconsolidated investment in Citrus.

These earnings improvements were partially offset by:

 
·
Lower EBIT contributions of $26.5 million from the Transportation and Storage segment largely due to the gain on CCE Holdings’ exchange of Transwestern in 2006, partially offset by higher LNG terminalling revenue associated with the Trunkline LNG Phase I and Phase II expansions completed in April 2006 and July 2006, respectively, higher pipeline reservation revenues driven by higher average rates on contracts, higher parking revenues and higher equity earnings from Citrus resulting from the Company’s increased equity ownership in Citrus from 25 percent to 50 percent effective December 1, 2006; and
 
·
Impact of the pre-acquisition pre-tax mark-to-market gain of $37.2 million in the 2006 period on the put options associated with the acquisition of the Sid Richardson Energy Services business, partially offset by $12.8 million of executive bonus compensation awarded and paid in 2006.

Year ended December 31, 2006 versus the year ended December 31, 2005. The Company’s $43.4 million increase in earnings was primarily attributable to improved earnings from Panhandle largely due to higher LNG terminalling revenue resulting from the LNG terminal enhancement construction projects completed during 2006, the earnings contribution from SUGS, which was acquired on March 1, 2006, and increased equity earnings primarily due to the gain on CCE Holdings’ exchange of Transwestern, partially offset by higher interest expense, most of which was related to debt and debt issuance costs associated with the SUGS acquisition, and losses and taxes associated with the sales of the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division.

Business Segment Results

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 from the Gulf Coast to Florida, and LNG terminalling and regasification services.  Prior to the completion of the Redemption Agreement on December 1, 2006, the Transportation and Storage segment also provided service to the Southwest region through its interests in Transwestern.  The Transportation and Storage segment’s operations, now conducted through Panhandle and Florida Gas, are regulated as to rates and other matters by FERC. Demand for gas transmission on Panhandle’s pipeline systems is seasonal, with the highest throughput and a higher portion of annual total operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters.  Florida Gas’ pipeline system experiences the highest throughput in the summer period due to gas-fired generation loads in the second and third calendar quarters. 

Historically, much of the Transportation and Storage segment’s business was conducted through long-term contracts with customers.  Over the past decade, some customers within the segment have shifted to shorter term transportation services contracts.  This overall shift, which can increase the volatility of revenues, is primarily due to changes in market conditions and competition with other pipelines, changing supply sources and volatility in natural gas prices. Average reservation revenue rates realized by the Company are dependent on certain factors, including but not limited to rate regulation, customer demand for reserved capacity, capacity sold levels for a given period and, in some cases, utilization of capacity.  Commodity revenues, which are more short-term sensitive in nature, are dependent upon a number of variable factors including weather, storage levels, and customer demand for firm, interruptible and parking services.  The majority of the Transportation and Storage segment revenues are related to firm capacity reservation charges.  For additional information related to Transportation and Storage segment risk factors and the weighted average remaining lives of firm transportation and storage contracts, see Item 1A. Risk Factors – Risks that Relate to the Company’s Transportation and


Storage Segment, and Item 1. Business – Business Segments – Transportation and Storage Segment, respectively.

The Company’s regulated transportation and storage businesses periodically file for changes in their rates, which are subject to approval by FERC.  Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to negatively impact the Company’s results of operations and financial condition.  For information related to the status of current rate filings, see Item 1.  Business – Business Segments – Transportation and Storage Segment.

The following table illustrates the results of operations applicable to the Company’s Transportation and Storage segment for the periods presented:
 
   
Years Ended December 31,
 
Transportation and Storage Segment
 
2007
   
2006
   
2005
 
   
(In thousands)
 
                   
Operating revenues
  $ 658,446     $ 577,182     $ 505,233  
                         
Operating expenses
    252,903       206,181       204,711  
Depreciation and amortization
    85,641       72,724       62,171  
Taxes other than on income
                       
and revenues
    29,699       25,405       28,196  
Total operating income
    290,203       272,872       210,155  
Earnings from unconsolidated
                       
investments
    99,222       141,310       70,618  
Other income, net
    1,604       3,354       571  
EBIT
  $ 391,029     $ 417,536     $ 281,344  
                         
Operating information:
                       
Panhandle natural gas volumes transported
                       
(in trillion British thermal units (TBtu))
    1,454       1,180       1,214  
CCE Holdings natural gas volumes transported (TBtu) (1)
                 
Florida Gas
    751       737       699  
Transwestern
    -       572       589  
                         
_____________
(1)
Represents 100 percent of Florida Gas and Transwestern natural gas volumes transported versus the Company’s effective equity ownership interests.  The Company’s effective equity ownership interests in Florida Gas and Transwestern were 25 percent and 50 percent, respectively, until December 1, 2006, when the Company’s indirect interest in Transwestern was transferred to Energy Transfer, increasing the Company’s effective indirect ownership interest in Florida Gas to 50 percent.

See Item 1. Business – Business Segments – Transportation and Storage Segment for additional related
operational and statistical information associated with the Transportation and Storage segment.

Year ended December 31, 2007 versus the year ended December 31, 2006.  The $26.5 million EBIT reduction in the year ended December 31, 2007 versus the same period in 2006 was primarily due to lower equity earnings from unconsolidated investments of $42.1 million, now primarily consisting of the Company’s investment in Citrus, offset by improved contributions from Panhandle totaling $15.6 million.

Panhandle’s $15.6 million EBIT increase was primarily related to the following items:

·
Higher operating revenues of $81.3 million as the result of:
·     
Increased transportation and storage revenue of $59.8 million attributable to:
 
o
Higher transportation reservation revenues of $27.4 million primarily due to reduced discounting resulting in higher average rates realized on contracts driven by higher customer demand and utilization of contract capacity;
 
o
Higher parking revenues of $18 million resulting from customer demand for parking services and market conditions;
 
o
Higher storage revenues of $7.8 million due to increased contracted capacity; and


 
o
Higher other commodity revenues of $6.5 million due to higher throughput volumes including transportation of higher LNG volumes on Trunkline, higher volumes on Sea Robin due to adverse hurricane impacts on 2006 throughput, and higher throughput on Panhandle due to storage refill activity.
·
A $23.6 million increase in LNG terminalling revenue based on a capacity increase on the BG LNG Services contract as a result of the Trunkline LNG Phase I and Phase II expansions, which were placed in service in April 2006 and July 2006, respectively, as well as higher volumes resulting from an increase in LNG cargoes; and
·
A decrease in other revenue of $2.2 million primarily due to higher operational sales of gas in 2006.

These increased revenues were offset by:

·
Higher operating expenses of $46.7 million as the result of:
 
o
A $15.6 million increase in corporate services costs relating to Southern Union’s disposition of certain assets during 2006, resulting in a larger allocation of corporate services costs to the remaining business units;
 
o
A $13.1 million increase in contract storage costs attributable to an increase in leased capacity;
 
o
A $6.2 million increase in LNG power costs resulting from increased cargoes;
 
o
A $3.4 million increase in fuel tracker costs primarily due to a net under-recovery in 2007;
 
o
A $2.4 million net increase in labor and benefits primarily due to incentive and merit increases; and
 
o
A $1.8 million increase in insurance due to higher premiums.
·
Increased depreciation and amortization expense of $12.9 million due to a $411.2 million increase in property, plant and equipment placed in service in 2007.  Depreciation and amortization expense is expected to continue to increase primarily due to higher capital spending, including compression modernization and other expenditures; and
·
Higher taxes other than on income of $4.3 million primarily due to a $2.8 million refund received in 2006 for franchise and sales taxes and higher property and compressor fuel taxes in 2007.

Equity earnings were lower by $42.1 million in 2007 versus 2006 primarily due to the following items, adjusted where applicable to reflect the Company’s proportionate equity share:

·
$74.8 million nonrecurring gain in 2006 resulting from the transfer of Transwestern to Energy Transfer in December 2006 in connection with the redemption of Energy Transfer’s interest in CCE Holdings pursuant to the Redemption Agreement;
·
$28 million of earnings in 2006 attributable to Transwestern;
·
Higher equity earnings of approximately $42 million from Citrus’ core business largely due to the increase in the Company’s effective ownership from 25 percent to 50 percent as a result of the transactions under the Redemption Agreement, which closed in December 2006;
·
A $7.6 million gain in 2007 related to a reduction in a previously established liability to Enron associated with the Duke lawsuit;
·
A gain of $7.5 million recognized by Citrus in 2007 associated with settlement of the Duke lawsuit; and
·
A $3.6 million gain in 2007 related to the sale of Enron bankruptcy claim receivables.

The Company’s indirect interest in Transwestern was transferred to Energy Transfer in December 2006 in connection with the redemption of Energy Transfer’s interest in CCE Holdings pursuant to the Redemption Agreement.

Year ended December 31, 2006 versus the year ended December 31, 2005.  The $136.2 million EBIT improvement in the year ended December 31, 2006 versus the same period in 2005 was primarily due to improved contributions from Panhandle totaling $65.5 million and higher equity earnings from the Company’s investment in CCE Holdings of $70.7 million, including a $74.8 million non-recurring gain.

Panhandle’s $65.5 million EBIT improvement was primarily related to the following items:

·
Higher operating revenues of $71.9 million primarily due to:
 
o
A $49.3 million increase in LNG terminalling revenue primarily due to expanded vaporization capacity, a base capacity increase on the BG LNG Services contract and higher volumes resulting from an increase in LNG cargoes;


 
o
Increased transportation and storage revenue of $17 million due to higher reservation revenues of $15.6 million, which were primarily driven by higher average rates on contracts, higher parking revenues of $1.6 million and higher storage revenues of $4.7 million due to increased contracted capacity.  These increases were partially offset by lower usage revenues of $4.9 million, of which $3.1 million resulted from the 2006 impact on Sea Robin in 2006 of the hurricanes that occurred in the third quarter of 2005 and $1.8 million resulted from lower overall capacity utilization at Trunkline; and
 
o
Increased other revenue of $5.7 million primarily due to $3.7 million of non-recurring operational sales of gas in 2006 and $1.1 million of higher liquids revenue.

·
Higher operating expenses of $1.5 million primarily due to:
 
o
Approximately $3.2 million of higher pipeline integrity assessment costs;
 
o
Approximately $1.6 million of higher maintenance project costs;
 
o
$1.3 million for 2006 inspections of facilities due to Hurricane Rita;
 
o
$2.1 million of higher LNG fuel and electric power tracker costs associated with greater LNG cargo activity;
 
o
A $3.8 million nonrecurring adjustment in 2005 for lower vacation accruals due to a change in vacation pay practice; and
 
o
Favorable offsetting impact of a $9.7 million decrease in insurance related costs due to accrued losses recorded in 2005 associated with the hurricanes and lower 2006 premiums and a $4.4 million decrease in benefit costs primarily related to lower postretirement benefit expenses including the impact of enactment of Medicare Part D reimbursements and benefit plan changes;
·
Increased depreciation and amortization expense of $10.6 million due to an increase in property, plant and equipment placed in service in 2006, including the Trunkline LNG Phase I and Phase II expansions;
·
Favorable offsetting impact of decreased taxes other than on income of $2.8 million primarily due to refunds of franchise and sales taxes received in 2006; and
·
Favorable offsetting impact of a $2.8 million increase in other income, net primarily due to a gain on sale of certain Trunkline assets in 2006.

Equity earnings were higher by $70.7 million primarily due to:

·
A nonrecurring gain of $74.8 million resulting from the transfer of Transwestern pursuant to the Redemption Agreement in 2006;
·
Higher earnings from Florida Gas of $5.5 million, $2.8 million of which related to the December 2006 incremental earnings resulting from the Company’s additional 25 percent indirect ownership interest in Florida Gas as a result of the transactions under the Redemption Agreement;
·
Lower earnings from discontinued operations of $10.6 million (adjusted to reflect the Company’s 50 percent share) related to Transwestern primarily due to:
 
o
Lower net revenues of $4.8 million primarily related to the $8 million impact of a decrease in transportation volumes associated with the replacement of expired contracts at discounted rates, partially offset by $3.2 million of increased operational gas sales revenue;
 
o
Higher operating expense of $5.5 million primarily related to higher system balancing expenses of $3.7 million and $2 million of higher electricity costs due to the addition of San Juan compression;
 
o
A decrease of $1.9 million in net earnings attributable to Transwestern because 2006 contained only eleven months versus a full year of operations in 2005 due to the redemption of Transwestern on December 1, 2006; and
 
o
Favorable offsetting impact of lower depreciation expense of $2.4 million due to the cessation of depreciation on Transwestern following the execution of the Redemption Agreement with Energy Transfer.



Gathering and Processing Segment.  The Gathering and Processing segment is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGLs, and redelivering natural gas and NGLs to a variety of markets. The results of operations provided by SUGS have been included in the Consolidated Statement of Operations since its March 1, 2006 acquisition.

The following table presents the results of operations applicable to the Company’s Gathering and Processing segment:
 
   
Years Ended December 31,
 
Gathering and Processing Segment
 
2007
   
2006 (1)
 
             
             
Gross margin  (2)
  $ 210,780     $ 172,152  
Operating expenses
    84,550       61,428  
Depreciation and amortization
    59,560       47,321  
Taxes other than on income and revenues
    2,742       2,156  
Total operating income
    63,928       61,247  
Earnings (loss) from unconsolidated investments
    1,300       (188 )
Other income, net
    140       1,571  
EBIT
  $ 65,368     $ 62,630  
                 
                 
Operating Statistics:
               
Volumes
               
Avg natural gas processed (MMBtu/d)
    426,097       451,675  
Avg NGLs produced (gallons/d)
    1,337,450       1,423,138  
Avg natural gas wellhead (MMBtu/d)
    637,794       585,185  
Natural gas sales (MMBtu)
    105,677,108       113,362,236  
NGLs sales (gallons)
    469,907,600       421,896,247  
                 
Average Pricing
               
Realized natural gas ($/MMBtu)
  $ 6.26     $ 5.83  
Realized NGLs ($/gallon)
    1.13       0.97  
Natural Gas Daily WAHA ($/MMBtu)
    6.35       5.78  
Natural Gas Daily El Paso ($/MMBtu)
    6.20       5.68  
Estimated plant processing spread ($/gallon)
    0.55       0.43  
                 
________________
(1)   Represents results of operations for the period March 1, 2006 (date of acquisition) through December 31, 2006.
(2) 
Gross margin consists of Operating revenues less Cost of gas and other energy.  The Company believes that this measurement is more meaningful for understanding and analyzing the Gathering and Processing segment’s operating results for the periods presented because commodity costs are a significant factor in the determination of the segment’s revenues.

Year ended December 31, 2007 versus the year ended December 31, 2006.  The $2.7 million EBIT increase for the year ended December 31, 2007 versus the post-acquisition ten-month period ended December 31, 2006 was primarily due to the following items:

·
Gross margin was higher by $38.6 million primarily due to:
 
o
Realization of operating results for the complete twelve-month period in 2007 versus ten months in the 2006 period;
 
o
Favorable impact of market-driven higher average realized natural gas and NGLs prices of $6.26 per MMBtu and $1.13 per gallon in the 2007 period versus $5.83 per MMBtu and $0.97 per gallon in the 2006 period, respectively; and
 
o
Higher producer fee revenues of $5 million primarily due to increased volumes from the Atoka producing region associated with the Company’s Mi Vida system.


The favorable gross margin impact was partially offset by unusually high levels of fuel, flare and unaccounted for gas losses in the 2007 period versus the 2006 period primarily attributable to capacity and treating limitations experienced during 2007 at the Jal Plant treating facility;

·
Operating expenses were higher by $23.1 million primarily due to:
 
o
Incurrence of twelve months of activity in the 2007 period versus ten months in the 2006 period;
 
o
A $4.9 million increase in corporate services costs relating to Southern Union’s disposition of certain assets during 2006, resulting in a larger allocation of corporate services costs to the remaining business units; and
 
o
Increases in operating costs such as employee labor and benefit costs and contractor services costs resulting from competitive forces within the midstream energy industry, as well as higher costs incurred for chemical and lubricant petroleum products used in SUGS’ gathering and processing operations;
·
Depreciation and amortization expense was higher by $12.2 million primarily due to the incurrence of twelve months of activity in the 2007 period versus ten months in the 2006 period and a $57.5 million increase in property, plant and equipment placed in service in 2007;
·
Earnings (loss) from unconsolidated investments increased by $1.5 million primarily due to the Company’s proportionate equity share of $463,000 related to a settlement with a producer for damages incurred from sour gas delivered into the Grey Ranch facility and the benefit derived from improved operating efficiencies realized at the Grey Ranch facility; and
·
Other income, net decreased by $1.4 million primarily due to approximately $911,000 of lower interest income resulting from higher available cash balances for investment purposes in the 2006 period versus the 2007 period, principally due to the $53.7 million of cash on hand at the March 1, 2006 acquisition date.
 
To alleviate the treating limitations discussed above related to the Jal Plant, the Company completed construction of an 18-mile, 16-inch high pressure pipeline to utilize existing treating capacity at the Keystone Plant.  The pipeline was put into service on June 21, 2007 at an approximate cost of $6.1 million.  The Company is exploring other expansion opportunities to provide additional growth capacity and further improve system operating efficiency.
 
Economic Hedging Activities.  The Company realizes NGL and/or natural gas volumes from its contractual arrangements associated with gas processing services it provides.  The Company utilizes various economic hedge techniques to manage its price exposure of Company owned volumes, including processing spread puts and natural gas swaps.  Expected NGL and/or natural gas volumes compared to the actual volumes sold and the effectiveness of the associated economic hedges utilized by the Company can be unfavorably impacted by:

 
·
Processing plant outages;
 
·
Higher than anticipated FF&U efficiency levels;
 
·
Impact of commodity prices in general;
 
·
Lower than expected recovery of NGLs from the residue gas stream; and
 
·
Lower than expected recovery of natural gas volumes to be processed.

For the purpose of reducing its processing spread exposure, the Company purchased put options for the period February 1, 2008 through December 31, 2008.  The put options reduce its processing spread exposure on 11,075 MMBtu/day, or approximately 25 percent of the Company's expected NGLs sales volumes based on 2007 historical processing trends.  The put options set a floor for the Company’s processing spread at $8.15 per MMBtu for such volumes.  The cost of the December 2007 transaction was $5.2 million, or $1.41 per MMBtu.

Additionally, in February 2008, for the period March 1, 2008 through December 31, 2008, the Company entered into various natural gas swaps which have reduced its commodity price exposure related to 30,000 MMBtu/day.  The natural gas swaps have effectively established an average fixed index price at locations where we sell natural gas, at the “basis adjusted price” of $8.28 per MMBtu for the related period.  The combination of the processing spread put option with an equal MMBtu portion of the natural gas swap effectively establishes a floor of $15.02 per MMBtu for 25 percent of the Company’s expected NGL sales volumes as noted above.  In February 2008, the Company also entered into natural gas swaps associated with 10,000 MMBtu/day for the period January 1, 2009 through December 31, 2009, fixing the 2009 basis adjusted sales price of such volumes at $8.19 per MMBtu.

For further information related to SUGS’ commodity-based put options and non-heding derivative instruments, see Item 8. Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment.





Distribution Segment.  The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.  The Company’s utilities operations are regulated as to rates and other matters by the regulatory commissions of the states in which each operates.  For information related to the status of current rate filings relating to the Distribution segment, see Item 1.  Business – Business Segments – Distribution Segment. The utilities operations have historically been sensitive to weather and are seasonal in nature, with a significant percentage of annual operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters.  However, the MPSC approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 87 percent of its total customers and approximately 67 percent of its operating revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

The following table illustrates the results of operations applicable to the Company’s Distribution segment for the periods presented:
 
   
Years Ended December 31,
 
Distribution Segment
 
2007
   
2006
   
2005
 
   
(In thousands)
 
                   
Net operating revenues   (1)
  $ 222,097     $ 174,584     $ 184,257  
                         
Operating expenses
    108,788       90,178       87,306  
Depreciation and amortization
    30,251       30,353       29,447  
Taxes other than on income
                       
and revenues
    10,588       10,040       3,208  
Total operating income
    72,470       44,013       64,296  
Other income (expenses), net
    (1,902 )     (2,130 )     (2,598 )
EBIT
  $ 70,568     $ 41,883     $ 61,698  
                         
___________________
(1)  Operating revenues for the Distribution segment are reported net of Cost
   
       of gas and other energy and Revenue-related taxes, which are both pass-through costs.

See Item 1. Business – Business Segments – Distribution Segment for additional related operational and statistical information related to the Distribution segment.

Year ended December 31, 2007 versus the year ended December 31, 2006.  The $28.7 million EBIT improvement in the year ended December 31, 2007 versus the same period in 2006 was primarily due to the following items:

·
Net operating revenues increased $47.5 million primarily due to the Missouri Gas Energy $27.2 million annual revenue rate increase effective April 3, 2007 and higher consumption volumes resulting from colder weather in 2007 versus 2006 as evidenced by a 13.8 percent increase in consumption volumes and a 14 percent increase in degree days;
·
The net operating revenues increase was partially offset by higher operating expenses of $18.6 million in the 2007 period versus the 2006 period primarily due to:
 
o
Increased benefit costs of approximately $7.1 million primarily due to higher pension costs resulting from the recent Missouri Gas Energy rate case;
 
o
Increased general expenses of approximately $4.5 million primarily due to cathodic protection maintenance, the establishment of a customer education program for energy efficiency associated with the 2007 rate case and other costs;
 
o
Increased labor expenses of approximately $5.5 million primarily due to the filling of vacant positions and incentive and merit increases in 2007 versus 2006;
 
o
Higher uncollectible accounts of approximately $1.8 million resulting primarily from higher revenues realized in the 2007 period versus the 2006 period.





Year ended December 31, 2006 versus the year ended December 31, 2005.  The $19.8 million EBIT reduction in the year ended December 31, 2006 versus the same period in 2005 was primarily due to the following items:

·
Net operating revenues were $9.7 million lower primarily due to a 12.6 percent reduction in consumption volumes resulting from the warmer than normal weather, as evidenced by a 15 percent reduction in degree days;
·
Higher taxes other than on income and revenues of $6.8 million primarily due to refunds received for Missouri property tax settlements in 2005; and
·
Higher operating expenses of $2.9 million primarily due to higher bad debt expenses of $900,000 due to the residual effects of higher gas prices in the 2005 to 2006 winter season and higher general expenses in 2006 of $1.3 million primarily due to higher corrosion control costs resulting from drier weather in 2006 compared to 2005.

Corporate and Other

Year ended December 31, 2007 versus the year ended December 31, 2006.  The $14.2 million EBIT reduction for the year ended December 31, 2007 versus the same period in 2006 was primarily due to the following items:

·
Impact of a mark-to-market gain in 2006 of $37.2 million on put options for the pre-acquisition period associated with the March 1, 2006 acquisition of the Sid Richardson Energy Services business; and
·
Favorable offsetting impact of a decrease in operating expenses in 2007 versus 2006 due to executive bonus compensation of $12.8 million awarded by the compensation committee of the Company’s Board of Directors in 2006 in respect of transactional activity and a $10.7 million increase in corporate services costs allocated to the Company’s business units in 2007.

Year ended December 31, 2006 versus the year ended December 31, 2005.  The $25.7 million EBIT improvement for the year ended December 31, 2006 versus the same period in 2005 was primarily due to the following items:

·
A mark-to-market gain of $37.2 million on put options for the pre-acquisition period associated with the March 1, 2006 acquisition of Sid Richardson Energy Services;
·
Negative impact of $12.8 million of executive bonus compensation awarded and paid in 2006;
·
Negative impact of a $6.5 million write-down in the carrying value of the Scranton corporate building recorded in 2006;
·
Negative impact of $1.4 million of corporate stock-based compensation costs resulting from the implementation of and accounting under Financial Accounting Standards Board (FASB) Statement No. 123(R), Accounting for Stock-Based Compensation in 2006;
·
Impact of $3.8 million of non-cash compensation expense in the third quarter of 2005 related to separation agreements with former executives of the Company; and
·
Charges of $6.3 million in the first quarter of 2005 to: (i) reserve for an other-than-temporary impairment in the Company’s investment in a technology company, and (ii) record a liability for the guarantee by a subsidiary of the Company of a line of credit between the technology company and a bank.

Interest Expense

Year ended December 31, 2007 versus the year ended December 31, 2006.  Interest expense was $6.9 million lower in 2007 compared with 2006 primarily due to:

·
Impact of interest expense of $49.2 million and debt issuance cost amortization of $7.8 million in 2006 associated with the bridge loan facility entered into to finance the acquisition of the Sid Richardson Energy Services business, which was retired using approximately $1.1 billion in net proceeds from the sale of certain assets in August 2006 and funds obtained in October 2006 from the issuance of the $600 million Junior Subordinated Notes;
·
Lower interest expense of $6 million associated with borrowings under the Company’s credit agreements primarily due to lower average outstanding balances in 2007 compared to 2006;
·
Lower interest expense of $2.2 million due to the retirement of the 2.75% Senior Notes in August 2006;


·
Lower interest expense of $1.6 million associated with interest owed to Missouri Gas Energy’s ratepayers in connection with its purchased gas cost recovery mechanism primarily due to higher levels of overcollections in 2006;
·
Partially offset by increased interest expense of $34.9 million related to the $600 million Junior Subordinated Notes issued in October 2006;
·
Partially offset by increased interest expense of $20.6 million related to Panhandle debt primarily due to higher debt balances in 2007 versus 2006; and
·
Partially offset by increased interest expense of $4.8 million under the 6.15% Senior Notes issued in August 2006.

Year ended December 31, 2006 versus the year ended December 31, 2005.  Interest expense was $81.6 million higher in 2006 compared with 2005 primarily due to:

·
Interest expense of $49.2 million and debt issuance cost amortization of $7.8 million associated with the bridge loan facility entered into to finance the acquisition of the Sid Richardson Energy Services business;
·
Increased interest expense of $10.8 million related to Panhandle debt primarily due to higher average interest rates in 2006 versus 2005;
·
Interest expense of $2.5 million under the $465 million 2006 Term Loan;
·
Interest expense of $8.3 million related to the $600 million Junior Subordinated Notes issued in 2006; and
·
Increased interest expense of $4.4 million associated with borrowings under the Company’s credit agreements primarily due to higher average outstanding balances and higher interest rates in 2006 compared to 2005.

Federal and State Income Taxes from Continuing Operations  

Year ended December 31, 2007 versus the year ended December 31, 2006.  The EITR from continuing operations for the years ended December 31, 2007 and 2006 was 29 percent and 33 percent, respectively. The decrease in the EITR from continuing operations was primarily due to:

·
Tax benefits of $30.9 million in 2007 versus $11.5 million in 2006 associated with the increase in the dividends received deduction as a result of increased dividends from the Company’s unconsolidated investment in Citrus;
·
Reduced tax expense of $523,000 in 2007 versus $5.4 million in 2006 associated with the decrease in nondeductible executive compensation; and
·
Partially offset by the release of $9.4 million of tax reserves in 2006 for uncertain tax positions established in prior years due to the completion of the Internal Revenue Service (IRS) audit for the fiscal year ended June 30, 2003 and expiring state statutes.

Year ended December 31, 2006 versus the year ended December 31, 2005.  The EITR from continuing operations for the years ended December 31, 2006 and 2005 was 33 percent and 25 percent, respectively.  The fluctuation in the EITR from continuing operations was primarily due to:

·
The release in 2005 of an $11.9 million valuation allowance, which was originally established in 2004 for a deferred tax asset related to the difference between the book and tax basis of the Company’s investment in CCE Holdings.  The Company determined that this valuation allowance was no longer necessary because the book income from CCE Holdings was substantially greater than the taxable income for 2005 and was expected to continue to be higher for the foreseeable future;
·
The release in 2006 of $9.4 million of tax reserves for uncertain tax positions established in prior years due to the completion of the IRS audit for the fiscal year ended June 30, 2003 and expiring state statutes; and
·
$5.4 million of additional taxes resulting from the $14.5 million of non-deductible executive compensation paid in 2006.

IRS Audit.

In November 2006, the IRS completed its examination of the Company’s federal income tax return for the fiscal year ended June 30, 2003.  The Company realized a favorable settlement regarding the like-kind exchange structure under Section 1031 of the Internal Revenue Code related to the sale of the assets of its Southern Union


Gas natural gas operating division and related assets to ONEOK Inc. for approximately $437 million in January 2003 and the acquisition of Panhandle in June 2003.

The Company was successful in sustaining all but $26.3 million of the original estimated $90 million of income tax deferral associated with the like-kind structure.  However, the Company’s net tax due to the IRS was reduced to $11.6 million, plus interest, primarily due to alternative minimum tax credits and other favorable audit results.  As a result of the IRS examination, the Company paid $12.6 million of income tax to the IRS in November 2006, received a refund of $1 million from the IRS and paid $1.4 million to state and local jurisdictions in 2007.  The Company also paid $2.4 million ($1.5 million net of tax) in 2007 representing interest payable to the IRS, and state and local jurisdictions as a result of the IRS examination of the year ended June 30, 2003.  No penalties were assessed against the Company in this IRS examination.
 
The Company will be entitled to recover a corresponding $26.3 million of future income tax benefit over time from additional depreciation deductions in respect of the Panhandle assets due to the higher tax basis in such assets as a result of the reduction of income tax benefits from the like-kind exchange.