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.

Net Earnings from Discontinued Operations

Earnings (loss) from discontinued operations included in the 2006 period are associated with 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, which were sold in August 2006.  See Item 8.  Financial Statements and Supplementary Data, Note 19 – Discontinued Operations for additional information.

Year ended December 31, 2006 versus the year ended December 31, 2005.  Earnings from discontinued operations before income taxes for the year ended December 31, 2006 versus the same period in 2005 were $109.2 million higher primarily due to the $175 million goodwill impairment recognized in 2005, partially offset by a loss of $56.8 million resulting from the sales of assets in 2006 and lower earnings of $8.9 million primarily due to the inclusion of a full year of activity in 2005 versus activity only through August 24 in 2006.  Significant components contributing to the $56.8 million loss include $19.4 million of asset impairment charges related to increases in plant, property and equipment during 2006, selling costs of $4.7 million, and charges associated with pre-closing arrangements between the Company and UGI Corporation and National Grid USA, principally consisting of $15.1 million of pension funding requirements and $5.8 million of premiums related to early retirement of debt.

The Company’s EITR from discontinued operations was significantly higher in 2006 compared to 2005 primarily due to the following items that resulted from the sale of the assets of the PG Energy natural gas distribution division and the Rhode Island operations of the New England Gas Company natural gas distribution division:

·
The Company incurred $142.4 million of income tax expense in 2006 resulting from $379.8 million of non-deductible goodwill related to the disposition of these assets in 2006 compared to $65.6 million of income tax expense resulting from $175 million of non-deductible goodwill impairment related to these assets recorded in 2005; and
·
The Company incurred income tax expense of $17.6 million in 2006 as a result of the write-off of a tax-related regulatory asset of PG Energy.

LIQUIDITY AND CAPITAL RESOURCES

Cash generated from internal operations constitutes the Company’s primary source of liquidity.  The Company’s $515.4 million working capital deficit at December 31, 2007 is primarily comprised of $425 million of debt maturing in August 2008.  The Company plans to refinance its $425 million of debt maturing in August 2008 with new capital market debt or bank financings.  See Item 1A. Risk Factors for additional information related to the refinancing.  Additional sources of liquidity include use of available credit facilities, project and bank financings and proceeds from asset dispositions.  The availability and terms relating to such liquidity will depend upon various factors and conditions such as the Company’s combined cash flow and earnings, the Company’s resulting capital structure and conditions in the financial markets at the time of such offerings. Acquisitions, which generally require a substantial increase in expenditures, and related financings also affect the Company’s combined results. Future acquisitions or related financings or refinancings may involve the issuance of shares of the Company’s common stock, which could have a dilutive effect on the then-current stockholders of the Company.



Operating Activities

Year ended December 31, 2007 versus the year ended December 31, 2006.  Cash flows provided by operating activities were $470.4 million for the year ended December 31, 2007 compared with cash flows provided by operating activities of $458.8 million for the same period in 2006.  Cash flows provided by operating activities before changes in operating assets and liabilities for 2007 were $516.6 million compared with $393.6 million for 2006.  Changes in operating assets and liabilities used cash of $46.2 million in 2007 and provided cash of $65.2 million in 2006, resulting in a decrease in cash of $111.4 million in 2007 compared to 2006.  The $111.4 million decrease in cash is primarily due to the impact of $91.8 million of lower receivables from the Distribution segment attributable to higher December 2005 balances realized from the colder related winter period versus the subsequent winter periods and the receipt of $38.8 million less from cash settlements of put options in the Gathering and Processing segment in the 2007 period versus the 2006 period.  
 
Year ended December 31, 2006 versus the year ended December 31, 2005.  Cash flows provided by operating activities were $458.8 million for the year ended December 31, 2006 compared with cash flows provided by operating activities of $218.6 million for the same period in 2005.  Cash flows provided by operating activities before changes in operating assets and liabilities for 2006 were $393.6 million compared with $356.6 million for 2005.  Changes in operating assets and liabilities provided cash of $65.2 million in 2006 and used cash of $138 million in 2005, resulting in an increase in cash of $203.2 million in 2006 compared to 2005.  The $203.2 million increase in cash is primarily due to the receipt in 2006 of $74.2 million from cash settlements of put options versus the purchase of $49.7 million of put options in 2005, higher net accounts receivable resulting from increased billings due to improved earnings and other increases of operating activities from the Gathering and Processing segment, partially offset by increased usage of cash primarily related to the replenishment of natural gas inventory levels in the 2006 period compared to 2005.

Investing Activities

Summary

The Company’s business strategy includes making prudent capital expenditures across its base of interstate transmission, storage, gathering, processing and distribution assets and growing the businesses through the selective acquisition of assets in order to position itself favorably in the evolving North American natural gas markets.



Cash flows used in investing activities in the years ended December 31, 2007 and 2006 were $666.6 million and $806.8 million, respectively.  The $140.2 million decrease in invested cash is primarily due to the $1.54 billion (net of $53.7 million cash received) acquisition of the Sid Richardson Energy Services business completed on March 1, 2006, offset by the effect of the $1.08 billion disposition in August 2006 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.  This decrease is partially offset by increased capital expenditures of $269 million for the same periods, primarily due to increased capital spending in the Transportation and Storage segment.  The following table presents a summary of additions to property, plant and equipment in continuing operations by segment, including additions related to major projects for the periods presented.
 
   
Years ended December 31,
 
Property, Plant and Equipment Additions
 
2007
   
2006
   
2005
 
   
(In thousands)
 
Transportation and Storage Segment
                 
LNG Terminal Expansions/Enhancements
  $ 133,469     $ 57,045     $ 75,263  
Trunkline Field Zone Expansion
    185,180       12,314       169  
East End Enhancement
    80,249       52,102       1,012  
Compression Modernization
    81,687       11,642       -  
Other, primarily pipeline integrity, system
                       
reliability, information technology, air
                       
emission compliance
    110,568       111,718       112,971  
Total
    591,153       244,821       189,415  
                         
Gathering and Processing Segment
    48,633       35,101  (1)     -  
                         
Distribution Segment
                       
Missouri Safety Program
    11,405       11,592       11,426  
Other, primarily system replacement
                       
and expansion
    33,364       36,362       73,470  
                         
Total
    44,769       47,954       84,896  
                         
Corporate and other
    4,173       4,798       2,306  
                         
Total  (2)
  $ 688,728     $ 332,674     $ 276,617  
                         
____________________
(1)  Reflects expenditures for the period subsequent to the March 1, 2006 acquisition of Sid Richardson Energy
       Services.
(2)  Includes net capital accruals totaling $71.8 million, $14.9 million and $(3.1) million for the years ended
      2007, 2006 and 2005, respectively.                                                                

Principal Capital Expenditure Projects

The following is a summary of the Company’s principal capital expenditure projects.

LNG Expansion Projects.  Trunkline LNG’s Phase I expansion project was placed into service on April 5, 2006 with a total project cost of $141 million, plus capitalized interest.  The expanded vaporization capacity portion of the expansion was placed into service on September 18, 2005.  Phase II went into service on July 8, 2006.  The final cost of Phase II was $79 million, plus capitalized interest.  The expansions increased sustainable send out capacity from .63 Bcf/d to 1.8 Bcf/d, and storage increased from 6.3 Bcf to 9 Bcf.

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 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 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 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.

Hurricane Damage.  Late in the third quarter of 2005, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast.  These hurricanes caused damage to property and equipment owned by Sea Robin, Trunkline, and Trunkline LNG.  As of December 31, 2007, the Company has incurred approximately $35 million of capital expenditures related to the hurricanes, primarily for replacement or abandonment of damaged property and equipment at Sea Robin and construction project delays at the Trunkline LNG terminal.

The Company anticipates reimbursement from its property insurance carriers for a significant portion of damages from the hurricanes in excess of its $5 million deductible.  Such reimbursement is currently estimated by the Company’s property insurance carrier ultimately to be limited to 70 percent of the portion of the claimed damages accepted by the insurance carrier, but the amount is subject to the level of total ultimate claims from all companies relative to the carrier’s $1 billion total limit on payout per event.  As of December 31, 2007, the Company has received payments of $7.6 million of the $19.5 million total estimated eligible recoveries from its insurance carriers.  No receivables due from the insurance carriers have been recorded as of December 31, 2007.

In addition, after the 2005 hurricanes, the U.S. Mineral Management Service mandated inspections by leaseholders and pipeline operators along the hurricane tracks.  The Company has detected exposed pipe and other facilities on Trunkline and Sea Robin that must be re-covered to comply with applicable regulations.  Capital expenditures of approximately $3.7 million have been incurred as of December 31, 2007 to address these issues.  The Company will seek recovery of these expense and capital amounts as part of the hurricane-related claims.




Missouri Safety Program.  Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in a major gas safety program in its service territories (Missouri Safety Program).  This program includes replacement of Company and customer-owned gas service and yard lines, the movement and resetting of meters, the replacement of cast iron mains and the replacement and cathodic protection of bare steel mains.  In recognition of the significant capital expenditures associated with this safety program, the MPSC initially permitted the deferral and subsequent recovery through rates of depreciation expense, property taxes and associated carrying costs over a 10-year period.  On August 28, 2003, the state of Missouri passed certain statutes that provided Missouri Gas Energy the ability to adjust rates periodically to recover depreciation expense, property taxes and carrying costs associated with the Missouri Safety Program, as well as investments in public improvement projects.  The continuation of the Missouri Safety Program will result in significant levels of future capital expenditures.  The Company incurred capital expenditures of $11.4 million in 2007 related to this program and estimates incurring approximately $141.3 million over the next 12 years, after which all service lines, representing about 40 percent of the annual safety program investment, will have been replaced.

For additional information related to the Company’s strategy regarding other growth opportunities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Strategy.

Financing Activities

Summary

The Company continues to pursue opportunities to enhance its credit profile by reducing its ratio of total debt to total capital.  At each of, December 31, 2007 and 2006, the Company’s ratio of total debt to total capital was 61 percent.  The issuance of common stock, equity units, preferred stock and asset sales and use of proceeds therefrom to reduce debt or limit use of debt in conjunction with acquisitions is continued evidence of the Company’s commitment to strengthen its balance sheet and solidify its current investment grade status.

Cash flows provided by financing activities were $196.1 million and $336.8 million for the years ended December 31, 2007 and 2006, respectively.  Financing activity cash flow changes were primarily due to the net impact of higher issuances of debt partially offset by higher payments on the revolving credit facilities in the 2006 period versus the 2007 period and the issuance of common stock in 2006.

Cash flows provided by financing activities were $336.8 million for the year ended December 31, 2006 compared with $50.8 million for the same period in 2005.  Financing activity cash flow changes were primarily due to the net impact of acquisition financing and the repayment of such debt, net borrowings under the revolving credit facilities and the payment of common and preferred stock dividends.

Common Stock, Equity Units and Preferred Stock Issuances

On August 16, 2006, the Company remarketed the 2.75% Senior Notes.  The interest rate on the Senior Notes was reset to 6.15 percent per annum effective on and after August 16, 2006.  The Senior Notes will mature on August 16, 2008.  On August 16, 2006, the Company issued 7,413,074 shares of common stock for $125 million in conjunction with the remarketing of its 2.75% Senior Notes.

On February 11, 2005, Southern Union issued 2,000,000 of its 5% Equity Units at a public offering price of $50 per unit, resulting in net proceeds, after underwriting discounts and commissions and other transaction related costs, of $97.4 million.  Southern Union used the proceeds to repay the balance of the bridge loan used to fund a portion of the Company’s investment in CCE Holdings (CCE Holdings Bridge Loan) and to repay borrowings under its credit facilities.  Each 5% Equity Unit consisted of a 1/20th interest in a $1,000 principal amount of Southern Union’s 4.375% Senior Notes due 2008 and a forward stock purchase contract that obligated the holder to purchase Southern Union common stock on February 16, 2008.  On February 8, 2008, the Company remarketed the 4.375% Senior Notes.  The interest rate on the Senior Notes was reset to 6.089 percent per annum effective on and after February 19, 2008.  The Senior Notes will mature on February 16, 2010.  On February 19, 2008, the Company issued 3,693,240 shares of common stock for $100 million in conjunction with the remarketing of its 4.375% Senior Notes.  See Item 8. Financial Statements and Supplementary Data, Note 25 – Subsequent Event.



For additional information related to the Company’s remarketed debt obligations, see Item 8. Financial Statements and Supplementary Data, Note 13 – Debt Obligations – Long-Term Debt and Note 25 – Subsequent Event.
 
On February 9, 2005, Southern Union issued 14,913,042 shares of its common stock at $23.00 per share, resulting in net proceeds, after underwriting discounts and commissions, of $332.6 million.  Southern Union used the net proceeds to repay a portion of the CCE Holdings Bridge Loan.

Debt Refinancing, Repayment and Issuance Activity

6.20% Senior Notes.  On October 26, 2007, PEPL issued $300 million in senior notes due November 1, 2017 with an interest rate of 6.20 percent (6.20% Senior Notes).  In connection with the issuance of the 6.20% Senior Notes, the Company incurred underwriting and discount costs of approximately $2.7 million.  The debt was priced to the public at 99.741 percent, resulting in $297.3 million in proceeds to the Company.  The proceeds were initially used to repay approximately $246 million outstanding under the credit facilities.  The remaining proceeds of $51.3 million were invested by the Company and subsequently utilized to fund working capital obligations. 

LNG Holdings Term Loans.  On March 15, 2007, LNG Holdings, LLC (LNG Holdings), as borrower, and PEPL and Trunkline LNG, as guarantors, entered into a $455 million unsecured term loan facility due March 13, 2012 (2012 Term Loan). The interest rate under the 2012 Term Loan is a floating rate tied to a LIBOR rate or prime rate at the Company’s option, in addition to a margin tied to the rating of PEPL’s senior unsecured debt.  The proceeds of the 2012 Term Loan were used to repay approximately $455 million in existing indebtedness that matured in March 2007, including the $200 million 2.75% Senior Notes and the LNG Holdings $255.6 million Term Loan.  LNG Holdings has entered into interest rate swap agreements that effectively fixed the interest rate applicable to the 2012 Term Loan at 4.98 percent plus a credit spread of 0.625, based upon PEPL’s credit rating for its senior unsecured debt.  See Item 8.  Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps on the 2012 Term Loan.

In connection with the December 1, 2006 closing of the Redemption Agreement, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, LLC, as guarantors, entered into the $465 million 2006 Term Loan due April 4, 2008.  On June 29, 2007, the parties entered into an amended and restated term loan facility (Amended Credit Agreement).  The Amended Credit Agreement extended the maturity of the term loan from April 4, 2008 to June 29, 2012, and decreased the interest rate from LIBOR plus 87.5 basis points to LIBOR plus 55 basis points, based upon the current credit rating of PEPL's senior unsecured debt.  The balance of the term loan facility at December 31, 2007 was $412.2 million.

Junior Subordinated Notes.  On October 23, 2006, the Company issued $600 million in Junior Subordinated Notes due November 1, 2066 with an initial fixed interest rate of 7.20 percent.  In connection with the issuance of the Junior Subordinated Notes, the Company incurred underwriting and discount costs of approximately $9 million.  The debt was priced to the public at 99.844 percent, resulting in $590.1 million in proceeds to the Company.  The outstanding balance of $525 million on the Sid Richardson Bridge Loan discussed below was retired using the proceeds from the debt offering and the remaining approximately $65 million of debt offering proceeds were used to pay down a portion of the Company’s credit facilities.  See related information in Item 8.  Financial Statements and Supplementary Data, Note 13 – Debt Obligations – Long-Term Debt – Junior Subordinated Notes.

Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt.

Credit Facilities.  On September 29, 2005, the Company entered into a Fourth Amended and Restated Revolving Credit Facility in the amount of $400 million (Long-Term Facility). The Long-Term Facility has a five-year term and matures on May 28, 2010. The Long-Term Facility replaced the Company’s May 28, 2004 long-term credit facility in the same amount. Borrowings under the Long-Term Facility are available for Southern Union’s working capital and letter of credit requirements and other general corporate purposes. The Long-Term Facility is subject to a commitment fee based on the rating of the Company’s senior unsecured notes (Senior Notes). As of December 31, 2007, the commitment fees were an annualized 0.15 percent.  The Company has an additional $30 million of availability under uncommitted lines of credit facilities with various banks.



Balances of $123 million and $100 million were outstanding under the Company’s credit facilities at effective interest rates of 5.82 percent and 6.02 percent at December 31, 2007 and December 31, 2006, respectively. The Company classifies its borrowings under the credit facilities due May 28, 2010 as short-term debt, as the individual borrowings are generally for periods of 15 to 180 days.  At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days.  As of February 22, 2008, there was a balance of $45 million outstanding under the Company’s credit facilities at an average effective interest rate of 3.77 percent.

Sid Richardson Bridge Loan.  On March 1, 2006, Southern Union acquired SUGS for $1.6 billion in cash.  The acquisition was funded by a bridge loan facility in the amount of $1.6 billion that was entered into on March 1, 2006 between the Company and a group of banks as lenders.  On August 24, 2006, the Company applied approximately $1.1 billion in net proceeds from the sales 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 to repayment of the Sid Richardson Bridge Loan.  On October 23, 2006, the Company retired the remainder of the Sid Richardson Bridge Loan using a portion of the $590.1 million in proceeds received from the $600 million Junior Subordinated Notes offering discussed above.

Interest expense totaling $49.2 million related to the Sid Richardson Bridge Loan was incurred during 2006 at an average interest rate of 5.72 percent.  Debt issuance costs totaling $9.2 million were incurred in connection with the financing of the acquisition, of which $7.8 million was related to the Sid Richardson Bridge Loan and $1.4 million was related to the placement of permanent financing.  The Company fully amortized the $7.8 million of the Sid Richardson Bridge Loan debt issuance cost to interest expense during 2006.

Expected Refinancing and Other Debt Matters
 
Expected Refinancing.  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.  As of December 31, 2007, both Southern Union’s and Panhandle’s debt are rated Baa3 by Moody's Investor Services, Inc., BBB- by Standard & Poor's and BBB by Fitch Ratings. If its current 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 relationships with state regulators, who may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.



OTHER MATTERS

Master Limited Partnership

On November 9, 2007, the Company announced its intention to pursue an initial public offering of units representing limited partner interests of a master limited partnership (MLP) to be formed by the Company to hold a portion of the gathering and processing assets of its SUGS business.  In light of recent unfavorable conditions in the MLP market, including the delay or cancellation of other previously announced initial public offerings, the Company has determined to postpone filing of a registration statement until such time as market conditions improve.
 
This Annual Report on Form 10-K shall not constitute an offer to sell or the solicitation of an offer to buy any securities. Any offers, solicitations of offers to buy, or any sales of securities will only be made in accordance with the registration requirements of the Securities Act of 1933 or an exemption therefrom.
 
Off-Balance Sheet Arrangements and Aggregate Contractual Obligations

The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2007:

   
Contractual Obligations (In thousands)
 
                                       
2013 and
 
   
Total
   
2008
   
2009
   
2010
   
2011
   
2012
   
thereafter
 
 
                                         
Long-term debt (1), (2)
  $ 3,388,913     $ 434,831     $ 60,623     $ 140,500     $ -     $ 857,389     $ 1,895,570  
Short-term borrowing,
                                                       
including credit facilities (1)
    123,000       123,000       -       -       -       -       -  
Gas purchases (3)
    618,822       244,103       209,202       165,517       -       -       -  
Missouri Gas Energy Safety Program
    141,324       12,991       12,633       12,760       12,887       10,868       79,185  
Transportation contracts
    310,987       74,786       70,732       55,815       44,664       11,819       53,171  
Storage contracts (4)
    175,169       32,273       24,242       18,720       17,250       14,302       68,382  
Operating lease payments
    143,903       16,423       19,236       18,294       18,230       13,929       57,791  
Interest payments on debt  (5), (6)
    4,196,668       213,424       190,243       184,631       182,961       151,448       3,273,961  
Benefit plan contributions
    24,314       24,314       -       -       -       -       -  
Other  (7)
    4,116       1,690       980       872       389       185       -  
Total contractual cash obligations
  $ 9,127,216     $ 1,177,835     $ 587,891     $ 597,109     $ 276,381     $ 1,059,940     $ 5,428,060  
                                                         
_________________________
(1)
The Company is party to debt agreements containing certain covenants that, if not satisfied, would give rise to an event of default that would cause such debt to become immediately due and payable.  Such covenants require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios, and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense.  At December 31, 2007, the Company was in compliance with all of its covenants.  See Item 8.  Financial Statements and Supplementary Data, Note 13 – Debt Obligations.
(2)
The long-term debt principal payment obligations exclude $6.1 million of unamortized debt premium as of December 31, 2007.
(3)
The Company has purchase gas tariffs in effect for all its utility service areas that provide for recovery of its purchased gas costs under defined methodologies.
(4)
Represents charges for third party storage capacity.
(5)
Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2007.  Includes approximately $2.5 billion of interest payments associated with the $600 million Junior Subordinated Notes due November 1, 2066.
(6)
Excludes interest on the $100 million 6.089% Senior Notes due February 16, 2010 entered into on February 19, 2008. See Item 8.  Financial Statements and Supplementary Data, Note 25 – Subsequent Event.
(7)
Includes FIN 48 unrecognized tax benefits and various other contractual obligations.

 
Contingencies

See Item 8.  Financial Statements and Supplementary Data, Note 18 – Commit­ments and Contingencies.

Inflation

The Company believes that inflation has caused, and will continue to cause, increases in certain operating expenses and has required, and will continue to require, it to replace assets at higher costs.  The Company continually reviews the adequacy of its rates in relation to the impact of market conditions, the increasing cost of providing services and the inherent regulatory lag experienced in the Transportation and Storage and Distribution segments in adjusting those rates.

Regulatory

 See Item 8.  Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.

Critical Accounting Policies

Summary

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.  The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Estimates and assumptions about future events and their effects cannot be determined with certainty.  On an ongoing basis, the Company evaluates its estimates based on historical experience, current market conditions and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources.  Nevertheless, actual results may differ from these estimates under different assumptions or conditions.  The following is a summary of the Company’s most critical accounting policies, which are defined as those policies whereby judgments or uncertainties could affect the application of those policies and materially different amounts could be reported under different conditions or using different assumptions.  For a summary of all of the Company’s significant accounting policies, see Item 8.  Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies.

Effects of Regulation

The Company is subject to regulation by certain state and federal authorities in each of its reportable segments and for certain of its operations reported as discontinued operations.  Missouri Gas Energy, New England Gas Company and Florida Gas have accounting policies that conform to FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71), and which are in accordance with the accounting requirements and ratemaking practices of the applicable regulatory authorities.  The application of these accounting policies allows the Company to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the Consolidated Statement of Operations by an unregulated company.  These deferred assets and liabilities then flow through the results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers.  Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders.  If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs.  The aggregate amount of regulatory assets reflected in the Consolidated Balance Sheet applicable to the Distribution segment are $64.2 million and $65.9 million at December 31, 2007 and 2006, respectively.  The aggregate amount of regulatory liabilities reflected in the Consolidated Balance Sheet applicable to the Distribution segment are $6.5 million and $8.9 million at December 31, 2007 and 2006, respectively.  For a summary of regulatory matters applicable to the


Company, see Item 8.  Financial Statements and Supplementary Data, Note 16 – Regulation and Rates.  Panhandle and SUGS do not currently apply Statement No. 71.

Long-Lived Assets

Long-lived assets, including property, plant and equipment and goodwill, comprise a significant amount of the Company’s total assets.  The Company makes judgments and estimates about the carrying value of these assets, including amounts to be capitalized, depreciation methods and useful lives.  The Company also reviews these assets for impairment on a periodic basis or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.  The impairment test consists of a comparison of an asset’s fair value with its carrying value; if the carrying value of the asset exceeds its fair value, an impairment loss is recognized in the Consolidated Statement of Operations in an amount equal to that excess.  When an asset’s fair value is not readily apparent from other sources, management’s determination of an asset’s fair value requires it to make long-term forecasts of future net cash flows related to the asset.  These forecasts require assumptions about future demand, future market conditions and regulatory developments.  Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period.

The Company assesses its goodwill for impairment at least annually based on FASB Statement 142, Goodwill and Other Intangible Assets.  An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with Statement 142, to the book value of each reporting unit.  If the fair value is less than the book value, an impairment is indicated, and a second test is performed to measure the amount of the impairment.  In the second test, the implied fair value of the goodwill is calculated by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment.  If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, an impairment charge is recorded.  As of November 30, 2007, the Company evaluated goodwill for impairment and no impairment was indicated.  Execution of agreements for the sale 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 in the first quarter of 2006 constituted a subsequent event of the type that under generally accepted accounting principles in the United States of America required the Company to consider the fair value indicated by the definitive sale agreements in its 2005 goodwill impairment evaluation.  Based on the purchase prices reflected in the definitive agreements, the Company reported a $175 million goodwill impairment in the fourth quarter of 2005.

Purchase Accounting

The Company’s acquisition of Sid Richardson Energy Services was accounted for using the purchase method of accounting in accordance with FASB Statement No. 141, Business Combinations. CCE Holdings, a joint venture in which Southern Union owned a 50 percent equity interest until it became a wholly-owned subsidiary on December 1, 2006 in conjunction with the closing of the Redemption Agreement, also applied the purchase method of accounting for its acquisition of CrossCountry Energy on November 17, 2004.  Under this statement, the purchase price paid by the acquirer, including transaction costs, is allocated to the net assets acquired as of the acquisition date based on their fair value. Determining the fair value of certain assets acquired and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  Southern Union has generally used outside appraisers to assist in the initial determination of fair value.  The appraisals related to Southern Union’s acquisition of CCE Holdings and Sid Richardson Energy Services were finalized in 2005 and 2006, respectively.

Southern Union effectively acquired an additional 25 percent interest in Citrus on December 1, 2006 as a result of the transactions described in Item 8.  Financial Statements and Supplementary Data, Note 3 – Acquisitions and Sales – CCE Holdings Transactions.  The purchase price allocation associated with this incremental equity investment in Citrus is accounted for under Accounting Principles Board Opinion 18, The Equity Method of Accounting for Investments in Common Stock.  For additional information, see Item 8.  Financial Statements and Supplementary Data, Note 9 – Unconsolidated Investments – CCE Holdings Goodwill Evaluation.



Pensions and Other Postretirement Benefits

Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R) (Statement No. 158).  Statement No. 158 does not amend the expense recognition provisions of Statements No. 87, 88 and 106, but requires employers to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.   Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive loss in stockholders’ equity.  Effective for years ending after December 15, 2008 (with early adoption permitted), Statement No. 158 also requires plan assets and benefit obligations to be measured as of the employers’ balance sheet date.  The Company has not yet adopted the measurement date provisions of Statement No. 158.

The Company accounted for the measurement of its defined benefit postretirement plans under Statement No. 87, Employers Accounting for Pensions (Statement No. 87) and Statement No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement No. 106).  Prior to the adoption of the recognition and disclosure provisions of Statement No. 158, Statement No. 87 required that a liability (minimum pension liability) be recorded when the accumulated benefit obligation liability exceeded the fair value of plan assets.  Any adjustment was recorded as a non-cash charge to Accumulated other comprehensive loss.  Statement No. 106 had no minimum liability provision.  Under both Statements No. 87 and 106, changes in the funded status were not immediately recognized, rather they were deferred and recognized ratably over future periods.  Upon adoption of the recognition provisions of Statement No. 158, the Company recognized the amounts of these prior changes in the funded status of its defined benefit postretirement plans through Accumulated other comprehensive loss.

The calculation of the Company’s pension expense and projected benefit obligation requires the use of a number of assumptions.  Changes in these assumptions can have a significant effect on the amounts reported in the financial statements.  The Company believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.

The Company establishes the discount rate using the Citigroup Pension Discount Curve as published on the Society of Actuaries website as the hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due.  Pension expense and projected benefit obligation (PBO) increases and equity decreases as the discount rate is reduced.  Lowering the discount rate assumption by 0.5 percent would increase the Company’s 2007 pension expense and PBO at the end of 2007 by $400,000 and $13.1 million, respectively, and would decrease equity at the end of 2007 by $8.1 million.

The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results.  Pension expense increases as the expected rate of return on plan assets is reduced.  Lowering the expected rate of return on plan assets assumption by 0.5 percent would increase the Company’s 2007 pension expense by $550,000.

See Item 8.  Financial Statements and Supplementary Data, Note 14 – Benefits for additional related information.

Derivatives and Hedging Activities

The Company follows FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, to account for derivative and hedging activities.  In accordance with this statement all derivatives are recognized on the balance sheet at their fair value.  On the date the derivative contract is entered into, the Company designates the derivative as:  (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge);  (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or economic hedging instrument).  For derivatives treated as a fair value hedge, the effective portion of changes in fair value are recorded as an adjustment to the hedged item.  The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used.  Upon termination of a fair value hedge of a debt instrument, the resulting


gain or loss is amortized to earnings through the maturity date of the debt instrument.  For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated other comprehensive loss until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.  For derivatives treated as trading or economic hedging instruments, changes in fair value are reported in current-period earnings.  Fair value is determined based upon quoted market prices and mathematical models using current and historical data.

The Company formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions have been highly effective in offsetting changes in the fair value or cash flows of hedged items and whether those derivatives may be expected to remain highly effective in future periods.  The Company discontinues hedge accounting when: (i) it determines that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item; (ii) the derivative expires or is sold, terminated, or exercised; (iii) it is no longer probable that the forecasted transaction will occur; or (iv) management determines that designating the derivative as a hedging instrument is no longer appropriate.  In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Company will carry the derivative at its fair value on the balance sheet, recognizing changes in the fair value in current-period earnings.  See Item 8.  Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities.

Commitments and Contingencies

The Company is subject to proceedings, lawsuits and other claims related to environmental and other matters.  Accounting for contingencies requires significant judgments by management regarding the estimated probabilities and ranges of exposure to potential liability.  For further discussion of the Company’s commitments and contingencies, see Item 8.  Financial Statements and Supplementary Data, Note 18 – Commitments and Contingencies.

New Accounting Pronouncements

See Item 8.  Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies – New Accounting Principles.


Interest Rate Risk

The Company is subject to the risk of loss associated with movements in market interest rates.  The Company manages this risk through the use of fixed-rate debt, floating-rate debt and interest rate swaps.  Fixed-rate swaps are used to reduce the risk of increased interest costs during periods of rising interest rates.  Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates.  At December 31, 2007, the interest rate on 88 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At December 31, 2007, $17.1 million is included in Deferred Credits in the Consolidated Balance Sheet related to the fixed-rate interest rate swaps on the $455 million Term Loan due 2012.

At December 31, 2007, a 100 basis point move in the annual interest rate on all outstanding floating-rate long-term debt would increase the Company’s interest payments by approximately $434,000 for each month during which such increase continued.  If interest rates changed significantly, the Company would take actions to manage its exposure to the change.  No change has been assumed, as a specific action and the possible effects are uncertain.



The Company also enters into treasury rate locks to manage its exposure against changes in future interest payments attributable to changes in the US treasury rates.  By entering into these agreements, the Company locks in an agreed upon interest rate until the settlement of the contract.  The Company accounts for the treasury rate locks as cash flow hedges.  At December 31, 2007, $1.7 million is included in Prepayments and Other in the Consolidated Balance Sheet related to the treasury rate locks.  The Company has treasury rate locks with an aggregate notional amount of $375 million outstanding as of December 31, 2007 to hedge the changes in cash flows of anticipated interest payments from changes in treasury rates prior to the issuance of new debt instruments.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2007 is not material to the Company.

See Item 8.  Financial Statements and Supplementary Data, Note 11 – Derivative Instruments and Hedging Activities and Note 13 - Debt Obligations.

Commodity Price Risk

Gathering and Processing Segment.  The Company markets natural gas and NGLs in its Gathering and Processing segment and manages associated commodity price risks using both economic and accounting hedge derivative financial instruments.  These instruments involve not only the risk of transacting with counterparties and their ability to meet the terms of the contracts but also the risk associated with unmatched positions and market fluctuations.  The Company is required to record its commodity derivative financial instruments at fair value, which is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.
 
To manage its commodity price risk related to natural gas and NGLs, the Company uses a combination of crude oil puts, NGL gross processing spread puts, fixed-price physical forward sales contracts, exchange-traded futures and options, and fixed or 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 highly effective in offsetting changes in the physical market and reducing basis risk.  Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations.  At December 31, 2007, the net asset derivative balance of the Company’s economic hedging derivatives in the Gathering and Processing segment was $6.7 million.  All previous accounting hedges designated as cash flow hedges in the Gathering and Processing segment expired at December 31, 2007.

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.

 

 
Transportation and Storage Segment.  The Company is exposed to commodity price risk as its interstate pipelines collect natural gas from its customers for operations or as part of their fee for services provided.  When the amount of natural gas utilized in operations by these pipelines differs from the amount provided by their customers, the pipelines may use natural gas from inventory or could have to buy or sell natural gas to cover these operational needs, and thus have some exposure to commodity price risk.  At December 31, 2007, there were no hedges in place in respect to natural gas price risk from its interstate pipeline operations.

Distribution Segment Economic Hedging Activities.  During 2007, 2006 and 2005, the Company entered into natural gas commodity swaps and collars to mitigate price volatility of natural gas passed through to utility customers in the Distribution segment. The cost of the derivative products and the settlement of the respective obligations are recorded through the gas purchase adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings. The fair values of the contracts are recorded as an adjustment to a regulatory asset or liability in the Consolidated Balance Sheet.  As of December 31, 2007, the fair values of the contracts, which expire at various times through December 2009, are included in the Consolidated Balance Sheet as assets and liabilities, respectively, with matching adjustments to deferred cost of gas of $22.3 million.

 
The information required here is included in the report as set forth in the Index to Consolidated Financial Statements on page F-1.


None.


EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Southern Union has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports filed or submitted under the Securities Exchange Act of 1934, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure.  The Company performed an evaluation under the supervision and with the participation of management, including its CEO and CFO, and with the participation of personnel from its Legal, Internal Audit, Risk Management and Financial Reporting Departments, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report.  Based on the evaluation, Southern Union’s CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2007.



MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Exchange Act Rule 13a-15(f) as a process designed by, or under the supervision of, the Company’s principal executive officer and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

·
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company;
·
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; and
·
Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Exchange Act Rules 13a-15(c) and 15d-15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of the Company to conduct an annual evaluation of the Company’s internal control over financial reporting and to provide a report on management’s assessment, including a statement as to whether or not internal control over financial reporting is effective.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s evaluation of the effectiveness of the Company’s internal control over financial reporting was based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under that framework and applicable SEC rules, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.

The Company’s internal control over financial reporting as of December 31, 2007 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

Southern Union Company
February 29, 2008

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is not aware of any change in Southern Union’s internal control over financial reporting that occurred during the quarter ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.




All information required to be reported on Form 8-K for the quarter ended December 31, 2007 was appropriately reported.

PART III


There is incorporated in this Item 10 by reference the information that will appear in the Company’s definitive proxy statement for the 2008 Annual Meeting of Stockholders under the captions Meetings and Committees of the Board – Board of Directors, 2007 Executive Compensation – Named Executive Officers, Section 16(a) Beneficial Ownership Reporting Compliance, Corporate Governance – Code of Ethics, Meetings and Committees of the Board – Board Committees – Corporate Governance Committee and – Audit Committee.

The Company has adopted a Code that applies to its CEO, CFO, Controller and other individuals in the finance department performing similar functions.  The Code is available on the Company’s website at www.sug.com.  If any substantive amendment to the Code is made or any waiver is granted thereunder, including any implicit waiver, the Company’s CEO, CFO or other authorized officer will disclose the nature of such amendment or waiver on the website at www.sug.com or in a Current Report on Form 8-K.

The CEO Certification and Annual Written Affirmation required by the NYSE Listing Standards, Section 303A.12(a), relating to the Company’s compliance with the NYSE Corporate Governance Listing Standards, was submitted to the NYSE on May 25, 2007.


There is incorporated in this Item 11 by reference the information that will appear in the Company’s definitive proxy statement for the 2008 Annual Meeting of Stockholders under the captions Compensation Discussion and Analysis, 2007 Executive Compensation - Summary Compensation Table - Grants of Plan-Based Awards - Outstanding Equity Awards at December 31, 2007 - Option Exercises and Stock Vested - Non-Qualified Deferred Compensation and - Potential Payments Upon Termination or Change of Control, and 2007 Director Compensation, and Meetings and Committees of the Board – Board Committees – Compensation Committee.


There is incorporated in this Item 12 by reference the information that will appear in the Company’s definitive proxy statement for the 2008 Annual Meeting of Stockholders under the captions Security Ownership of Certain Beneficial Owners and Management.


There is incorporated in this Item 13 by reference the information that will appear in the Company’s definitive proxy statement for the 2008 Annual Meeting of Stockholders under the caption Corporate Governance – Transactions with Related Persons and – Review, Approval or Ratification of Transactions with Related Persons, and Corporate Governance – Director Independence and Independent Director Chairman.


There is incorporated in this Item 14 by reference the information that will appear in the Company’s definitive proxy statement for the 2008 Annual Meeting of Stockholders under the caption Meetings and Committees of the Board – Board Committees and Meetings – Audit Committee.



PART IV


(a)(1) and (2)
Financial Statements and Financial Statement Schedules.

(a)(3)
Exhibits.

Exhibit No.                                                                              Description

 
2(a)
Purchase and Sale Agreement by and among SRCG, Ltd. and SRG Genpar, L.P., as Sellers and Southern Union Panhandle LLC and Southern Union Gathering Company LLC, as Buyers, dated as of December 15, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on December 16, 2005 and incorporated herein by reference.)

 
2(b)
Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of January 26, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on January 30, 2006 and incorporated herein by reference.)

 
2(c)
First Amendment to the Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of August 24, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

 
2(d)
Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of February 15, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 17, 2006 and incorporated herein by reference.)

 
2(e)
Limited Settlement Agreement between Southern Union Company, Narragansett Electric Company d/b/a National Grid, the Department of the Attorney General for the State of Rhode Island and the Rhode Island Department of Environmental Management, dated as of August 24, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

 
2(f)
First Amendment to the Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of August 24, 2006. (Filed as Exhibit 10.3 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

 
2(g)
Redemption Agreement by and between CCE Holdings, LLC and Energy Transfer Partners, L.P., dated as of September 18, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on September 18, 2006 and incorporated herein by reference.)

 
2(h)
Letter Agreement by and between Southern Union Company and Energy Transfer Partners, L.P., dated as of September 14, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on September 18, 2006 and incorporated herein by reference)

 
3(a)
Amended and Restated Certificate of Incorporation of Southern Union Company. (Filed as Exhibit 3(a) to Southern Union’s Annual Report on Form 10-K filed on March 16, 2006 and incorporated herein by reference.)

 
3(b)
By-Laws of Southern Union Company, as amended through January 3, 2007.  (Filed as Exhibit 3.1 to Southern Union’s Current Report on Form 8-K filed on January 3, 2007 and incorporated herein by reference.)

 
3(c)
Certificate of Designations, Preferences and Rights re: Southern Union Company’s 7.55% Noncumulative Preferred Stock, Series A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-A/A dated October 17, 2003 and incorporated herein by reference.)


 
4(a)
Specimen Common Stock Certificate.  (Filed as Exhibit 4(a) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1989 and incorporated herein by reference.)

 
4(b)
Indenture between The Bank of New York Trust Company, N.A., as successor to Chase Manhattan Bank, N.A., as trustee, and Southern Union Company dated January 31, 1994.  (Filed as Exhibit 4.1 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein by reference.)

 
4(c)
Officers' Certificate dated January 31, 1994 setting forth the terms of the 7.60% Senior Debt Securities due 2024.  (Filed as Exhibit 4.2 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein by reference.)

 
4(d)
Officer's Certificate of Southern Union Company dated November 3, 1999 with respect to 8.25% Senior Notes due 2029.  (Filed as Exhibit 99.1 to Southern Union's Current Report on Form 8-K filed on November 19, 1999 and incorporated herein by reference.)

 
4(e)
Form of Supplemental Indenture No. 1, dated June 11, 2003, between Southern Union Company and The Bank of New York Trust Company, N.A., as successor to JP Morgan Chase Bank (formerly the Chase Manhattan Bank, National Association). (Filed as Exhibit 4.5 to Southern Union’s Form 8-A/A dated June 20, 2003 and incorporated herein by reference.)

 
4(f)
Supplemental Indenture No. 2, dated February 11, 2005, between Southern Union Company and The Bank of New York Trust Company, N.A., as successor to JP Morgan Chase Bank, N.A. (f/n/a JP Morgan Chase Bank). (Filed as Exhibit 4.4 to Southern Union’s Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)

 
Subordinated Debt Securities Indenture between Southern Union Company and The Bank of New York Trust Company, N.A., as successor to JP Morgan Chase Bank (as successor to The Chase Manhattan Bank, N.A.), as Trustee. (Filed as Exhibit 4-G to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

 
4(h)
Second Supplemental Indenture, dated October 23, 2006, between Southern Union Company and The Bank of New York Trust Company, N.A., successor to JP Morgan Chase Bank, N.A., formerly known as JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank (National Association).  (Filed as Exhibit 4.1 to Southern Union’s Form 8-K/A dated October 24, 2006 and incorporated herein by reference.)

 
4(i)
2006 Series A Junior Subordinated Notes Due November 1, 2066 dated October 23, 2006 (Filed as Exhibit 4.2 to Southern Unions Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)

 
4(j)
Replacement Capital Covenant, dated as of October 23, 2006 by Southern Union Company, a Delaware corporation with its successors and assigns, in favor of and for the benefit of each Covered Debtor (as defined in the Covenant). (Filed as Exhibit 4.3 to Southern Union’s Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)

 
  4(k)
Southern Union is a party to other debt instruments, none of which authorizes the issuance of debt securities in an amount which exceeds 10% of the total assets of Southern Union.  Southern Union hereby agrees to furnish a copy of any of these instruments to the Commission upon request.

 
10(a)
Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of February 5, 2008. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 8, 2008 and incorporated herein by reference.)

 
10(b)
Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative


 
agent, dated as of June 29, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 6, 2007 and incorporated herein by reference.)

 
10(c)
Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of March 15, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 21, 2007 and incorporated herein by reference.)

 
10(d)
Fourth Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein dated September 29, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on October 5, 2005 and incorporated herein by reference.)

 
10(e)
First Amendment to the Fourth Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein.  (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 6, 2006 and incorporated herein by reference.)

 
10(f)
Second Amendment to Fourth Amended and Restated Revolving Credit Agreement dated September 29, 2005, among the Company, as borrower, and the lenders party there. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on October 23, 2007 and incorporated herein by reference.)

 
10(g)
Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company.  (Filed as Exhibit 10(i) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 1986 and incorporated herein by reference.)

 
10(h)
Southern Union Company 1992 Long-Term Stock Incentive Plan, As Amended. (Filed as Exhibit 10(l) to Southern Union’s Annual Report on Form 10-K for the year ended June 30, 1998 and incorporated herein by reference.)

 
10(i)
Southern Union Company Director's Deferred Compensation Plan.  (Filed as Exhibit 10(g) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference.)

 
10(j)
First Amendment to Southern Union Company Director’s Deferred Compensation Plan, effective April 1, 2007. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report for the quarter ended September 30, 2007 and incorporated herein by reference.)

 
10(k)
Southern Union Company Amended Supplemental Deferred Compensation Plan with Amendments.  (Filed as Exhibit 4 to Southern Union’s Form S-8 filed May 27, 1999 and incorporated herein by reference.)

 
10(l)
Separation Agreement and General Release Agreement between Thomas F. Karam and Southern Union Company dated November 8, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on November 8, 2005 and incorporated herein by reference.)

 
10(m)
Separation Agreement and General Release Agreement between John E. Brennan and Southern Union Company dated July 1, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

 
10(n)
Separation Agreement and General Release Agreement between David J. Kvapil and Southern Union Company dated July 1, 2005. (Filed as Exhibit 10.4 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

 
10(o)
Second Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-138524, filed on November 8, 2006 and incorporated herein by reference.)


 
10(p)
Southern Union Company Pennsylvania Division Stock Incentive Plan.  (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36146, filed on May 3, 2000 and incorporated herein by reference.)

 
10(q)
Southern Union Company Pennsylvania Division 1992 Stock Option Plan.  (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36150, filed on May 3, 2000 and incorporated herein by reference.)
 
 
 
10(r)
Form of Long Term Incentive Award Agreement, dated December 28, 2006, between Southern Union Company and the undersigned. (Filed as Exhibit 99.1 to Southern Union’s Form 8-K dated January 3, 2007) and incorporated herein by reference.)

 
 10(s)
Capital Stock Agreement dated June 30, 1986, as amended April 3, 2000 ("Agreement"), among El Paso Energy Corporation (as successor in interest to Sonat, Inc.); CrossCountry Energy, LLC (assignee of Enron Corp., which is the successor in interest to InterNorth, Inc. by virtue of a name change and successor in interest to Houston Natural Gas Corporation by virtue of a merger) and Citrus Corp. (Filed as Exhibit 10(p) to Southern Union’s Form 10-K dated March 1, 2007 and incorporated herein by reference.)

 
 10(t)
Certificate of Incorporation of Citrus Corp.  (Filed as Exhibit 10(q) to Southern Union’s Form 10-K dated March 1, 2007 and incorporated herein by reference.)

 
 10(u)
By-Laws of Citrus Corp., filed herewith.  (Filed as Exhibit 10(r) to Southern Union’s Form 10-K dated March 1, 2007 and incorporated herein by reference.)


 
14
Code of Ethics and Business Conduct. (Filed as Exhibit 14 to Southern Union’s Annual Report on Form 10-K filed on March 16, 2006 and incorporated herein by reference.)


 
 








Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Southern Union has duly caused this report to be signed by the undersigned, thereunto duly authorized, on February 29, 2008.


 
SOUTHERN UNION COMPANY
   
 
By: /s/   George L. Lindemann
 
      George L. Lindemann
 
      Chairman of the Board, President and
 
      Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of Southern Union and in the capacities indicated as of February 29, 2008.

Signature/Name
Title
 
/s/ George L. Lindemann*
George L. Lindemann
 
Chairman of the Board, President and
Chief Executive Officer
(Principal Executive Officer)
 
/s/ Richard N. Marshall
Richard N. Marshall
 
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
 
/s/ George E. Aldrich
George E. Aldrich
 
Vice President and Controller
(Chief Accounting Officer)
 
/s/ David Brodsky*
David Brodsky
 
Director
 
/s/ Frank W. Denius*
Frank W. Denius
 
Director
 
/s/ Kurt A. Gitter, M.D.*
Kurt A. Gitter, M.D
 
Director
 
/s/ Herbert H. Jacobi*
Herbert H. Jacobi
 
Director
 
/s/ Adam M. Lindemann*
Adam M. Lindemann
 
Director
 
/s/ Thomas N. McCarter, III*
Thomas N. McCarter, III
 
Director
 
/s/ George Rountree, III*
George Rountree, III
 
Director
 
/s/ Allan D. Scherer*
Allan Scherer
 
Director
   
*By:  /s/ RICHARD N. MARSHALL
*By:  /s/ ROBERT M. KERRIGAN, III
         Richard N. Marshall
         Robert M. Kerrigan, III
         Senior Vice President and Chief Financial Officer
         Vice President, Assistant General Counsel and
         Attorney-in-fact
         Secretary
 
         Attorney-in-fact

 


INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 

 


All schedules are omitted as the required information is not applicable or the information is presented in the consolidated financial statements or related notes.
 
 
 
 
F-1


CONSOLIDATED STATEMENT OF OPERATIONS



 

   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands, except per share amounts)
 
Operating revenues (Note 21):
                 
Gas distribution
  $ 732,109     $ 668,721     $ 752,699  
Gas transportation and storage
    658,446       577,182       505,233  
Gas gathering and processing
    1,221,747       1,090,216       -  
Other
    4,363       4,025       8,950  
Total operating revenues
    2,616,665       2,340,144       1,266,882  
                         
Operating expenses:
                       
Cost of gas and other energy
    1,483,715       1,377,147       529,450  
Revenue-related taxes
    38,584       35,281       40,080  
Operating, maintenance and general
    444,408       381,844       302,025  
Depreciation and amortization
    177,999       152,103       92,562  
Taxes, other than on income and revenues
    44,874       38,684       33,648  
Total operating expenses
    2,189,580       1,985,059       997,765  
                         
Operating income
    427,085       355,085       269,117  
                         
Other income (expenses):
                       
Interest expense
    (203,146 )     (210,043 )     (128,470 )
Earnings from unconsolidated investments
    100,914       141,370       70,742  
Other, net  (Note 4)
    (883 )     39,918       (8,241 )
Total other expenses, net
    (103,115 )     (28,755 )     (65,969 )
                         
Earnings from continuing operations before income taxes
    323,970       326,330       203,148  
                         
Federal and state income taxes (Note 15)
    95,259       109,247       50,052  
                         
Earnings from continuing operations
    228,711       217,083       153,096  
                         
Discontinued operations (Note 19):
                       
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 )
                         
Net earnings
    228,711       64,131       20,683  
                         
Preferred stock dividends
    (17,365 )     (17,365 )     (17,365 )
                         
Net earnings available for common stockholders
  $ 211,346     $ 46,766     $ 3,318  
                         
Net earnings available for common stockholders
                       
from continuing operations per share (Note 5):
                       
Basic
  $ 1.76     $ 1.74     $ 1.24  
Diluted
  $ 1.75     $ 1.70     $ 1.20  
                         
Net earnings available for common stockholders per
                       
share (Note 5):
                       
Basic
  $ 1.76     $ 0.41     $ 0.03  
Diluted
  $ 1.75     $ 0.40     $ 0.03  
Cash dividends declared on common stock per share:
  $ 0.45     $ 0.40       N/A  
                         
Weighted average shares outstanding (Note 5):
                       
Basic
    119,930       114,787       109,395  
Diluted
    120,674       117,344       112,794  
                         

 

 

The accompanying notes are an integral part of these consolidated financial statements.
 
ASSETS


   
Years Ended December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
Current assets:
           
Cash and cash equivalents
  $ 5,690     $ 5,751  
Accounts receivable, billed and unbilled,
               
net of allowances of $4,144 and $4,830, respectively
    358,521       298,231  
Accounts receivable – affiliates
    29,943       3,546  
Inventories
    263,618       241,137  
Deferred gas purchase costs
    3,496       -  
Gas imbalances - receivable
    105,371       69,877  
Prepayments and other assets
    41,685       72,317  
Total current assets
    808,324       690,859  
                 
Property, plant and equipment (Note 6):
               
Plant in service
    5,509,992       5,025,631  
Construction work in progress
    377,918       178,935  
      5,887,910       5,204,566  
Less accumulated depreciation and amortization
    (785,623 )     (620,139 )
Net property, plant and equipment
    5,102,287       4,584,427  
                 
Deferred charges:
               
Regulatory assets  (Note 8)
    64,193       65,865  
Deferred charges
    60,468       61,602  
Total deferred charges
    124,661       127,467  
                 
Unconsolidated investments  (Note 9)
    1,240,420       1,254,749  
                 
Goodwill  (Note 7)
    89,227       89,227  
                 
Other
    32,994       36,061  
                 
                 
Total assets
  $ 7,397,913     $ 6,782,790  
                 


















The accompanying notes are an integral part of these consolidated financial statements.
 
 
 
STOCKHOLDERS' EQUITY AND LIABILITIES


 
 
   
Years Ended December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
Stockholders’ equity (Note 10):
           
Common stock, $1 par value; 200,000 shares authorized;
           
121,102 shares issued at December 31, 2007
  $ 121,102     $ 120,718  
Preferred stock, no par value; 6,000 shares authorized;
               
920 shares issued at December 31, 2007  (Note 12)
    230,000       230,000  
Premium on capital stock
    1,784,223       1,775,763  
Less treasury stock: 1,063 and 1,059
               
shares, respectively, at cost
    (27,839 )     (27,708 )
Less common stock held in trust: 783
               
and 863 shares, respectively
    (15,085 )     (14,628 )
Deferred compensation plans
    15,148       14,691  
Accumulated other comprehensive loss
    (11,594 )     (901 )
Retained earnings (deficit)
    109,851       (47,527 )
Total stockholders' equity
    2,205,806       2,050,408  
                 
Long-term debt obligations  (Note 13)
    2,960,326       2,689,656  
                 
Total capitalization
    5,166,132       4,740,064  
                 
Current liabilities:
               
Long-term debt due within one year  (Note 13)
    434,680       461,011  
Notes payable (Note 13)
    123,000       100,000  
Accounts payable and accrued liabilities
    335,253       316,764  
Federal, state and local taxes payable
    35,461       30,828  
Accrued interest
    45,911       46,342  
Customer deposits
    17,589       14,670  
Deferred gas purchases
    -       15,551  
Gas imbalances - payable
    272,850       146,995  
Other
    58,969       68,663  
Total current liabilities
    1,323,713       1,200,824  
                 
Deferred credits
    215,063       224,725  
                 
Accumulated deferred income taxes  (Note 15)
    693,005       617,177  
                 
Commitments and contingencies  (Note 18)
               
                 
Total stockholders' equity and liabilities
  $ 7,397,913     $ 6,782,790  
                 










The accompanying notes are an integral part of these consolidated financial statements.

F-4


CONSOLIDATED STATEMENT OF CASH FLOWS





   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
Cash flows provided by (used in) operating activities:
                 
   Net earnings
  $ 228,711     $ 64,131     $ 20,683  
   Adjustments to reconcile net earnings to net cash flows
                       
provided by (used in) operating activities:
                       
Depreciation and amortization
    177,999       154,601       126,393  
Goodwill impairment
    -       -       175,000  
Amortization of debt expense, net
    743       12,130       2,186  
Deferred income taxes
    71,147       225,843       61,211  
Provision for bad debts
    11,391       20,151       22,519  
Provision for impairment of other assets
    7,660       6,500       2,338  
(Gain) loss on derivative
    9       (55,146 )     -  
Loss on sale of subsidiaries and other assets
    -       56,815       -  
Non-cash stock compensation
    3,345       6,804       3,848  
Earnings from unconsolidated investments, adjusted for cash distributions
    2,636       (92,607 )     (55,742 )
Other
    12,999       (5,643 )     (1,821
Changes in operating assets and liabilities, net of acquisitions:
                       
Accounts receivable, billed and unbilled
    (76,778 )     147,450       (126,590 )
Accounts payable and accrued liabilities
    (22,788 )     (67,021 )     43,681  
Customer deposits
    2,919       3,542       2,940  
Deferred gas purchase costs
    (19,047 )     (35,906 )     59,385  
Inventories
    41,113       (14,369 )     (52,420 )
Deferred charges and credits
    (3,443 )     (37,459 )     (26,849 )
Prepaids and other assets
    47,700       104,889       (41,256 )
Taxes and other liabilities
    (15,908 )     (35,900 )     3,131  
Net cash flows provided by operating activities
    470,408       458,805       218,637  
Cash flows (used in) provided by investing activities:
                       
Additions to property, plant and equipment
    (616,883 )     (347,896 )     (279,721 )
Acquisitions of operations, net of cash received
    -       (1,537,627 )     -  
Proceeds (payments) from sale of subsidiaries
    (49,304 )     1,076,714       -  
Other
    (417 )     2,005       (2,808 )
Net cash flows used in investing activities
    (666,604 )     (806,804 )     (282,529 )
Cash flows provided by (used in) financing activities:
                       
Decrease in book overdraft
    (7,738 )     (4,941 )     (17,091 )
Issuance of long-term debt
    755,000       1,065,000       255,626  
Issuance costs of debt and equity
    (5,794 )     (10,590 )     (3,536 )
Issuance of common stock and equity units
    -       125,000       431,772  
Issuance of Bridge Loan
    -       1,600,000       -  
Repayment of Bridge Loan
    -       (1,600,000 )     -  
Dividends paid on common and preferred stock
    (65,295 )     (51,695 )     (17,365 )
Repayment of debt and capital lease obligation
    (508,406 )     (470,365 )     (335,567 )
Net (payments) borrowings under revolving credit facilities
    23,000       (320,000 )     (279,000 )
Proceeds from exercise of stock options
    3,718       9,216       22,242  
Other
    1,650       (4,813 )     (6,304 )
Net cash flows provided by financing activities
    196,135       336,812       50,777  
Change in cash and cash equivalents
    (61 )     (11,187 )     (13,115 )
Cash and cash equivalents at beginning of period
    5,751       16,938       30,053  
Cash and cash equivalents at end of period
  $ 5,690     $ 5,751     $ 16,938  
                         
                         
Cash paid for interest, net of amounts capitalized
  $ 213,656     $ 204,573     $ 139,770  
Cash paid for income taxes, net of refunds
    13,979       50,750       (2,007 )
                         










The accompanying notes are an integral part of these consolidated financial statements.

F-5



CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME





 
Common
 
Preferred
 
Premium
     
Common
 
Deferred
 
Accumulated
   
Total
 
 
Stock,
 
Stock,
 
on
 
Treasury
 
Stock
 
Compen-
 
Other
 
Retained
Stock
 
 
$1 Par
 
No Par
 
Capital
 
Stock,
 
Held
 
sation
 
Comprehensive
 
Earnings
Holders
 
 
Value
 
Value
 
Stock
 
at cost
 
In Trust
 
Plans
 
Income (Loss)
 
(Deficit)
Equity
 
 
(In thousands)
 
                                   
Balance December 31, 2004
 $          90,763
 
 $    230,000
 
 $  1,204,590
 
 $   (12,870)
 
 $   (17,980)
 
 $   14,128
 
 $            (59,118)
 
 $    48,044
 $   1,497,557
 
Comprehensive income (loss):
 
                               
   Net earnings
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                          -
 
       20,683
           20,683
 
   Unrealized gain on hedging
   
                               
       activities, net of tax
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                  1,075
 
                -
             1,075
 
   Minimum pension liability
 
                               
      adjustment, net of tax
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                  1,771
 
                -
             1,771
 
   Comprehensive income
 
                           
           23,529
 
   Preferred stock dividends
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                          -
 
     (17,365)
          (17,365)
 
   Distibution of common stock
 
                               
       held in trust
                      -
 
                   -
 
            3,130
 
                 -
 
         4,186
 
                -
 
                          -
 
                -
             7,316
 
   Issuance of common stock
             14,913
 
                   -
 
        316,859
 
                 -
 
                 -
 
                -
 
                          -
 
                -
         331,772
 
   Issuance cost of equity units
                      -
 
                   -
 
          (2,622)
 
                 -
 
                 -
 
                -
 
                          -
 
                -
            (2,622)
 
   Restricted stock award
                      -
 
                   -
 
            4,998
 
                 -
 
                 -
 
      (4,998)
 
                          -
 
                -
                     -
 
   Restricted stock amortization
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
        2,198
 
                          -
 
                -
             2,198
 
   Contract adjustment payment
                      -
 
                   -
 
          (1,759)
 
                 -
 
                 -
 
                -
 
                          -
 
                -
            (1,759)
 
   Purchase of treasury stock
                      -
 
                   -
 
                    -
 
      (15,032)
 
                 -
 
                -
 
                          -
 
                -
          (15,032)
 
   5% stock dividend
               5,294
 
                   -
 
        129,121
 
                 -
 
                 -
 
                -
 
                          -
 
   (134,415)
                     -
 
   Stock option award
                      -
 
                   -
 
            3,848
 
                 -
 
                 -
 
                -
 
                          -
 
                -
             3,848
 
   Exercise of stock options
               1,560
 
                   -
 
          20,617
 
            336
 
           (271)
 
                -
 
                          -
 
                -
           22,242
 
   Payment on note receivable
                      -
 
                   -
 
            2,385
 
                 -
 
                 -
 
                -
 
                          -
 
                -
             2,385
 
   Contributions to Trust
                      -
 
                   -
 
                    -
 
                 -
 
        (1,025)
 
        1,025
 
                          -
 
                -
                     -
 
   Disbursements from Trust
                      -
 
                   -
 
                    -
 
                 -
 
         2,180
 
      (2,180)
 
                          -
 
                -
                     -
 
Balance December 31, 2005
 $        112,530
 
 $    230,000
 
 $  1,681,167
 
 $   (27,566)
 
 $   (12,910)
 
 $   10,173
 
 $            (56,272)
 
 $  (83,053)
 $   1,854,069
 
                                   
                                   
Comprehensive income (loss):
 
                               
   Net earnings
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                          -
 
       64,131
           64,131
 
   Unrealized loss on hedging
 
                               
       activities, net of tax
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                     918
 
                -
                918
 
  Change in fair value of hedging
 
                               
     derivatives, net of tax
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                  5,276
 
                -
             5,276
 
  Reversal of minimum pension
 
                               
     liability related to disposition
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                26,331
 
                -
           26,331
 
   Minimum pension liability
 
                               
      adjustment, net of tax
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                  6,803
 
                -
             6,803
 
   Comprehensive income
 
                           
         103,459
 
   Adjustment to initially apply FASB
 
 
                             
      Statement No. 158
                      -
 
                   -
 
                    -
 
                 -
 
                 -
 
                -
 
                16,043
 
                -
           16,043
 
   Preferred stock dividends
                      -
 
                   -
 
          (8,683)
 
                 -
 
                 -
 
                -
 
                          -
 
       (8,682)
          (17,365)
 
  Cash dividends declared
                      -
 
                   -
 
        (26,366)
 
                 -
 
                 -
 
                -
 
                          -
 
     (19,923)
          (46,289)
 
  Share-based compensation
                      -
 
                   -
 
            6,804
 
                 -
 
                 -
 
                -
 
                          -
 
                -
             6,804
 
  Implementation of FAS 123R
                      -
 
                   -
 
          (2,800)
 
                 -
 
                 -
 
        2,800
 
                          -
 
                -
                     -
 
  Restricted stock awards
                  146
 
                   -
 
             (146)
 
           (142)
 
                 -
 
                -
 
                          -
 
                -
               (142)
 
  Exercise of stock options
                  629
 
                   -
 
            9,544
 
                 -
 
                 -
 
                -
 
                          -
 
                -
           10,173
 
  Contributions to Trust
                      -
 
                   -
 
                    -
 
                 -
 
        (3,079)
 
        3,079
 
                          -
 
                -
                     -
 
  Disbursements from Trust
                      -
 
                   -
 
                    -
 
                 -
 
         1,361
 
      (1,361)
 
                          -
 
                -
                     -
 
  Equity Units Conversion
               7,413
 
                   -
 
        116,243
 
                 -
 
                 -
 
                -
 
                          -
 
                -
         123,656
 
Balance December 31, 2006
 $        120,718
 
 $    230,000
 
 $  1,775,763
 
 $   (27,708)
 
 $   (14,628)
 
 $   14,691
 
 $                 (901)
 
 $  (47,527)
 $   2,050,408
 
                                   


The accompanying notes are an integral part of these consolidated financial statements.

F-6


SOUTHERN UNION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME




(Continued)

   
Common
   
Preferred
   
Premium
         
Common
   
Deferred
   
Accumulated
         
Total
 
   
Stock,
   
Stock,
   
on
   
Treasury
   
Stock
   
Compen-
   
Other
   
Retained
   
Stock-
 
   
$1 Par
   
No Par
   
Capital
   
Stock,
   
Held
   
sation
   
Comprehensive
   
Earnings
   
holders'
 
   
Value
   
Value
   
Stock
   
at cost
   
In Trust
   
Plans
   
Income (Loss)
   
(Deficit)
   
Equity
 
   
(In thousands)
 
                                                       
Balance December 31, 2006
  $ 120,718     $ 230,000     $ 1,775,763     $ (27,708 )   $ (14,628 )   $ 14,691     $ (901 )   $ (47,527 )   $ 2,050,408  
Comprehensive income (loss):
                                                                       
   Net earnings
    -       -       -       -       -       -       -       228,711       228,711  
   Reclassification of unrealized
                                                                       
        gain on hedging activities,
                                                                       
        net of tax
    -       -       -       -       -       -       (4,001 )     -       (4,001 )
  Change in fair value of hedging
                                                                       
     derivatives, net of tax
    -       -       -       -       -       -       (11,320 )     -       (11,320 )
  Realized gain (loss) on interest
                                                                       
      rate hedges, net of tax
    -       -       -       -       -       -       (2,366 )             (2,366 )
Recognized actuarial gain (loss)    
 
                                                                 
     and prior service credit (cost),
                                                                       
     net of tax
    -       -       -       -       -       -       6,994       -       6,994  
   Comprehensive income
    -       -       -       -       -       -       -       -       218,018  
   Preferred stock dividends
    -       -       -       -       -       -       -       (17,365 )     (17,365 )
  Cash dividends declared
    -       -       -       -       -       -       -       (53,968 )     (53,968 )
  Share-based compensation
    -       -       3,345       -       -       -       -       -       3,345  
  Restricted stock issuances
    111       -       (111 )     (131 )     -       -       -       -       (131 )
  Exercise of stock options
    273       -       5,226       -       -       -       -       -       5,499  
  Contributions to Trust
    -       -       -       -       (769 )     769       -       -       -  
  Disbursements from Trust
    -       -       -       -       312       (312 )     -       -       -  
Balance December 31, 2007
  $ 121,102     $ 230,000     $ 1,784,223     $ (27,839 )   $ (15,085 )   $ 15,148     $ (11,594 )   $ 109,851     $ 2,205,806  
                                                                         


The Company’s common stock is $1 par value.  Therefore, the change in Common Stock, $1 par value, is equivalent to the change in the number of shares of common stock issued.



























The accompanying notes are an integral part of these consolidated financial statements.

F-7


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  Corporate Structure

Operations.  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.  Through Southern Union’s wholly-owned subsidiary, Panhandle Eastern Pipe Line Company, LP (PEPL), and its subsidiaries (collectively, Panhandle), the Company owns and operates approximately 10,000 miles of interstate pipelines that transport up to 5.3 billion cubic feet per day (Bcf/d) of natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions.  Panhandle also owns and operates a liquefied natural gas (LNG) import terminal, located on Louisiana’s Gulf Coast, which is one of the largest operating LNG facilities in North America.  Through its investment in Citrus Corp. (Citrus), the Company has an interest in and operates Florida Gas Transmission Company (Florida Gas), an interstate pipeline company that transports natural gas from producing areas in South Texas through the Gulf Coast region to Florida.  See the related discussion of the change in ownership interests of CCE Holdings, LLC (CCE Holdings) on December 1, 2006 applicable to Florida Gas and Transwestern Pipeline Company, LLC (Transwestern) in Note 3 – Acquisitions and Sales – CCE Holdings Transactions.  Through Southern Union’s wholly-owned subsidiary, Southern Union Gas Services (SUGS), the Company owns approximately 4,800 miles of natural gas and natural gas liquids (NGLs) pipelines, four active cryogenic plants with a combined capacity of 410 million cubic feet per day (MMcf/d) and five active natural gas treating plants with a combined throughput of 470 MMcf/d.  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.  The operations are located primarily throughout Texas and in the southwestern United States.  Through Southern Union’s regulated utility operations, Missouri Gas Energy and the Massachusetts operations of New England Gas Company, the Company serves natural gas end-user customers in Missouri and Massachusetts, respectively.  The Company’s discontinued operations relate to its PG Energy natural gas distribution division in Pennsylvania and the Rhode Island operations of its New England Gas Company natural gas distribution division, which were sold on August 24, 2006.
 
2.  Summary of Significant Accounting Policies

Basis of Presentation.   The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

Principles of Consolidation.  The consolidated financial statements include the accounts of Southern Union and its wholly-owned subsidiaries.  Investments in which the Company has significant influence over the operations of the investee are accounted for using the equity method.  All sig­nifi­cant intercompany accounts and transactions are eliminated in consolidation.  Certain reclassifications have been made to prior years' financial statements to conform to the current year presentation.

Purchase Accounting. The Company’s March 1, 2006 acquisition of Sid Richardson Energy Services, Ltd. and related entities (collectively, Sid Richardson Energy Services) was accounted for using the purchase method of accounting in accordance with Financial Accounting Standards Board (FASB) Statement No. 141, Business Combinations.  Under this statement, the purchase price paid by the acquirer, including transaction costs, is allocated to the assets and liabilities acquired as of the acquisition date based on their fair value. Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  Southern Union generally has used outside appraisers to assist in the initial determination of fair value.  The appraisal related to Southern Union’s acquisition of Sid Richardson Energy Services was finalized in 2006.  See Note 3 – Acquisitions and Sales – Acquisition of Sid Richardson Energy Services.

Southern Union effectively acquired an additional 25 percent interest in Citrus on December 1, 2006 as a result of the transactions described in Note 3 – Acquisitions and Sales – CCE Holdings Transactions.  The allocation of fair value associated with this incremental equity investment in Citrus is accounted for under Accounting

F-8


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Principles Board Opinion 18, The Equity Method of Accounting for Investments in Common Stock (APB 18).  For additional information, see Note 9 – Unconsolidated Investments – CCE Holdings Goodwill Evaluation.

Property, Plant and Equipment.  Ongoing additions of property, plant and equipment (PP&E) are stated at cost. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. The cost of renewals and betterments that extend the useful life of PP&E is also capitalized. The cost of repairs and replacements of minor PP&E items is charged to expense as incurred.

When PP&E is retired, the original cost less salvage value is charged to accumulated depreciation and amortization.  When entire regulated operating units of PP&E are retired or sold or non-regulated properties are retired or sold, the property and related accumulated depreciation and amortization accounts are reduced, and any gain or loss is recorded in earnings.

The Company computes depreciation expense using the straight-line method.  Depreciation rates for the utility plants are approved by the applicable regulatory commissions.

Computer software, which is a component of PP&E, is stated at cost and is generally amortized on a straight-line basis over its useful life on a product-by-product basis.

For additional information, see Note 6 – Property, Plant and Equipment.

Use of Estimates.  The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

Cash and Cash Equivalents.  The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.  Short-term investments are highly liquid investments with maturities of more than three months when purchased, and are carried at cost, which approximates market.  The Company places its temporary cash invest­ments with a high credit quality financial institution that, in turn, invests the temporary funds in a variety of high-quality short-term financial securities.

Under the Company’s cash management system, checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the Consolidated Balance Sheet.  At December 31, 2007 and December 31, 2006, such book overdraft balances classified in accounts payable were approximately $37.5 million and $45.3 million, respectively.

Segment Reporting.  FASB Statement No. 131, Disclosures about Segments of an Enterprise and Related Information, requires disclosure of segment data based on how management makes decisions about allocating resources to segments and measuring performance.  The Company is principally engaged in the transportation and storage, gathering and processing and distribution of natural gas in the United States, and reports these operations under three reportable segments: the Transportation and Storage segment, the Gathering and Processing segment and the Distribution segment.  See Note 21 – Reportable Segments.

Transportation and Storage Revenues.  In the Transportation and Storage segment, revenues from transportation and storage of natural gas and LNG terminalling are based on capacity reservation charges and commodity usage charges.  Reservation revenues are based on contracted rates and capacity reserved by customers and are recognized monthly.  Revenues from commodity usage charges are also recognized monthly, based on the volumes received from or delivered to customers, depending on the tariff of that particular entity, with any differences in received and delivered volumes resulting in an imbalance.  Volume imbalances generally are settled in-kind with no impact on revenues, with the exception of PEPL’s subsidiary, Trunkline Gas Company, LLC (Trunkline), which settles imbalances in cash pursuant to its tariff, and records gains and losses on such cashout sales as a component of revenue, to the extent not owed back to customers.


F-9


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Gathering and Processing Revenues and Cost of Sales Recognition.  Revenue and the related cost of sales for natural gas and NGLs are recognized in the period when the physical product is delivered to the customer at the contractually agreed-upon price and title is transferred. Cost of sales primarily includes the cost of purchased natural gas and NGLs.

SUGS accounts for sale and purchase arrangements on a gross basis in the Consolidated Statement of Operations as Operating revenues and Cost of gas and other energy, respectively. Contractual arrangements establish the purchase of natural gas and NGLs at specified locations and the sale at different locations on the same or other specified dates. Both purchase and sale transactions require physical delivery of the natural gas and NGLs. The transfer of ownership is evidenced by the purchaser’s assumption of title, price risk, credit risk, counterparty nonperformance risk, environmental risk, and transportation scheduling.

Gas Distribution Revenues and Gas Purchase Costs.   In the Distribution segment, gas utility customers are billed on a monthly-cycle basis.  The related cost of gas and revenue taxes are matched with cycle-billed revenues through utilization of purchased gas adjustment provisions in tariffs approved by the regulatory agencies having jurisdiction.  Revenues from gas delivered but not yet billed are accrued, along with the related gas purchase costs and revenue-related taxes.  Unbilled receivables related to the Distribution segment recorded in Accounts receivable in the Consolidated Balance Sheet at December 31, 2007 and 2006 were $56.8 million and $47.3 million, respectively.

Accounts Receivable and Allowance for Doubtful Accounts.  The Company manages trade credit risks to minimize exposure to uncollectible trade receivables.  In the Transportation and Storage and Gathering and Processing segments, prospective and existing customers are reviewed for creditworthiness based upon pre-established standards.  Customers that do not meet minimum standards are required to provide additional credit support.  In the Distribution segment, concentrations of credit risk in trade receivables are limited due to the large customer base with relatively small individual account balances.  Additionally, the Company requires a deposit from customers in the Distribution segment who lack a credit history or whose credit rating is substandard. The Company utilizes the allowance method for recording its allowance for uncollectible accounts, which is primarily based on the application of historical bad debt percentages applied against its aged accounts receivable.  Increases in the allowance are recorded as a component of operating expenses.  Reductions in the allowance are recorded when receivables are written off or subsequently collected.
 
The following table presents the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2007, 2006 and 2005:
 
   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
Beginning balance
  $ 4,830     $ 15,893     $ 15,424  
Additions: charged to cost and expenses     (1)
    11,391       9,646       22,519  
Deductions: write-off of uncollectible accounts
    (12,657 )     (9,756 )     (22,751 )
Balance related to discontinued operations (2)
    -       (10,968 )     -  
Other
    580       15       701  
Ending balance
  $ 4,144     $ 4,830     $ 15,893  
                         
_________________
(1)   Additions charged to cost and expenses applicable to continuing operations for the years ended December 31, 2007, 2006 and 2005
        were $11.4 million, $9.6 million and $8.5 million, respectively.
(2) 
Represents elimination of the allowance for doubtful accounts balance resulting from the Company’s August 24, 2006 sale of the assets of the PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division.



F-10


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Earnings Per Share.  The Company’s earnings per share (EPS) presentation conforms to FASB Statement No. 128, Earnings per Share.  All share and per share data have been appropriately restated for all stock dividends, unless otherwise stated.  See Note 10 – Stockholders’ Equity – Dividends.

Stock-Based Compensation.  The Company follows FASB Statement No. 123(R), Accounting for Stock-Based Compensation (Statement No. 123R), to account for stock-based employee compensation.  The Company adopted Statement No. 123R effective January 1, 2006, using the modified prospective method.  The statement requires the Company to measure all employee stock-based compensation using a fair value method and record such expense in its Consolidated Statement of Operations.  Prior to adoption of Statement No. 123R, the Company used the intrinsic value method of accounting for stock-based compensation awards in accordance with APB Opinion No. 25, Accounting for Stock Issued to Employees, which generally resulted in no compensation expense for employee stock options with an exercise price not less than fair value on the date of grant.  For more information, see Note 24 – Stock-Based Compensation.

Pursuant to the modified prospective application method of transition, the Company has not adjusted results of operations for prior periods. The following table reflects pro forma net earnings and net EPS adjusted for subsequent stock dividends that the Company would have reported if it had elected to adopt the fair value approach of Statement No. 123 prior to January 1, 2006:

   
Year Ended
 
   
December 31,
 
   
2005
 
   
(In thousands, except per share amounts)
 
 
       
Net earnings, as reported
  $ 20,683  
Add stock-based compensation expense included in      
reported net earnings, net of related taxes
    3,767  
Deduct total stock-based employee compensation
       
expense determined under fair value based
       
method for all awards, net of related taxes
    4,355  
Pro forma net earnings
  $ 20,095  
         
Net earnings available for common stockholders per share:      
Basic- as reported
  $ 0.03  
Basic- pro forma
  $ 0.02  
         
Diluted- as reported
  $ 0.03  
Diluted- pro forma
  $ 0.02  
         
 
Accumulated Other Comprehensive Loss.  The Company reports comprehensive income and its components in accordance with FASB Statement No. 130, Reporting Comprehensive Income.  The main components of comprehensive income that relate to the Company are net earnings, unrealized gain (loss) on hedging activities and unrealized actuarial gain (loss) and prior service credits (cost) on pension and other postretirement plans, all of which are presented in the Consolidated Statement of Stockholders’ Equity and Comprehensive Income.  For more information, see Note 22 – Accumulated Other Comprehensive Loss.

Inventories.  In the Transportation and Storage segment, inventories consist of gas held for operations and materials and supplies, both of which are carried at the lower of weighted average cost or market, while gas received from or owed back to customers is valued at market.  The gas held for operations that the Company

F-11


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




does not expect to consume in its operations in the next 12 months is reflected in non-current assets.  Gas held for operations at December 31, 2007 was $187 million, or 26,001,000 million British thermal units (MMBtu), of which $19 million was classified as non-current.  Gas held for operations at December 31, 2006 was $129 million, or 20,965,000 MMBtu, of which $14.9 million was classified as non-current.  Materials and supplies include spare parts which are critical to the pipeline system operations and are valued at the lower of cost or market. Materials and supplies inventory in the Transportation and Storage segment were $12.8 million and $13.2 million at December 31, 2007 and 2006, respectively.

In the Gathering and Processing segment, inventories consist of materials and supplies and are stated at the lower of weighted average cost or market.  Materials and supplies in the Gathering and Processing segment, primarily comprised of compressor components and parts, were $6.2 million and $6.9 million at December 31, 2007 and 2006, respectively.

In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies, both of which are carried at weighted average cost.  Natural gas in underground storage at December 31, 2007 and 2006 was $72.8 million and $103.5 million, respectively, and consisted of 11,823,474 and 14,702,000 MMBtu, respectively.  Materials and supplies inventories in the Distribution segment were $3.8 million and $3.7 million at December 31, 2007 and 2006, respectively.

Unconsolidated Investments.  Investments in affiliates over which the Company may exercise significant influence, generally 20 percent to 50 percent ownership interests, are accounted for using the equity method. Any excess of the Company’s investment in affiliates, as compared to its share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which the Company may not exercise significant influence are accounted for under the cost method.  The Company reviews its portfolio of unconsolidated investment securities on a quarterly basis to determine whether a decline in value is other-than-temporary. Factors that are considered in assessing whether a decline in value is other-than-temporary include, but are not limited to, the following: earnings trends and asset quality; near term prospects and financial condition of the issuer, including the availability and terms of any additional financing requirements; financial condition and prospects of the issuer's region and industry, customers and markets; and the Company's intent and ability to retain the investment. If the Company determines that a decline in value of an investment security is other-than-temporary, the Company will record a charge in its Consolidated Statement of Operations to reduce the carrying value of the security to its estimated fair value.  Write-downs associated with equity-method investments are recognized in Earnings from unconsolidated investments in the Consolidated Statement of Operations, and write-downs associated with cost-method investments are recognized in Other income (expenses), net, in the Consolidated Statement of Operations.  See Note 9 – Unconsolidated Investments.

Regulatory Assets and Liabilities.  The Company is subject to regulation by certain state and federal authorities.  In its Distribution segment and for certain of its operations reported as discontinued operations, the Company has accounting policies that conform to FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71), and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.  The application of these accounting policies allows the Company to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the Consolidated Statement of Operations by an unregulated company.  These deferred assets and liabilities then flow through the results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers.  Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders.  If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs.  See Note 8 – Regulatory Assets.

F-12


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Goodwill.  The Company accounts for its goodwill and other intangible assets in accordance with FASB Statement No. 142, Accounting for Goodwill and Other Intangible Assets. Goodwill acquired in a purchase business combination and determined to have an indefinite useful life is not amortized, but instead is tested for impairment at a reporting unit level at least annually by applying a fair-value based test.  The Company’s goodwill is related to its Distribution segment.  See Note 7 – Goodwill.

Fair Value of Financial Instruments.  The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equiva­lents, accounts receivable, accounts payable, derivative instruments and notes payable approximate their fair value.  The fair value of the Com­pany’s long-term debt is estimated using current market quotes and other estimation techniques.  See Note 13 – Debt Obligations.

Gas Imbalances.  In the Transportation and Storage and Gathering and Processing segments, gas imbalances occur as a result of differences in volumes of gas received and delivered. In the Transportation and Storage segment, the Company records gas imbalance in-kind receivables and payables at cost or market, based on whether net imbalances have reduced or increased system gas balances, respectively.  Net imbalances that have reduced system gas are valued at the cost basis of the system gas, while net imbalances that have increased system gas and are owed back to customers are priced, along with the corresponding system gas, at market.

In the Gathering and Processing segment, the Company records gas imbalances at the lower of cost or market.  Imbalances due to a pipeline are recorded at market and imbalances due from a pipeline are recorded at the lower of cost or market.  Market prices are based upon gas daily indexes.

Fuel Tracker.  Liability accounts are maintained in the Transportation and Storage segment for net volumes of fuel gas owed to customers collectively. Whenever fuel is due from customers from prior under-recovery based on contractual and specific tariff provisions, Trunkline and Trunkline LNG Company, LLC (Trunkline LNG) record an asset.  Panhandle’s other companies that are subject to fuel tracker provisions record an expense when fuel is under-recovered. The pipelines’ fuel reimbursement is in-kind and non-discountable.

Interest Cost Capitalized.  The Company capitalizes interest on certain qualifying assets that are undergoing activities to prepare them for their intended use in accordance with FASB Statement No. 34, Capitalization of Interest Cost.  Interest costs incurred during the construction period are capitalized and amortized over the life of the assets.  Capitalized interest for the years ended December 31, 2007, 2006 and 2005 was $14.7 million, $5.4 million and $9 million, respectively.

Derivative Instruments and Hedging Activities.  The Company follows FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (Statement No. 133), to account for derivative and hedging activities.  In accordance with this statement, all derivatives are recognized on the Consolidated Balance Sheet at their fair value.  On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge);  (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or  economic hedging instrument).  For derivatives treated as a fair value hedge, the effective portion of changes in fair value are recorded as an adjustment to the hedged item.  The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used.  Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument.  For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated other comprehensive loss until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.  For derivatives treated as trading or  economic hedging instruments, changes in fair value are reported in current-period earnings.  Fair value is determined based upon quoted market prices and mathematical models using current and historical data.  See Note 11 – Derivative Instruments and Hedging Activities.


F-13


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Asset Retirement Obligations.  The Company accounts for its asset retirement obligations in accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations (ARO) (Statement No. 143) and FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN No. 47).  These accounting principles require legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time the obligations are incurred.  Upon initial recognition of a liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset.  The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset.  In certain rate jurisdictions, the Company is permitted to include annual charges for cost of removal in its regulated cost of service rates charged to customers.

For more information, see Note 20 – Asset Retirement Obligations.

Income Taxes.  Income taxes are accounted for under the asset and liability method in accordance with the provisions of FASB Statement No. 109, Accounting for Income Taxes. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized

The determination of the Company’s provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged. When facts and circumstances change, these reserves are adjusted through the provision for income taxes. Effective January 1, 2007, with the adoption of FIN 48, Accounting for Uncertainty in Income Taxes (FIN 48), the Company began evaluating its tax reserves under the recognition, measurement and derecognition thresholds as prescribed by FIN 48.

Pensions and Other Postretirement Benefit Plans.  Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of Statement No. 158.  Statement No. 158 does not amend the expense recognition provisions of Statements No. 87, 88 and 106, but requires employers to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.   Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive loss in stockholders’ equity.  Effective for years ending after December 15, 2008 (with early adoption permitted), Statement No. 158 also requires plan assets and benefit obligations to be measured as of the employers’ balance sheet date.  The Company has not yet adopted the measurement date provisions of Statement No. 158.

The Company accounted for the measurement of its defined benefit postretirement plans under Statement No. 87 and Statement No. 106.  Prior to the adoption of the recognition and disclosure provisions of Statement No. 158, Statement No. 87 required that a liability (minimum pension liability) be recorded when the accumulated benefit obligation liability exceeded the fair value of plan assets.  Any adjustment was recorded as a non-cash charge to Accumulated other comprehensive loss.  Statement No. 106 had no minimum liability provisions.  Under both Statements No. 87 and 106, changes in the funded status were not immediately recognized, rather they were deferred and recognized ratably over future periods.  Upon adoption of the recognition provisions of Statement No. 158, the Company recognized the amounts of these prior changes in the funded status of its defined benefit postretirement plans through Accumulated other comprehensive loss.


F-14


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Commitments and Contingencies.  The Company is subject to proceedings, lawsuits and other claims related to environmental and other matters.  Accounting for contingencies requires significant judgments by management regarding the estimated probabilities and ranges of exposure to potential liability.  For further discussion of the Company’s commitments and contingencies, see Note 18 – Commitments and Contingencies.

New Accounting Principles

Accounting Principles Recently Adopted.

FIN 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109”:  Issued by the FASB in June 2006, FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes.  FIN 48 prescribes a recognition and measurement threshold attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition.  FIN 48 became effective for fiscal years beginning after December 15, 2006.  The Company’s consolidated financial statements have not been materially impacted by the adoption of FIN 48 as of January 1, 2007. See Note 15 - Taxes on Income.

FSP No. FIN 48-1, “Definition of ’Settlement’ in FASB Interpretation No. 48” (FIN 48-1):  Issued by the FASB in May 2007, FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.  The Company’s adoption of FIN 48, effective January 1, 2007, was consistent with FIN 48-1.

Accounting Principles Not Yet Adopted.

FASB Statement No. 157, “Fair Value Measurements”:  Issued by the FASB in September 2006, this Statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. Where applicable, this Statement simplifies and codifies related guidance within GAAP.  Except for certain non financial assets and liabilities more fully discussed in FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP No. FAS 157-2) which was issued by the FASB in February 2008, this Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.  For those non financial assets and liabilities deferred pursuant to FSP No. FAS 157-2, this Statement is effective for financial statements for fiscal years beginning after November 15, 2008.  The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”:  Issued by the FASB in February 2007, this Statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value.  Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings.  The Statement does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value.  The Statement is effective for fiscal years beginning after November 15, 2007.  At January 1, 2008, the Company did not elect the fair value option under the Statement and, therefore, there was no impact to the Company’s consolidated financials statements.

FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (FIN 39-1):  Issued by the FASB in April 2007, FIN 39-1 impacts entities that enter into master netting arrangements as part of their derivative transactions by allowing net derivative positions to be offset in the financial statements against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral or the obligation to return cash collateral under those arrangements.  FIN 39-1 is effective for fiscal years beginning after November 15, 2007.  The Company has determined the impact of FIN 39-1 will not have a material impact on its consolidated financial statements.


F-15


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




FASB Statement No. 141 (revised),Business Combinations”.  Issued by the FASB in December 2007, this Statement changes the accounting for business combinations including the measurement of acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for preacquisition gain and loss contingencies, the recognition of capitalized in-process research and development costs, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.
 
FASB Statement No. 160,Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”.  Issued by the FASB in December 2007, this Statement changes the accounting for noncontrolling (minority) interests in consolidated financial statements, including the requirements to classify noncontrolling interests as a component of consolidated stockholders’ equity, and the elimination of minority interest accounting in results of operations with earnings attributable to noncontrolling interests reported as part of consolidated earnings. Additionally, the Statement revises the accounting for both increases and decreases in a parent’s controlling ownership interest. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.  The Company is currently evaluating the impact of this statement on its consolidated financial statements.

Staff Accounting Bulletin No. 110 (SAB 110):  Issued by the Securities and Exchange Commission (SEC) in December 2007, SAB 110 expresses the views of the SEC staff regarding the use of a “simplified” method, as discussed in SAB No. 107, in developing an estimate of expected term of “plain vanilla” share options in accordance with FAS 123R.  The SEC staff indicated in SAB No. 107 that it would accept a company’s election to use the simplified method, regardless of whether the company has sufficient information to make more refined estimates of expected term, for options granted prior to December 31, 2007.  In SAB 110, the SEC staff states that it will continue to accept, under certain circumstances, the use of the simplified method beyond December 31, 2007.  The Company is currently evaluating the impact of SAB 110 on its consolidated financial statements.

3.  Acquisitions and Sales

Acquisition of Sid Richardson Energy Services.  On March 1, 2006, Southern Union acquired 100 percent of the partnership interests in Sid Richardson Energy Services for approximately $1.6 billion in cash.  The acquisition was undertaken by the Company to increase its investment in higher growth businesses.  The acquisition was funded under a short-term bridge loan facility in the amount of $1.6 billion (Sid Richardson Bridge Loan).  See Note 13 – Debt Obligations – Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt for additional information related to the bridge loan facility.

The principal assets of the acquired Sid Richardson Energy Services business, now known as SUGS, are located in the Permian Basin of Texas and New Mexico and include approximately 4,800 miles of natural gas and NGLs pipelines, four active cryogenic plants and five active natural gas treating plants.  SUGS’ operations are located primarily throughout Texas and in the southwestern United States.  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’ primary sales customers include producers, power generating companies, utilities, energy marketers, and industrial users located primarily in the southwestern United States.  SUGS receives hydrocarbons for purchase or transportation to market from over 240 producers and suppliers.  SUGS’ major natural gas pipeline interconnects are with ATMOS Pipeline, El Paso Natural Gas Company, Energy Transfer Fuel, LP, DCP Guadalupe Pipeline, LP, Enterprise Texas Pipeline, Northern Natural Gas Company, Oasis Pipeline, LP, ONEOK Wes Tex Transmission, LP, Public Service Company of New Mexico and Transwestern, a former affiliate of the Company (see Note 9 – Unconsolidated Investments).  Its major NGLs pipeline interconnects are with Chapparal, Louis Dreyfus and Chevron.


F-16


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The acquisition was accounted for using the purchase method of accounting, with the purchase price paid by the Company allocated to SUGS’ net assets as of the acquisition date based on their fair values.  SUGS’ assets acquired and liabilities assumed have been recorded in the Consolidated Balance Sheet beginning March 1, 2006 at their estimated fair values and have been adjusted to reflect the results of a third-party appraisal and final working capital adjustments.  SUGS’ results of operations have been included in the Consolidated Statement of Operations since March 1, 2006.  Thus, the Consolidated Statement of Operations for the periods subsequent to the acquisition are not comparable to the same periods in prior years.

The following table summarizes the estimated fair values of SUGS’ assets acquired and liabilities assumed at the date of acquisition.

   
At March 1, 2006
 
   
(In thousands)
 
       
Property, plant and equipment (1)
  $ 1,562,835  
Current assets (2)
    162,793  
Unconsolidated investment  (3)
    5,767  
Other non-current assets (4)
    2,618  
Total assets acquired
    1,734,013  
Current liabilities
    141,244  
Deferred taxes
    8,427  
Other non-current liabilities
    634  
Total liabilities assumed
    150,305  
Net assets acquired
  $ 1,583,708  
         
_________________________
(1)
Includes an allocation of $13.5 million to other intangibles for leases and software with weighted average lives of 4 years and 1 year respectively.
(2)
Includes cash and cash equivalents of approximately $53.7 million.
(3)
Represents a 50 percent ownership interest in Grey Ranch Plant LP (Grey Ranch).
(4)
Except for $33,000 of other non-current assets, balance is comprised of intangibles for customer relationships with a weighted-average life of 3 years.

The following unaudited pro forma financial information for the periods presented is reported as though the acquisition of Sid Richardson Energy Services and the related permanent financing, including utilization of the proceeds from the sales of the Company’s Pennsylvania and Rhode Island natural gas distribution divisions,
occurred at January 1, 2005.  The pro forma financial information is not necessarily indicative of the results that would have been obtained if the acquisition of Sid Richardson Energy Services and the related financing had been completed as of the assumed date for the period presented or of the results that may be obtained in the future.
 
   
Year Ended
 
   
December 31,
 
   
2006
   
2005
 
   
(In thousands, except per share amounts)
             
Operating revenue
  $ 2,570,693     $ 2,636,056  
Net earnings available for common shareholders              
from continuing operations
    209,807       163,471  
                 
Net earnings available for common shareholders from              
continuing operations per share:
               
Basic
  $ 1.83     $ 1.49  
Diluted
  $ 1.79     $ 1.45  
                 

F-17


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Sale of PG Energy.  On August 24, 2006, the Company completed the sale of the assets of its PG Energy natural gas distribution division to UGI Corporation for approximately $580 million in cash, excluding certain working capital adjustment reductions of approximately $24.4 million, which were paid in the first quarter of 2007.  Proceeds from the sale were used to retire a portion of the acquisition debt incurred in connection with Southern Union’s $1.6 billion purchase of Sid Richardson Energy Services.

Sale of the Rhode Island Operations of New England Gas Company.  On August 24, 2006, the Company completed the sale of the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA for $575 million in cash, less the assumption of approximately $77 million of debt and excluding certain working capital adjustment reductions of approximately $24.9 million, which were paid in the first quarter of 2007.  Proceeds from the sale were used to retire a portion of the acquisition debt incurred in connection with Southern Union’s $1.6 billion purchase of Sid Richardson Energy Services.

See Note 7 – Goodwill and Note 19 – Discontinued Operations for additional information, including loss on sales amounts, related to the sales of the assets of the PG Energy natural gas distribution division and the Rhode Island operations of the New England Gas Company natural gas distribution division.

CCE Holdings Transactions.

On December 1, 2006, the Company completed a series of transactions that resulted in it increasing its effective ownership interest in Citrus from 25 percent to 50 percent and eliminating its effective 50 percent ownership interest in Transwestern.  On September 14, 2006, Energy Transfer Partners, L.P. (Energy Transfer) entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings held by GE Financial Services and other investors.  At the same time, Energy Transfer and CCE Holdings entered into a definitive 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 (Redemption Agreement).  Upon the closing of the transactions under 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.  This resulted in the elimination of the Company’s prior equity investment in CCE Holdings of $680.9 million from its Consolidated Balance Sheet as of December 1, 2006, and the separate inclusion of Citrus as an equity investment with a balance of $1.23 billion in the Company’s Consolidated Balance Sheet.  Prior to December 1, 2006, Citrus was a 50 percent equity investment of CCE Holdings and was included within the Company’s 50 percent equity interest in CCE Holdings.  The resulting increase in the Company’s equity investment from CCE Holdings to Citrus is primarily attributable to the Company becoming obligated to retire $455 million of debt held by CCE Holdings and recognition of a pre-tax $74.8 million gain associated with the transaction.  The debt was simultaneously paid off using the proceeds of the $465 million LNG Holdings 2006 Term Loan more fully described in Note 13 – Debt Obligations.

Florida Gas is an open-access interstate pipeline system extending approximately 5,000 miles with a capacity of 2.1 Bcf/d 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.

At December 1, 2006, Transwestern was an open-access natural gas interstate pipeline extending approximately 2,500 miles with a capacity of 2.1 Bcf/d from the gas producing regions of west Texas, Oklahoma, eastern and northwest New Mexico and southern Colorado primarily to pipeline interconnects off the east end of its system and to the California market. Transwestern has access to three significant gas basins: the Permian Basin in west Texas and eastern New Mexico; the San Juan Basin in northwest New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle.


F-18


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




4.  Other Income and Expense Items

Operating, maintenance and general expense for the year ended December 31, 2007 includes a $6.9 million impairment of the Company’s former corporate office building due to a change in the Company’s expected proceeds from the sale of the building.

Other, net income of $39.9 million for the year ended December 31, 2006 primarily includes $37.2 million of pre-acquisition mark-to-market gains on put options associated with the acquisition of Sid Richardson Energy Services and $3.2 million in gains on sales of certain assets.  See Note 11 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment, for more information related to the gain on put options mentioned above.

Other, net expense for the year ended December 31, 2005 of $8.2 million primarily includes charges of $6.3 million to reserve for the other-than-temporary impairment of the Company’s investment in separate technology companies and to record a liability for a related loan guaranty (see Note 9 – Unconsolidated Investments), partially offset by a $1.8 million gain related to the mark-to-market accounting of put options purchased in connection with the agreement to acquire Sid Richardson Energy Services.  See Note 11 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment for additional information related to the put options.

5.  Earnings Per Share

The following table summarizes the Company’s basic and diluted earnings EPS calculations for the years ended December 31, 2007, 2006 and 2005:
 
   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands, except per share amounts)
 
                   
Net earnings from continuing operations
  $ 228,711     $ 217,083     $ 153,096  
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  
                         
Weighted average shares outstanding - Basic
    119,930       114,787       109,395  
Weighted average shares outstanding - Diluted
    120,674       117,344       112,794  
                         
Basic earnings per share:
                       
Net earnings available for common stockholders
                       
from continuing operations
  $ 1.76     $ 1.74     $ 1.24  
Loss from discontinued operations
    -       (1.33 )     (1.21 )
Net earnings available for common stockholders
  $ 1.76     $ 0.41     $ 0.03  
                         
Diluted earnings per share:
                       
Net earnings available for common
                       
stockholders from continuing operations
  $ 1.75     $ 1.70     $ 1.20  
Loss from discontinued operations
    -       (1.30 )     (1.17 )
Net earnings available for common stockholders
  $ 1.75     $ 0.40     $ 0.03  
                         
 

F-19


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Basic EPS is computed based on the weighted-average number of common shares outstanding during each period.  Diluted EPS is computed based on the weighted-average number of common shares outstanding during each period, increased by common stock equivalents from stock options, stock appreciation rights (SARs), warrants, restricted stock and convertible equity units. A reconciliation of the shares used in the basic and diluted EPS calculations is shown in the following table.
 
   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
Weighted average shares outstanding - Basic
    119,930       114,787       109,395  
Add assumed vesting of restricted stock
    35       35       16  
Add assumed conversion of equity units
    248       2,021       2,141  
Add assumed exercise of stock options
                       
and stock appreciation rights
    461       501       1,242  
Weighted average shares outstanding - Dilutive
    120,674       117,344       112,794  
                         
 
For the years ended December 31, 2007, 2006 and 2005, no adjustments were required in Net earnings available for common stockholders in the diluted EPS calculations.

The Company repurchased nil, nil and 649,343 shares of its common stock outstanding during the years ended December 31, 2007, 2006 and 2005, respectively.  The 2005 repurchases substantially occurred in private off-market large-block transactions.

There were nil, nil and 87,346 “anti-dilutive” options outstanding for the years ended December 31, 2007, 2006 and 2005, respectively.  At December 31, 2007, 783,445 shares of common stock were held by various rabbi trusts for certain of the Company’s benefit plans.  From time to time, the Company’s benefit plans may purchase shares of Southern Union common stock subject to regular restrictions.

See Note 10 – Stockholders’ Equity – 2005 Equity Issuances and 2006 Equity Issuances for information related to the 5.75% and 5% Equity Units issued on June 11, 2003 and February 11, 2005, respectively, which had a dilutive effect on EPS for the years 2005 through 2007.


F-20


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




6.  Property, Plant and Equipment

The following table provides a summary of PP&E at the dates indicated:
 
       
December 31,
 
Property, Plant and Equipment
 
Lives in Years (1)
 
2007
   
2006
 
       
(In thousands)
 
                 
Gathering and processing plant
 
 3-50
  $ 1,678,953     $ 1,623,265  
Transmission plant
 
 36-46
    1,770,742       1,400,547  
Distribution plant
 
 10-75
    930,349       897,075  
General - LNG
 
 20-40
    624,250       619,018  
Underground storage plant
 
 36-46
    290,753       279,845  
General plant and other
 
 1-50
    214,945       205,881  
Plant in service (2)
        5,509,992       5,025,631  
Construction work in progress
        377,918       178,935  
          5,887,910       5,204,566  
Less accumulated depreciation and amortization (2)
        785,623       620,139  
Net property, plant and equipment
      $ 5,102,287     $ 4,584,427  
_________________________
                   
(1) The composite weighted-average depreciation rates for the years ended December 31, 2007, 2006 and                  
      2005 were 3.4 percent, 3.0 percent and 3.0 percent, respectively.  
     
               
                     
(2) Includes capitalized computerized software cost totaling:
                   
                     
Unamortized computer software cost
      $ 109,167     $ 96,556  
Less accumulated amortization
        45,824       41,186  
Net capitalized computer software costs
      $ 63,343     $ 55,370  
                     
 
Amortization expense of capitalized computer software costs for the years ended December 31, 2007, 2006 and 2005 was $10.6 million, $9.8 million and $11 million, respectively.  Computer software costs are amortized between four and fifteen years.


F-21


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




7.  Goodwill

The following table displays changes in the carrying amount of goodwill, which relates solely to the Distribution segment:

Goodwill Analysis
 
Amounts
 
   
(In thousands)
 
       
Balance as of December 31, 2004
    640,547  
Impairment losses
    (175,000 )
Balance as of December 31, 2005
    465,547  
Impairment losses
    -  
Write-off associated with sales
    (376,320 )
Balance as of December 31, 2006
    89,227  
Impairment losses
    -  
Balance as of December 31, 2007
  $ 89,227  
         

During 2005, the Company changed the date upon which its annual goodwill impairment assessment is performed from May 31 to November 30 to correspond with the Company’s change in its fiscal year end from June 30 to December 31 and related change in the timing of completing the Company’s annual operating and capital budgets.  The Company believes this change is preferable.  The determination of whether an impairment has occurred is based on an estimate of discounted future cash flows attributable to the Company’s reporting units that have goodwill, as compared to the carrying value of those reporting units’ net assets.  No impairment was evident based upon the evaluations performed as of May 31, 2005 and November 30, 2005.  Execution of agreements for the sale 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 constituted a subsequent event of the type that, under GAAP, required the Company to consider the market value indicated by the definitive sale agreements in its 2005 goodwill impairment evaluation.  Accordingly, based on the fair values of these reporting units derived principally from the definitive sales agreements, a goodwill impairment charge of $175 million was recorded in the 2005 period in Loss  from discontinued operations before income taxes in the Consolidated Statement of Operations.  Goodwill of $376.3 million was written off on August 24, 2006 upon the completion of the sale of the assets of the PG Energy natural gas distribution division and the Rhode Island operations of the New England Gas Company natural gas distribution division.  See Note 19 – Discontinued Operations for related information.  All goodwill reflected in the Company’s Consolidated Balance Sheet is applicable to its Distribution segment.  There were no goodwill impairment indicators evident for the year ended December 31, 2007 or 2006.

8.  Regulatory Assets

The Company records regulatory assets and liabilities with respect to its Distribution segment operations in accordance with Statement No. 71.  Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply Statement No. 71 in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of Statement No. 71 primarily due to the level of discounting from tariff rates and its inability to recover specific costs.


F-22


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The following table provides a summary of regulatory assets at the dates indicated:
 
   
December 31,
 
Regulatory Assets
 
2007
   
2006
 
   
(In thousands)
 
             
Pension and Postretirement Benefits
  $ 32,889     $ 33,969  
Environmental
    21,782       15,571  
Missouri Safety Program
    5,546       8,751  
Other
    3,976       7,574  
    $ 64,193     $ 65,865  
                 
 
The Company’s regulatory assets at December 31, 2007 relating to Distribution segment operations that are being recovered through current rates totaled $44.8 million.  The Company expects that the $19.4 million of regulatory assets not currently in rates will be included in its rates as rate cases occur in the future.  The remaining recovery period associated with these assets ranged from 7 months to 93 months.  The Company’s regulatory assets at December 31, 2006 relating to Distribution segment operations that are being recovered through current rates totaled $30.7 million.  The remaining recovery period associated with these assets ranged from 12 months to 93 months.

9.  Unconsolidated Investments

 
A summary of the Company’s unconsolidated investments at the dates indicated is as follows:
 
   
December 31,
 
Unconsolidated Investments
 
2007
   
2006
 
   
(In thousands)
 
Equity investments:
           
Citrus
  $ 1,219,009     $ 1,233,172  
Other
    21,411       20,802  
Investments at cost
    -       775  
    $ 1,240,420     $ 1,254,749  
                 
 
Equity Investments.  Unconsolidated investments at December 31, 2007 and 2006 included the Company’s 50 percent, 50 percent, 29 percent and 49.9 percent investments in Citrus, Grey Ranch, Lee 8 and PEI Power II, respectively. The Company accounts for these investments using the equity method.  The Company’s share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the Consolidated Statement of Operations.

Dividends.  During the year ended December 31, 2007, Citrus paid dividends of $103.6 million to the Company.  Citrus also declared a dividend in December 2007, payable in January 2008, of which the Company’s share of $21.3 million is included in Accounts receivable — affiliates in the Consolidated Balance Sheet at December 31, 2007.  The Company received this dividend on January 18, 2008.

For the eleven months ended November 30, 2006 and the year ended December 31, 2005, prior to becoming a wholly-owned subsidiary of the Company on December 1, 2006, CCE Holdings paid the Company distributions totaling $48.8 million and $15 million, respectively.


F-23


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Summarized financial information for the Company’s equity investments is as follows:

   
At December 31, 2007
   
At December 31, 2006
 
         
Other Equity
         
Other Equity
 
   
Citrus
   
Investments
   
Citrus
   
Investments
 
   
(In thousands)
 
Balance Sheet Data:
                       
  Current assets
  $ 59,644     $ 7,324     $ 64,295     $ 3,552  
  Non-current assets
    3,049,214       38,008       3,056,818       37,633  
  Current liabilities
    208,508       1,040       191,341       1,589  
  Non-current liabilities
    1,697,218       1,792       1,636,671       1,802  
                                 

   
Year Ended
   
Year Ended
 
   
December 31, 2007
   
December 31, 2006
 
         
Other Equity
   
CCE
         
Other Equity
 
   
Citrus
   
 Investments
   
 Holdings (1)
   
Citrus (4)
   
Investments
 
   
 (In thousands)
 
Statement of Operations Data:                              
Revenues
  $ 495,513     $ 13,061     $ -     $ 37,598     $ 5,386  
Operating income (loss)
    283,203       4,424       (5,729 )     21,201       1,157  
Equity earnings
    -       -       70,086   (2)     -       -  
Interest expense
    73,871       127       25,445       7,109       146  
Earnings from discontinued
                                       
operations
    -       -       156,612   (3)     -       -  
Net earnings
 
  157,092       5,256       196,857       9,579       1,005  
                                         
_____________________
(1)  The statement of operations information of CCE Holdings is through the period ended December 1, 2006.  See
       Note 3 - Acquisitions and Sales - CCE Holdings Transactions for a description of the transactions
       that led to the Company's consolidation of CCE Holdings as of December 1, 2006.
(2)  Represents equity earnings of CCE Holdings in Citrus through the period ending December 1, 2006.
(3)  Earnings from discontinued operations for CCE Holdings relates primarily to the eleven months of operations of
      Transwestern and to the closing of the transactions on December 1, 2006 included in the Redemption Agreement,
      resulting in Energy Transfer’s interest in CCE Holdings being exchanged for CCE Holdings’ interest in Transwestern.
      The year ended December 31, 2006 includes a pre-tax gain of $74.8 million related to the closing of the transactions
      included in the Redemption Agreement.  See Note 3 - Acquisitions and Sales - CCE Holdings Transactions for
      a description of the transaction.
(4)  Includes Citrus results for the post-Redemption Agreement period of December 2006.

Citrus and CCE Holdings.  On December 1, 2006, as more fully described in Note 3 – Acquisitions and Sales – CCE Holdings Transactions, 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.  Upon closing of the transactions under 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.  This resulted in the elimination of the Company’s equity investment in CCE Holdings as of December 1, 2006 and the separate presentation of Citrus as an equity investment.  Prior to December 1, 2006, Citrus was a 50 percent equity investment of CCE Holdings and included within the Company’s 50 percent equity interest in CCE Holdings.


F-24


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The Company’s equity investment balances include amounts in excess of the Company’s share of the underlying equity of the investee of $617.4 million and $585.6 million as of December 31, 2007 and 2006, respectively.  These amounts relate to the Company’s 50 percent equity ownership interest in Citrus.  The equity goodwill includes an allocation of $208.4 million of excess purchase cost associated with the increased interest in Citrus effectively acquired on December 1, 2006.  The combined fair value amount recorded in excess of the Company’s 50 percent share of the underlying Citrus equity at December 31, 2007 was as follows:

   
Excess Purchase Costs
   
Amortization Period
 
   
(In thousands)
   
             
Property, plant and equipment
  $ 2,885    
40 years
 
Capitalized software
    1,478    
5 years
 
Long-term debt  (1)
    (80,204 )  
4-20 years
 
Deferred taxes  (1)
    (6,883 )  
40 years
 
Other net liabilities
    (541 )  
 N/A
 
Goodwill  (2)
    664,609    
 N/A
 
Sub-total
    581,344        
Accumulated, net accretion to equity earnings
    36,102        
Net investment in excess of underlying equity
  $ 617,446        
               
____________________
(1)
Accretion of this amount increases equity earnings and accumulated net accretion.
(2)
The Company’s tax basis in the investment in Citrus includes equity goodwill.  See “Goodwill Evaluation” below.


Other.   The Company’s investments in Grey Ranch, the Lee 8 partnership and PEI Power are accounted for under the equity method.  The Grey Ranch Plant, LP is a 225 MMcf/d carbon dioxide treatment facility.  The Lee 8 partnership operates a 3.0 Bcf natural gas storage facility in Michigan.  PEI Power II is a 45-megawatt, natural gas-fired electric generation plant operated through a joint venture with Cayuga Energy in Pennsylvania.

Investments at Cost.  As of December 31, 2007, the Company, either directly or through a subsidiary, owned common and preferred stock in two non-public companies, Advent Networks, Inc. (Advent) and PointServe, Inc. (PointServe), whose fair values are not readily determinable. These investments are accounted for under the cost method. Realized gains and losses on sales of these investments, as determined on a specific identification basis, are included in the Consolidated Statement of Operations when incurred, and dividends are recognized within earnings when received. Various officers, directors and employees of Southern Union either directly or through a partnership also have an equity ownership interest in Advent.  As of December 31, 2007, the Company had fully reserved the related book balances for other-than-temporary impairments.  See Note 4 – Other Income and Expense Items for additional related information.

Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus.

Phase VIII Expansion.  Florida Gas plans to seek FERC approval to construct an expansion to increase its natural gas capacity into Florida by approximately 800 MMcf/d (Phase VIII Expansion).  The proposed Phase VIII Expansion includes construction of approximately 500 miles of additional large diameter pipeline and the installation of approximately 170,000 horsepower of additional compression.  Pending FERC approval, which is expected in 2009, Florida Gas anticipates an in-service date of 2011, at an approximate cost of $2 billion.  Florida Gas has signed a 25-year agreement with Florida Power and Light Company, a whollyowned subsidiary of FPL Group, Inc., for 400 MMcf/d of capacity.
 
On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement (Citrus Credit Agreement) with a wholly-owned subsidiary of FPL Group Capital Inc, which is a whollyowned subsidiary of FPL Group, Inc.   Citrus will contribute the proceeds of this loan to Florida Gas in order to finance a portion of the Phase VIII Expansion.     

F-25


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The Citrus Credit Agreement provides for a single $500 million draw after Florida Gas’ receipt of a certificate from the FERC authorizing construction of the Phase VIII Expansion and Citrus’ satisfaction of customary conditions precedent, which are expected to be met in the second half of 2009.  On or before the Phase VIII Expansion in-service date, the construction loan will convert to an amortizing 20-year term loan with a $300 million balloon payment at maturity.  The loan requires semi-annual payments of principal beginning five years and six months after the conversion to a term loan.  The Citrus Credit Agreement provides for interest on the outstanding principal amount at the rate of six-month LIBOR plus 535 basis points prior to conversion to a term loan and at the twenty-year treasury rate plus 535 basis points after conversion to a term loan.  The loan is not guaranteed by Florida Gas and does not include a prepayment option.   The Citrus Credit Agreement contains certain customary representations, warranties and covenants and requires the execution of a negative pledge agreement by Florida Gas.
 
Environmental Matters.  Florida Gas is responsible for environmental remediation of contamination resulting from past releases of hydrocarbons and chlorinated compounds at certain sites on its gas transmission systems.   Florida Gas is implementing a program to remediate such contamination.  Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity.  The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Spill Prevention, Control and Countermeasure Rules (SPCC).  In May 2007, the U.S. EPA extended the SPCC rule compliance dates until July 1, 2009 permitting owners and operators of facilities to prepare or amend and implement SPCC Plans in accordance with previously enacted modifications to the regulations.  In October of 2007, the U.S. EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements, and streamlining requirements.  The Company is currently reviewing the impact of the modified regulations on its operations and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures.  Costs associated with such activities cannot be estimated with certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

CCE Holdings’ Goodwill Evaluation.  CCE Holdings applied the purchase method of accounting for its acquisition of CrossCountry Energy on November 17, 2004.  Goodwill associated with CCE Holdings’ equity investment in Citrus accounted for under APB 18 was approximately $664.6 million and $642.2 million at December 31, 2007 and 2006, respectively.  The amounts recorded at December 31, 2007 includes final purchase price allocations related to the December 1, 2006 redemption of Transwestern and the resulting increase in Southern Union’s equity interest in Citrus.  See Note 3 – Acquisitions and Sales – CCE Holdings Transactions.

Regulatory Assets and Liabilities.  Florida Gas is subject to regulation by certain state and federal authorities.  Florida Gas has accounting policies that conform to Statement No. 71 and are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities.  Management’s assessment for Florida Gas of the probability of its recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders.  If, for any reason, Florida Gas ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from its consolidated balance sheet, resulting in an impact to the Company’s share of its equity earnings.  Florida Gas’ regulatory asset and liability balances at December 31, 2007 were $19.2 million and $14.8 million, respectively.

Federal Pipeline Integrity Rules.  On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas” (HCAs).  This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002.  The rule requires operators to have identified HCAs along their pipelines by December 2004 and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by June 2004.  Operators were required to rank the risk of their pipeline segments containing

F-26


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




HCAs and to complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007.  Assessments will generally be conducted on the higher risk segments first, with the balance being completed by December 2012.  As of December 31, 2007, Florida Gas completed 62 percent of the risk assessments.  In addition, some system modifications will be necessary to accommodate the in-line inspections.  All systems operated by the Company will be compliant with the rule; however, while identification and location of all HCAs has been completed, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections.  For Florida Gas, the required modifications and inspections are currently estimated to be in the range of approximately $21 million to $28 million per year through 2012.

Florida Gas Pipeline Relocation Costs.  The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects that have impacted or may, over time, impact one or more of Florida Gas’ mainline pipelines co-located in FDOT/FTE rights-of-way.  The first phase of the turnpike project includes replacement of approximately 11.3 miles of its existing 18- and 24- inch pipelines located in FDOT/FTE right-of-way in Florida.  Estimated cost of such replacement would be $110 million.  Florida Gas is also in discussions with the FDOT/FTE related to additional projects that may affect Florida Gas’ 18- and 24-inch pipelines within FDOT/FTE rights-of-way.  The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or right-of-way costs, cannot be determined at this time.

Under certain conditions, existing agreements between Florida Gas and the FDOT/FTE require the FDOT/FTE to provide any new rights-of-way needed for relocation of the pipelines and for Florida Gas to pay for rearrangement or relocation costs. Under certain other conditions, Florida Gas may be entitled to reimbursement for the costs associated with relocation, including construction and right-of-way costs.  On January 25, 2007, Florida Gas filed a complaint against the FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, seeking relief with respect to three specific sets of FDOT/FTE widening projects in Broward County.  The complaint seeks damages for breach of easement and relocation agreements for the one set of projects on which construction has already commenced, and injunctive relief as well as damages for the two other sets of projects on which construction has yet to commence.  The FDOT/FTE filed an amended answer and counterclaim against Florida Gas on February 5, 2008 in the Broward County action.  The counterclaim alleges Florida Gas is subject to estoppel and breach of contract regarding removal from service of the existing pipelines on the project currently under construction and seeks a declaratory judgment that Florida Gas is responsible for all relocation costs and is not entitled to workspace and uniform minimum area precluding FDOT/FTE activity.  On February 14, 2008, the case was transferred to the Broward County Complex Business Civil Division 07.  As a result, the March 10, 2008 hearing on the motion by Florida Gas for a temporary injunction enjoining the FDOT/FTE interference with the pipelines of Florida Gas will be rescheduled.  On April 24, 2007, the FDOT/FTE filed a complaint against Florida Gas in the Ninth Judicial Circuit, Orange County, Florida, seeking a declaratory judgment that, under existing agreements, Florida Gas is liable for the costs of relocation associated with such projects and is not entitled to certain other rights.  On August 7, 2007, the Orange County Court granted a motion by Florida Gas to abate and stay the Orange County action.

On October 24, 2007, Florida Gas filed a complaint in the US District Court of the Northern District of Florida, Tallahassee Division, against Stephanie C. Kopelousos (Kopelousos) in her official capacity as the Secretary of the Florida Department of Transportation, seeking to enjoin Kopelousos from violating federal law in connection with construction of the FDOT/FTE Golden Glades project, a new toll plaza in Miami-Dade County, Florida.  Florida Gas seeks a declaratory judgment that certain Florida statutes are preempted by federal law to the extent such state statutes purport to regulate the abandonment or relocation schedule for the federally regulated pipelines of Florida Gas and prospective preliminary and permanent injunctive relief enjoining Kopelousos from proceeding with construction on the Golden Glades project over and around such pipelines.  Kopelousos has filed a motion to dismiss and Florida Gas has responded.  Based upon representations by the FDOT/FTE that work would not begin on the Golden Glades project until 2013, the parties entered into a joint stipulation of dismissal without prejudice on February 15, 2008.

F-27


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Should Florida Gas be denied reimbursement by the FDOT/FTE for any possible relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings.  Florida Gas expects to seek rate recovery at FERC for all reasonable and prudent costs incurred in relocating its pipelines to accommodate the FDOT/FTE to the extent not reimbursed by the FDOT/FTE.  There can be no assurance that Florida Gas will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of reimbursement will fully compensate Florida Gas for its costs.

Citrus Trading Litigation.  On January 29, 2007, Citrus Trading, Citrus, Southern Union and El Paso Corporation (collectively, Citrus Parties) entered into a settlement regarding litigation with Spectra Energy LNG Sales, Inc., formerly known as Duke Energy LNG Sales, Inc. (Duke), and its parent company, Spectra Energy Corporation (collectively, Spectra), whereby Spectra agreed to pay $100 million to Citrus Trading.  The litigation related to a natural gas purchase contract between Citrus Trading and Duke that had been terminated in 2003.  Citrus recorded a net gain of $15 million in the first quarter of 2007, $7.5 million of which is included in Earnings from unconsolidated investments in the Consolidated Statement of Operations.  The Citrus Parties also entered into a settlement on January 29, 2007 with Enron Corp. pursuant to which CCE Holdings’ obligation to remit to Enron Corp. certain proceeds of any Duke settlement was reduced, resulting in a $7.6 million gain recorded in Earnings from unconsolidated investments in the Consolidated Statement of Operations.

Citrus Enron Bankruptcy Receivable.  Citrus previously filed bankruptcy related claims against an Enron-affiliated bankrupt company.  The parties reached a settlement in the amount of $22.7 million on the allowed claim, which was approved by the bankruptcy court in March 2007.  Citrus fully reserved for the amounts in 2001 and sold the receivable claim in the second quarter of 2007 to a third-party for $11.4 million, resulting in a gain.  Earnings from unconsolidated investments includes $5.7 million of the gain ($3.6 million, net of tax), representing the Company’s 50 percent equity share of the gain.

Litigation.

Jack Grynberg.  Jack Grynberg, an individual, has filed actions against a number of companies, including Florida Gas, alleging mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  For additional information related to these filed actions, see Note 18 – Commitments and Contingencies – Litigation.

10.  Stockholders’ Equity

Dividends.  The table below presents the amount of cash dividends declared and paid in the respective periods:
 
Shareholder
 
Date
 
Amount
   
Amount
 
Record Date
 
Paid
 
Per Share
   
Paid
 
             
(In thousands)
 
                 
December 28, 2007
 
January 11, 2008
  $ 0.15     $ 17,999  
September 28, 2007
 
October 12, 2007
    0.10       11,997  
June 29, 2007
 
July 13, 2007
    0.10       11,995  
March 30, 2007
 
April 13, 2007
    0.10       11,977  
                     
December 29, 2006
 
January 12, 2007
  $ 0.10     $ 11,961  
September 29, 2006
 
October 13, 2006
    0.10       11,956  
June 30, 2006
 
July 14, 2006
    0.10       11,197  
March 31, 2006
 
April 14, 2006
    0.10       11,175  
                     
 

 
F-28


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




For the year ended December 31, 2006, the Company reduced Retained earnings (deficit) and Premium on capital stock in the Consolidated Statement of Stockholders’ Equity and Comprehensive Income by $19.9 million (to the extent that retained earnings were available) and $26.4 million, respectively.

Prior to 2006, the Company distributed common stock dividends in lieu of cash dividend payments.  On September 1, 2005, the Company distributed its then annual five percent common stock dividend to stockholders of record on August 22, 2005.  Unless other­wise stated, all per share and share data in this report for periods prior to 2006 have been restated to give effect to the stock dividend.

Under the terms of the indenture governing its Senior Notes, Southern Union may not declare or pay any cash or asset dividends on its common stock (other than dividends and distributions payable solely in shares of its common stock or in rights to acquire its common stock) or acquire or retire any shares of its common stock, unless no event of default exists and certain financial ratio requirements are satisfied.  Currently, the Company is in compliance with these requirements and, therefore, the Senior Note indenture does not prohibit the Company from paying cash dividends.
 
Stock Award Plans.  On May 9, 2005, the stockholders of the Company adopted the Southern Union Company Amended and Restated 2003 Stock and Incentive Plan (Amended 2003 Plan).  The Amended 2003 Plan allows for awards in the form of stock options (either incentive stock options or non-qualified options), SARs, stock bonus awards, restricted stock, performance units or other equity-based rights.  The persons eligible to receive awards under the Amended 2003 Plan include all of the employees, directors, officers and agents of, and other service providers to, the Company and its affiliates and subsidiaries.  The Amended 2003 Plan provides that each non-employee director will receive annually a restricted stock award, or at the election of the non-employee director options having an equivalent value, which will be granted at such time or times as the compensation committee shall determine. Under the Amended 2003 Plan: (i) no participant may receive in any calendar year awards covering more than 500,000 shares; (ii) the exercise price for a stock option may not be less than 100 percent of the fair market value of the common stock on the date of grant; and (iii) no award may be granted more than ten years after the date of the Amended 2003 Plan.
 
On May 2, 2006, the stockholders of the Company adopted the Second Amended and Restated 2003 Plan (Second Amended 2003 Plan), which included the following changes to the Amended 2003 Plan:

 
·
An increase from 7,000,000 to 9,000,000 in the aggregate number of shares of stock that may be issued under the plan;
 
·
An increase from 725,000 to 1,500,000 in the total number of shares of stock that may be issued pursuant to stock awards, performance units and other equity-based rights; and
 
·
An increase from 4,000 to 5,000 in the maximum number of shares of restricted common stock that each non-employee director is eligible to receive annually.
 
On July 1, 2005, pursuant to the respective separation agreements between the Company and each of its former Vice Chairman of the Board of Directors and former Chief Financial Officer, the Company modified the terms of approximately 307,000 options to purchase its common stock that had previously been granted to and were exercisable by these executives under the Company’s 1992 Long-Term Stock Incentive Plan (1992 Plan) and Amended 2003 Plan.  As a result of the modification and re-valuation of the options as of July 1, 2005, the Company recorded $3.8 million of non-cash compensation expense during the quarter ended September 30, 2005.  All of these options were exercised as of December 31, 2006.
 


F-29


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The Company maintains its 1992 Plan, under which options to purchase 8,491,540 shares of its common stock were authorized to be granted until July 1, 2002 to officers and key employees at prices not less than the fair market value on the date of grant.  The 1992 Plan allowed for the granting of SARs, dividend equivalents, performance shares and restricted stock.  Options granted under the 1992 Plan are exercisable for ten years from the date of grant or such lesser period as may be designated for particular options, and become exercisable after a specified period of time from the date of grant in cumulative annual installments.  Options typically vest at the rate of 20 percent per year, but may vest over a longer or shorter period as designated for a particular option grant.  At December 31, 2006, there were no shares available for future option grants under the 1992 Plan.

In connection with the acquisition of Pennsylvania Enterprises, Inc., the Company adopted the Pennsylvania Division 1992 Stock Option Plan (Pennsylvania Option Plan) and the Pennsylvania Division Stock Incentive Plan (Pennsyl­vania Incentive Plan and, together with the Pennsylvania Option Plan, the Pennsylvania Plans).  At December 31, 2007, no options were outstanding and no additional options will be granted under the Pennsylvania Plans.  During the year ended December 31, 2005, options exercised under the Pennsylvania Option Plan were 466,127.  During the year ended December 31, 2005, 139,837 and 91,831 options were exercised and canceled, respectively, under the Pennsylvania Incentive Plan.

For more information on share-based awards, see Note 24 – Share-Based Compensation.

2006 Equity Issuances.  On August 16, 2006, the Company received $125 million from the issuance of 7,413,074 shares of common stock in conjunction with the remarketing of its 2.75% Senior Notes and the consummation of the forward stock purchase contracts that were issued with the 2.75% Senior Notes as part of the June 2003 5.75% Equity Units issuance.  See Note 13 – Debt Obligations – Long-Term Debt

2005 Equity Issuances.  On February 11, 2005, Southern Union issued 2,000,000 of its 5% Equity Units at a public offering price of $50 per unit, resulting in net proceeds to the Company, after underwriting discounts and commissions and other transaction related costs, of $97.4 million.  Southern Union used the proceeds to repay the balance of the bridge loan used to finance a portion of its investment in CCE Holdings and to repay borrowings under its credit facilities.  Each 5% Equity Unit consisted of a 1/20th interest in a $1,000 principal amount of Southern Union’s 4.375% Senior Notes due 2008 (see Note 13 – Debt Obligations) and a forward stock purchase contract that obligated the holder to purchase Southern Union common stock on February 16, 2008, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $22.74 and $28.42, respectively, which were subject to adjustments for future stock splits or stock dividends).  On February 19, 2008, the Company issued 3,693,240 shares of its common stock upon the consummation of the forward purchase contracts.  The 5% Equity Units carried a total annual coupon of 5.00 percent (4.375 percent annual face amount of the senior notes plus 0.625 percent annual contract adjustment payments).  The present value of the 5% Equity Units’ contract adjustment payments was initially charged to stockholders’ equity, with an offsetting credit to liabilities.  The liability was accreted over three years by interest charges to the Consolidated Statement of Operations.  Before the issuance of Southern Union’s common stock upon settlement of the purchase contracts, the 5% Equity Units were reflected in the Company’s diluted EPS calculations using the treasury stock method.  See Note 25 – Subsequent Event.

On February 9, 2005, Southern Union issued 14,913,042 shares of common stock at a public offering price of $23.00 per share, resulting in net proceeds, after underwriting discounts and commissions of $332.6 million.  Southern Union used the net proceeds to repay a portion of the bridge loan used to finance a portion of its investment in CCE Holdings.

F-30


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




11.  Derivative Instruments and Hedging Activities

Interest Rate Swaps.  The Company uses interest rate swaps to reduce interest rate risks and to manage interest expense.  By entering into these agreements, the Company converts floating-rate debt into fixed-rate debt, or alternatively converts fixed-rate debt to floating-rate debt.  Interest differentials paid or received under the swap agreements are reflected as an adjustment to interest expense.  These interest rate swaps are financial derivative instruments that qualify for hedge treatment.  The notional amounts of the interest rate swaps are not exchanged and do not represent exposure to credit loss.  In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.  For the years ended December 31, 2007, 2006 and 2005, there was no swap ineffectiveness.  At December 31, 2007, $17.1 million is included in Deferred Credits in the Consolidated Balance Sheet related to the fixed-rate interest rate swaps on the $455 million Term Loan due 2012.  As of December 31, 2007, approximately $3.2 million of net after-tax losses in Accumulated other comprehensive loss will be amortized into interest expense during the next twelve months related to the swap agreements.  Current market pricing models were used to estimate fair values of interest rate swap agreements.

Treasury Rate Locks.  The Company enters into treasury rate locks to hedge the changes in cash flows of anticipated interest payments from changes in treasury rates prior to the issuance of new debt instruments.  The Company accounts for the treasury rate locks as cash flow hedges.  At December 31, 2007, $1.7 million is included in Prepayments and Other in the Consolidated Balance Sheet related to the treasury rate locks entered into during 2007.   As of December 31, 2007, approximately $1 million of net after-tax losses in Accumulated other comprehensive loss will be amortized into interest expense during the next twelve months related to these treasury rate locks.

Distribution Segment

Economic Hedging Activities.  During 2007, 2006 and 2005, the Company entered into natural gas commodity swaps and collars to mitigate price volatility of natural gas passed through to utility customers in the Distribution Segment. The cost of the derivative products and the settlement of the respective obligations are recorded through the gas purchase adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings. The fair values of the contracts are recorded as an adjustment to a regulatory asset or liability in the Consolidated Balance Sheet.  As of December 31, 2007 and 2006, the fair values of the contracts, which expire at various times through December 2009, are included in the Consolidated Balance Sheet as assets and liabilities, respectively, with matching adjustments to deferred cost of gas of $22.3 million and $19 million, respectively.

Gathering and Processing Segment

The Company markets natural gas and NGLs in its Gathering and Processing segment and manages associated commodity price risks using derivative financial instruments.  These instruments involve not only the risk of transacting with counterparties and their ability to meet the terms of the contracts but also the risk associated with unmatched positions and market fluctuations.  The Company is required to record derivative financial instruments at fair value, which is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.


F-31


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Economic Hedging Derivatives.  The Company uses various derivative financial instruments to manage commodity price risk and to take advantage of pricing anomalies among derivative financial instruments related to natural gas and NGLs.  The Company uses a combination of crude oil puts, NGL gross processing spread puts, fixed-price physical forward contracts, exchange-traded futures and options, and fixed or floating index and basis swaps to manage sales commodity price risk.  These economic hedge 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.  Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations.  For the year ended December 31, 2007 and the ten-months ended December 31, 2006, gains of $1.2 million and $1.2 million, respectively, were recorded for the economic hedging activities.  At December 31, 2007 and 2006, the net asset derivative balance was $6.7 million and $10.3 million, respectively.
 
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.


F-32


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Accounting Hedges Designated as Cash Flow Hedges. In accordance with Statement No. 133, the Company designated its natural gas, propane and ethane put options as accounting (cash flow) hedges.  The Company used such accounting hedges to manage its commodity price risk and reduce fluctuations in operating cash flows.  All of the Company’s put options on its natural gas, propane and ethane products expired as of December 31, 2007. 

The table below summarizes the financial statement impact of hedged put options related to natural gas and NGLs the Company had in place during the respective periods.

   
Years Ended December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
             
Change in fair value of commodity hedges - increase
           
(decrease) in Accumulated other comprehensive loss,
           
excluding tax expense effect of $(775) and $7,556, respectively
  $ (2,054 )   $ 19,826  
Reclassification of unrealized gain on
               
commodity hedges - increase of Operating Revenues,
               
excluding tax expense effect of $2,425 and $4,266, respectively
    6,422       11,350  
Loss realized upon cash settlement - decrease
               
of Operating revenues
    718       45  
Loss on ineffectiveness of commodity hedges
    -       1,634  
Cash realized on settlement of commodity hedges
    35,374       74,214  
                 

At December 31, 2007 and 2006, the Company reported in the Consolidated Balance Sheet in Prepayments and other assets, derivative asset balances for its hedged put options of nil and $38.1 million, respectively.  During 2007, the Company reclassified all previously deferred gains included in Accumulated other comprehensive loss into earnings.

12.  Preferred Securities

On October 8, 2003, the Company issued 9,200,000 depositary shares, each representing a 1/10th interest in a share of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 Per Share) (Preferred Stock), at the public offering price of $25 per share, or $230 million in the aggregate.  The total net proceeds were used to repay debt under the Company’s revolving credit facilities.  The Company may redeem the Preferred Stock beginning on October 8, 2008.


F-33


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




13.  Debt Obligations

The following table sets forth the debt obligations of Southern Union and Panhandle under their respective notes, debentures and bonds at the dates indicated:

   
December 31, 2007
   
December 31, 2006
 
   
Carrying Value
   
Fair Value
   
Carrying Value
   
Fair Value
 
   
(In thousands)
 
Long-Term Debt Obligations:
                       
                         
Southern Union
                       
7.60% Senior Notes due 2024
  $ 359,765     $ 378,473     $ 359,765     $ 384,948  
8.25% Senior Notes due 2029
    300,000       336,090       300,000       371,367  
7.24% to 9.44% First Mortgage Bonds
    19,500       19,500       19,500       19,500  
due 2020 to 2027
                               
4.375% Senior Notes due 2008
    100,000       100,000       100,000       100,000  
6.15% Senior Notes due 2008
    125,000       124,538       125,000       125,655  
7.20% Junior Subordinated Notes due 2066
    600,000       590,280       600,000       598,572  
      1,504,265       1,548,881       1,504,265       1,600,042  
                                 
Panhandle
                               
2.75% Senior Notes due 2007
    -       -       200,000       200,000  
4.80% Senior Notes due 2008
    300,000       298,140       300,000       300,000  
6.05% Senior Notes due 2013
    250,000       252,650       250,000       251,053  
6.20% Senior Notes due 2017
    300,000       297,240       -       -  
6.50% Senior Notes due 2009
    60,623       62,132       60,623       61,721  
8.25% Senior Notes due 2010
    40,500       43,396       40,500       43,180  
7.00% Senior Notes due 2029
    66,305       65,198       66,305       71,947  
Term Loan due 2007
    -       -       255,626       255,626  
Term Loan due 2012  (1)
    412,220       412,220       465,000       465,000  
Term Loan due 2012
    455,000       455,000       -       -  
Net premiums on long-term debt
    6,093       6,093       9,613       9,613  
      1,890,741       1,892,069       1,647,667       1,658,140  
                                 
Total Long-Term Debt Obligations
    3,395,006       3,440,950       3,151,932       3,258,182  
                                 
Credit Facilities
    123,000       123,000       100,000       100,000  
                                 
Total consolidated debt obligations
    3,518,006     $ 3,563,950       3,251,932     $ 3,358,182  
Less fair value swaps of Panhandle
    -               1,265          
Less current portion of long-term debt  (2), (3)
    434,680               461,011          
Less short-term debt
    123,000               100,000          
Total consolidated long-term debt obligations
  $ 2,960,326             $ 2,689,656          
                                 
___________________________
(1)
At December 31, 2006, this Term Loan was due in 2008.  See the following LNG Holdings Term Loans discussion for information related
 
to the extension of the maturity date from April 4, 2008 to June 29, 2012.
(2)  Includes nil and $1.3 million of fair value of swaps related to debt classified as current at December 31, 2007 and 2006,
       respectively.
(3)  Excludes $100 million related to the 4.375% Senior Notes that were remarketed in February 2008 resulting in a change of the maturity
       date to February 16, 2010.  See Note 25 — Subsequent Event for additional related information.
 
 
 
F-34


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



 
Long-Term Debt.

Southern Union has $3.4 billion of long-term debt, including net premiums of $6.1 million, recorded at December 31, 2007, of which $434.7 million is current.  Debt of $2.98 billion is at fixed rates ranging from 4.38 percent to 9.44 percent.  Southern Union also has floating rate debt totaling $412.2 million, bearing an interest rate of 5.37 percent as of December 31, 2007.

As of December 31, 2007, the Company has scheduled long-term debt payments, excluding credit facility payments and net premiums on debt, as follows:

                                 
2013 and
 
   
2008
   
2009
   
2010
   
2011
   
2012
   
thereafter
 
   
(In thousands)
 
                                     
Southern Union Company
  $ 125,000     $ -     $ 100,000     $ -     $ -     $ 1,279,265  
Panhandle
    309,831       60,623       40,500       -       857,389       616,305  
Total
  $ 434,831     $ 60,623     $ 140,500     $ -     $ 857,389     $ 1,895,570  
                                                 
 
Each note, debenture or bond is an obligation of Southern Union or a unit of Panhandle, as noted above.  Panhandle’s debt is non-recourse to Southern Union.  All debts that are listed as debt of Southern Union are direct obligations of Southern Union.  None of the Company’s long-term debt is cross-collateralized and most of its long-term debt obligations contain cross-default provisions.

6.20% Senior Notes.  On October 26, 2007, PEPL issued $300 million in senior notes due November 1, 2017 with an interest rate of 6.20 percent (6.20% Senior Notes).  In connection with the issuance of the 6.20% Senior Notes, the Company incurred underwriting and discount costs of approximately $2.7 million.  The debt was priced to the public at 99.741 percent, resulting in $297.3 million in proceeds to the Company.  The proceeds were initially used to repay approximately $246 million outstanding under the credit facilities.  The remaining proceeds of $51.3 million were invested by the Company and subsequently utilized to fund working capital obligations. 

LNG Holdings Term Loans.  On March 15, 2007, LNG Holdings, as borrower, and PEPL and Trunkline LNG, as guarantors, entered into a $455 million unsecured term loan facility due March 13, 2012 (2012 Term Loan). The interest rate under the 2012 Term Loan is a floating rate tied to a LIBOR rate or prime rate at the Company’s option, in addition to a margin tied to the rating of PEPL’s senior unsecured debt.  The proceeds of the 2012 Term Loan were used to repay approximately $455 million in existing indebtedness that matured in March 2007, including the $200 million 2.75% Senior Notes and the LNG Holdings $255.6 million Term Loan.  LNG Holdings has entered into interest rate swap agreements that effectively fixed the interest rate applicable to the 2012 Term Loan at 4.98 percent plus a credit spread of 0.625, based upon PEPL’s credit rating for its senior unsecured debt.  See Note 11 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps.

In connection with the December 1, 2006 closing of the Redemption Agreement, LNG Holdings, as borrower, and PEPL and CrossCountry Citrus, LLC, as guarantors, entered into a $465 million unsecured term loan facility due April 4, 2008 (2006 Term Loan).  On June 29, 2007, the parties entered into an amended and restated term loan facility (Amended Credit Agreement).  The Amended Credit Agreement extended the maturity of the 2006 Term Loan from April 4, 2008 to June 29, 2012, and decreased the interest rate from LIBOR plus 87.5 basis points to LIBOR plus 55 basis points, based upon the current credit rating of PEPL's senior unsecured debt.  The balance of the term loan facility at December 31, 2007 was $412.2 million.


F-35


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Junior Subordinated Notes.  On October 23, 2006, the Company issued $600 million in junior subordinated notes due November 1, 2066 with an initial fixed interest rate of 7.20 percent (Junior Subordinated Notes).  In connection with the issuance of the Junior Subordinated Notes, the Company incurred underwriting and discount costs of approximately $9 million.  The debt was priced to the public at 99.844 percent, resulting in $590.1 million in proceeds to the Company.  The outstanding Sid Richardson Bridge Loan balance of approximately $525 million was retired using the proceeds from the debt offering and the remaining approximately $65 million of debt offering proceeds were used to pay down a portion of the Company’s credit facilities.

Pursuant to the terms of the Junior Subordinated Notes, the Company may at its discretion defer interest payments for up to ten consecutive years at a time.  The Company may make such election on more than one occasion, provided that payment of all previously deferred interest has been made and the deferral period does not extend beyond the November 1, 2066 maturity date, at which time all deferred interest would become due and payable.

The Company has entered into a covenant agreement for the benefit of holders of a designated series of indebtedness, other than the Junior Subordinated Notes, that it will not redeem or repurchase the Junior Subordinated Notes, in whole or in part, on or before October 31, 2036, unless, subject to certain limitations, during the 180 days prior to the date of that redemption or repurchase, the Company has received an equal or greater amount of net cash proceeds from the sale of common stock or other qualifying securities.

Remarketing Obligation.  In June 2003, the Company issued $125 million aggregate principal amount of 2.75% senior notes due August 16, 2006 in conjunction with the issuance of its 5.75% equity units.  Each equity unit was comprised of a senior note in the principal amount of $50 and a forward purchase contract under which the equity unit holder agreed to purchase shares of Southern Union common stock on August 16, 2006 at a price based on the preceding 20-trading day average closing price subject to a minimum conversion price per share of $13.82 (in which case 9.044 million shares would be issued) and a maximum conversion price of $16.86 (in which case 7.413 million shares would be issued).  On August 16, 2006, the Company remarketed the 2.75% senior notes, which are now due August 16, 2008.

As part of the remarketing, the interest rate on the senior notes was reset to 6.15 percent.  The senior notes paid interest in arrears on each February 16 and August 16, which commenced on February 16, 2007.  The senior notes will mature on August 16, 2008.  The senior notes are unsecured and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness from time to time outstanding.

Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt.

Credit Facilities.  On September 29, 2005, Southern Union entered into a Fourth Amended and Restated Revolving Credit Facility in the amount of $400 million (Long-Term Facility).  The Long-Term Facility has a five-year term and matures on May 28, 2010.  The Long-Term Facility replaced the Company’s May 28, 2004 long-term credit facility in the same amount.  Borrowings under the Long-Term Facility are available for Southern Union’s working capital and letter of credit requirements and for other general corporate purposes.   The Long-Term Facility is subject to a commitment fee based on the rating of the Company’s senior unsecured notes (Senior Notes).  As of December 31, 2007, the commitment fees were an annualized 0.15 percent.  The Company has an additional $30 million of availability under uncommitted line of credit facilities with various banks.

Balances of $123 million and $100 million were outstanding under the Company’s credit facilities at effective interest rates of 5.82 percent and 6.02 percent at December 31, 2007 and 2006, respectively.  The Company classifies its borrowings under the credit facilities due May 28, 2010 as short-term debt, as the individual borrowings are generally for periods of 15 to 180 days.  At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days.  As of February 22, 2008, there was a balance of $45 million outstanding under the Company’s credit facilities, with an effective interest rate of 3.77 percent.

F-36


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Sid Richardson Bridge Loan.  On March 1, 2006, Southern Union acquired Sid Richardson Energy Services for approximately $1.6 billion in cash.  The acquisition was funded under a bridge loan facility in the amount of $1.6 billion that was entered into on March 1, 2006 between the Company and a group of banks as lenders.  On August 24, 2006, the Company applied approximately $1.1 billion in net proceeds from the sales 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 to repayment of the Sid Richardson Bridge Loan.  See Note 19 – Discontinued Operations for related information.  On October 23, 2006, the Company retired the remainder of the Sid Richardson Bridge Loan using a portion of the proceeds received from the Company’s issuance of $600 million in Junior Subordinated Notes.

Interest expense totaling $49.2 million related to the Sid Richardson Bridge Loan was incurred during 2006 at an average interest rate of 5.72 percent.  Debt issuance costs totaling $9.2 million were incurred in connection with the financing of the acquisition, of which $7.8 million was related to the Sid Richardson Bridge Loan and $1.4 million was related to the placement of permanent financing.  The Company fully amortized the $7.8 million of the Sid Richardson Bridge Loan debt issuance cost to interest expense during 2006.

Other Debt Activity.

In conjunction with the Company’s sale of the assets of its PG Energy natural gas distribution division, $15 million of the Company’s First Mortgage Bonds were repaid.  National Grid USA assumed $77 million of the Company’s First Mortgage Bonds in conjunction with its purchase of the Rhode Island operations of the Company’s New England Gas Company natural gas distribution division.  See Note 19 – Discontinued Operations for related information.

On July 14, 2005, the Company amended an existing short-term bank note to increase the principal amount thereunder from $15 million to $65 million in order to provide additional liquidity.  The note is repayable upon demand.  The Company borrowed $50 million under the note on July 19, 2005 at an initial interest rate of 4.54 percent, which was based on LIBOR plus 70 basis points.  The Company repaid the $50 million additional principal amount on April 17, 2006.

Restrictive Covenants.  The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating.  Certain covenants exist in certain of the Company’s debt agreements that require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense.  A failure by the Company to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

The Company’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:

 
(a)  
Under the Company’s Long-Term Facility, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65 percent.
 
(b)  
Under the Company’s Long-Term Facility, the Company must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times.
 
(c)  
Under the Company’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, the Company’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70 percent at the end of any calendar quarter.
 
(d)  
All of the Company’s major borrowing agreements contain cross-defaults if the Company defaults on an agreement involving at least $3 million of principal.

 


F-37


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




 
In addition to the above restrictions and default provisions, the Company and/or its subsidiaries are subject to a number of additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in the cash management program; and limitations on the Company’s ability to prepay debt.

Retirement of Debt Obligations

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.

14.  Benefits

Pension and Other Postretirement Benefit Plans.  The Company has funded non-contributory defined benefit pension plans (pension plans) which cover substantially all Distribution segment employees.  Normal retirement age is 65, but certain plan provisions allow for earlier retirement.  Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.  At the beginning of 2006, the Company had eight pension plans.  Effective August 24, 2006, the Company’s responsibility for benefit obligations under five of these plans was relieved upon the transfer of the plans to the buyers of the assets of PG Energy and the Rhode Island operations of New England Gas Company.

The Company has postretirement health care and life insurance plans (other postretirement plans) which cover substantially all Distribution and Transportation and Storage segment employees and effective January 1, 2008, all Corporate employees.  The health care plans generally provide for cost sharing between the Company and its retirees in the form of retiree contributions, deductibles, coinsurance and a fixed cost cap on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.  At the beginning of 2006, the Company had six other postretirement plans.  Effective August 24, 2006, the Company’s responsibility for benefit obligations under two of these plans was relieved upon the transfer of the plans to the buyer of the Rhode Island operations of New England Gas Company.













F-38


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The following tables summarize the impact of the adoption of Statement No. 158, after recognition of the current period change in additional minimum liabilities (AML) under Statement No. 87, on the Company’s pension plans and other postretirement plans reported in the Consolidated Balance Sheet at December 31, 2006:

   
Pension Plans
 
   
Pre-SFAS 158
     
Pre-SFAS 158
 
SFAS 158
     
   
without AML
 
AML
 
with AML
 
adoption
 
Post-SFAS
 
   
adjustment
 
adjustment
 
adjustment
 
adjustment
 
158
 
     
(in thousands)
 
Intangible asset (included in Deferred charges)
  $
4,883
 
  (1,085)
 
        3,798
  $  
     (3,798)
  $
-
 
Pension liabilities, current (included in Other
                               
  current liabilities)
   
                 -
   
              -
   
                  -
   
               13
   
             13
 
Pension liabilities, noncurrent (included in
                               
  Deferred credits)
   
        58,062
   
  (12,016)
   
        46,046
   
          7,066
   
      53,112
 
Accumulated deferred income taxes (benefit)
   
      (16,234)
   
      4,128
   
       (12,106)
   
        (4,107)
   
     (16,213)
 
Accumulated other comprehensive income (loss),
                               
   net of tax
   
      (26,711)
   
      6,803
   
       (19,908)
   
        (6,770)
   
     (26,678)
 
Accumulated other comprehensive income (loss),
                               
   pre-tax
   
      (42,945)
   
    10,931
   
       (32,014)
   
      (10,877)
   
     (42,891)
 
                                 
 
   
Other Postretirement Plans
 
   
Pre-SFAS 158
     
Pre-SFAS 158
 
SFAS 158
     
   
without AML
 
AML
 
with AML
 
adoption
 
Post-SFAS
 
   
adjustment
 
adjustment
 
adjustment
 
adjustment
 
158
 
   
(in thousands)
 
Prepaid postretirement costs (included in Deferred
                               
  charges)
  $
-
  $  
         -
   $ 
               -
   $  
        248
  $
248
 
Postretirement liabilities, current (included in Other
                               
 current liabilities)
   
                 -
   
            -
   
                  -
   
               87
   
             87
 
Postretirement liabilities, noncurrent (included in
                               
  Deferred credits)
   
        57,258
   
            -
   
        57,258
   
      (29,402)
   
      27,856
 
Accumulated deferred income taxes
   
                 -
   
            -
   
                  -
   
          6,750
   
        6,750
 
Accumulated other comprehensive income (loss),
                               
   net of tax
   
                 -
   
            -
   
                  -
   
        22,813
   
      22,813
 
Accumulated other comprehensive income (loss),
                               
   pre-tax
   
                 -
   
            -
   
                  -
   
        29,563
   
      29,563
 
                                 
 
The adoption of Statement No. 158 had no effect on the Consolidated Statement of Operations for the year ended December 31, 2006, or for any prior period presented and has not negatively impacted any financial covenants.

F-39


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Obligations and Funded Status.

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.  The following tables contain information about the obligations and funded status of the Company’s pension and other postretirement plans on a combined basis:
 
               
Other
 
   
Pension Benefits At
   
Postretirement Benefits At
 
   
December 31,
   
December 31,
 
   
2007
   
2006
   
2007
   
2006
 
   
(In thousands)
 
Change in benefit obligation:
                       
Benefit obligation at beginning of period
  $ 162,955     $ 415,338     $ 74,082     $ 115,148  
Service cost
    2,715       7,443       1,788       2,507  
Interest cost
    9,388       20,889       4,053       5,556  
Benefits paid, net
    (9,900 )     (19,668 )     (2,893 )     (4,418 )
Medicare Part D subsidy receipts
    -       -       289       -  
Actuarial (gain) loss and other
    (3,512 )     (24,347 )     (3,780 )     (9,925 )
Plan amendments
    1,178       -       2,734       972  
Curtailment recognition
    -       (28,119 )     -       (2,250 )
Settlement recognition and other  (1)
    -       (208,581 )     -       (33,508 )
Benefit obligation at end of period
  $ 162,824     $ 162,955     $ 76,273     $ 74,082  
                                 
Change in plan assets:
                               
Fair value of plan assets at beginning of period
  $ 108,633     $ 298,289     $ 46,233     $ 45,509  
Return on plan assets and other
    12,796       17,187       1,494       3,203  
Employer contributions
    16,813       28,399       9,176       14,926  
Benefits paid, net
    (9,900 )     (19,668 )     (2,893 )     (4,418 )
Settlement recognition and other  (1)
    -       (215,574 )     -       (12,987 )
Fair value of plan assets at end of period
  $ 128,342     $ 108,633     $ 54,010     $ 46,233  
                                 
Funded status:
                               
Funded status at measurement date
  $ (34,482 )   $ (54,322 )   $ (22,263 )   $ (27,849 )
Contributions subsequent to measurement date
    4,025       1,197       440       154  
Funded status at end of period
  $ (30,457 )   $ (53,125 )   $ (21,823 )   $ (27,695 )
                                 
Amounts recognized in the Consolidated
                               
  Balance Sheet consist of:
                               
Noncurrent assets
  $ -     $ -     $ 1,418     $ 248  
Current liabilities
    (13 )     (13 )     (57 )     (87 )
Noncurrent liabilities
    (30,444 )     (53,112 )     (23,184 )     (27,856 )
    $ (30,457 )   $ (53,125 )   $ (21,823 )   $ (27,695 )
                                 
Amounts recognized in Accumulated other
                               
  comprehensive loss (pre-tax basis) consist of:
                               
Net actuarial loss (gain)
  $ 24,376     $ 39,093     $ (12,831 )   $ (11,128 )
Prior service cost (credit)
    4,353       3,798       (12,892 )     (18,435 )
    $ 28,729     $ 42,891     $ (25,723 )   $ (29,563 )
                                 
___________________
(1)
Effective August 24, 2006, the Company transferred five pension plans and two other postretirement plans to the buyers 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.

F-40


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The accumulated benefit obligation for all defined benefit pension plans was $155 million and $155.9 million at December 31, 2007 and 2006, respectively.

The following table summarizes information for plans with an accumulated benefit obligation in excess of plan assets:

               
Other
 
   
Pension Benefits
   
Postretirement Benefits
 
   
December 31,
   
December 31,
 
   
2007
   
2006
   
2007
   
2006
 
   
(In thousands)
 
                         
Projected benefit obligation
  $ 162,824     $ 162,955       N/A       N/A  
Accumulated benefit obligation
    154,950       155,876     $ 71,571     $ 68,033  
Fair value of plan assets
    128,342       108,633       47,890       39,937  
                                 
 
Net Periodic Benefit Cost.

Net periodic benefit cost for the years ended December 31, 2007, 2006 and 2005 includes the components noted in the table below.  The table below has been reclassified for all prior periods to present net periodic benefit cost included in operating expenses from continuing operations, and excludes the net periodic benefit cost of the Company’s discontinued operations.  Net periodic pension cost for discontinued operations totaled $50.4 million and $7.9 million for the years ended December 31, 2006 and 2005, respectively.  Net periodic other postretirement benefit costs for discontinued operations totaled $(13.8) million and $2.9 million for the years ended December 31, 2006 and 2005, respectively.  See Note 19 – Discontinued Operations for additional related information.
 
   
Pension Benefits
   
Other Postretirement Benefits
 
   
Years Ended December 31,
   
Years Ended December 31,
 
   
2007
   
2006
   
2005
   
2007
   
2006
   
2005
 
   
(In thousands)
 
Net Periodic Benefit Cost:
                                   
Service cost
  $ 2,715     $ 2,599     $ 2,550     $ 1,788     $ 1,890     $ 2,908  
Interest cost
    9,388       8,899       9,355       4,053       3,615       4,908  
Expected return on plan assets
    (9,619 )     (8,909 )     (8,728 )     (2,858 )     (1,871 )     (1,375 )
Prior service cost amortization
    623       584       782       (2,809 )     (3,011 )     (551 )
Actuarial (gain) loss amortization
    8,029       7,236       5,364       (768 )     (145 )     (163 )
Curtailment recognition
    -       -       3,172       -       -       -  
Settlement recognition
    -       -       (644 )     -       -       -  
Transfer of assets in excess
                                               
of obligations
    -       -       -       1,915       -       -  
      11,136       10,409       11,851       1,321       478       5,727  
Regulatory adjustment (1)
    (1,578 )     (7,710 )     (7,521 )     2,665       2,665       2,665  
Net periodic benefit cost
  $ 9,558     $ 2,699     $ 4,330     $ 3,986     $ 3,143     $ 8,392  
                                                 
___________________
(1)
In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act or other utility commission specific guidelines.  The difference between these amounts and periodic benefit cost calculated pursuant to Statement No. 87 is initially deferred as a regulatory asset and subsequently amortized to periodic benefit cost over periods, promulgated by the applicable utility commission, in which this difference will be recovered in rates.


F-41


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The estimated net actuarial loss (gain) and prior service cost (credit) for pension plans that will be amortized from Accumulated other comprehensive loss into net periodic benefit cost during 2008 are $6.9 million and $552,000, respectively.  The estimated net actuarial loss (gain) and prior service cost (credit) for other postretirement plans that will be amortized from Accumulated other comprehensive loss into net periodic benefit cost during 2008 are ($1.2) million and ($2.4) million, respectively.

Assumptions.

The weighted-average assumptions used in determining benefit obligations are shown in the table below:

   
Pension Benefits
 
Other Postretirement Benefits
   
Years Ended December 31,
 
Years Ended December 31,
   
2007
 
2006
 
2005
 
2007
 
2006
 
2005
                                     
Discount rate
    6.24 %     5.77 %     5.50 %     6.34 %     5.78 %     5.50 %
Rate of compensation increase
                                               
(average)
    3.47 %     3.24 %     3.24 %     N/A       N/A       N/A  
                                                 
 
The weighted-average assumptions used in determining net periodic benefit cost are shown in the table below.  The table has been reclassified for all prior periods to present discount rate data for plans relating to continuing operations, and excludes the discount rate data of the plans that relate to the Company’s discontinued operations.  See Note 19 – Discontinued Operations for additional related information.
 
   
Pension Benefits
 
Other Postretirement Benefits
   
Years Ended December 31,
 
Years Ended December 31,
   
2007
 
2006
 
2005
 
2007
 
2006
 
2005
                                     
Discount rate
    5.77 %     5.50 %     5.75 %     5.78 %     5.50 %     5.75 %
Expected return on assets:
                                               
Tax exempt accounts
    8.75 %     8.75 %     9.00 %     7.00 %     7.00 %     7.00 %
Taxable accounts
    N/A       N/A       N/A       5.00 %     5.00 %     5.00 %
Rate of compensation increase
    3.24 %     3.24 %     3.40 %     N/A       N/A       N/A  
                                                 
 
The Company employs a building block approach in determining the expected long-term rate of return on the plans’ assets, with proper consideration of diversification and rebalancing.  Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run.  Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend rates used for measurement purposes are shown in the table below:
 
   
December 31,
   
2007
 
2006
             
Health care cost trend rate assumed for next year
    10.00 %     11.00 %
Ultimate trend rate
    5.13 %     4.80 %
Year that the rate reaches the ultimate trend rate
   
2017
   
2013
                 

F-42


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans.  A one-percentage-point change in assumed health care cost trend rates would have the following effects:
 
   
One Percentage Point
   
One Percentage Point
 
   
Increase
   
Decrease
 
   
(In thousands)
 
             
Effect on total of service and interest cost
  $ 733     $ (587 )
Effect on accumulated postretirement benefit obligation
  $ 7,082     $ (5,754 )
                 
 
Plan Assets.

The assets of the pension plans are invested in accordance with several investment practices that emphasize long-term investment fundamentals with an investment objective of long-term growth, taking into consideration risk tolerance and asset allocation strategies.

The broad goal and objective of the investment of the pension plans’ assets is to ensure that future growth of the assets is sufficient to offset normal inflation plus liability requirements of the plans’ beneficiaries. Pension plan assets should be invested in such a manner to minimize the necessity of net contributions to the plans to meet the plans’ commitments. The contributions will also be affected by the applicable discount rate that is applied to future liabilities. The discount rate will affect the net present value of the future liability and, therefore, the funded status.

The assets of the postretirement health care and life insurance plans are invested in accordance with sound investment practices that emphasize long-term investment fundamentals.  The Investment Committee of the Company’s Board of Directors has adopted an investment objective of income and growth for the postretirement plans.  This investment objective (i) is a risk-averse balanced approach that emphasizes a stable and substantial source of current income and some capital appreciation over the long-term; (ii) implies a willingness to risk some declines in value over the short-term, so long as the postretirement plans are positioned to generate current income and exhibit some capital appreciation; (iii) is expected to earn long-term returns sufficient to keep pace with the rate of inflation over most market cycles (net of spending and investment and administrative expenses), but may lag inflation in some environments; (iv) diversifies the postretirement plans in order to provide opportunities for long-term growth and to reduce the potential for large losses that could occur from holding concentrated positions; and (v) recognizes that investment results over the long-term may lag those of a typical balanced portfolio since a typical balanced portfolio tends to be more aggressively invested.  Nevertheless, the postretirement plans are expected to earn a long-term return that compares favorably to appropriate market indices.

It is expected that these objectives can be obtained through a well-diversified portfolio structured in a manner consistent with the investment policy.

The Company’s weighted average asset allocation by asset category for the measurement periods presented is as follows:
 
   
Pension Benefits
 
Other Postretirement Benefits
   
At September 30,
 
At September 30,
Asset Category
 
2007
 
2006
 
2007
 
2006
                         
Equity securities
    61 %     76 %     31 %     24 %
Debt securities
    24 %     10 %     62 %     66 %
Other - cash equivalents
    15 %     14 %     7 %     10 %
Total
    100 %     100 %     100 %     100 %
                                 

F-43


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Based on the pension plan objectives, target asset allocations are as follows: equity of 50 percent to 80 percent, fixed income of 20 percent to 50 percent and cash and cash equivalents of 0 percent to 10 percent.

Based on the other postretirement plan objectives, target asset allocations are as follows: equity of 25 percent to 35 percent, fixed income of 65 percent to 75 percent and cash and cash equivalents of 0 percent to 10 percent.
 
The above referenced target asset allocations for pension and other postretirement benefits are based upon guidelines established by the Company’s Investment Policy and is monitored by the Investment Committee of the board of directors in conjunction with an external investment advisor.  On occasion, the asset allocations may fluctuate as compared to these guidelines as a result of Investment Committee actions.

Contributions.

The Company expects to contribute approximately $14.3 million to its pension plans and approximately $10 million to its other postretirement plans in 2008.  The Company funds the cost of the plans in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments.

The Company’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the five succeeding years and in the aggregate for the five years thereafter are shown in the table below:

         
Other
   
Other
 
         
Postretirement
   
Postretirement
 
         
Benefits
   
Benefits
 
   
Pension
   
(Gross, Before
   
(Medicare Part D
 
Years
 
Benefits
   
Medicare Part D)
   
Subsidy Receipts)
 
   
(In thousands)
 
                   
2008
  $ 10,172     $ 4,093     $ 607  
2009
    10,774       4,083       684  
2010
    10,929       4,296       763  
2011
    10,854       4,831       855  
2012
    12,084       5,467       809  
2013-2017
    61,034       37,394       5,533  
                         
 
The Medicare Prescription Drug Act was signed into law December 8, 2003.  This act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy, which is not taxable, to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Defined Contribution Plan.  The Company sponsors a defined contribution savings plan (Savings Plan) that is available to all employees.  The Company provides maximum matching contributions based upon certain Savings Plan provisions ranging from 2 percent to 6.25 percent to the participant’s compensation paid into the Savings Plan.  Company con­tributions are 100 percent vested after five years of continuous service for all plans other than Missouri Gas Energy union employees and employees of the Fall River operation, which are 100 percent vested after six years of continuous service. Company contribu­tions to the Savings Plan during the years ended December 31, 2007, 2006 and 2005 were $3.8 million, $5.1 million and $4.5 million, respectively.

In addition, the Company makes employer contributions to separate accounts, re­ferred to as Retirement Power Accounts, within the defined contribution plan.  The contribution amounts are determined as a percentage of compensation and range from 2.5 percent to 11 percent.  Company contributions to Retirement Power Accounts during the years ended December 31, 2007, 2006 and 2005 were $6.6 million, $5.1 million and $4.8 million, respectively.


F-44


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Common Stock Held in Trust.  From time to time, Southern Union purchases outstanding shares of its common stock to fund certain Company employee stock-based compensation plans.  At December 31, 2007 and 2006, 783,445 and 863,458 shares, respectively, of common stock were held by various rabbi trusts for certain of those Company’s benefit plans.

Benefit Plan Termination.  Effective June 30, 2005, the Company terminated its 1997 Supplemental Retirement Plan (Supplemental Plan), which was a non-contributory cash balance retirement plan for certain current and former executive employees of the Company.  As a result, the Company had an estimated pension net loss of $1.3 million comprised of a $1.6 million loss on pension curtailment, recognized in the second quarter of 2005, and a $251,000 gain on pension settlement, recognized in the third quarter of 2005.  Prior to the termination of the Supplemental Plan, the Company also recorded a $1.1 million loss on pension curtailment in the second quarter of 2005 that was triggered by pension payments made to a former executive of the Company under this plan.

Also effective June 30, 2005, the Company terminated its 2000 Executive Deferred Stock Plan, which was a defined contribution deferred compensation plan for certain management and highly compensated employees.  The plan’s assets were held in a rabbi trust and were distributed to participants during the fourth quarter of 2005.  The termination of this plan did not have a material effect on the Company’s consolidated financial statements.

15.  Taxes on Income

The following table provides a summary of the current and deferred components of income tax expense from continuing operations for the periods presented:
 
   
Years Ended December 31,
 
Income Tax Expense
 
2007
   
2006
   
2005
 
   
(In thousands)
 
Current:
                 
Federal
  $ 18,458     $ 19,798     $ 168  
State
    5,654       2,251       1,062  
      24,112       22,049       1,230  
                         
Deferred:
                       
Federal
    62,502       74,563       43,110  
State
    8,645       12,635       5,712  
      71,147       87,198       48,822  
                         
Total federal and state income tax
                       
expense from continuing operations
  $ 95,259     $ 109,247     $ 50,052  
                         
Effective tax rate
    29.4 %     33.5 %     24.6 %
                         










F-45


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.  The principal components of the Company’s deferred tax assets (liabilities) are as follows:
 
   
December 31,
 
Deferred Income Tax Analysis
 
2007
   
2006
 
   
(In thousands)
 
Deferred income tax assets:
           
Alternative minimum tax credit
  $ 13,560     $ 8,178  
Post-retirement benefits
    24,320       17,673  
Pension benefits
    6,579       13,810  
Unconsolidated investments
    5,443       11,530  
Other
    19,621       27,936  
Total deferred income tax assets
    69,523       79,127  
                 
Deferred income tax liabilities:
               
Property, plant and equipment
    (693,350 )     (624,797 )
Investment in CCE Holdings (Citrus)
    (34,113 )     (18,700 )
Goodwill
    (15,665 )     (14,592 )
Regulatory liability
    (2,020 )     (2,989 )
Other
    (16,077 )     (35,738 )
Total deferred income tax liabilities
    (761,225 )     (696,816 )
Net deferred income tax liability
    (691,702 )     (617,689 )
Less current income tax assets (liabilities)
    1,303       (512 )
Accumulated deferred income taxes
  $ (693,005 )   $ (617,177 )
                 
 
Deferred credits in the accompanying Consolidated Balance Sheet includes $87,000 and $133,000 of unamortized deferred investment tax credit as of December 31, 2007 and 2006, respectively.

The Company completed an analysis of its deferred tax accounts in 2005.  As a result of the 2005 analysis and expiring statute of limitations in 2006, federal and state income tax expense for the years ending December 31, 2006 and 2005 was decreased $8.4 million and $6.4 million, respectively, primarily due to adjustments related to bad debt reserves and PP&E.  The decrease in income tax expense for the years ended December 31, 2006 and 2005 is comprised of federal income taxes of $7.5 million and $4.8 million, respectively, and state income taxes of $900,000 and $1.6 million, respectively.

In November 2006, the Internal Revenue Service (IRS) completed its examination of the Company’s federal income tax return for the fiscal year ended June 30, 2003.  The Company reached 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, state and local jurisdictions as a result of the IRS examination of the year ended June 30, 2003.  No penalties were assessed to the Company in this IRS examination.

F-46


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The Company will be entitled to recover a corresponding $26.3 million of income tax benefit over time from additional depreciation deductions from the Panhandle assets due to higher tax basis in such assets as a result of the reduction of income tax benefits from the like-kind exchange.

The differences between the Company’s effective income tax rate (EITR) and the U.S. federal income tax statutory rate are as follows:
 
   
Years Ended December 31,
 
Effective Income Tax Rate Analysis
 
2007
   
2006
   
2005
 
   
(In thousands)
 
Computed statutory income tax expense
                 
from continuing operations at 35%
  $ 113,389     $ 114,215     $ 71,102  
Changes in income taxes resulting from:
                       
Valuation allowance
    -       -       (11,942 )
Dividend received deduction
    (28,994 )     (10,696 )     (8,732 )
Executive compensation, non deductible
    491       5,063       -  
State income taxes, net of federal income tax benefit
    9,295       9,411       4,403  
Analysis of deferred tax accounts
    -       (7,490 )     (4,757 )
Other
    1,078       (1,256 )     (22 )
Actual income tax expense from continuing operations
  $ 95,259     $ 109,247     $ 50,052  
                         
 
The Company adopted FIN 48 on January 1, 2007.  The implementation of FIN 48 did not have a material impact on the consolidated financial statements and did not require an adjustment to Retained earnings (deficit). The amount of unrecognized tax benefits at January 1, 2007 was $600,000, all of which would impact the Company’s EITR if recognized.  There are no changes to the Company’s unrecognized tax benefits during 2007.  The remaining amount of unrecognized tax benefits should be reduced to nil based on anticipated statute of limitations expirations in 2008.

The Company’s policy is to classify and accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense in its Consolidated Statement of Operations, which is consistent with the recognition of these items in prior reporting periods. At January 1, 2007, the Company recorded a liability of $2.4 million ($1.5 million, net of tax) representing interest payable to the IRS, state and local jurisdictions as a result of the IRS examination of the year ended June 30, 2003. All of the interest liability was paid in 2007.  At December 31, 2007, the Company had no remaining federal, state and local interest liabilities.  There were no federal penalties assessed as a result of this examination and no significant state penalties associated with the amended tax return filings.

The Company is no longer subject to U.S. federal, state or local examinations for the tax year ended June 30, 2002 and prior years.  Although the Company settled the IRS examination of the year ended June 30, 2003 in 2006, the statute did not expire until December 31, 2007.  The state impact of the federal change remains subject to state and local examination for a period of up to one year after formal notification to the state and local jurisdictions.  The Company filed all required amended state tax returns in 2007 as a result of the federal change.  Therefore, the state and local statutes will expire with respect to the tax year ended June 30, 2003 in 2008.


F-47


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




16.  Regulation and Rates

Panhandle.  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.

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 2006, respectively.  

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 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 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.


F-48


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




FERC is responsible under the Natural Gas Act for assuring that rates charged by interstate pipelines are "just and reasonable."  To enforce that requirement, FERC applies a ratemaking methodology that determines an allowed rate of return on common equity for the companies it regulates.  On October 25, 2006, a group including producers and various trade associations filed a complaint under Section 5 of the Natural Gas Act against Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage) requesting that FERC initiate an investigation into Southwest Gas Storage’s rates, terms and conditions of service and grant immediate interim rate relief.  FERC initiated a Section 5 proceeding on December 21, 2006, setting this issue for hearing.  Pursuant to FERC order, Southwest Gas Storage filed a cost and revenue study with FERC on February 20, 2007.  On August 1, 2007, Southwest Gas Storage filed a Section 4 rate case requesting an increase in rates.  On August 31, 2007, the FERC accepted Southwest Gas Storage’s rate increase to become effective on February 1, 2008, subject to refund.  This order also consolidated the Section 5 proceeding with the Section 4 rate case.  On November 28, 2007, Southwest Gas Storage filed a settlement with FERC.  The settlement was approved by FERC on February 12, 2008, which settlement resulted in Southwest Gas Storage’s rates remaining substantially similar to its rates that were in effect prior to the Section 4 and Section 5 proceedings.

On January 26, 2007, Southwest Gas Storage filed an abandonment application to reduce the certificated storage capacity of its North Hopeton field by approximately 6 Bcf and to acquire 3 Bcf of additional base gas to maintain storage field operations.  This filing brings the certificated capacity in line with operational performance of the field.  On September 7, 2007, FERC approved Southwest Gas Storage’s North Hopeton field modifications.  Southwest Gas Storage has entered into a third-party agreement to replace this storage capacity, effective April 1, 2007, with an initial term of two years.

Sea Robin Pipeline Company, LLC (Sea Robin) filed a rate case with FERC in June 2007, requesting an increase in its maximum rates.  Several parties have submitted protests to the rate increase filing with FERC.  On July 30, 2007, FERC suspended the effectiveness of the filed rate increase until January 1, 2008.  The filed rates were put into effect January 1, 2008, subject to refund.  The final outcome of the rate case has many variables and potential outcomes and it is impossible to predict its timing or materiality at this time. 

On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as HCAs.  This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002.  The rule requires operators to have identified HCAs along their pipelines by December 2004, and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by June 2004.  Operators must rank the risk of their pipeline segments containing HCAs and must complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007.  Assessments will generally be conducted on the higher risk segments first, with the balance being completed by December 2012.  In addition, some system modifications will be necessary to accommodate the in-line inspections.  As of December 31, 2007, the Company had completed 80 percent of the risk assessments.  All systems operated by the Company will be compliant with the rule; however, while identification and location of all HCAs has been completed, it not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections.  The required modifications and inspections are currently estimated to be in the range of approximately $20 million to $28 million per year through 2012.

Missouri Gas Energy.  On September 21, 2004, the Missouri Public Service Commission (MPSC) issued a rate order authorizing Missouri Gas Energy to increase base revenues by $22.4 million, effective October 2, 2004.  Missouri Gas Energy filed various appeals related to this matter seeking increased base revenues in addition to those contained in the MPSC’s order on grounds that the capital structure and 10.5 percent return on equity used by the MPSC in determining such increase did not provide an adequate rate of return.  On April 11, 2006, the Missouri Supreme Court denied a hearing on this matter, effectively concluding the Company’s appeal.

On May 1, 2006, Missouri Gas Energy announced the filing of a proposal with the MPSC to increase annual revenues by approximately $41.7 million, or 6.8 percent.  A hearing on this matter with the MPSC was held in January 2007.  The MPSC issued a Report and Order on March 22, 2007, authorizing an annual revenue increase of $27.2 million, or 4.5 percent.  In its order, the MPSC calculated the revenue increase using a return

F-49


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




on equity of 10.5 percent and set residential rates using a straight fixed-variable rate design, thereby eliminating the impact of weather and conservation on residential margin revenues and related earnings.  The new rates went into effect on April 3, 2007.  This rate order has been appealed by Missouri Gas Energy and the Office of the Public Counsel, with Missouri Gas Energy challenging the authorized return as too low and the Office of the Public Counsel challenging the residential rate design.  A final ruling in the appeal is not expected until 2009.

Through filings made on various dates, the staff of the MPSC recommended the MPSC disallow a total of approximately $47.7 million in gas costs incurred during the period July 1, 1997 through June 30, 2005.  By order issued August 2, 2007, the MPSC adopted the MPSC staff’s formal withdrawal of disallowance recommendations totaling approximately $35.3 million in response to a January 2007 Missouri Supreme Court ruling.  By orders issued on August 2, 2007 and October 2, 2007, the MPSC also rejected the MPSC staff’s recommendations regarding $8 million of the remaining gas cost disallowance.  In a filing made with the MPSC on November 2, 2007, the MPSC staff withdrew from consideration the remaining $4.4 million in disallowance recommendations.  By orders issued on November 8, 2007, the MPSC accepted the withdrawal of these remaining disallowance recommendations and closed these cases.  There was no impact to the Company’s consolidated financial statements related to the withdrawal of these gas cost disallowance recommendations.

New England Gas Company.  On June 8, 2007, New England Gas Company filed with the Massachusetts Department of Public Utilities (MDPU) a proposed rate settlement with respect to its Massachusetts operations. The settlement agreement provides, among other things, for an overall revenue increase of $4.6 million phased in over an eight-month period, including the implementation of adjustment mechanisms for the recovery of pension costs, other postretirement benefit costs and gas cost-related uncollectible expense effective August 1, 2007, and a base rate increase of $2 million on April 1, 2008.  The MDPU issued an order on July 31, 2007 approving the rate settlement agreement effective August 1, 2007.


17.  Leases

The Company leases certain facilities, equipment and office space under cancelable and non-cancelable operating leases.  The minimum annual rentals under operating leases for the next five years ending December 31 are as follows: 2008— $16.4 million; 2009—$19.2 million; 2010—$18.3 million; 2011— $18.2 million; 2012—$13.9 million and thereafter $57.8 million.  Rental expense was $19.9 million, $18.7 million and $20.1 million for the years ended December 31, 2007, 2006 and 2005, respectively.

18.  Commitments and Contingencies

Environmental

The Company’s operations are subject to federal, state and local laws and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Failure to comply with environmental requirements may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.  The Company follows the provisions of American Institute of Certified Public Accountants Statement of Position 96-1, Environmental Remediation Liabilities, for recognition, measurement, display and disclosure of environmental remediation liabilities.


F-50


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment. Although significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms, management does not believe that environmental expenditures will have a material adverse effect on the Company's financial position, results of operations or cash flows. The table below reflects the amount of accrued liabilities recorded in the Consolidated Balance Sheet at December 31, 2007 and 2006 to cover probable environmental response actions:
 
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
             
Current
  $ 6,772     $ 5,098  
Noncurrent
    15,209       18,632  
Total Environmental Liabilities
  $ 21,981     $ 23,730  
                 

During the year ended December 31, 2007, the Company had $9.3 million of expenditures related to environmental cleanup programs.

Transportation and Storage Segment Environmental Matters.

Gas Transmission Systems.  Panhandle is responsible for environmental remediation at certain sites on its gas transmission systems for contamination resulting from the past use of lubricants containing polychlorinated biphenyls (PCBs) in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. Panhandle has developed and is implementing a program to remediate such contamination. Remediation and decontamination has been completed at each of the 35 compressor station sites where auxiliary buildings that house the air compressor equipment were impacted by the past use of lubricants containing PCBs. At some locations, PCBs have been identified in paint that was applied many years ago. A program has been implemented to remove and dispose of PCB impacted paint during painting activities. At one location on the Trunkline system, PCBs were discovered on the painted surfaces of equipment in a building that is outside of the scope of the compressed air system program and the existing PCB impacted paint program.  The estimated cost to remediate the painted surfaces at this location is approximately $300,000.  An initial assessment program was undertaken at seven locations to determine whether this condition exists at any of the other 78 similar buildings on the PEPL, Trunkline and Southwest Gas systems.  At the seven locations assessed, which comprised a total of 15 buildings, preliminary analysis identified PCBs at regulated levels in a small number of samples at two locations.  An expanded assessment program has been developed and is currently underway.  As of December 31, 2007, 19 of 37 total locations have been assessed indicating PCBs at regulated levels in a small number of samples at a total of five locations. Until the results of the expanded assessment program are available, the costs associated with remediation of the painted surfaces cannot be reasonably estimated.

Other remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility.  The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Panhandle could potentially be held responsible for contamination caused by other parties. In some instances, such as the Pierce Waste Oil sites described below, Panhandle may share liability associated with contamination with other potentially responsible parties (PRPs).  Panhandle may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.  The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

PEPL and Trunkline, together with other non-affiliated parties, have been identified as potentially liable for conditions at three former waste oil disposal sites in Illinois – the Pierce Oil Springfield site, the Dunavan Waste

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Oil site and the McCook site (collectively, the Pierce Waste Oil sites).  PEPL and Trunkline received notices of potential liability from the U.S. EPA for the Dunavan site by letters dated September 30, 2005. The notices demanded reimbursement to the U.S. EPA for costs incurred as of that date in the amount of approximately $1.8 million and encouraged each PRP to voluntarily negotiate an administrative settlement agreement with the U.S. EPA within certain limited time frames providing for the PRPs to conduct or finance the response activities required at the site.  The demand was declined in a joint letter dated December 15, 2005 by the major PRPs, including PEPL and Trunkline.  Although no formal notice has been received for the Pierce Oil Springfield site, special notice letters are anticipated and the process of listing the site on the National Priority List has begun.  No formal notice has been received for the McCook site. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

On June 16, 2005, PEPL experienced a release of liquid hydrocarbons near Pleasant Hill, Illinois. The release occurred in the form of a mist at a valve that was in use to reduce the pressure in the pipeline as part of maintenance activities. The hydrocarbon mist affected several acres of adjacent agricultural land and a nearby marina. Approximately 27 gallons of hydrocarbons reached the Mississippi River. PEPL contacted appropriate federal and state regulatory agencies and the U.S. EPA took the lead role in overseeing the subsequent cleanup activities, which have been completed. PEPL has resolved claims of affected boat owners and the marina operator.  PEPL received a violation notice from the Illinois Environmental Protection Agency (IEPA) alleging that PEPL was in apparent violation of several sections of the Illinois Environmental Protection Act by allowing the release.  The violation notice did not propose a penalty.  Responses to the violation notice were submitted and the responses were discussed with the agency.  On December 14, 2005, the IEPA notified PEPL that the matter might be considered for referral to the Office of the Attorney General, the State’s Attorney or the U.S. EPA for formal enforcement action and the imposition of penalties.  By letter dated November 22, 2006, PEPL received a follow-up information request from the IEPA on the status of certain measures PEPL had agreed to undertake in connection with the original responses to the violation notice.  On January 5, 2007, PEPL submitted a response.  There has been no further contact from the IEPA on this matter.  The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.
 
Air Quality Control.  The U.S. EPA issued a final rule on regional ozone control (NOx SIP Call) in April 2004 that affected 20 large internal combustion engines on Panhandle’s system in Illinois and Indiana.  Panhandle has substantially completed the required capital improvements of approximately $23 million as of December 31, 2007.  Indiana has promulgated state regulations to address the requirements of the NOx SIP Call rule that essentially follow the U.S. EPA guidance.
 
In early April 2007, the IEPA proposed a rule to the Illinois Pollution Control Board (IPCB) for adoption to control NOx emissions from reciprocating engines and turbines, including a provision applying the rule beyond issues addressed by federal provisions, pursuant to a blanket statewide application.  As originally proposed, the Illinois rule required controls on engines regulated under the U.S. EPA NOx SIP Call by May 1, 2007 and the remaining engines by January 1, 2011.  A pipeline consortium including PEPL and Trunkline filed an objection to the rule requesting the IPCB to bifurcate and address separately the statewide applicability provision, which was the primary driver of costs to PEPL and Trunkline.  On May 17, 2007, the IPCB ruled in favor of the pipeline consortium by bifurcating the statewide applicability provision from the rest of the proposed rule.  On September 20, 2007 the IPCB approved the rule that applies to the engines regulated under the NOx SIP Call rule, which the pipeline consortium was not contesting. Due to delayed approval of the rule, the compliance deadline was changed from May 1, 2007 to January 1, 2008.  On August 23, 2007, the IEPA filed a motion to cancel hearings and pre-filing deadlines for the bifurcated statewide portion of the proposed Illinois engine rule, which was later granted. On December 20, 2007, the IEPA filed an amended proposal withdrawing the statewide applicability provisions of the current proposed rule and apply the rule requirements to non-attainment areas. The amended proposal was approved on January 10, 2008.  No controls on PEPL and Trunkline stations are required under the most recent proposal. However, the IEPA indicated in earlier industry discussions that it was reserving the right to make future proposals for statewide controls.  In the event the IEPA proposes a statewide rule again, preliminary estimates indicate the cost of compliance would require minimum capital expenditures of approximately $45 million for emission controls.

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In 2002, the Texas Commission on Environmental Quality (TCEQ) enacted the Houston/Galveston SIP regulations requiring reductions in NOx emissions in an eight-county area surrounding Houston.  Trunkline’s Cypress compressor station is affected and required the installation of emission controls.  Regulations also require certain grandfathered facilities in East Texas to enter into the new source permit program, which may require the installation of emission controls at one additional facility owned by Panhandle.  Management estimates capital improvements of $17.1 million will be needed at the two affected East Texas locations.  The approximately $17 million of the required capital expenditures for the two affected East Texas locations have been substantially completed as of December 31, 2007.  Permit limits were placed on grandfathered engines at two facilities in West Texas that are owned by PEPL.  An estimated $1.9 million in capital expenditures will be required to comply with permit limitations for the West Texas facilities.
 
The U.S. EPA promulgated various Maximum Achievable Control Technology (MACT) rules in February 2004. The rules require that PEPL and Trunkline control Hazardous Air Pollutants (HAPs) emitted from certain internal combustion engines at major HAPs sources.  Most PEPL and Trunkline compressor stations are major HAPs sources. The HAPs pollutant of concern for PEPL and Trunkline is formaldehyde.  The rule, with which PEPL and Trunkline are in compliance and which had a final implementation date of June 2007, seeks to reduce formaldehyde emissions by 76 percent from these engines by requiring use of catalytic controls. PEPL has one engine fully regulated under this rule.  For the other PEPL and Trunkline engines potentially subject to the engine MACT rule, emission controls and operating restrictions have been used to lower emissions below MACT thresholds. Compliance with these regulations necessitated an estimated expenditure of $1.4 million for capital improvements.

Spill Prevention, Control and Countermeasure Rules.  In May 2007, the U.S. EPA extended the SPCC rule compliance dates until July 1, 2009 permitting owners and operators of facilities to prepare or amend and implement SPCC Plans in accordance with previously enacted modifications to the regulations.  In October 2007, the U.S. EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements, and streamlining requirements.  The Company is currently reviewing the impact of the modified regulations on its operations and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures.  Costs associated with such activities cannot be estimated with certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Gathering and Processing Segment Environmental Matters.

Gathering and Processing Systems.  SUGS is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons.  SUGS has a program to remediate such contamination.  The remediation typically involves the management of contaminated soils and may involve remediation of groundwater.  Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity.  The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Air Quality Control. On June 16, 2006, SUGS, as the facility operator and holder of a 50 percent interest in the Grey Ranch facility, submitted information to the TCEQ in connection with a request to permit its Grey Ranch, Texas facility to continue its current level of emissions.  The State of Texas requires all previously grandfathered emission sources to obtain permits or shut down by March 1, 2008.  By letter dated September 5, 2007, the TCEQ issued a permit extending current emission levels to March 1, 2009.  At the conclusion of the extension period, SUGS must implement an emission control strategy that achieves specific maximum allowable emissions rates.  At this time, it is anticipated that the Company will not bear any of the costs associated with an emissions control strategy.

Spill Prevention, Control and Countermeasure Rules.  In May 2007, the U.S. EPA extended the SPCC rule compliance dates until July 1, 2009 permitting owners and operators of facilities to prepare or amend and implement SPCC Plans in accordance with previously enacted modifications to the regulations.  In October 2007, the U.S. EPA proposed amendments to the SPCC rules with the stated intention of providing greater

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clarity, tailoring requirements, and streamlining requirements.  The Company is currently reviewing the impact of the modified regulations on its operations and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures.  Costs associated with such activities cannot be estimated with certainty at this time, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Distribution Segment Environmental Matters.

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former manufactured gas plants (MGPs) and sites associated with the operation and disposal activities of former MGPs that produced a fuel known as “town gas”. Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required.  The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater.  Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs.  The ultimate liability and total costs associated with these sites will depend upon many factors.  If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties.  In some instances, the Company may share liability associated with contamination with other PRPs, and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs.  These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

North Attleborough MGP Site in Massachusetts.  In November 2003, the Massachusetts Department of Environmental Protection (MADEP) issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the site.  Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties.  The Company, working with the MADEP, is in the process of performing assessment work at these properties.  In a September 2006 report filed with MADEP, the Company proposed a remedy for the upland portion of the site by means of an engineered barrier, construction of which is anticipated in 2008.  Assessment activities continue both on- and off-site to define the nature and extent of the impacts.  It is estimated that the Company will spend approximately $8.3 million over the next several years to complete the investigation and remediation activities at this site, as well as maintain the engineered barrier.  As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with this site have been included in Regulatory assets in the Consolidated Balance Sheet.

Litigation

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts.  Where appropriate, the Company has made accruals in accordance with FASB Statement No. 5, Accounting for Contingencies, in order to provide for such matters.  The Company believes the final disposition of these proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Bay Street, Tiverton, Rhode Island Site.  On March 17, 2003, the Rhode Island Department of Environmental Management (RIDEM) sent the Company’s New England Gas Company division a letter of responsibility pertaining to soils allegedly impacted by historic MGP residuals in a residential neighborhood in Tiverton, Rhode Island.  Without admitting responsibility or accepting liability, New England Gas Company began assessment work in June 2003 and has continued to perform assessment field work since that time. On September 19,

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2006, RIDEM filed an Amended Notice of Violation seeking an administrative penalty of $1,000/day, which as of the date of RIDEM’s filing totaled $258,000 and continues to accrue.  In June 2007, the Rhode Island Legislature considered, but failed to adopt, legislation that would have increased the maximum administrative penalty under a Notice of Violation to $50,000/day on a prospective basis.  In that RIDEM administrative proceeding, RIDEM has moved to extend to April 2008 the date for the completion of discovery, which motion has not yet been ruled upon by the Hearing Officer.  On April 19, 2007, the Company filed a complaint, and an accompanying preliminary injunction motion, against RIDEM in Rhode Island Superior Court, seeking, among other things, a declaratory judgment that RIDEM's Amended Notice of Violation is premised on an unlawful application of RIDEM's regulations and that RIDEM's pending administrative proceeding against the Company is invalid.  On July 13, 2007, the Superior Court dismissed the Company’s suit, finding that RIDEM’s Administrative Adjudication Division (AAD) has original jurisdiction to determine “responsible party” status and finding premature the Company’s challenge to RIDEM’s unlawful application of its own regulations because the Company did not first seek a ruling on that issue from RIDEM’s AAD.  The Company has appealed from part of the Superior Court’s ruling, and has also filed a motion for summary judgment in the AAD proceeding seeking dismissal of same based on RIDEM’s unlawful application of its own regulations.  Briefing on the summary judgment motion is now complete.  The Hearing Officer in the AAD proceeding has not yet issued a ruling on that motion.  The Company will continue to vigorously defend itself in the AAD proceedings.

During 2005, four lawsuits were filed against New England Gas Company in Rhode Island regarding the Tiverton neighborhood.  The plaintiffs seek to recover damages for the diminution in value of their property, lost use and enjoyment of their property and emotional distress in an unspecified amount.  The Company removed the lawsuits to federal court and filed motions to dismiss.  On November 3, 2006, the Court dismissed plaintiffs’ claims relating to gross negligence, private nuisance, infliction of emotional distress and violation of the Rhode Island Hazardous Waste Management Act.  The Court denied the Company’s motion to dismiss as to claims relating to negligence, strict liability and public nuisance, as well as plaintiffs’ request for punitive damages.  In September and October 2007, the court granted the Company’s motion to serve third-party complaints on a total of nine PRPs.  Among the PRPs the Company impleaded is the Town of Tiverton, which asserted a counterclaim against the Company under CERCLA.  On January 30, 2008, the Court denied the Company's motion for partial judgment on the pleadings seeking dismissal of plaintiffs' claims for remediation, finding, contrary to the Company's contention, that RIDEM does not have exclusive jurisdiction to determine the responsibility for and extent of remediation of plaintiffs' properties.  On February 13, 2008, the Court entered a "Trial Order" superseding several prior orders, and directing that (1) on or about April 24, 2008, the Court will conduct a "Phase I" trial on claims asserted by plaintiffs and by Tiverton against the Company; (2)  the Phase I trial will be bifurcated into a liability stage, and, if necessary, a damages stage, with both stages to be tried before the same jury; (3) the discovery cutoff date for the Phase I trial is extended from February 29 to March 21, 2008; (4) if necessary, a “Phase II” trial shall address the Company's third-party claims against the PRPs it has impleaded; and (5) the parties to the Phase II trial shall have 120 days after the Phase I trial to conduct discovery related thereto.  The Company subsequently filed a motion seeking extension of the discovery and trial date.  The Company will continue to vigorously defend itself against all four lawsuits, which have now been consolidated for trial.  Based upon its current understanding of the facts, the Company does not believe the outcome of these matters will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Mercury Release.  In October 2004, New England Gas Company discovered that one of its facilities had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away.  Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings.  Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted.  On October 16, 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island alleging violation of permitting requirements under the federal Resource Conservation and Recovery Act and notification requirements under the federal Emergency Planning and Community Right to Know Act relating to the 2004 incident.  The Company entered a not guilty plea on October 29, 2007 and will vigorously defend itself in such action.  On January 17, 2008, the Court granted the Company’s motion to extend the deadline for completion of discovery to March 13, 2008, and to extend the deadline for the filing of certain motions to April 8, 2008.  The Court has not yet set a trial date.  The Company

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believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

On January 20, 2006, a complaint was filed against the Company in the Superior Court in Providence, Rhode Island regarding the mercury release from the Pawtucket facility, asserting claims for personal injury and property damage as a result of the release.  The suit was removed to Rhode Island federal court on January 27, 2006.  A motion to remand the case to state court filed by plaintiffs was denied on April 16, 2007.  The Company thereafter moved to dismiss plaintiffs’ amended complaint, which motion was granted in part, dismissing claims for public nuisance, private nuisance and violation of Rhode Island’s Hazardous Waste Management Act, leaving plaintiffs with claims for negligence and strict liability.  The Court has set December 1, 2008 as the Closure Date for all discovery.  On October 18, 2007, an attorney representing other Pawtucket residents filed suit against the Company in the Superior Court in Providence asserting claims similar to those pending in the above-described federal court suit for personal injury and property damage.  An additional complaint alleging personal injury arising out of the mercury release was filed on behalf of three plaintiffs with the District Court for the Sixth District, Providence County, Rhode Island, on January 22, 2008. The Company will vigorously defend all such suits.  The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Hope Land.  Hope Land Mineral Corporation (Hope Land) claimed trespass and unjust enrichment in respect of the storage rights to property that contains a portion of the Company’s Howell storage field.  The Company filed an action for condemnation to obtain the storage rights from Hope Land.  Trial before the Michigan Circuit Court commenced in April 2007, and on May 2, 2007, the jury awarded Hope Land total compensation of approximately $91,000 in respect of condemnation and trespass and no recovery in respect of unjust enrichment.  Following the verdict, the matter was settled and an Order of Dismissal was entered in the Court on July 3, 2007.  The settlement of this matter had no material impact on the Company’s consolidated financial position, results of operations or cash flows.

Jack Grynberg.  Jack Grynberg, an individual, filed actions for damages against a number of companies, including Panhandle, now transferred to the U.S. District Court for the District of Wyoming, alleging mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  Among the defendants are Panhandle, Citrus, Florida Gas and certain of their affiliates (Company Defendants).  On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against the Company Defendants.  Grynberg is appealing that action to the Tenth Circuit Court of Appeals.  Grynberg’s opening brief was filed on July 31, 2007.  Respondents filed their brief rebutting Grynberg’s arguments on November 21, 2007.  A similar action, known as the Will Price litigation, also has been filed against a number of companies, including Panhandle, in U.S. District Court for the District of Kansas.  Panhandle is currently awaiting the decision of the trial judge on the defendants’ motion to dismiss the Will Price action.  Panhandle and the other Company Defendants believe that their measurement practices conformed to the terms of their FERC gas tariffs, which were filed with and approved by FERC.  As a result, the Company believes that it has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Panhandle and the other Company Defendants complied with the terms of their tariffs) and will continue to vigorously defend against them, including any appeal from the dismissal of the Grynberg case.  The Company does not believe the outcome of these cases will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Southwest Gas Litigation.  During 1999, several actions were commenced in federal courts by persons involved in competing efforts to acquire Southwest Gas Corporation.  All of these actions eventually were transferred to the U.S. District Court for the District of Arizona (District Court).  The trial of the Company’s claims against the sole remaining defendant, former Arizona Corporation Commissioner James Irvin, was concluded on December 18, 2002, with a jury award to the Company of nearly $400,000 in actual damages and $60 million in punitive damages against former Commissioner Irvin.  Following appeal to the Ninth Circuit Court of Appeals and remand to the District Court, the District Court reconsidered the punitive damages award and entered an order of remittitur on November 21, 2006, reducing the punitive damages amount to $4 million, plus interest.  Irvin has appealed to the Ninth Circuit Court of Appeals.  The Company anticipates that the Court’s opinion will be issued in 2008.  The Company intends to continue to vigorously pursue its case against former

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Commissioner Irvin, including seeking to collect all damages ultimately determined to lie against him. There can be no assurance, however, as to the amount of such damages, or as to the amount, if any, that the Company ultimately will collect.

GP II Energy Litigation.  On October 23, 2006, landowners filed suit against the Company in the 109th District Court of Winkler County, Texas.  Plaintiffs are seeking money damages, equitable relief and punitive damages alleging continuing pollution to underground aquifers underlying the plaintiffs’ approximately 16,000 acre property. SUGS operated the Halley Plant, a hydrocarbon processing facility, which is located on a limited portion of the plaintiff landowners’ ranch pursuant to a lease.  On February 15, 2008, the Company learned that plaintiffs significantly revised their claims to include approximately $40 million in economic damages and approximately $85 million in punitive damages.  The trial date has been postponed to June 10, 2008.  The Company will continue to vigorously defend the suit.  The Company does not believe the outcome of this case will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Other Commitments and Contingencies.

Hurricane Damage.  Late in the third quarter of 2005, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast.  These hurricanes caused damage to property and equipment owned by Sea Robin, Trunkline, and Trunkline LNG.  As of December 31, 2007, the Company has incurred $35 million of capital expenditures related to the hurricanes, primarily for replacement or abandonment of damaged property and equipment at Sea Robin and construction project delays at the Trunkline LNG terminal.

The Company anticipates reimbursement from its property insurance carriers for a significant portion of damages from the hurricanes in excess of its $5 million deductible.  Such reimbursement is currently estimated by the Company’s property insurance carrier ultimately to be limited to 70 percent of the portion of the claimed damages accepted by the insurance carrier, but the amount is subject to the level of total ultimate claims from all companies relative to the carrier’s $1 billion total limit on payout per event.  As of December 31, 2007, the Company has received payments of $7.6 million from its insurance carriers.  No receivables due from the insurance carriers have been recorded as of December 31, 2007.

In addition, after the 2005 hurricanes, the U.S. MMS mandated inspections by leaseholders and pipeline operators along the hurricane tracks.  The Company has detected exposed pipe and other facilities on Trunkline and Sea Robin that must be re-covered to comply with applicable regulations.  Capital expenditures of approximately $3.7 million have been incurred as of December 31, 2007 to address these issues.  The Company will seek recovery of these expense and capital amounts as part of the hurricane-related claims.

Panhandle Capital Expenditures.  The Company estimates remaining expenditures associated with its Trunkline field zone expansion and LNG terminal enhancement projects will be approximately $245 million, with approximately $200 million to be incurred in 2008, plus capitalized interest.  These estimates were developed for budgeting purposes and are subject to revision.

Purchase Commitments.  At December 31, 2007, the Company had purchase commitments for natural gas transportation services, storage services and certain quantities of natural gas at a combination of fixed, variable and market-based prices that have an aggregate value of approximately $1.1 billion.  The Company’s purchase commitments may be extended over several years depending upon when the required quantity is purchased.  The Company has purchase gas tariffs in effect for all its utility service areas that provide for recovery of its purchase gas costs under defined methodologies and the Company believes that all costs incurred under such commitments will be recovered through its purchase gas tariffs.

TIF Debt Guarantee.  The Company has a guaranty with a bank whereby the Company unconditionally guaranteed payment of financing obtained for the development of PEI Power Park.  In March 1999, the Borough of Archbald, the County of Lackawanna, and the Valley View School District (collectively the Taxing Authorities) approved a Tax Incremental Financing Plan (TIF Plan) for the development of PEI Power Park.  The TIF Plan requires that:  (i) the Redevelopment Authority of Lackawanna County raise $10.6 million of funds to be used for infrastructure improvements of the PEI Power Park; (ii) the Taxing Authorities create a tax increment district and use incremental tax revenues generated from new development to service the $10.6 million debt; and (iii) PEI

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Power Corporation, a subsidiary of the Company, guarantee the debt service payments.  In May 1999, the Redevelopment Authority of Lackawanna County borrowed $10.6 million from a bank under a promissory note (TIF Debt), which was refinanced and modified in May 2004.  Beginning May 15, 2004 the TIF Debt bears interest at a variable rate equal to three-quarters percent (0.75 percent) lower than the National Prime Rate of Interest with no interest rate floor or ceiling.  The TIF Debt matures on June 30, 2011.  Interest-only payments were required until June 30, 2003, and semi-annual interest and principal payments are required thereafter.  As of December 31, 2007, the balance outstanding on the TIF Debt was $4.6 million with an interest rate of 6.5 percent.  Estimated incremental tax revenues are expected to cover approximately 51 percent of the 2008 annual debt service.  Based on information available at this time, the Company believes that the $2.1 million amount provided for the potential shortfall in estimated future incremental tax revenues is adequate as of December 31, 2007.

Missouri Safety Program.  Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in a major gas safety program in its service territories (Missouri Safety Program).  This program includes replacement of Company and customer-owned gas service and yard lines, the movement and resetting of meters, the replacement of cast iron mains and the replacement and cathodic protection of bare steel mains.  In recognition of the significant capital expenditures associated with this safety program, the MPSC initially permitted the deferral and subsequent recovery through rates of depreciation expense, property taxes and associated carrying costs over a 10-year period.  On August 28, 2003, the state of Missouri passed certain statutes that provided Missouri Gas Energy the ability to adjust rates periodically to recover depreciation expense, property taxes and carrying costs associated with the Missouri Safety Program, as well as investments in public improvement projects.  The continuation of the Missouri Safety Program will result in significant levels of future capital expenditures.  The Company incurred capital expenditures of $11.4 million in 2007 related to this program and estimates incurring approximately $141.3 million over the next 12 years, after which all service lines, representing about 40 percent of the annual safety program investment, will have been replaced.

Other.  Effective May 28, 2006, PEPL agreed to a three-year contract with a bargaining unit representing its employees.

Of the Company’s employees represented by unions, Missouri Gas Energy employs 61 percent, New England Gas Company employs 10 percent and Panhandle employs 29 percent.  No employees of SUGS are currently represented by bargaining units.

The Company had standby letters of credit outstanding of $18.5 million and $8.7 million at December 31, 2007 and 2006, respectively, which guarantee payment of insurance claims and other various commitments.

 
19.  Discontinued Operations

On August 24, 2006, the Company completed the sale of the assets of its PG Energy natural gas distribution division to UGI Corporation for $580 million in cash, excluding certain working capital adjustment reductions of approximately $24.4 million, which were paid in the first quarter of 2007.  Additionally, on August 24, 2006, the Company completed the sale of the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA for $575 million in cash, less the assumption of approximately $77 million of debt and excluding certain working capital adjustment reductions of approximately $24.9 million, which were paid in the first quarter of 2007.

The results of operations of these divisions have been segregated and reported as Discontinued operations in the Consolidated Statement of Operations for all periods presented.  The PG Energy natural gas distribution division and Rhode Island operations of the New England Gas Company natural gas distribution division were historically reported within the Distribution segment.

Loss from discontinued operations before income taxes in the Consolidated Statement of Operations includes a loss for 2006 of $56.8 million recorded by the Company upon 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.  Significant components contributing to the loss include $19.4 million of asset impairment charges related to increases in PP&E during 2006, selling costs of $4.7 million, and charges associated with pre-closing

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SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




arrangements between the Company and the buyers, principally consisting of $15.1 million of pension funding requirements and $5.8 million of premiums related to the early retirement of debt.  An additional factor related to higher PP&E balances is the cessation of recording depreciation expense subsequent to approval of the Company’s Board of Directors in January 2006 to dispose of the applicable assets.

The Company incurred $142.4 million of income tax expense in 2006 resulting from $379.8 million of non-deductible goodwill that had no tax basis.  Additionally, the Company incurred $17.6 million of income tax expense as a result of the write-off of a tax-related regulatory asset.

See Note 7 – Goodwill for information related to the $175 million goodwill impairment charge recorded in 2005 related to the Company’s discontinued operations.
The following table summarizes the combined results of operations that have been segregated and reported as discontinued operations in the Consolidated Statement of Operations.
 
   
Years Ended
 
   
December 31,
 
   
2006 (2)
   
2005
 
   
(In thousands,except per share amounts)
 
             
Operating revenues
  $ 512,935     $ 752,549  
Operating income (loss)
    54,662       (106,073 )
Loss from discontinued operations  (1)
    (152,952 )     (132,413 )
Net loss available from discontinued
               
operations per share:
               
Basic
  $ (1.33 )   $ (1.21 )
Diluted
  $ (1.30 )   $ (1.17 )
                 
__________________
(1)  Loss from discontinued operations does not include any allocation of corporate interest
       expense or other corporate costs.
(2)  Represents results of operations for year 2006 through August 24, 2006.


20.  Asset Retirement Obligations

Statement No. 143 requires an ARO to be recorded when a legal obligation to retire the asset exists.  FIN No. 47 clarifies that an ARO should be recorded for all assets with legal retirement obligations, even if the enforcement of the obligation is contingent upon the occurrence of events beyond the company’s control (Conditional ARO).  The fair values of the AROs were calculated using an expected present value technique.  This technique reflects assumptions such as removal and remediation costs, inflation and profit margins that third parties would demand to settle the amount of the future obligation.  The Company did not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium could not be reliably estimated.

Although a number of other assets in the Company’s system are subject to agreements or regulations that give rise to an ARO or a Conditional ARO upon the Company’s discontinued use of these assets, AROs were not recorded for most of these assets because the fair values of these AROs were not reliably estimable.  The principal reason the fair values of these AROs were not subject to reliable estimation was because the lives of the underlying assets are indeterminate.  Management has concluded that the Panhandle pipeline system, as a whole, and the SUGS natural gas gathering and processing system, as a whole, have indeterminate lives.  In reaching this conclusion, management considered its intent for operating the systems, the economic life of the underlying assets, its past practices and industry practice.


F-59


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The Company intends to operate the pipeline and the natural gas gathering and processing systems indefinitely as a going concern.  Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists.  Based on the widespread use of natural gas in industrial and power generation activities and current estimates of recoverable reserves, management expects supply and demand to exist for the foreseeable future.

The Company has in place a rigorous repair and maintenance program that keeps the pipeline and the natural gas gathering and processing systems in good working order.  Therefore, although some of the individual assets on the systems may be replaced, the pipeline and the natural gas gathering and processing systems themselves will remain intact indefinitely.  AROs generally do not arise unless a pipeline or a facility (or portion thereof) is abandoned.  The Company does not intend to make any such abandonments as long as supply and demand for natural gas remains relatively stable.
The following table is a general description of ARO and associated long-lived assets at December 31, 2007.
 
   
In Service
         
ARO Description
 
Date
 
Long-Lived Assets
 
Amount
 
           
(In thousands)
 
Retire offshore lateral lines
 
Various
 
Offshore lateral lines
  $ 5,539  
Other
 
Various
 
Mainlines, compressors and gathering plants
    1,446  
                 

The following table is a reconciliation of the carrying amount of the ARO liability for the periods presented.
 
   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
                   
Beginning balance
  $ 10,535     $ 8,200     $ 5,657  
Addition from Sid Richardson
                       
Energy Services acquisition
    -       885       -  
Incurred
    2,314       1,189       2,371  
Settled
    (907 )     (414 )     (285 )
Accretion expense
    820       675       457  
Ending balance
  $ 12,762     $ 10,535     $ 8,200  
                         
 
21.  Reportable Segments

The Company’s reportable business segments are organized 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.

The Transportation and Storage segment operations are conducted through Panhandle and the investment in Citrus.  Through Panhandle, the Company is primarily engaged in the interstate transportation and storage of natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions.  Panhandle also provides LNG terminalling and regasification services.  Through its investment in Citrus, the Company has an interest in and operates Florida Gas.  Florida Gas is primarily engaged in the interstate transportation of natural gas from South Texas through

F-60


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




the Gulf Coast region to Florida.  See the related discussion of the change in ownership interests of CCE Holdings on December 1, 2006 applicable to Florida Gas and Transwestern in Note 3 – Acquisitions and Sales – CCE Holdings Transactions.

The Company acquired Sid Richardson Energy Services on March 1, 2006, which represents the Gathering and Processing reportable 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.  Its operations are conducted through SUGS throughout Texas and in the southwestern United States.  See Note 3 – Acquisition and Sales – Acquisition of Sid Richardson Energy Services.

The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.  The Company’s discontinued operations relate to its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division.  During the first quarter of 2006, the Company entered into definitive agreements to sell 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.  The Company completed the sales in August 2006.  See Note 19 – Discontinued Operations.

Revenue included in the Corporate and other category is primarily attributable to PEI Power Corporation, which generates and sells electricity.  PEI Power Corporation does not meet the quantitative threshold for segment reporting.

The Company evaluates operational and financial segment performance based on several factors, of which the primary financial measure is earnings before interest and taxes (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.

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 and 2005.

The following table sets forth certain selected financial information for the Company’s segments for the years ended December 31, 2007, 2006 and 2005.  Financial information for the Gathering and Processing segment reflects operations of SUGS beginning on its acquisition date of March 1, 2006.  The Consolidated Statement of Operations segment information for all periods presented has been reclassified to distinguish between results of operations from continuing and discontinued operations.  Segment information presented for expenditures of long-lived assets for the year ended December 31, 2005 has not been adjusted for discontinued operations.


F-61


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




   
Years Ended December 31,
 
Segment Data
 
2007
   
2006
   
2005
 
   
(In thousands)
 
Operating revenues from external customers:
                 
Transportation and Storage
  $ 658,446     $ 577,182     $ 505,233  
Gathering and Processing
    1,221,747       1,090,216       -  
Distribution
    732,109       668,721       752,699  
Total segment operating revenues
    2,612,302       2,336,119       1,257,932  
Corporate and other
    4,363       4,025       8,950  
    $ 2,616,665     $ 2,340,144     $ 1,266,882  
                         
Depreciation and amortization:
                       
Transportation and Storage
  $ 85,641     $ 72,724     $ 62,171  
Gathering and Processing
    59,560       47,321       -  
Distribution
    30,251       30,353       29,447  
Total segment depreciation and amortization
    175,452       150,398       91,618  
Corporate and other
    2,547       1,705       944  
    $ 177,999     $ 152,103     $ 92,562  
                         
Earnings (loss) from unconsolidated investments:
                       
Transportation and Storage
  $ 99,222     $ 141,310     $ 70,618  
Gathering and Processing
    1,300       (188 )     -  
Corporate and other
    392       248       124  
    $ 100,914     $ 141,370     $ 70,742  
                         
Other income (expense), net:
                       
Transportation and Storage
  $ 1,604     $ 3,354     $ 571  
Gathering and Processing
    140       1,571       -  
Distribution
    (1,902 )     (2,130 )     (2,598 )
Total segment other income (expense), net
    (158 )     2,795       (2,027 )
Corporate and other
    (725 )     37,123       (6,214 )
    $ (883 )   $ 39,918     $ (8,241 )
                         
Segment performance:
                       
Transportation and Storage EBIT
  $ 391,029     $ 417,536     $ 281,344  
Gathering and Processing EBIT
    65,368       62,630       -  
Distribution EBIT
    70,568       41,883       61,698  
Total segment EBIT
    526,965       522,049       343,042  
Corporate and other
    151       14,324       (11,424 )
Interest expense
    203,146       210,043       128,470  
Federal and state income taxes
    95,259       109,247       50,052  
Earnings from continuing operations
    228,711       217,083       153,096  
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 )
Net earnings
    228,711       64,131       20,683  
Preferred stock dividends
    17,365       17,365       17,365  
Net earnings available for common stockholders
  $ 211,346     $ 46,766     $ 3,318  
                         

F-62




SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


   
Years Ended December 31,
 
Segment Data
 
2007
   
2006
 
   
(In thousands)
 
Total assets:
           
Transportation and Storage
  $ 4,550,822     $ 3,874,318  
Gathering and Processing
    1,709,901       1,722,055  
Distribution
    1,020,460       1,016,491  
Total segment assets
    7,281,183       6,612,864  
Corporate and other
    116,730       169,926  
Total consolidated assets
  $ 7,397,913     $ 6,782,790  
                 

   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
Expenditures for long-lived assets:
                 
Transportation and Storage
  $ 591,153     $ 244,821     $ 189,415  
Gathering and Processing
    48,633       35,101       -  
Distribution
    44,769       47,954       84,896  
Total segment expenditures for
                       
long-lived assets
    684,555       327,876       274,311  
Corporate and other
    4,173       4,798       2,306  
Total consolidated expenditures for
                       
long-lived assets
  $ 688,728     $ 332,674     $ 276,617  
                         
 

F-63




SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
Significant Customers and Credit Risk.  The following tables provide summary information of significant customers for Panhandle and SUGS by applicable segment and on a consolidated basis for the periods presented.  The Distribution segment has no single customer, or group of customers under common control, that accounted for ten percent or more of the Company’s Distribution segment or consolidated operating revenues for the periods presented.
 
       
Percent of Consolidated
   
Percent of Transportation and
 
Company Total
   
Storage Segment Revenues
 
Operating Revenues
   
Years Ended December 31,
 
Years Ended December 31,
Customer
 
2007
 
2006
 
2005
 
2007
 
2006
 
2005
                                     
BG LNG Services
    28 %     24 %     17 %     7 %     6 %     4 %
ProLiance
    11       12       16       3       3       4  
Ameren Corp
    9       10       11       2       3       3  
Other top 10 customers
    17       19       14       4       5       4  
Remaining customers
    35       35       42       9       8       10  
Total percentage
    100 %     100 %     100 %     25 %     25 %     25 %
                                                 
 
   
Percent of Gathering and
   
Percent of Consolidated
 
   
Processing Segment Revenues
   
Company Total Operating Revenues
 
   
Years Ended December 31,
   
Years Ended December 31,
 
Customer
 
2007
 
2006 (1)
 
2007
 
2006 (1)
                         
ConocoPhillips Company
    16 %     22 %     8 %     10 %
BP Energy Company
    6       11       3       5  
Constellation Power Source
    7       10       3       5  
Other top 10 customers
    34       22       16       10  
Remaining customers
    37       35       17       17  
Total percentage
    100 %     100 %     47 %     47 %
                                 
_______________________
(1)
Represents results from operations for the period subsequent to the March 1, 2006 acquisition.




















F-64


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




22.  Accumulated Other Comprehensive Loss

The table below provides an overview of Comprehensive income (loss) for the periods indicated:

   
Year Ended December 31,
 
Other Comprehensive Income (Loss)
 
2007
   
2006
   
2005
 
   
(In thousands)
 
Net Earnings
  $ 228,711     $ 64,131     $ 20,683  
Other Comprehensive Income (Loss) Adjustments:
                       
Change in fair value of interest rate hedges, net of tax of $(5,241),
                       
$(745) and $73, respectively
    (10,041 )     (49 )     108  
Reclassification of unrealized gain on interest rate hedges
                       
into earnings, net of tax of $(13), $608 and $608, respectively
    (4 )     967       967  
Realized gain (loss) on interest rate hedges, net of tax of $(1,488),
                       
$0 and $0, respectively
    (2,366 )     -       -  
Reversal of minimum pension liability related to disposition, net
                       
of tax of $0, $16,004 and $0, respectively
    -       26,331       -  
Minimum pension liability adjustment, net of tax of $0, $4,128
                       
and $1,064, respectively
    -       6,803       1,771  
Change in fair value of commodity hedges, net of tax of $(775),
                       
$7,466 and $0, respectively
    (1,279 )     12,360       -  
Reclassification of unrealized gain on commodity hedges
                       
into earnings, net of tax of $(2,425), $(4,266) and $0, repectively
    (3,997 )     (7,084 )     -  
Actuarial gain and prior service credit (cost) relating to
                       
pension and other postretirement benefits,
                       
net of tax of $1,055, $0 and $0, respectively
    3,597       -       -  
Reclassification of actuarial gain and prior service credit
                       
(cost) relating to pension and other postretirement benefits
                       
into earnings, net of tax of $1,619, $0 and $0, respectively
    3,397       -       -  
Total other comprehensive income (loss)
    (10,693 )     39,328       2,846  
Total comprehensive income
  $ 218,018     $ 103,459     $ 23,529  
                         
 
The table below provides an overview of the components in Accumulated other comprehensive loss as of the periods indicated:
 
   
Years Ended December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
Interest rate hedges, net
  $ (14,723 )   $ (2,312 )
Commodity hedges, net
    -       5,276  
Benefit Plans:
               
Net actuarial loss and prior service costs, net - pensions
    (17,907 )     (26,678 )
Net actuarial gain and prior service credit, net - other postretirement benefits
    21,036       22,813  
Total Accumulated other comprehensive loss, net of tax
  $ (11,594 )   $ (901 )
                 
 
 
23. Related Party Transactions
 
See Note 9 – Unconsolidated Investments – Dividends for information related to dividends received by the Company from its unconsolidated investments.

On November 5, 2004, SU Pipeline Management LP (Manager), a wholly-owned subsidiary of Southern Union, and PEPL entered into an Administrative Services Agreement (Management Agreement) with CCE Holdings.

F-65


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




Pursuant to the Management Agreement, Manager provided administrative services to CCE Holdings and its subsidiaries from November 17, 2004 to December 1, 2006.  The Management Agreement was terminated on December 1, 2006 following the redemption of Transwestern as more fully discussed in Note 3 – Acquisitions and Sales – CCE Holdings Transactions.

Pursuant to the Management Agreement, Southern Union billed CCE Holdings $4.3 million in 2005 for management fees.  No billings were made for management fees in 2006 under the Management Agreement.  In years 2006 and 2005, Southern Union billed CCE Holdings $14 million and $12 million, respectively, for certain corporate costs provided under the Management Agreement prior to its termination on December 1, 2006 in conjunction with the transactions contemplated by the Redemption Agreement.
 
24. Stock-Based Compensation
 
Stock Options.  Effective January 1, 2006, the Company adopted Statement No. 123R, using the modified prospective application method of transition, as defined in Statement No. 123R. Since the adoption of Statement No. 123R, the Company has recorded the grant date fair value of share-based payment arrangements, net of estimated forfeitures, as compensation expense using a straight-line basis over the awards’ requisite service period. Under the modified prospective application method, Statement No. 123R applies to new awards and to awards modified, repurchased, or cancelled after December 31, 2005. Compensation cost for the portion of awards for which the requisite service has not been rendered that are outstanding as of December 31, 2005 is recognized as the requisite service is rendered on or after January 1, 2006.  Additionally, no transition adjustment is generally permitted for the deferred tax assets associated with outstanding equity instruments, as these deferred tax assets will be recorded as a credit to Premium on capital stock when realized.  No cumulative effect of a change in accounting principle was recognized upon adoption of Statement No. 123R.

The Company previously disclosed the fair value of stock options granted and the assumptions used in determining fair value pursuant to Statement No. 123, Accounting for Stock-Based Compensation.  The Company historically used a Black-Scholes valuation model to determine the fair value of stock options granted. Stock options (either incentive stock options or non-qualified options) and SARs generally vest over a three-, four- or five-year period from the date of grant and expire ten years after the date of grant.  The adoption of Statement No. 123R in 2006 reduced Operating Income, Earnings from continuing operations before income taxes and Net earnings by $2.4 million, $2.4 million and $1.9 million, respectively, or $0.02 per basic share and $0.02 per diluted share for the year ended December 31, 2006.

The fair value of each option award is estimated on the date of grant using a Black-Scholes option pricing model. The Company’s expected volatilities are based on historical volatility of the Company’s stock.  To the extent that volatility of the Company’s stock price increases in the future, the estimates of the fair value of options granted in the future could increase, thereby increasing share-based compensation expense in future periods.  Additionally, the expected dividend yield is considered for each grant on the date of grant.  The Company’s expected term of options granted was derived from the average midpoint between vesting and the contractual term.  In the future, as information regarding post-vesting termination becomes more accessible, the Company may change the method of deriving the expected term.  This change could impact the fair value of options granted in the future.  The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

The following table represents the Black-Scholes estimated ranges under the Company plans for grants issued in the periods presented:

   
Years ended December 31,
 
   
2007
 
2006
 
2005
 
Expected volatility
 
30.11% to 32.12%
 
32.90%
 
20.57% to 37.61%
 
Expected dividend yield
 
2.10%
 
1.43%
 
1.67%
 
Risk-free interest rate
 
3.70% to 3.89%
 
4.69%
 
3.76% to 4.63%
 
Expected life
 
6.00 to 7.50 years
 
6.00 years
 
0.75 to 6.50 years
               


F-66


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The following table provides information on stock options granted, exercised, canceled, outstanding and exercisable under the Second Amended 2003 Plan and the 1992 Plan for the years ended December 31, 2007, 2006 and 2005:
 
         
Second Amended 2003 Plan
   
1992 Plan
 
               
Weighted
         
Weighted
 
         
Shares
   
Average
   
Shares
   
Average
 
         
Under
   
Exercise
   
Under
   
Exercise
 
         
Option
   
Price
   
Option
   
Price
 
                               
Outstanding January 1, 2005
          698,522     $ 16.83       2,390,705     $ 12.81  
Granted
          731,349       23.52       136,608       12.75  
Exercised
          (62,976 )     16.83       (794,105 )     12.47  
Forfeited
          (77,385 )     16.83       (473,584 )     12.45  
Outstanding December 31, 2005
          1,289,510     $ 20.62       1,259,624     $ 13.15  
Granted
          -  (1)     -       -       -  
Exercised
          (121,137 )     17.31       (521,289 )     13.92  
Forfeited
          (157,894 )     18.23       (23,139 )     12.92  
Outstanding December 31, 2006
          1,010,479     $ 21.39       715,196     $ 12.60  
Granted
          717,098  (2)     28.48       -       -  
Exercised
          (98,027 )     19.32       (176,515 )     10.51  
Forfeited
          (97,875 )     22.95       (1,979 )     13.03  
Outstanding December 31, 2007
          1,531,675     $ 24.74       536,702     $ 13.28  
                                       
Exercisable December 31, 2005
          355,259       21.85       1,147,902       13.06  
Exercisable December 31, 2006
          533,363       22.38       715,196       12.60  
Exercisable December 31, 2007
          565,560       22.25       536,702       13.28  
                                       
_____________________
(1)  Excludes 133,610 SARs which vest in equal increments on December 27, 2007 through 2009.  Each SAR entitles the holder to shares of Southern Union’s common stock equal to the fair market value of
 
 Southern Union’s common stock in excess of $28.07 for each SAR on the applicable vesting date.
(2)  Excludes 282,163 SARs which vest in equal increments on December 17, 2008 through 2010.  Each SAR entitles the holder to shares of Southern Union’s common stock equal to the fair market value of
 
 Southern Union’s common stock in excess of $28.48 for each SAR on the applicable vesting date.


F-67


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




The following table summarizes information about stock options outstanding under the Second Amended 2003 Plan and the 1992 Plan at December 31, 2007:

   
Options Outstanding
 
Options Exercisable
 
       
Weighted Average
 
Weighted
     
Weighted
 
       
Remaining
 
Average
 
Number of
 
Average
 
Range of Exercise Prices  
Number of Options
 
Contractual Life
 
Exercise Price
 
Options
 
Exercise Price
 
                       
 
Second Amended 2003 Plan:
                     
16.82 - 20.00
 
  242,135  
6.11 years
  $ 16.83     105,800   $ 16.83  
20.01 - 25.00
    572,442  
7.70 years
    23.41     459,760     23.50  
25.01 - 28.48
    717,098  
9.97 years
    28.48     -     -  
      1,531,675  
8.51 years
  $ 24.74     565,560   $ 22.25  
                               
1992 Plan:
                             
12.63 - 14.66
    536,702  
1.50 years
  $ 13.28     536,702   $ 13.28  
      536,702  
1.50 years
  $ 13.28     536,702   $ 13.28  
                               

The weighted average remaining contractual life of options and SARs outstanding under the Second Amended 2003 Plan and the 1992 Plan at December 31, 2007 was 8.75 and 1.50 years, respectively.  The weighted average remaining contractual life of options and SARs exercisable under the Second Amended 2003 Plan and the 1992 Plan at December 31, 2007 was 7.49 and 1.50 years, respectively. The aggregate intrinsic value of total options and SARs outstanding and exercisable at December 31, 2007 was $16.6 million and $12.9 million, respectively.

As of December 31, 2007, there was $11.1 million of total unrecognized compensation cost related to non-vested stock options and SARs compensation arrangements granted under the stock option plans. That cost is expected to be recognized over a weighted-average contractual period of 3.4 years. The total fair value of options and SARs vested as of December 31, 2007 was $8.2 million. Compensation expense recognized related to stock options and SARs totaled $1.5 million ($1.2 million, net of tax) for the year ended December 31, 2007 and $2.4 million ($1.9 million, net of tax) for the year ended December 31, 2006.  Cash received from the exercise of stock options was $3.7 million for the year ended December 31, 2007.

The intrinsic value of options exercised during the year ended December 31, 2007 was approximately $4.9 million.  The Company realized an additional tax benefit of approximately $1.7 million for the excess amount of deductions related to stock options over the historical book compensation expense multiplied by the statutory tax rate in effect, which has been reported as an increase in financing cash flows in the Consolidated Statement of Cash Flows.

Restricted Stock.  The Company’s Second Amended 2003 Plan also provides for grants of restricted stock equity units and restricted stock liability units.  The Company settles restricted stock equity units with shares of common stock, and restricted stock liability units with cash.  The restrictions associated with a grant of restricted stock equity units under the Second Amended 2003 Plan generally expire equally over a period of three years or in total after five years.  Restrictions on certain grants made to non-employee directors and senior executives of the Company expire over a shorter time period, in certain cases less than one year, and may be subject to accelerated expiration over a shorter term if certain criteria are met.  The restrictions associated with a grant of restricted stock liability units expire equally over a period of three years and are payable in cash at the vesting date.




F-68


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




A summary of the activity of non-vested restricted stock equity awards as of December 31, 2007 is presented below:

   
Number of
   
Weighted-Average
 
   
Restricted Shares
   
Grant-Date
 
Nonvested Restricted Stock Equity Units
 
Outstanding
   
Fair-Value
 
             
Nonvested restricted shares at January 1, 2005
    -     $ -  
Granted
    209,903       24.15  
Vested
    -       -  
Forfeited
    -       -  
Nonvested restricted shares at December 31, 2005
    209,903     $ 24.15  
Granted
    137,036       26.50  
Vested
    (146,335 )     24.17  
Forfeited
    (31,820 )     24.44  
Nonvested restricted shares at December 31, 2006
    168,784     $ 25.98  
Granted
    156,044       28.99  
Vested
    (111,322 )     26.67  
Forfeited
    (12,336 )     24.96  
Nonvested restricted shares at December 31, 2007
    201,170     $ 28.00  
                 

A summary of the activity of nonvested restricted stock unit liability awards as of December 31, 2007 is presented below:

   
Number of
   
Weighted-Average
 
   
Restricted Stock Liability
   
Grant-Date
 
Nonvested Restricted Stock Liability Units
 
Units Outstanding
   
Fair-Value
 
             
Nonvested restricted shares at December 31, 2005
    -     $ -  
Granted
    108,869       28.07  
Vested
    -       -  
Forfeited
    -       -  
Nonvested restricted shares at December 31, 2006
    108,869     $ 28.07  
Granted
    143,460       28.49  
Vested
    (36,283 )     28.07  
Forfeited
    (2,744 )     28.07  
Nonvested restricted shares at December 31, 2007
    213,302     $ 28.35  
                 

As of December 31, 2007, there was $10.1 million of total unrecognized compensation cost related to non-vested, restricted stock equity units and restricted stock liability units compensation arrangements granted under the restricted stock plans. That cost is expected to be recognized over a weighted-average contractual period of 3 years. The total fair value of restricted stock equity and liability units that vested during the year ended December 31, 2007 was $4 million. Compensation expense recognized related to restricted stock equity and liability units totaled $3 million ($1.9 million, net of tax) for the year ended December 31, 2007, and $4.3 million ($2.7 million, net of tax) for the year ended December 31, 2006.

The Company settled the restricted stock liability awards vesting in 2007 with cash payments of $1.1 million.


F-69


SOUTHERN UNION COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




25.  Subsequent Event

On February 8, 2008, the Company remarketed the 4.375% Senior Notes.  The interest rate on the Senior Notes was reset to 6.089 percent per annum effective on and after February 19, 2008.  The Senior Notes will mature on February 16, 2010.  On February 19, 2008, the Company issued 3,693,240 shares of common stock for $100 million in conjunction with the remarketing of its 4.375% Senior Notes.  For additional information, see Note 10 – Stockholder’s Equity – 2005 Equity Issances.

26.  Quarterly Operations (Unaudited)

The following table presents the operating results for each quarter of the year ended December 31, 2007:
 
   
Quarters Ended
 
   
March 31
   
June 30
   
September 30
   
December 31
 
   
(In thousands, except per share amounts)
 
                         
Operating revenues
  $ 780,232     $ 588,049     $ 525,473     $ 722,911  
Operating income
    129,594       87,400       96,980       113,111  
Earnings from continuing operations
    78,721       50,975       45,283       53,732  
Net earnings available for common
                               
stockholders
    74,380       46,634       40,941       49,391  
Diluted net earnings per share
                               
available for common stockholders:
                               
Continuing operations
  $ 0.62     $ 0.39     $ 0.34     $ 0.41  
Available for common stockholders
  $ 0.62     $ 0.39     $ 0.34     $ 0.41  
                                 
 
The following table presents the operating results for each quarter of the year ended December 31, 2006:
 
   
Quarters Ended
 
   
March 31
   
June 30
   
September 30
   
December 31
 
   
(In thousands, except per share amounts)
 
                         
Operating revenues
  $ 547,166     $ 552,355     $ 564,418     $ 676,205  
Operating income
    102,847       69,792       69,961       112,485  
Earnings from continuing operations
    73,418       16,321       11,829       115,515  
Net earnings (loss) from discontinued operations
    24,529       (2,587 )     (174,473 )     (421 )
Net earnings (loss) available for common
                               
    stockholders
    93,606       9,393       (166,985 )     110,752  
Diluted net earnings (loss) per share
                               
    available for common stockholders:
                               
        Continuing operations
  $ 0.60     $ 0.10     $ 0.06     $ 0.92  
        Available for common stockholders
  $ 0.82     $ 0.08     $ (1.42 )   $ 0.92  
                                 

The sum of EPS by quarter in the above tables may not equal the net earnings per common and common share equivalents for the applicable year due to variations in the weighted average common and common share equivalents outstanding used in computing such amounts.





 

 





Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors
     of Southern Union Company:

In our opinion, the accompanying consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Southern Union Company and its subsidiaries (the "Company") at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting under Item 9A.  Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 15 to the consolidated financial statements, the Company adopted the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109", as of January 1, 2007.  As discussed in Notes 2 and 14 to the consolidated financial statements, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statement No. 87, 88, 106 and 132(R)", as of December 31, 2006.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ PricewaterhouseCoopers LLP
 
 
Houston, Texas
February 29, 2008







 
 
 
 


 
F-71

 
 

 


 




Citrus Corp. and Subsidiaries
Consolidated Financial Statements
Years ended December 31, 2007, 2006 and 2005
with Report of Independent Registered Public Accounting Firm

 
 
 
 

 


 
 

 


Consolidated Financial Statements
         
Years ended December 31, 2007, 2006 and 2005
         
         
         
TABLE OF CONTENTS
 
       
     
Page
 
         
Report of Independent Registered Public Accounting Firm
 
2
 
         
Audited Consolidated Financial Statements
     
 
Consolidated Balance Sheets
 
3
 
 
Consolidated Statements of Income
 
4
 
 
Consolidated Statements of Stockholders' Equity
 
5
 
 
Consolidated Statements of Comprehensive Income
 
5
 
 
Consolidated Statements of Cash Flows
 
6
 
 
Notes to Consolidated Financial Statements
 
7 - 29
 
 

 
1
 
 

 



 

 
 
Report of Independent Registered Public Accounting Firm
 


To the Board of Directors and Stockholders of Citrus Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity, of comprehensive income and of cash flows present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the “Company”) at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with the accounting principles generally accepted in the United States of America.  These consolidated financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 2 and 6 to the consolidated financial statements, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158 "Employers' Accounting for Defined Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and 132(R)," as of December 31, 2006.



/s/ PricewaterhouseCoopers LLP


Houston, Texas
February 25, 2008



 
2

 
CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 
 
             
             
             
             
   
December 31,
   
December 31,
 
   
2007
   
2006
 
   
(In thousands)
 
ASSETS
           
             
Current Assets
           
Cash and cash equivalents
  $ 3,572     $ 15,267  
Accounts receivable, billed and unbilled,
               
     less allowances of $18 and $282, respectively
    39,350       45,049  
Materials and supplies
    12,745       2,954  
Exchange gas receivable
    1,729       -  
Other
    2,248       1,025  
    Total Current Assets
    59,644       64,295  
                 
Property, Plant and Equipment
               
Plant in service
    4,265,844       4,163,082  
Construction work in progress
    150,742       85,746  
      4,416,586       4,248,828  
Less accumulated depreciation and amortization
    1,401,638       1,304,133  
    Property, Plant and Equipment, Net
    3,014,948       2,944,695  
                 
Other Assets
               
Unamortized debt expense
    4,221       4,687  
Regulatory assets
    19,207       31,007  
Other
    10,838       76,429  
    Total Other Assets
    34,266       112,123  
                 
Total Assets
  $ 3,108,858     $ 3,121,113  
                 
                 
 LIABILITIES AND STOCKHOLDERS' EQUITY
               
                 
 Current Liabilities
               
 Current portion of long-term debt
  $ 44,000     $ 84,000  
 Accounts payable - trade and other
    33,422       25,070  
 Accounts payable - affiliated companies
    8,416       2,823  
 Accrued interest
    14,251       14,805  
 Accrued income taxes
    7,599       2,375  
 Accrued taxes, other than income
    5,437       9,332  
 Exchange gas payable
    22,547       24,225  
 Capital accruals
    22,636       22,185  
 Dividends payable
    42,600       -  
 Other
    7,600       6,526  
     Total Current Liabilities
    208,508       191,341  
                 
 Deferred Credits
               
 Deferred income taxes, net
    763,364       777,404  
 Regulatory liabilities
    14,842       14,256  
 Other
    9,202       8,129  
     Total Deferred Credits
    787,408       799,789  
                 
 Long-Term Debt
    909,810       836,882  
 Commitments and contingencies (Note 14)
               
                 
 Stockholders' Equity
               
Common stock, $1 par value; 1,000 shares  authorized, issued and outstanding
    1       1  
Additional paid-in capital
    634,271       634,271  
Accumulated other comprehensive loss
    (7,885 )     (10,524 )
Retained earnings
    576,745       669,353  
     Total Stockholders' Equity
    1,203,132       1,293,101  
                 
 Total Liabilities and Stockholders' Equity
  $ 3,108,858     $ 3,121,113  
                 

 
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 
 
3

 
CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
 
 
                   
                   
                   
                   
                   
                   
   
Year Ended
   
Year Ended
   
Year Ended
 
   
December 31,
   
December 31,
   
December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
                   
Operating Revenues
                 
Transportation of natural gas
  $ 495,513     $ 485,189     $ 476,049  
                         
Total Operating Revenues
    495,513       485,189       476,049  
                         
Operating Expenses
                       
Operations and maintenance
    82,058       77,941       78,829  
Depreciation and amortization
    100,634       98,653       91,125  
Taxes, other than income taxes
    29,618       34,765       34,306  
                         
    Total Operating Expenses
    212,310       211,359       204,260  
                         
                         
Operating Income
    283,203       273,830       271,789  
                         
Other Income (Expenses)
                       
Interest expense and related charges, net
    (73,871 )     (76,428 )     (79,290 )
Other, net
    39,984       4,633       6,531  
                         
    Total Other Income (Expenses), net
    (33,887 )     (71,795 )     (72,759 )
                         
Income Before Income Taxes
    249,316       202,035       199,030  
                         
Federal and State Income Tax Expense
    92,224       75,960       75,086  
                         
Net Income
  $ 157,092     $ 126,075     $ 123,944  
                         
 
 
 
 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 
 
4

 
CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
 
 
                   
                   
                   
   
Year Ended
   
Year Ended
   
Year Ended
 
   
December 31,
   
December 31,
   
December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
                   
Common Stock
                 
Balance, beginning and end of period
  $ 1     $ 1     $ 1  
                         
Additional Paid-in Capital
                       
Balance, beginning and end of period
    634,271       634,271       634,271  
                         
Accumulated Other Comprehensive Loss
                       
Balance, beginning of period
    (10,524 )     (13,162 )     (15,800 )
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges
    2,639       2,638       2,638  
Balance, end of period
    (7,885 )     (10,524 )     (13,162 )
                         
Retained Earnings
                       
Balance, beginning of period
    669,353       668,678       665,934  
Net income
    157,092       126,075       123,944  
Dividends  (1)
    (249,700 )     (125,400 )     (121,200 )
Balance, end of period
    576,745       669,353       668,678  
                         
Total Stockholders' Equity
  $ 1,203,132     $ 1,293,101     $ 1,289,788  
                         
                         
                         
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                         
                         
                         
   
Year Ended
   
Year Ended
   
Year Ended
 
   
December 31,
   
December 31,
   
December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
                         
Net income
  $ 157,092     $ 126,075     $ 123,944  
Recognition in earnings of previously deferred net losses related to derivative instruments used as cash flow hedges
    2,639       2,638       2,638  
 Total Comprehensive Income
  $ 159,731     $ 128,713     $ 126,582  
                         
                         
                         
(1) Includes $42.6 million in Dividends Payable, declared in December 2007, payable in January, 2008 and which was paid on January 18, 2008. (See Note 7 - Related Party Transaction)
 
                         
 
 
 

 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 
 
5

 
CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
                   
                   
                   
                   
                   
                   
   
Year Ended
   
Year Ended
   
Year Ended
 
   
December 31,
   
December 31,
   
December 31,
 
   
2007
   
2006
   
2005
 
   
(In thousands)
 
Cash flows provided by operating activities
                 
Net income
  $ 157,092     $ 126,075     $ 123,944  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
                         
Depreciation and amortization
    100,634       98,653       91,125  
Amortization of hedge loss in other comprehensive income
    2,639       2,638       2,638  
Amortization of discount and swap hedge loss in long term debt
    528       527       530  
Amortization of regulatory assets and other deferred charges
    1,250       3,274       3,380  
Amortization of debt costs
    994       1,048       1,053  
Deferred income taxes
    (12,277 )     18,629       12,740  
Allowance for funds used during construction
    (4,683 )     (1,630 )     (1,441 )
Gain on sale of assets
    -       -       (1,236 )
Changes in operating assets and liabilities:
                       
Accounts receivable
    5,699       (3,327 )     403  
Accounts payable
    11,950       (3,316 )     (10,567 )
Accrued interest
    (554 )     (286 )     (324 )
Accrued income tax
    5,224       3,247       (7,204 )
Other current assets and liabilities
    (8,944 )     18,749       3,234  
Other long-term assets and liabilities
    74,668       (24,627 )     36,140  
Net cash provided by operating activities
    334,220       239,654       254,415  
                         
Cash flows used in investing activities
                       
Capital expenditures
    (175,370 )     (106,023 )     (37,610 )
Allowance for funds used during construction
    4,683       1,630       1,441  
Proceeds from sale of assets
    -       -       1,715  
Net cash used in investing activities
    (170,687 )     (104,393 )     (34,454 )
                         
Cash flows used in financing activities
                       
Dividends paid
    (207,100 )     (125,400 )     (121,200 )
Net (payments) borrowings on the revolving credit facilities
    76,400       (2,000 )     (75,000 )
Long-term debt finance costs
    (528 )     -       -  
Payments on long-term debt
    (44,000 )     (14,000 )     (14,000 )
Net cash used in financing activities
    (175,228 )     (141,400 )     (210,200 )
                         
Net increase (decrease) in cash and cash equivalents
    (11,695 )     (6,139 )     9,761  
                         
Cash and cash equivalents, beginning of period
    15,267       21,406       11,645  
                         
Cash and cash equivalents, end of period
  $ 3,572     $ 15,267     $ 21,406  
                         
Supplemental disclosure of cash flow information
                       
                         
Interest paid (net of amounts capitalized)
  $ 72,439     $ 72,067     $ 74,714  
Income tax paid
  $ 103,589     $ 56,814     $ 66,954  
                         
 
 
 
 
 
 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 
 
6

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)
Corporate Structure

Citrus Corp. (Citrus, the Company), a holding company formed in 1986, owns 100 percent of the membership interest in Florida Gas Transmission Company, LLC (Florida Gas), and 100 percent of the stock of Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI), collectively the Company.  At December 31, 2007, the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a wholly-owned subsidiary of El Paso Corporation (El Paso), and 50 percent by CrossCountry Citrus, LLC (CCC), a wholly-owned subsidiary of CrossCountry Energy, LLC (CrossCountry).  In November 2007, Southern Natural Gas Company (Southern), whose parent is El Paso, distributed EPCH to El Paso.  CrossCountry was a wholly-owned subsidiary of Enron Corp. (Enron) and certain of its subsidiary companies.  Effective November 17, 2004, CrossCountry became a wholly-owned subsidiary of CCE Holdings, LLC (CCE Holdings), which was a joint venture owned by subsidiaries of Southern Union Company (Southern Union) (50 percent), GE Commercial Finance Energy Financial Services (GE) (approximately 30 percent) and four minority interest owners (approximately 20 percent in the aggregate).

On December 1, 2006, a series of transactions were completed which resulted in Southern Union increasing its indirect ownership interest in Citrus from 25 percent to 50 percent.  On September 14, 2006, Energy Transfer Partners, L.P. (Energy Transfer), an unaffiliated company, entered into a definitive purchase agreement to acquire the 50 percent interest in CCE Holdings from GE and other investors.  At the same time, Energy Transfer and CCE Holdings entered into a definitive 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 interest in Transwestern Pipeline Company, LLC (TW) (Redemption Agreement).  Upon closing of the Redemption Agreement on December 1, 2006, Southern Union became the indirect owner of 100 percent of CCE Holdings, whose principal remaining asset was its 50 percent interest in Citrus, with the remaining 50 percent of Citrus continuing to be owned by EPCH.

Florida Gas, an interstate natural gas pipeline extending from South Texas to South Florida, is engaged in the interstate transmission of natural gas and is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).

On September 1, 2006, Florida Gas converted its legal entity type from a corporation to a limited liability company, pursuant to the Delaware Limited Liability Company Act.


(2)
Significant Accounting Policies

Basis of Presentation – The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

 
Regulatory AccountingFlorida Gas’ accounting policies generally conform to Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71).  Accordingly, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under GAAP for non-regulated entities.

 
Revenue Recognition – Revenues consist primarily of fees earned from gas transportation services.  Reservation revenues are based on contracted rates and capacity reserved by the customers and are recognized monthly.  For interruptible or volumetric based services, commodity revenues are recorded upon the delivery of natural gas to the agreed upon delivery point.  Revenues for all services are generally based on the thermal quantity of gas delivered or subscribed at a rate specified in the contract.

 
Because Florida Gas is subject to FERC regulations, revenues collected during the pendency of a rate proceeding may be required by the FERC to be refunded in the final order.  Florida Gas establishes reserves for such potential refunds, as appropriate.  There were no reserves for potential rate refund at December 31, 2007 and 2006, respectively.

 
Derivative Instruments – The Company follows FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (Statement No. 133) to account for derivative and hedging activities.  In accordance with this statement, all derivatives are recognized on the Consolidated Balance Sheets

 
7

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
at their fair value.  On the date the derivative contract is entered into, the Company designates the derivative as (i) a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of a forecasted transaction or the variability of cash flows to be received or paid in conjunction with a recognized asset or liability (a cash flow hedge); or (iii) an instrument that is held for trading or non-hedging purposes (a trading or non-hedging instrument).  For derivatives treated as a fair value hedge, the effective portion of changes in fair value is recorded as an adjustment to the hedged item.  The ineffective portion of a fair value hedge is recognized in earnings if the short cut method of assessing effectiveness is not used.  Upon termination of a fair value hedge of a debt instrument, the resulting gain or loss is amortized to earnings through the maturity date of the debt instrument.  For derivatives treated as a cash flow hedge, the effective portion of changes in fair value is recorded in Accumulated Other Comprehensive Loss until the related hedge items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current period earnings.  For derivatives treated as trading or non-hedging instruments, changes in fair value are reported in current-period earnings.  Fair value is determined based upon quoted market prices and mathematical models using current and historical data.  As of December 31, 2007, the Company does not have any hedges in place as it is only amortizing previously terminated hedges.

 
Property, Plant and Equipment  – Property, Plant and Equipment consists primarily of natural gas pipeline and related facilities and is recorded at its original cost.  Florida Gas capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and cost of funds, both interest and an equity return component (see third following paragraph).   Costs of replacements and renewals of units of property are capitalized.  The original cost of units of property retired are charged to accumulated depreciation, net of salvage and removal costs.  Florida Gas charges to maintenance expense the costs of repairs and renewal of items determined to be less than units of property.

The Company amortized that portion of its investment in Florida Gas property which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual composite rate of 1.6 percent based upon the estimated remaining useful life of the pipeline system.

Florida Gas has provided for depreciation of assets, on a straight-line basis, at an annual composite rate of 2.77 percent, 2.78 percent and 2.56 percent for the years ended December 31, 2007, 2006 and 2005, respectively.

 
The recognition of an allowance for funds used during construction (AFUDC) is a utility accounting practice with calculations under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant.  It represents the cost of capital invested in construction work-in-progress.  AFUDC has been segregated into two component parts – borrowed funds and equity funds.  The allowance for borrowed and equity funds used during construction, including related gross up, totaled $10.3 million, $3.4 million and $1.4 million for the years ended December 31, 2007, 2006 and 2005, respectively.  AFUDC borrowed is included in Interest Expense and AFUDC equity is included in Other Income in the accompanying statements of income.

 
Asset Retirement Obligations – The Company applies the provisions of FASB Statement No. 143, Accounting for Asset Retirement Obligations to record a liability for the estimated removal costs of assets where there is a legal obligation associated with removal.  Under this standard, the liability is recorded at its fair value, with a corresponding asset that is depreciated over the remaining useful life of the long-lived asset to which the liability relates.  An ongoing expense will also be recognized for changes in the value of the liability as a result of the passage of time.

 
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN No. 47) issued by the FASB in March 2005 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity.  Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation (ARO) when incurred, if the fair value of the liability can be reasonably estimated.  FIN No. 47 provides guidance for assessing whether sufficient information is available to record an estimate.  This interpretation was effective for the Company beginning on December 31, 2005.   Upon adoption of FIN No. 47, Florida Gas recorded an increase in plant in service and a liability for an ARO of $0.5 million.  This new asset and liability related to obligations associated with the removal and disposal of asbestos and asbestos containing materials on Florida Gas’ pipeline system.  The ARO asset at December 31, 2007 had a net book value of $0.5 million.

 
8

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below provides a reconciliation of the carrying amount of the ARO liability for the period indicated:

   
Year Ended December 31, 2007
   
Year Ended December 31, 2006
   
Year Ended December 31, 2005
 
   
(In thousands)
 
                   
Beginning balance
  $ 481     $ 493     $ -  
Incurred
    -       -       493  
Settled
    (37 )     (36 )     -  
Accretion  Expense
    27       24       -  
Ending balance
  $ 471     $ 481     $ 493  
                         

 
Asset Impairment – The Company applies the provisions of FASB No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, to account for impairments on long-lived assets.  Impairment losses are recognized for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying value.  The amount of impairment is measured by comparing the fair value of the asset to its carrying amount.

 
Exchange Gas – Gas imbalances occur as a result of differences in volumes of gas received and delivered by a pipeline system. These imbalances due to or from shippers and operators are valued at an appropriate index price.  Imbalances are settled in cash or made up in-kind subject to terms of Florida Gas’ tariff, and generally do not impact earnings.

 
Environmental Expenditures (Note 12) – Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future generation, are expensed.  Environmental expenditures relating to current or future revenues are expensed or capitalized as appropriate based on the nature of the cost incurred.  Liabilities are recorded when environmental assessments and/or clean ups are probable and the cost can be reasonably estimated. Remediation obligations are not discounted because the timing of future cash flow streams is not predictable.

 
Cash and Cash Equivalents – Cash equivalents consist of highly liquid investments with original maturities of three months or less.  The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments.

 
Materials and Supplies – Materials and supplies are valued at the lower of cost or market value.  Materials transferred out of warehouses are priced at average cost.   Materials and supplies include spare parts which are critical to the pipeline system operations and are valued at the lower of cost or market.
 
 
Fuel Tracker – A liability is recorded for net volumes of gas owed to customers collectively.  Whenever fuel is due from customers from prior under recovery based on contractual and specific tariff provisions an asset is recorded.  Gas owed to or from customers is valued at market.  Changes in the balances have no effect on the consolidated income of the Company.
 
 
 
Income Taxes (Note 4)  –  Income taxes are accounted for under the asset and liability method in accordance with the provisions of FASB Statement No. 109, Accounting for Income Taxes.  Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis.  Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date.  Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

 
9

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The determination of the Company’s provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws.  Significant judgment is required in assessing the timing and amounts of deductible and taxable items.  Reserves are established when, despite management’s belief that the Company’s tax return positions are fully supportable, management believes that certain positions may be successfully challenged.  When facts are circumstances change, these reserves are adjusted through the provision for income taxes.

 
Accounts ReceivableThe Company establishes an allowance for doubtful accounts on accounts receivable based on the expected ultimate recovery of these receivables.  The Company considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectibility.  Unrecovered accounts receivable charged against the allowance for doubtful accounts were $0.3 million, nil and nil in the years ended December 31, 2007, 2006 and 2005, respectively.

Pensions and Postretirement Benefits – Effective December 31, 2006, the Company adopted the recognition and disclosure provisions of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (Statement No. 158).  Statement No. 158 requires employers to recognize in their balance sheets the overfunded or underfunded status of defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.   Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated Other Comprehensive Loss in stockholders’ equity.  Effective for years beginning after December 15, 2008 (with early adoption permitted), Statement No. 158 also requires plan assets and benefit obligations to be measured as of the employers’ balance sheet date.  The Company has not yet adopted the measurement provisions of Statement No. 158.

Prior to adoption of the recognition provisions of Statement No. 158, the Company accounted for its defined benefit postretirement plans under FASB Statement No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement No. 106).”  Statement No. 106 required that the liability recorded should represent the actuarial present value of all future benefits attributable to an employee’s service rendered to date.  Under Statement No. 106, changes in the funded status were not immediately recognized; rather they were deferred and recognized ratably over future periods.  Upon adoption of the recognition provisions of Statement No. 158, the Company recognized the amounts of these prior changes in the funded status of its postretirement benefit plans.  The Company's plan is in an overfunded position as of December 31, 2007.  As the plan assets are derived through rates charged to customers, under Statement No. 71, to the extent the Company has collected amounts in excess of what is required to fund the plan, the Company has an obligation to refund the excess amounts to customers through rates.  As such, the Company recorded the previously unrecognized changes in the funded status (i.e., actuarial gains) as a regulatory liability and not as an adjustment to Accumulated Other Comprehensive Loss.

 
Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
 
New Accounting Principles   

Accounting Principles Not Yet Adopted.

FIN 48,” Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109” (FIN 48 or the Interpretation): Issued by the FASB in June 2006, this Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes.  FIN 48 prescribes a recognition and measurement threshold attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition.  FIN 48 is effective for fiscal years beginning after December 15, 2006, for public enterprises and December 15, 2007, for nonpublic enterprises,

 
10

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

such as Citrus.  The Company has determined the implementation of this Statement will not have a material impact on its consolidated financial statements.
 
FSP No. FIN 48-1, “Definition of ‘Settlement’ in FASB Interpretation No. 48” (FIN 48-1):  Issued by the FASB in May 2007, FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.
 
FASB Statement No. 157, “Fair Value Measurements” (FASB Statement No. 157 or the Statement):  Issued by the FASB in September 2006, this Statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. Where applicable, this Statement simplifies and codifies related guidance within GAAP.  Except for certain non financial assets and liabilities more fully discussed in FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP No. FAS 157-2) which was issued by the FASB in February 2008, this Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.  For those non financial assets and liabilities deferred pursuant to FSP No. FAS 157-2, this Statement is effective for financial statements for fiscal years beginning after November 15, 2008.  The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”:  Issued by the FASB in February 2007, this Statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value.  Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings.  The Statement does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value.  The Statement is effective for fiscal years beginning after November 15, 2007.  At January 1, 2008, the Company did not elect the fair value option under the Statement and, therefore, there was no impact to the Company’s consolidated financials statements.

FASB Statement No. 141 (revised), “Business Combinations”.  Issued by the FASB in December 2007, this Statement changes the accounting for business combinations including the measurement of acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for preacquisition gain and loss contingencies, the recognition of capitalized in-process research and development costs, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.

FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”.  Issued by the FASB in December 2007, this Statement changes the accounting for noncontrolling (minority) interests in consolidated financial statements including the requirements to classify noncontrolling interests as a component of consolidated stockholders’ equity, and the elimination of minority interest accounting in results of operations with earnings attributable to noncontrolling interests reported as part of consolidated earnings. Additionally, the Statement revises the accounting for both increases and decreases in a parent’s controlling ownership interest. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.  The Company is currently evaluating the impact of this statement on its consolidated financial statements.

 



 
11

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
(3)
Long Term Debt

The table below sets forth the long-term debt of the Company as of the dates indicated:
 
   
Years
   
December 31, 2007
   
December 31, 2006
 
   
Due
   
Book Value
   
Fair Value
   
Book Value
   
Fair Value
 
         
(In thousands)
 
Citrus
                             
8.490% Senior Notes
 
2007-2009
    $ 60,000     $ 63,572     $ 90,000     $ 95,011  
Revolving Credit Agreement Citrus
 
2012
      62,400       62,400       -       -  
FGT
                                     
9.750% Senior B Notes
 
1999-2008
      6,500       6,736       13,000       13,663  
10.110% Senior C Notes
 
2009-2013
      70,000       82,282       70,000       82,773  
9.190% Senior Notes
 
2005-2024
      127,500       158,843       135,000       167,004  
7.625% Senior Notes
 
2010
      325,000       353,352       325,000       348,137  
7.000% Senior Notes
 
2012
      250,000       277,281       250,000       271,893  
Revolving Credit Agreement FGT
 
2007
      -       -       40,000       40,000  
Revolving Credit Agreement FGT
 
2012
      54,000       54,000       -       -  
   Total debt outstanding
        $ 955,400     $ 1,058,466     $ 923,000     $ 1,018,481  
Current portion of long-term debt
          (44,000 )             (84,000 )        
Unamortized Debt Discount and Swap Loss
          (1,590 )             (2,118 )        
   Total long-term debt
        $ 909,810             $ 836,882          
                                       

Annual maturities of long-term debt outstanding as of the date indicated were as follows:

   
December 31, 2007
 
Year
 
(In thousands)
 
       
2008
  $ 44,000  
2009
    51,500  
2010
    346,500  
2011
    21,500  
2012
    387,900  
Thereafter
    104,000  
    $ 955,400  
         

On August 13, 2004 Florida Gas entered into a Revolving Credit Agreement (“2004 Revolver”) with an initial commitment level of $50 million, subsequently increased by $125 million to $175 million.   Since that time, Florida Gas has routinely utilized the 2004 Revolver to fund working capital needs.  On December 31, 2006, the amount drawn under the 2004 Revolver was $40 million, with a weighted average interest rate of 6.08 percent (based on LIBOR plus 0.70 percent).  Additionally, a commitment fee of 0.15 percent is payable quarterly on the unused portion of the commitment balance.  The 2004 Florida Gas Revolver terminated in August 2007 and was replaced by a new revolving credit agreement at Florida Gas in the amount of $300 million (“2007 Florida Gas Revolver”), which will mature on August 16, 2012.  The 2007 Florida Gas Revolver

 
12

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

requires interest based on LIBOR plus a margin tied to the debt rating of the Company’s senior unsecured debt, currently 0.28 percent, and has a facility fee of 0.07 percent.  As of December 31, 2007, the amount drawn under the 2007 Florida Gas Revolver was $54 million with a weighted average interest rate of 5.30 percent (based on LIBOR plus 0.28 percent).

Also on August 16, 2007, Citrus entered into a revolving credit facility in the amount of $200 million (“2007 Citrus Revolver”), which will mature on August 16, 2012.  This facility will enable Citrus to meet its funding needs and repay its debt maturities.  As of December 31, 2007, the amount drawn under the 2007 Citrus Revolver was $62.4 million with a weighted average interest rate of 5.22 percent (based on LIBOR plus 0.28 percent), and has a facility fee of 0.07 percent.  Issuance costs for the 2007 Florida Gas Revolver and 2007 Citrus Revolver were $0.3 million and $0.2 million, respectively at December 31, 2007.

The book value of the 2004 Revolver, 2007 Florida Gas Revolver, and 2007 Citrus Revolver approximates their market value given the variable rate of interest.  Estimated fair value amounts of other long-term debt were obtained from independent parties, and are based upon market quotations of similar debt at interest rates currently available.  Judgment is required in interpreting market data to develop the estimates of fair value.  Accordingly, the estimates determined as of December 31, 2007 and 2006 are not necessarily indicative of the amounts the Company could have realized in current market exchanges.

The agreements relating to Florida Gas’ debt include, among other things, restrictions as to the payment of dividends and maintaining certain restrictive financial covenants, including a required ratio of consolidated funded debt to total capitalization.

Under the terms of its debt agreements, Florida Gas may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Citrus’ and Florida Gas’ consolidated debt does not exceed specific debt to total capitalization ratios, as defined in certain debt instruments.  Incurrence of additional indebtedness to refinance the current maturities would not result in a debt to capitalization ratio exceeding these limits.

All of the debt obligations of Citrus and Florida Gas have events of default that contain commonly used cross-default provisions.  An event of default by either Citrus or Florida Gas on any of their borrowed money obligations, in excess of certain thresholds which is not cured within defined grace periods, would cause the other debt obligations of Citrus and Florida Gas to be accelerated.


(4)
Income Taxes

The principal components of the Company's net deferred income tax liabilities as of the dates indicated were as follows:
 
   
December 31, 2007
   
December 31, 2006
 
   
(In thousands)
 
Deferred income tax asset
           
Regulatory and other reserves
  $ 5,554     $ 8,595  
      5,554       8,595  
                 
Deferred income tax liabilities
               
Depreciation and amortization
    759,576       742,566  
Deferred charges and other assets
    -       27,981  
Regulatory costs
    4,717       9,298  
Other
    4,625       6,154  
      768,918       785,999  
Net deferred income tax liabilities
  $ 763,364     $ 777,404  
                 

 
13

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Total income tax expense for the periods indicated was as follows:
 
   
Year Ended December 31, 2007
   
Year Ended December 31, 2006
   
Year Ended December 31, 2005
 
   
(In thousands)
 
Current Tax Provision
                 
Federal
  $ 99,083     $ 52,135     $ 53,526  
State
    5,418       5,196       8,820  
      104,501       57,331       62,346  
                         
Deferred Tax Provision
                       
Federal
    (14,531 )     15,863       11,079  
State
    2,254       2,766       1,661  
      (12,277 )     18,629       12,740  
Total income tax expense
  $ 92,224     $ 75,960     $ 75,086  
                         

The differences between taxes computed at the U.S. federal statutory rate of 35 percent and the Company’s effective tax rate for the periods indicated are as follows:
 
   
Year Ended
December 31, 2007
 
Year Ended
December 31, 2006
 
Year Ended
December 31, 2005
   
(In thousands)
                   
Statutory federal income tax provision
  $ 87,261     $ 70,712     $ 69,661  
State income taxes, net of federal benefit
    4,986       5,176       6,813  
Other
    (23 )     72       (1,388 )
Income tax expense
  $ 92,224     $ 75,960     $ 75,086  
                         
Effective Tax Rate
    37.0 %     37.6 %     37.7 %
                         
 
The Company files a consolidated federal income tax return separate from that of its stockholders.


(5)
Employee Benefit Plans

The employees of the Company were covered under Enron’s employee benefit plans until November 2004.

Enron maintained a pension plan that was a noncontributory defined benefit plan, the Enron Corp. Cash Balance Plan (the Cash Balance Plan), covering certain Enron employees in the United States and certain employees in foreign countries.  The basic benefit accrual was 5 percent of eligible annual base pay.  In 2003 the Company recognized its portion of the expected Cash Balance Plan settlement by recording a $9.6 million current liability, which was cash settled in 2005 (Note 7), and a charge to operating expense.  In 2004, with the settlement of the rate case (Note 8), Florida Gas recognized a regulatory asset for its portion, $9.3 million, with a reduction to operating expense.  Per the rate case settlement Florida Gas will amortize, over five years retroactive to April 1, 2004, its allocated share of costs to fully fund and terminate the Cash Balance Plan.  Amortization recorded was $1.9 million, $1.8 million and $1.9 million for the years ended December 31, 2007,

 
14

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2006 and 2005, respectively.  At December 31, 2007 and 2006 the remaining regulatory asset balance was $2.3 million and $4.2 million, respectively (Note 10).

Effective November 1, 2004 all employees of the Company were transferred to an affiliated entity, CrossCountry Energy Services, LLC (CCES) and during November 2004, employee insurance coverage migrated (without lapse) from Enron plans to new CCES welfare and benefit plans.  Effective March 1, 2005 essentially all such employees were transferred to Florida Gas and became eligible at that time to participate in employee welfare and benefit plans adopted by Florida Gas.

Effective March 1, 2005 Florida Gas adopted the Florida Gas Transmission Company 401(k) Savings Plan (the Plan).  All employees of Florida Gas are eligible to participate and, within one Plan, may contribute up to 50 percent of pre-tax compensation, subject to IRS limitations.  This Plan allows additional “catch-up” contributions by participants over age 50, and allows Florida Gas to make discretionary profit sharing contributions for the benefit of all participants.  Florida Gas matched 50 percent of participant contributions under this Plan up to a maximum of four percent of eligible compensation through December 31, 2007.  The matching was increased effective January 1, 2008 to 100 percent of the first two percent and 50 percent of the next three percent of the participant’s compensation paid into the Plan.  Participants vest in such matching and any profit sharing contributions at the rate of 20 percent per year, except that participants with five years of service at the date of adoption of the Plan were immediately vested.  Administrative costs of the Plan and certain asset management fees are paid from Plan assets.  Florida Gas’ expensed its contribution of $0.3 million, $0.4 million, and $0.3 million for the years ended December 31, 2007, 2006, and 2005 respectively.
 
Other Post – Employment Benefits

Prior to December 1, 2004  Florida Gas was a participating employer in the Enron Gas Pipelines Employee Benefit Trust (the Trust), a voluntary employees’ beneficiary association (VEBA) under Section 501(c)(9) of the Internal Revenue Code of 1986, as amended (Tax Code), which provided certain post-retirement medical, life insurance and dental benefits to employees of Florida Gas and certain other Enron affiliates pursuant to the Enron Corp. Medical Plan and the Enron Corp. Medical Plan for Inactive Participants.  Enron has made the determination that it will partition the Trust and distribute the assets and liabilities of the Trust among the participating employers of the Trust on a pro rata basis according to the contributions and liabilities associated with each participating employer.  The Trust Committee has final approval on allocation methodology for the Trust assets.  It is estimated that Florida Gas will receive approximately $6.8 million from the Trust, including an estimated investment return as early as first quarter 2008.  Enron filed a motion in the Enron bankruptcy proceedings on July 22, 2003 which was stayed and then refiled and amended on June 17, 2005 and again refiled and amended on December 1, 2006 which provides that each participating employer expressly assumes liability for its allocable portion of retiree benefits and releases Enron from any liability with respect to the Trust in order to receive the assets of the Trust.  On June 7, 2005 a class action suit captioned Lou Geiler et al v. Robert W. Jones, et al., was filed in United States District Court for the District of Nebraska by, among others, former employees of Northern Natural Gas Company (Northern) on behalf of the participants in the Northern Medical and Dental Plan for Retirees and Surviving Spouses against former and present members of the Trust Committee, the Trustee and the participating employers of the Trust, including Florida Gas, claiming the Trust Committee and the Trustee have violated their fiduciary duties under ERISA and seeking a declaration from the Court binding on all participating employers of an accounting and distribution of the assets held in the Trust and a complete and accurate listing of the individuals properly allocated to Northern from the Enron Plan.  On the same date essentially the same group filed a motion in the Enron bankruptcy proceedings to strike the Enron motion from further consideration. On February 6, 2006 the Nebraska action was dismissed.  The plaintiffs filed an appeal of the dismissal on March 8, 2006. An agreement was reached on the conditions of the partition of the Trust among the VEBA participating employers, Enron and the Trust Committee and approved by the Enron bankruptcy court on December 21, 2006. As a result, the Nebraska action appeal was dismissed on January 25, 2007.

During the period December 1, 2004 through February 28, 2005, following Florida Gas’ November 17, 2004 acquisition by CCE Holdings, coverage to eligible employees and their eligible dependents was provided by CrossCountry Energy Retiree Health Plan, which provides only medical benefits.  Florida Gas continues to provide certain retiree benefits through employer contributions to a qualified contribution plan, with the amounts generally varying based on age and years of service.

 
15

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Effective March 1, 2005 such benefits are provided under an identical plan sponsored by Florida Gas as a single employer post-retirement benefit plan.

With regard to its sponsored plan, Florida Gas has entered into a VEBA trust (the “VEBA Trust”) agreement with JPMorgan Chase Bank Trust Company as trustee.  The VEBA Trust has established or adopted plans to provide certain post-retirement life, health, accident and other benefits.  The VEBA Trust is a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to employees of the Company.  Florida Gas contributed $0.5 million and $1.2 million to the VEBA Trust for the years ended December 31, 2007 and 2006, respectively.   Upon settlement of the Trust, the anticipated distribution of assets to Florida Gas from the Trust will be contributed to the VEBA Trust.

Prior to 2005, Florida Gas’ general policy was to fund accrued post-retirement health care costs as allocated by Enron.  As a result of Florida Gas’ change in 2005 from a participant in a multi employer plan to a single employer plan, Florida Gas now accounts for its OPEB liability and expense on an actuarial basis, recording its health and life benefit costs over the active service period of employees to the date of full eligibility for the benefits.  At December 31, 2005 Florida Gas recognized its OPEB liability by recording a deferred credit of $2.2 million and a corresponding regulatory asset of $2.2 million.

The Company has postretirement health care plans which cover substantially all employees.  The health care plans generally provide for cost sharing in the form of retiree contributions, deductibles, and coinsurance between the Company and its retirees, and a fixed cost cap on the amount the Company pays annually to provide future retiree health care coverage under certain of these plans.

The following table summarizes the impact of adopting Statement No. 158 on the Company’s postretirement plan reported in the Consolidated Balance Sheet at December 31, 2006:
 
   
Pre-FASB 158
   
FASB 158 adoption adjustment
   
Post-FASB 158
 
   
(in thousands)
 
                   
Prepaid postretirement benefit cost (non-current) (Note 10)
  $ (721   $ 3,423     $ 2,702  
Regulatory asset      1,951        (1,951     -     
Regulatory liability
    -          (1,472 )     (1,472 )
                         
 
The adoption of Statement No. 158 had no effect on the Consolidated Statements of Income for the years ended December 31, 2007 and December 31, 2006, or for any prior period presented, has not negatively impacted any financial covenants, and is not expected to affect the Company’s operating results in future periods.

 





 
16

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.   The following table represents a reconciliation of Florida Gas’ OPEB plan for the periods indicated:
 
   
Year Ended December 31, 2007
   
Year Ended December 31, 2006
 
   
(In thousands)
 
Change in Benefit Obligation
           
Benefit obligation at the beginning of period
  $ 5,795     $ 6,665  
Service cost
    37       46  
Interest cost
    296       312  
Actuarial gain
    (320 )     (691 )
Retiree premiums
    415       427  
Benefits paid
    (1,029 )     (964 )
CMS Medicare Part D Subsidies Received
    108       -  
Benefit obligation at end of year
    5,302       5,795  
                 
Change in Plan Assets
               
Fair value of plan assets at the beginning of period
    8,497       7,840  
Return on plan assets
    336       (37 )
Employer contributions
    380       1,231  
Retiree premiums
    415       427  
Benefits paid
    (1,029 )     (964 )
Fair value of plan assets at end of year   (1)
    8,599       8,497  
                 
Funded Status
               
Funded status at the end of the year
  $ 3,297     $ 2,702  
                 
Amount recognized in the Consolidated Balance Sheets
               
Other assets - other (Note 10)
  $ 3,297     $ 2,702  
Regulatory liability (Note 11)
    (3,390 )     (1,472 )
Net asset (liability) recognized
  $ (93 )   $ 1,230  
                 

 
 (1)  Plan assets at December 31, 2007 and 2006 include the amounts of assets expected to be received from the Enron Trust of $6.8 million and $6.5 million, respectively, including a 5 percent annual investment return based on estimate.














 
17

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted-average assumptions used to determine Florida Gas’ benefit obligations for the periods indicated were as follows:
 
   
Year Ended
December 31, 2007
 
Year Ended
December 31, 2006
 
Year Ended
December 31, 2005
                   
Discount rate
    6.09 %     5.68 %     5.50 %
Health care cost trend rates
    10.00 %     11.00 %     12.00 %
   
graded to 5.20% by 2017
   
graded to 4.85% by 2013
   
graded to 4.65% by 2012
 
                         
 
Florida Gas’ net periodic (benefit) costs for the periods indicated consisted of the following:
 
   
Year Ended December 31, 2007
   
Year Ended December 31, 2006
   
Year Ended December 31, 2005
 
   
(In thousands)
 
                   
Service cost
  $ 37     $ 46     $ 71  
Interest cost
    296       312       490  
Expected return on plan assets
    (414 )     (402 )     (352 )
Recognized actuarial gain
    (230 )     (223 )     (174 )
Net periodic (benefit) cost
  $ (311 )   $ (267 )   $ 35  
                         
 
The weighted-average assumptions used to determine Florida Gas’ net periodic benefit costs for the periods indicated were as follows:
 
   
Year Ended
December 31, 2007
 
Year Ended
December 31, 2006
 
Year Ended
December 31, 2005
                   
Discount rate
    5.68 %     5.50 %     5.75 %
Rate of compensation increase
    N/A       N/A       N/A  
Expected long-term return on plan assets
    5.00 %     5.00 %     5.00 %
Health care cost trend rates
    11.00 %     12.00 %     12.00 %
   
graded to 4.85% by 2013
   
graded to 4.65% by 2012
   
graded to 4.75% by 2012
 
                         
 
Florida Gas employs a building block approach in determining the expected long-term rate on return on plan assets.  Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run.  Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined.  The long-term portfolio return is established via a building block approach with proper consideration of diversification and rebalancing.  Peer data and historical returns are reviewed to check for reasonability and appropriateness.
 
 

 
 
18

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans.  A one-percentage-point change in assumed health care cost trend rates would have the following effects:

   
One Percentage Point Increase
   
One Percentage Point Decrease
 
   
(In thousands)
 
Effect on total service and interest cost components
  $ 15     $ (13 )
Effect on postretirement benefit obligation
  $ 240     $ (215 )
                 
 
Discount Rate Selection - The discount rate for each measurement date has been determined consistent with the discount rate selection guidance in Statement No. 106 (as amended by Statement No. 158) using the Citigroup Pension Discount Curve as published on the Society of Actuaries website as the hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due.

Plan Asset Information - The plan assets shall be invested in accordance with sound investment practices that emphasize long-term investment fundamentals.  An investment objective of income and growth for the plan has been adopted.  This investment objective: (i) is a risk-averse balanced approach that emphasizes a stable and substantial source of current income and some capital appreciation over the long-term; (ii) implies a willingness to risk some declines in value over the short-term, so long as the plan is positioned to generate current income and exhibits some capital appreciation; (iii) is expected to earn long-term returns sufficient to keep pace with the rate of inflation over most market cycles (net of spending and investment and administrative expenses), but may lag inflation in some environments; (iv) diversifies the plan in order to provide opportunities for long-term growth and to reduce the potential for large losses that could occur from holding concentrated positions; and (iv) recognizes that investment results over the long-term may lag those of a typical balanced portfolio since a typical balanced portfolio tends to be more aggressively invested.  Nevertheless, this plan is expected to earn a long-term return that compares favorably to appropriate market indices.

It is expected that these objectives can be obtained through a well-diversified portfolio structure in a manner consistent with the investment policy.

Florida Gas’ OPEB weighted-average asset allocation by asset category for the $1.8 million and $2.0 million of assets actually in the VEBA Trust at December 31, 2007 and 2006, respectively, were approximately as follows:

   
December 31, 2007
 
December 31, 2006
             
Equity securities
    31 %     0 %
Debt securities
    69 %     0 %
Cash and cash equivalents
    0 %     100 %
Total
    100 %     100 %
                 
 
Based on the postretirement plan objectives, asset allocations should be maintained as follows: equity of 25 percent to 35 percent, fixed income of 65 percent to 75 percent, and cash and cash equivalents of 0 percent to 10 percent.

 
19

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The above referenced asset allocations for postretirement benefits are based upon guidelines established by Florida Gas’ Investment Policy and is monitored by the Investment Committee of the board of directors in conjunction with an external investment advisor.

Florida Gas expects to contribute approximately $1.1 million to its post-retirement benefit plan in 2008 and approximately $1.1 million annually thereafter until modified by rate case proceedings.

The estimated employer portion of benefit payments, which reflect expected future service, as appropriate, that are projected to be paid are as follows:

Years
 
Expected Benefits Before Effect of Medicare Part D
   
Payments Medicare Part D
   
Net
 
   
(In thousands)
 
                   
2008
  $ 551     $ 96     $ 455  
2009
    594       99       495  
2010
    614       101       513  
2011
    625       101       524  
2012
    624       100       524  
2013 - 2017
    2,935       454       2,481  
 
The Medicare Prescription Drug Act was signed into law December 8, 2003.  The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy, which is not taxable, to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.


(6)
Major Customers and Concentration of Credit Risk
 
Revenues from individual third party and affiliate customers exceeding 10 percent of total revenues for the periods indicated were approximately as listed below, and in total represented 56%, 58% and 54% of total revenue, respectively.
 
   
Year Ended December 31, 2007
   
Year Ended December 31, 2006
   
Year Ended December 31, 2005
 
   
(In thousands)
 
                   
Florida Power & Light Company
  $ 195,622     $ 200,592     $ 181,486  
TECO Energy, Inc.
    80,815       80,192       76,059  
                         










 
20

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company had the following transportation receivables from these customers at the dates indicated:
 
   
December 31, 2007
   
December 31, 2006
 
   
(In thousands)
 
             
Florida Power & Light Company
  $ 15,130     $ 15,065  
TECO Energy, Inc.
    6,201       6,161  
                 
 
The Company has a concentration of customers in the electric and gas utility industries.  These concentrations of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions.  Credit losses incurred on receivables in these industries compare favorably to losses experienced in the Company's receivable portfolio as a whole.  The Company also has a concentration of customers located in the southeastern United States, primarily within the state of Florida.  Receivables are generally not collateralized. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments, deposits, or other forms of security to the Company.  Florida Gas sought additional assurances from customers due to credit concerns, and had customer deposits totaling $1.6 million and $1.6 million, and prepayments of $43,000 and $0.2 million at December 31, 2007 and 2006, respectively.  The Company's management believes that the portfolio of Florida Gas’ receivables, which includes regulated electric utilities, regulated local distribution companies, and municipalities, is of minimal credit risk.


(7)
Related Party Transactions

In December 2001 Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy court.  At December 31, 2004 Florida Gas and Trading had aggregate outstanding claims with the Bankruptcy Court against Enron and affiliated bankrupt companies of $220.6 million.  Of these claims, Florida Gas and Trading filed claims totaling $68.1 and $152.5 million, respectively.  Florida Gas and Trading claims pertaining to contracts rejected by ENA were $21.4 and $152.3 million, respectively.  In March 2005, ENA filed objections to Trading’s claim.  In September 2006 the judge issued an order rejecting certain of Trading's arguments and ruling that a contract under which ENA had an in the money position against Trading may be offset against a related contract under which Trading had an in the money position against ENA. The result of the order was a reduction in the allowable amount of Trading's initial claim to $22.7 million.  The parties reached a settlement which was approved by the Bankruptcy Court in March 2007 (See Note 14).

Florida Gas’ claims against ENA on transportation contracts were reduced by approximately $21.2 million when a third party took assignment of ENA’s transportation contracts.  In 2004 Florida Gas settled the amount of all of its claims against Enron and a subsidiary debtor.  Total allowed claims (including debtor set-offs) were $13.3 million.  After approval of the settlement by the Bankruptcy Court, in June 2005 Florida Gas sold its claims, received $3.4 million and recorded Other Income of $0.9 million.

Florida Gas had a construction reimbursement agreement with ENA under which amounts owed to Florida Gas were delinquent.  These obligations totaled approximately $7.4 million and were included in Florida Gas’ filed bankruptcy claims.  These receivables were fully reserved by Florida Gas prior to 2003.   Under the Settlement filed by Florida Gas on August 13, 2004 and approved by the FERC on December 21, 2004 Florida Gas will recover the under-recovery on this obligation by rolling in the costs of the facilities constructed, less the recovery from ENA, in its tariff rates (see Note 8).   As part of the June 2005 sale of its claims, Florida Gas received $2.1 million for this part of the claim.

 
The Company provided natural gas sales and transportation services to El Paso affiliates at rates equal to rates charged to non-affiliated customers in the same class of service.  Revenues related to these transportation services were approximately nil, $1.0 million and $4.5 million in the years ended December 31, 2007, 2006 and 2005, respectively.  The Company’s gas sales were immaterial in the years ended December 31, 2007, 2006 and 2005.  Florida Gas also purchased transportation services from Southern in connection with its Phase III

 
21

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
Expansion completed in early 1995.  Florida Gas contracted for firm capacity of 100,000 Mcf/day on Southern’s system for a primary term of 10 years, to be continued for successive terms of one year each year thereafter unless cancelled by either party, by giving 180 days notice to the other party prior to the end of the primary term or any yearly extension thereof.  The amount expensed for these services totaled $6.8 million, $6.6 million and $6.3 million in the years ended December 31, 2007, 2006 and 2005, respectively.

Effective April 1, 2004 services previously provided by bankrupt Enron affiliates to the Company pursuant to the allocation methodology ordered by the Bankruptcy Court were covered and charged under the terms of the Transition Services Agreement / Transition Supplemental Services Agreement (TSA/TSSA).  This agreement between Enron and CrossCountry was administered by CrossCountry Energy Services, LLC (CCES), a subsidiary of CCE Holdings, which allocated to the Company its share of total costs.  Effective November 17, 2004 an Amended TSA/TSSA agreement was put into effect. This agreement expired on July 31, 2005. The total costs are not materially different from those previously charged.  The amount expensed for the seven month-period ended July 31, 2005 was approximately $1.5 million.

On November 5, 2004, CCE Holdings entered into an Administrative Services Agreement (ASA) with SU Pipeline Management LP (Manager), a Delaware limited partnership and a wholly-owned subsidiary of Southern Union.  Pursuant to the ASA, Manager was responsible for the operations and administrative functions of the enterprise, CCE Holdings and Manager shared certain operations of Manager and its affiliates, and CCE Holdings was obligated to bear its share of costs of Manager and its affiliates.  Costs are allocated by Manager and its affiliates to the operating subsidiaries and investees, based on relevant criteria, including time spent, miles of pipe, total assets, labor allocations, or other appropriate methods.   Manager provided services to CCE Holdings from November 17, 2004 to December 1, 2006.  Following the closing of the Redemption Agreement on December 1, 2006, services continue to be provided by Southern Union affiliates to Florida Gas, and costs allocated using allocation methods consistent with past practices.

The Company has related party activities for operational and administrative services performed by CCES, Panhandle Eastern Pipe Line Company, LP (PEPL), an indirect wholly-owned subsidiary of Southern Union, and other related parties, on behalf of the Company, and corporate service charges from Southern Union.  Expenses are generally charged based on either actual usage of services or allocated based on estimates of time spent working for the benefit of the various affiliated companies.  Amounts expensed by the Company were $21.5 million, $20.6 million and $20.2 million in the years ended December 31, 2007, 2006 and 2005, respectively, and included corporate service charges from Southern Union of $5.9 million, $4.0 million and $1.6 million in the years ended December 31, 2007, 2006 and 2005, respectively.  Additionally, the Company receives allocated costs of certain shared business applications from PEPL and Southern Union.  At December 31, 2007 and 2006, the Company had current accounts payable to affiliated companies of $8.4 million and $2.8 million, respectively, relating to these services.

In 2005, the Company paid a subsidiary of CCE Holdings $9.6 million to settle the Cash Balance Plan obligation, which CCE Holdings effectively paid in conjunction with the 2004 acquisition of the Company.

The Company paid cash dividends to its shareholders of $207.1 million, $125.4 million and $121.2 million in the years ended December 31, 2007, 2006, and 2005, respectively.  The Company also declared a dividend in December 2007 of $42.6 million, payable in January, 2008 and which was paid on January 18, 2008.


(8)
Regulatory Matters

On August 13, 2004 Florida Gas filed a Stipulation and Agreement of Settlement ("Rate Case Settlement") in its Section 4 rate proceeding in Docket No. RP04-12, which established settlement rates and resolved all issues.  The settlement rates were approved and became effective on April 1, 2004 for all Florida Gas services and again on April 1, 2005 for Rate Schedule FTS-2 when the basis for rates on Florida Gas incremental facilities changed from a levelized cost of service to a traditional cost of service.

On December 15, 2003 the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas” (“HCA”).  This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002.  The rule

 
22

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

requires operators to identify HCAs along their pipelines by December 2004 and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing, or direct assessment, by June 2004.  Operators were required to rank the risk of their pipeline segments containing HCAs and to complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007.  Assessments will generally be conducted on the higher risk segments first with the balance being completed by December 2012.  As of December 31, 2007, Florida Gas completed 62 percent of the risk assessments.  In addition, some system modifications will be necessary to accommodate the in-line inspections.  All systems operated by the Company will be compliant with the rule; however, while identification and location of all the HCAs has been completed, it is impossible to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections.  The required modifications and inspections are currently estimated to be in the range of approximately $21 million to $28 million per year through 2012.  Pursuant to the August 13, 2004 Rate Case Settlement, Florida Gas has the right to make limited sections 4 filings to recover, via a surcharge during the settlement’s term, depreciation and return on up to approximately $40 million of such costs, as well as security, and Florida Turnpike relocation and modification costs. A reservation surcharge of $0.02 per MMBtu has been in effect since April 1, 2007, subject to refund and further review by the FERC.

In June 2005 FERC issued an order Docket No. AI05-1-000 that expands on the accounting guidance in the proposed accounting release issued in November 2004 on mandated pipeline integrity programs.  The order interprets the FERC’s existing accounting rules and standardizes classifications of expenditures made by pipelines in connection with an integrity management program.  The order is effective for integrity management expenditures incurred on or after January 1, 2006.  Florida Gas capitalizes all pipeline assessment costs pursuant to its August 13, 2004 Rate Case Settlement.  The Rate Case Settlement contained no reference to the FERC Docket No. AI05-1-000 regarding pipeline assessment costs and provided that the final FERC order approving the Rate Case Settlement constituted final approval of all necessary authorizations to effectuate its provisions.  The Rate Case Settlement provisions became effective on March 1, 2005 and new tariff sheets to implement these provisions were filed on March 15, 2005.  FERC issued an order accepting the tariff sheets on May 20, 2005.    In the years ended December 31, 2007 and 2006, Florida Gas completed and capitalized $9.5 million and $6.7 million, respectively on pipeline assessment projects, as part of the integrity programs.

On October 5, 2005 Florida Gas filed an application with FERC for the Company’s proposed Phase VII expansion project.  The project will expand Florida Gas’ existing pipeline infrastructure in Florida and provide the growing Florida energy market access to additional natural gas supply from the Southern LNG Elba Island liquefied natural gas import terminal near Savannah, Georgia.  The Phase VII project calls for Florida Gas to build approximately 17 miles of 36-inch diameter pipeline looping in several segments along an existing right of way and install 9,800 horsepower of compression in a first phase with the possibility of a future second phase.  The expansion as currently planned will provide about 100 million cubic feet per day (MMcf/d) of additional capacity to transport natural gas from a connection with Southern Natural Gas Company’s Cypress Pipeline project in Clay County, Florida.  The FERC issued an order approving the project on June 15, 2006 and construction commenced on November 6, 2006.  The first phase was partially placed in service in May 2007 while certain modifications at compressor station 26 are expected to be in service by the end of March, 2008.  The updated estimated cost of the expansion is approximately $62 million, including AFUDC.  Approximately $12.6 million and $39.3 million is recorded in the line item Construction work in progress at December 31, 2007 and December 31, 2006, respectively.

On October 20, 2005, Florida Gas filed an application with FERC for the Company’s State Road 91 Relocation Project.  The proposed project will consist of the abandonment of approximately 11.15 miles of 18-inch diameter pipeline and 10.75 miles of 24-inch diameter pipeline in Broward, County Florida.  The replacement pipeline will consist of approximately 11.15 miles of 36-inch diameter pipeline.  The abandonment and replacement is being performed to accommodate the widening of State Road 91 by the Florida Department of Transportation/Florida Turnpike Enterprise (FDOT/FTE).  The estimated cost of the pipeline relocation project is estimated at $110 million, including AFUDC, and Florida Gas is seeking recovery of the construction costs from the FDOT/FTE.  The FERC issued an order approving the project on May 3, 2006.  Florida Gas notified the FERC that construction commenced on April 25, 2007.

Florida Gas plans to seek FERC approval to construct an expansion to increase its natural gas capacity into Florida by approximately 800 MMcf/d (Phase VIII Expansion).  The Phase VIII Expansion includes

 
23

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

construction of approximately 500 miles of additional large diameter pipeline and the installation of approximately 170,000 horsepower of additional compression.  Pending FERC approval, which is expected in 2009, Florida Gas anticipates an in-service date of 2011, at an approximate cost of $2 billion.  Florida Gas has signed a 25-year agreement with Florida Power and Light Company, (FPL), a wholly-owned subsidiary of FPL Group, Inc., for 400 MMcf/d of capacity.


(9)
Property, Plant and Equipment

The principal components of the Company's property, plant and equipment at the dates indicated were as follows:
 
   
December 31, 2007
   
December 31, 2006
 
   
(In thousands)
 
             
Transmission plant
  $ 2,970,560     $ 2,859,920  
General plant
    28,540       24,970  
Intangibles
    31,196       25,726  
Construction work-in-progress
    133,824       85,746  
Acquisition adjustment
    1,252,466       1,252,466  
      4,416,586       4,248,828  
Less: Accumulated depreciation and amortization
    (1,401,638 )     (1,304,133 )
Property, Plant and Equipment, net
  $ 3,014,948     $ 2,944,695  
                 

(10)
Other Assets

The principal components of the Company's regulatory assets at the dates indicated were as follows:

   
December 31, 2007
 
December 31, 2006
 
   
(In thousands)
 
           
Ramp-up assets, net (1)
  $ 11,616   $ 11,928  
Fuel Tracker
    2,295     11,747  
Cash balance plan settlement (Note 5)
    2,326     4,185  
Environmental non-PCB clean-up cost (Note 12)
    1,147     1,000  
Other miscellaneous
    1,823     2,147  
     Total Regulatory Assets
  $ 19,207   $ 31,007  
               

(1) Ramp-up assets are regulatory assets which Florida Gas was specifically allowed to establish in the FERC certificates authorizing the Phase IV and V Expansion projects.



 



 
24

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The principal components of the Company's other assets at the dates indicated were as follows:

   
December 31, 2007
 
December 31, 2006
 
   
(In thousands)
 
           
Long-term receivables  (Note 14)
  $ 2,859   $ 71,648  
Other post employment benefits (Note 5)
    3,297     2,702  
Preliminary survey & investigation
    3,021     996  
FERC ACA fee
    1,061     839  
Other miscellaneous
    600     244  
     Total Other Assets - other
  $ 10,838   $ 76,429  
               


(11)
Deferred Credits

The principal components of the Company's regulatory liabilities at the dates indicated were as follows:
 
   
December 31, 2007
 
December 31, 2006
 
   
(In thousands)
 
           
Balancing tools (1)
  $ 11,413   $ 12,154  
Other post employment benefits (Note 5)
    3,390     1,472  
Other miscellaneous
    39     630  
     Total Regulatory liabilities
  $ 14,842   $ 14,256  
               
 
(1) Balancing tools are a regulatory method by which Florida Gas recovers the costs of operational balancing of the pipeline’s system.  The balance can be a deferred charge or credit, depending on timing, rate changes and operational activities.
 
The principal components of the Company's other deferred credits at the dates indicated were as follows:
 
   
December 31, 2007
 
December 31, 2006
 
   
(In thousands)
 
           
Post construction mitigation costs
  $ 1,686   $ 2,073  
Deferred compensation
    889     1,090  
Environmental non-PCB clean-up cost reserve (Note 12)
    1,337     1,423  
Taxes Payable
    3,116     1,664  
Asset retirement obligation (Note 2)
    471     481  
Other miscellaneous
    1,703     1,398  
     Total Deferred Credits - other
  $ 9,202   $ 8,129  
               




 
25

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
(12)
Environmental Reserve
 
The Company is subject to extensive federal, state and local environmental laws and regulations.  These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites.  The implementation of the Clean Air Act Amendments resulted in increased operating expenses.  These increased operating expenses did not have a material impact on the Company’s consolidated financial statements.

Florida Gas conducts assessment, remediation, and ongoing monitoring of soil and groundwater impact which resulted from its past waste management practices at its Rio Paisano and Station 11 facilities.  The anticipated costs over the next five years are:  2008 - $0.3 million, 2009 - $0.1 million, 2010 - $0.2 million, 2011 - $0.3 million and 2012 – $0.1 million.  The expenditures thereafter are estimated to be $0.6 million for soil and groundwater remediation.  The liability is recognized in other current liabilities and in other deferred credits and in total amounted to $1.6 million and $1.6 million at December 31, 2007 and 2006, respectively.   Costs of $0.2 million, $0.1 million and $0.8 million were expensed during the years ended December 31, 2007, 2006 and 2005, respectively.  Florida Gas recorded the estimated costs of remediation to be spent after April 1, 2010 of $1.1 million and $1.0 million at December 31, 2007 and 2006, respectively (Note 10), as a regulatory asset based on the probability of recovery in rates in its next rate case.

Prior to December 31, 2005, no such liability was recognized since it was previously estimated to be less than $1.0 million, and therefore, considered not to be material.  Amounts incurred for environmental assessment and remediation were expensed as incurred.


(13)
Accumulated Other Comprehensive Loss

Deferred gains and losses in connection with the termination of the following derivative instruments which were previously accounted for as cash flow hedges form part of other comprehensive income.  Such amounts are being amortized over the terms of the hedged debt.

The table below provides an overview of comprehensive income for the periods indicated:
 
   
Year Ended
   
Year Ended
   
Year Ended
 
   
December 31, 2007
   
December 31, 2006
   
December 31, 2005
 
   
(In thousands)
 
Interest rate swap loss on 7.625% $325 million note due 2010
  $ 1,873     $ 1,872     $ 1,872  
Interest rate swap loss on 7.0% $250 million note due 2012
    1,228       1,228       1,228  
Interest rate swap gain on 9.19% $150 million note due 2005-2024
    (462 )     (462 )     (462 )
     Total
  $ 2,639     $ 2,638     $ 2,638  
                         




 





 
26

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



The table below provides an overview of the components in accumulated other comprehensive loss at the dates indicated:
 
 
Termination Date
 
Amortization Period
 
Original Gain/(Loss)
 
December 31, 2007
 
December 31, 2006
 
         
(In thousands)
 
Interest rate swap loss on 7.625% $325 million note due 2010
December 2000
 
10 years
  $ (18,724 ) $ (5,461 ) $ (7,334 )
Interest rate swap loss on 7.0% $250 million note due 2012
July 2002
 
10 years
    (12,280 )   (5,579 )   (6,807 )
Interest rate swap gain on 9.19% $150 million note due 2005-2024
November 1994
 
20 years
    9,236     3,155     3,617  
     Total
              $ (7,885 ) $ (10,524 )
                           
 

 
(14)
Commitments and Contingencies

From time to time, in the normal course of business, the Company is involved in litigation, claims or assessments that may result in future economic detriment.  Where appropriate, Citrus has made accruals in accordance with FASB Statement No. 5, Accounting for Contingencies, in order to provide for such matters.  Management believes the final disposition of these matters will not have a material adverse effect on the Company’s’ results of operations or financial position.

Florida Gas plans to seek FERC approval to construct an expansion to increase its natural gas capacity into Florida by approximately 800 MMcf/d.  The Phase VIII Expansion includes construction of approximately 500 miles of additional large diameter pipeline and the installation of approximately 170,000 horsepower of additional compression.  Pending FERC approval, which is expected in 2009, Florida Gas anticipates an in-service date of 2011, at an approximate cost of $2 billion.  Florida Gas has signed a 25-year agreement with FPL for 400 MMcf/d of capacity.

On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement (Citrus Credit Agreement) with a wholly owned subsidiary of FPL Group Capital Inc., which is a wholly-owned subsidiary of FPL Group, Inc.  Citrus will contribute the proceeds of this loan to Florida Gas in order to finance a portion of the Phase VIII Expansion.  The Citrus Credit Agreement provides for a single $500 million draw after Florida Gas’ receipt of a certificate from the FERC authorizing construction of the Phase VIII Expansion and Citrus’ satisfaction of customary conditions precedent.  On or before the Phase VIII Expansion in-service date, the construction loan will convert to an amortizing 20-year term loan with a $300 million balloon payment at maturity.  The loan requires semi-annual payments of principal beginning five years and six months after the conversion to a term loan.  The Citrus Credit Agreement provides for interest on the outstanding principal amount at the rate of six-month LIBOR plus 535 basis points prior to conversion to a term loan and at the twenty-year treasury rate plus 535 basis points after conversion to a term loan.  The loan is not guaranteed by Florida Gas and does not include a prepayment option.  The Citrus Credit Agreement contains certain customary representations, warranties and covenants and requires the execution of a negative pledge agreement by Florida Gas.

The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects that have or may, over time, impact one or more of Florida Gas’ mainline pipelines co-located in FDOT/FTE rights-of-way.  The first phase of the turnpike project includes replacement of approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE right-of-way in Florida.  The estimated cost of such replacement is approximately $110 million, including AFUDC.  Florida Gas is also in discussions with the FDOT/FTE related to additional projects that may affect Florida Gas’ 18- and 24-inch pipelines within FDOT/FTE right-of-way.  The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or right-of-way costs, cannot be determined at this time.
 
 
 

 
 
27

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Under certain conditions, existing agreements between Florida Gas and the FDOT/FTE require the FDOT/FTE to provide any new right-of-way needed for relocation of the pipelines and for Florida Gas to pay for rearrangement or relocation costs. Under certain other conditions, Florida Gas may be entitled to reimbursement for the costs associated with relocation, including construction and right-of-way costs.  On January 25, 2007, Florida Gas filed a complaint against FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, to seek relief for three specific sets of FDOT widening projects in Broward County.  The complaint seeks damages for breach of easement and relocation agreements for the one set of projects on which construction has already commenced, and injunctive relief as well as damages for the two other sets of projects upon which construction has yet to commence.  On April 24, 2007 the FDOT/FTE filed a complaint against Florida Gas in the Ninth Judicial Circuit, Orange County, Florida, to seek a declaratory judgment that under the existing agreements Florida Gas is liable for the costs of relocation associated with such projects and is not entitled to certain other rights.  On August 7, 2007 the Orange County Court granted a motion by Florida Gas to abate and stay the Orange County action.  The FDOT/FTE filed an amended answer and counterclaim against Florida Gas on February 8, 2008 in the Broward County action.  The counterclaim alleges Florida Gas is subject to estoppel and breach of contract regarding removal from service of the existing pipelines on the project currently under construction and seeks a declaratory judgment that Florida Gas is responsible for all relocation costs and is not entitled to workspace and uniform minimum area precluding FDOT/FTE activity.  On February 14, 2008 the case was transferred to the Broward County Complex Business Civil Division 07.  As a result, the March 10, 2008 hearing on the motion by Florida Gas for a temporary injunction enjoining the FDOT/FTE interference with the pipelines of Florida Gas will be rescheduled.

On October 24, 2007, Florida Gas filed a complaint in the US District Court of the Northern District of Florida, Tallahassee Division, against Stephanie C. Kopelousos (Kopelousos) in her official capacity as the Secretary of the Florida Department of Transportation, seeking to enjoin Kopelousos from violating federal law in connection with construction of the FDOT/FTE Golden Glades project, a new toll plaza in Miami-Dade County, Florida.  Florida Gas seeks a declaratory judgment that certain Florida statutes are preempted by federal law to the extent such state statutes purport to regulate the abandonment or relocation schedule for the federally regulated pipelines of Florida Gas and prospective preliminary and permanent injunctive relief enjoining Kopelousos from proceeding with construction on the Golden Glades project over and around such pipelines.  Kopelousos has filed a motion to dismiss the complaint and Florida Gas has responded.  Based upon representations by the FDOT/FTE that the Golden Glades project has been moved to 2013, the parties entered into a joint stipulation of dismissal without prejudice on February 15, 2008.

Should Florida Gas be denied reimbursement by the FDOT/FTE for any possible relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings.  Florida Gas expects to seek rate recovery at FERC for all reasonable and prudent costs incurred in relocating its pipelines to accommodate the FDOT/FTE to the extent not reimbursed by the FDOT/FTE.  There can be no assurance that Florida Gas will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of reimbursement will fully compensate Florida Gas for its costs.

Florida Gas and Trading previously filed bankruptcy-related claims against Enron and other affiliated bankrupt companies totaling $220.6 million. Of these claims, Florida Gas and Trading filed claims totaling $68.1 and $152.5 million, respectively.  Florida Gas and Enron agreed on the amount of the claim at $13.3 million, and Florida Gas assigned its claims to a third party and received $3.4 million in June 2005.  Trading’s claim was for rejection damages on two physical/financial swaps and a gas sales contract, as well as certain delinquent amounts owed pre-petition.  In March 2005, Enron North America Corp. (ENA) filed objections to Trading’s claim.  In September 2006 the judge issued an order which rejected certain of Trading's arguments and ruled that a contract under which ENA had an in the money position against Trading could be offset against a related contract under which Trading had an in the money position against ENA. The result of the order was a reduction in the allowable amount of Trading's initial claim to $22.7 million. The parties reached a settlement  on the amount of the allowed claim which was approved by the bankruptcy court in March 2007.  Citrus fully reserved for the amounts in 2001 and sold the receivable claim in the second quarter of 2007 to a third party for a pre-tax gain on $11.4 million.  The gain has been reported in Other, net in the accompanying Consolidated Statements of Income, which is consistent with the presentation of the original write-off recorded in 2001.

 
28

 
CITRUS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On March 7, 2003, Trading filed an action, requesting the court to declare that Duke Energy LNG Sales, Inc. (Duke) breached a natural gas trading contract by failing to provide sufficient volumes of gas to Trading. Duke sent Trading a notice of termination of the contract and answered and filed a counterclaim, arguing that Trading failed to timely increase the amount of a letter of credit that was required of Trading under the contract, and that Trading had breached a “resale restriction” on the gas.  On June 2, 2003, Trading notified Duke that, because Duke had defaulted on the contract and failed to cure, Trading was terminating the contract effective as of June 5, 2003.  On August 8, 2003, Trading sent its final “termination payment” invoice to Duke in the amount of $187 million, and recorded a receivable of $75 million (subsequently reduced by $6.5 million to $68.5 million, reflected in Other Assets at December 31, 2006, to provide for a related settlement, see below).  After denying motions for summary judgment by both parties, the judge ordered the parties to attempt to narrow the scope of the issues to be tried.  Pre-trial conferences were held in January 2007, a jury was selected and opening arguments were scheduled.  Following the judge’s rulings on certain matters, on January 29, 2007, Trading, Citrus, Southern Union and El Paso (collectively, Citrus Parties) entered into a settlement regarding litigation with Spectra Energy LNG Sales, Inc., formerly known as Duke Energy LNG Sales, Inc. (Duke), and its parent company Spectra Energy Corporation (collectively, Spectra), whereby Spectra agreed to pay $100 million to Trading, which was received on January 30, 2007.  Citrus recorded a pre-tax gain of $24 million in the first quarter of 2007.  This gain has been reported in Other, net in the accompanying Consolidated Statements of Income, which is consistent with the historical results of Trading’s activities.

In June 2004 the Company recorded an accrual for a contingent obligation of up to $6.5 million to terminate a gas sales contract with a third party.  The contingent obligation was extinguished with a payment to the third party on February 6, 2007 of $6.5 million from proceeds resulting from the settlement of the Duke litigation.

Jack Grynberg, an individual, filed actions for damages against a number of companies, including Florida Gas and Citrus, now transferred to the U.S. District Court for the District of Wyoming, alleging mismeasurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against the defendants.  Grynberg is appealing that action to the Tenth Circuit Court of Appeals.  Grynberg’s opening brief was filed on July 31, 2007.  Respondents filed their brief rebutting Grynberg’s arguments on November 21, 2007.  Florida Gas believes that its measurement practices conformed to the terms of its FERC gas tariffs, which were filed with and approved by FERC. As a result, Florida Gas believes that it has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Florida Gas complied with the terms of its tariffs) and will continue to vigorously defend against them, including any appeal from the dismissal of the Grynberg case.  The Company does not believe the outcome of this case will have a material adverse effect on its financial position, results of operations or cash flows.
 
 
 
 
 
 
 
 
 
 
29