10-K 1 southernunion201210-k.htm 10-K Southern Union 2012 10-K
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, 2012
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.)
5051 Westheimer Road
77056-5622
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:

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

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 x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 
Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the 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. x

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. Large accelerated filer ¨  Accelerated filer ¨  Non-accelerated filer x  Smaller reporting company ¨

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

Southern Union Company meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format. Items 1, 2 and 7 have been reduced and Items 6, 10, 11, 12 and 13 have been omitted in accordance with Instruction I.




TABLE OF CONTENTS

 
 
PAGE
 
 
 
ITEM 1.
 
 
 
ITEM 1A.
 
 
 
ITEM 1B.
 
 
 
ITEM 2.
 
 
 
ITEM 3.
 
 
 
ITEM 4.
 
 
 
 
ITEM 5.
 
 
 
ITEM 6.
 
 
 
ITEM 7.
 
 
 
ITEM 7A.
 
 
 
ITEM 8.
 
 
 
ITEM 9.
 
 
 
ITEM 9A.
 
 
 
ITEM 9B.
 
 
 
 
ITEM 10.
 
 
 
ITEM 11.
 
 
 
ITEM 12.
 
 
 
ITEM 13.
 
 
 
ITEM 14.
 
 
 
 
ITEM 15.
 
 







Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Southern Union Company and its subsidiaries (“Southern Union” or the “Company”) in periodic press releases and some oral statements of the Company’s officials during presentations about the Company, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Company believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Company’s actual results may vary materially from those anticipated, projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Item 1A. Risk Factors” included in this annual report.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
/d
 
per day
 
 
 
AOCI
 
accumulated other comprehensive income (loss)
 
 
 
ARO
 
Asset retirement obligation
 
 
 
Bbls
 
barrels
 
 
 
Bcf
 
Billion cubic feet
 
 
 
Btu
 
British thermal units
 
 
 
Citrus
 
Citrus Corp.
 
 
 
CrossCountry Energy
 
CrossCountry Energy, LLC
 
 
 
DGCL
 
Delaware General Corporation Law
 
 
 
EBIT
 
Earnings before interest and taxes
 
 
 
EBITDA
 
Earnings before interest, taxes, depreciation and amortization
 
 
 
EITR
 
Effective income tax rate
 
 
 
EPA
 
United States Environmental Protection Agency
 
 
 
ETE
 
Energy Transfer Equity, L.P.
 
 
 
ETP
 
Energy Transfer Partners, L.P., a subsidiary of ETE
 
 
 
ETP Merger Sub
 
Citrus ETP Acquisition, L.L.C.
 
 
 
Exchange Act
 
Securities Exchange Act of 1934
 
 
 
FERC
 
Federal Energy Regulatory Commission
 
 
 
Florida Gas
 
Florida Gas Transmission Company, LLC
 
 
 
GAAP
 
Accounting principles generally accepted in the United States of America
 
 
 
Holdco
 
ETP Holdco Corporation
 
 
 
LIBOR
 
London Interbank Offer Rate
 
 
 
KDHE
 
Kansas Department of Health and Environment
 
 
 
Laclede Massachusetts
 
Plaza Massachusetts Acquisition, Inc.
 
 
 
Laclede Missouri
 
Plaza Missouri Acquisition, Inc.
 
 
 

1


LNG
 
Liquefied natural gas
 
 
 
LNG Holdings
 
Trunkline LNG Holdings, LLC
 
 
 
MADEP
 
Massachusetts Department of Environmental Protection
 
 
 
MDPU
 
Massachusetts Department of Public Utilities
 
 
 
MGPs
 
Manufactured gas plants
 
 
 
MMBtu
 
Million British thermal units
 
 
 
MMcf
 
Million cubic feet
 
 
 
MPSC
 
Missouri Public Service Commission
 
 
 
NGL
 
Natural gas liquids
 
 
 
NMED
 
New Mexico Environment Department
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
OPEB plans
 
Other postretirement employee benefit plans
 
 
 
Panhandle
 
Panhandle Eastern Pipe Line Company, LP and its subsidiaries
 
 
 
PCBs
 
Polychlorinated biphenyls
 
 
 
PEPL
 
Panhandle Eastern Pipe Line Company, LP
 
 
 
PEPL Holdings
 
PEPL Holdings, LLC
 
 
 
ppb
 
parts per billion
 
 
 
PRPs
 
Potentially responsible parties
 
 
 
RCRA
 
Resource Conservation and Recovery Act
 
 
 
Regency
 
Regency Energy Partners LP
 
 
 
SARs
 
Stock Appreciation Rights
 
 
 
Sea Robin
 
Sea Robin Pipeline Company, LLC
 
 
 
SEC
 
United States Securities and Exchange Commission
 
 
 
Sigma
 
Sigma Acquisition Corporation
 
 
 
Southern Union Credit Facility
 
the Company’s $700 million Eighth Amended and Restated Revolving Credit Agreement
 
 
 
Southwest Gas
 
Pan Gas Storage, LLC (d.b.a. Southwest Gas)
 
 
 
SUGS
 
Southern Union Gas Services
 
 
 
Sunoco
 
Sunoco, Inc.
 
 
 
TBtu
 
Trillion British thermal units
 
 
 
TCEQ
 
Texas Commission on Environmental Quality
 
 
 
Trunkline
 
Trunkline Gas Company, LLC
 
 
 
Trunkline LNG
 
Trunkline LNG Company, LLC
 
 
 
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, unrealized gains and losses on commodity risk management activities, non-cash impairment charges and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA includes amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.

2



PART I

ITEM 1.    BUSINESS.

OUR BUSINESS

Introduction

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.
On March 26, 2012, the Company, ETE, and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub), completed their previously announced merger transaction.  Pursuant to the Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 (as amended, the Merger Agreement), among the Company, ETE and Merger Sub, Merger Sub was merged with and into the Company, with the Company continuing as the surviving corporation as an indirect, wholly-owned subsidiary of ETE (the Merger).  The Merger became effective on March 26, 2012 at 12:59 p.m., Eastern Time (the Effective Time).
In connection with, and immediately prior to the Effective Time of the Merger, CrossCountry Energy, an indirect wholly-owned subsidiary of the Company, ETP, ETP Merger Sub, Citrus ETP Finance LLC, ETE, PEPL Holdings, LLC, a newly created indirect wholly-owned subsidiary of the Company, and the Company consummated the transactions contemplated by that certain Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 and Amendment No. 2 thereto dated as of March 23, 2012 (as amended, the Citrus Merger Agreement) by and among ETP, ETP Merger Sub and Citrus ETP Finance LLC, on the one hand, and ETE, CrossCountry Energy, PEPL Holdings and the Company, on the other hand.
Immediately prior to the Effective Time, the Company, CrossCountry Energy and PEPL Holdings became parties to the Citrus Merger Agreement by joinder and the Company assumed the obligations and rights of ETE thereunder.  The Company made certain customary representations, warranties, covenants and indemnities in the Citrus Merger Agreement.  Pursuant to the Citrus Merger Agreement, ETP Merger Sub was merged with and into CrossCountry Energy (the Citrus Merger), with CrossCountry Energy continuing as the surviving entity in the Citrus Merger as a wholly-owned subsidiary of ETP and, as a result thereof, ETP, through its subsidiaries, indirectly owns 50% of the outstanding capital stock of Citrus Corp. (Citrus).  As consideration for the Citrus Merger, the Company received from ETP $2.0 billion, consisting of approximately $1.9 billion in cash and $105 million of common units representing limited partner interests in ETP.
Immediately prior to the Effective Time, $1.45 billion of the total cash consideration received in respect of the Citrus Merger was contributed to Merger Sub in exchange for an equity interest in Merger Sub.  In connection with the Merger, at the Effective Time, such equity interest in Merger Sub held by CCE Holdings, LLC (CCE Holdings) was cancelled and retired.
Pursuant to the Citrus Merger Agreement, immediately prior to the Effective Time, (i) the Company contributed its ownership interests in Panhandle Eastern Pipe Line Company, LP and Southern Union Panhandle, LLC (collectively, the Panhandle Interests) to PEPL Holdings (the Panhandle Contribution); and (ii) following the Panhandle Contribution, the Company entered into a contingent residual support agreement (the Support Agreement) with ETP and Citrus ETP Finance LLC, pursuant to which the Company agreed to provide contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to Southern Union) with respect to Citrus ETP Finance LLC’s obligations to ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.
On October 5, 2012, ETE and ETP completed the Holdco Transaction, immediately following the closing of ETP’s acquisition of Sunoco whereby, (i) ETE contributed its interest in Southern Union into an ETP-controlled entity, in exchange for a 60% equity interest in the new entity, Holdco, and (ii) ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Pursuant to a stockholders agreement between ETE and ETP, ETP will control Holdco. This transaction did not result in a new basis of accounting for Southern Union.

See Note 3 to our consolidated financial statements for information related to Southern Union’s merger with ETE.
 

3


BUSINESS SEGMENTS

Reportable Segments

The Company’s operations, as reported, include three reportable segments:
 
The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas and also provides LNG terminalling and regasification services.  Its operations are conducted through Panhandle.
The Gathering and Processing segment is primarily engaged in the gathering, treating, processing and redelivery of natural gas and NGL in Texas and New Mexico.  Its operations are conducted through SUGS. On February 27, 2013, the Company entered into a definitive contribution agreement to contribute to Regency all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration to be paid by Regency in connection with this transaction will consist of (i) the issuance of 31,372,419 Regency common units to the Company, (ii) the issuance of 6,274,483 Regency Class F units to the Company, (iii) the distribution of $570 million in cash to the Company, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The transaction is expected to close in the second quarter of 2013. The Regency Class F units will have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.
The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.  Its operations are conducted through the Company’s operating divisions:  Missouri Gas Energy and New England Gas Company.  On December 17, 2012, Southern Union and The Laclede Group, Inc. entered into definitive purchase and sale agreements dated December 14, 2012 with Laclede Missouri and Laclede Massachusetts, both of which are subsidiaries of Laclede Gas Company, Inc. pursuant to which Laclede Missouri has agreed to acquire the assets of Southern Union’s Missouri Gas Energy division, and Laclede Massachusetts has agreed to acquire the assets of Southern Union’s New England Gas Company division for approximately $1.035 billion, subject to customary closing adjustments.  On February 11, 2013, The Laclede Group, Inc. announced that it had entered into an agreement with Algonquin Power & Utilities Corp (APUC) that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals. It is expected that the transactions contemplated by the purchase and sale agreements will close by the end of the third quarter of 2013.

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 activities category.

For information about the results, assets and other financial information relating to reportable segments and the Corporate and Other activities, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Business Segment Results” and Note 18 to our consolidated financial statements.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.  There were no material intersegment revenues.

Transportation and Storage Segment
 
Services

The Transportation and Storage segment is primarily engaged in the interstate transportation of natural gas to Midwest, Gulf Coast and Midcontinent United States markets and related storage, and also provides LNG terminalling and regasification services.

Panhandle.  Panhandle owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the PEPL, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States 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, Indiana and to Michigan.  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 natural gas pipeline transmission and storage systems, Panhandle has five natural gas storage fields located in Illinois, Kansas,

4


Louisiana, Michigan and Oklahoma.  Southwest Gas operates four of these fields and Trunkline operates one.  Through Trunkline LNG, Panhandle owns and operates an LNG terminal in Lake Charles, Louisiana.
We are currently developing plans to convert certain existing pipeline assets from natural gas transportation to crude oil transportation.  These plans include the proposed abandonment of certain pipeline segments of Trunkline, which are currently operating in natural gas service, and the conversion of some or all of those segments of pipeline to crude oil transportation service.  Trunkline's application to abandon those segments of pipeline from natural gas service, filed July 26, 2012, is currently pending before the FERC.  As of February 13, 2013, ETP and Enbridge (U.S.), Inc. entered into an agreement under which they will jointly market a project to transport up to 420,000 Bbls/d of crude oil from Patoka, Illinois, to refinery markets in and around Memphis, Tennessee, Baton Rouge, Louisiana, and St. James, Louisiana, utilizing a combination of newly constructed pipeline and approximately 574 miles of pipeline to be abandoned by Trunkline.  Subject to receipt of sufficient customer commitments for long-term transportation capacity and regulatory approvals, this project is expected to be in service by 2015.

We are currently studying the commercial and engineering feasibility of constructing a liquefaction facility at Trunkline LNG's existing Lake Charles LNG regasification terminal. The project is anticipated to utilize a portion of the existing LNG regasification infrastructure, including storage tanks and marine facilities, and is expected to have the capacity to export up to 15 million tons per annum of LNG.  We expect to complete certain studies, permits and approvals through 2014, and we do not anticipate making any significant capital expenditures related to this project prior to the completion of those items.

Panhandle earns most of its revenue by entering into firm transportation and storage contracts, providing capacity for customers to transport and store natural gas or LNG in its facilities.  Panhandle provides firm transportation services under contractual arrangements to local distribution company customers and their affiliates, natural 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 and long-term basis.  Demand for natural gas transmission on Panhandle’s pipeline systems peaks during the winter months, with the highest throughput and a higher portion of annual total operating revenues occurring during the first and fourth calendar quarters.  Average reservation revenue rates realized by Panhandle are dependent on certain factors, including but not limited to rate regulation, customer demand for capacity, and capacity sold for a given period and, in some cases, utilization of capacity.  Commodity or utilization revenues, which are more variable in nature, are dependent upon a number of factors including weather, storage levels and pipeline capacity availability levels, and customer demand for firm and interruptible services, including parking services.  The majority of Panhandle’s revenues are related to firm capacity reservation charges, which reservation charges accounted for approximately 87% of total segment revenues and 41% of consolidated revenues in the successor period in 2012.

Prior to the completion of the Citrus Merger in the first quarter of 2012, the Transportation and Storage segment also included the Company’s equity ownership interest in Florida Gas through our 50% equity ownership in Citrus.  See discussion of the Citrus Merger at Note 3 to our consolidated financial statements.

Operating Data

The following table provides a summary of pipeline transportation (including deliveries made throughout the Company’s pipeline network) (in TBtu).

 
 
Successor
 
 
Predecessor
 
 
Period from Acquisition (March 26, 2012) to December 31, 2012
 
 
Period from January 1, 2012 to March 25, 2012
 
Years Ended December 31,

 
 
 
 
2011
 
2010
Panhandle:
 
 
 
 
 
 
 
 
 
PEPL transportation
 
430

 
 
152

 
564

 
563

Trunkline transportation
 
533

 
 
177

 
743

 
664

Sea Robin transportation
 
91

 
 
20

 
113

 
172


5



The following table provides a summary of certain statistical information associated with Panhandle at the date indicated.
 
December 31, 2012
Panhandle:
 
Approximate Miles of Pipelines
 
PEPL
6,000

Trunkline
3,000

Sea Robin
1,000

Peak Day Delivery Capacity (Bcf/d)
 

PEPL
2.8

Trunkline
1.7

Sea Robin
1.9

Trunkline LNG Sustained Send Out Capacity (Bcf/d)
2.1

Underground Storage Capacity-Owned (Bcf)
68.1

Underground Storage Capacity-Leased (Bcf)
33.3

Trunkline LNG Terminal Storage Capacity (Bcf)
9.0

Approximate Average Number of Transportation Customers
500

Weighted Average Remaining Life in Years of Firm Transportation Contracts (1)
 

PEPL
5.7

Trunkline
8.9

Sea Robin  (2)
N/A

Weighted Average Remaining Life in Years of Firm Storage Contracts (1)
 

PEPL
8.8

Trunkline
6.0


(1) 
Weighted by firm capacity volumes.
(2) 
Sea Robin’s contracts are primarily interruptible, with only four firm contracts in place.

Regulation and Rates

Panhandle is subject to regulation by various federal, state and local governmental agencies, including those specifically described below.

FERC has comprehensive jurisdiction over Panhandle.  In accordance with the Natural Gas Act of 1938, FERC’s jurisdiction over natural gas companies encompasses, among other things, the acquisition, operation and disposition of assets and facilities, the services 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, and Southwest Gas hold certificates of public convenience and necessity issued by FERC, authorizing them to operate the pipelines, facilities and properties now in operation and to transport and store natural gas in interstate commerce.

Panhandle is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.

For additional information regarding Panhandle’s regulation and rates, see “Item 1A.  Risk Factors – Risks That Relate to the Company’s Transportation and Storage Segment” and Note 14 and Note 19 to our consolidated financial statements.


6


Competition

The interstate pipeline and storage systems of Panhandle 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.  In order to meet these challenges, Panhandle will need to adapt their marketing strategies, the types of transportation and storage services provided and their pricing and rates to address competitive forces.  In addition, FERC may authorize the construction of new interstate pipelines that compete with the Company’s existing pipelines.

Gathering and Processing Segment

Services

SUGS’ operations consist of a network of natural gas and NGL pipelines, six processing plants and seven natural gas treating plants.  The principal assets of SUGS are located in the Permian Basin of Texas and New Mexico.

SUGS is primarily engaged in connecting producing wells of exploration and production companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets.  SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds, and margin sharing contracts (conditioning fee and wellhead purchase contracts).  SUGS’ primary sales customers include exploration and production companies, power generating companies, electric and natural gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemical companies.  With respect to customer demand for the products and services it provides, SUGS’ business is not generally seasonal in nature; however, SUGS’ operations and the operations of its exploration and production producers can be adversely impacted by severe weather.

As a result of the operational flexibility built into SUGS’ gathering systems 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 natural gas and NGL.

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee-based services.  The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control.  The Company monitors these drivers and manages the associated commodity price risk using both economic and accounting hedge derivative instruments.  For additional information related to the Company’s commodity price risk management, see Note 11 to our consolidated financial statements and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk – Gathering and Processing Segment.”

Operating Data

The following table provides a summary of certain statistical information associated with SUGS at the date indicated.

 
 
December 31, 2012
Approximate Miles of Pipelines
 
5,700
Plant capacity (MMcf/d):
 
 
   Processing
 
510
   Natural gas treating
 
630
Approximate Average Number of Customers
 
52


7


See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Segment Results – Gathering and Processing Segment” for volume information related to SUGS.

Natural Gas and NGL Connections

SUGS’ major natural gas pipeline interconnects are with ATMOS Pipeline Texas, El Paso Natural Gas Company, Energy Transfer Fuel, Enterprise Texas Pipeline, Northern Natural Gas Company, Oasis Pipeline, ONEOK Westex Transmission, Public Service Company of New Mexico and Transwestern Pipeline Company.  Its major NGL pipeline interconnects are with Chaparral Energy, Lone Star Pipeline and Chevron Natural Gas.

Natural Gas Supply Contracts

SUGS’ natural gas supply contracts primarily include percent-of-proceeds, fee-based and margin sharing contracts (conditioning fee and wellhead purchase contracts) which, as of December 31, 2012, comprised 87%, 10% and 3% by volume of its natural gas supply contracts, respectively.  These natural 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.  Additionally, some contracts contain a combination of these contractual types of structure (e.g., percent-of-proceeds contractual structure combined with a treating fee component).  

Following is a summary description of the natural gas supply contracts utilized by SUGS:

Percent-of-Proceeds, Percent-of-Value or Percent-of-Liquids.  Under percent-of-proceeds arrangements, SUGS generally gathers, treats and processes natural gas for producers for an agreed percentage of the proceeds from the sales of residual natural gas and NGL.  The percent-of-value and percent-of-liquids arrangements are variations on the percent-of-proceeds structure.  These types of arrangements expose SUGS to significant commodity price risk as the revenues derived from the contracts are directly related to natural gas and NGL prices.

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

Conditioning Fee.  Conditioning fee arrangements provide a guaranteed minimum unit margin or fee on natural gas that must be processed for NGL extraction in order to meet the quality specifications of the natural gas transmission pipelines.  In addition to the minimum unit margin or fee, SUGS retains a significant percentage of the processing spread, if any.  While the revenue earned is directly related to the processing spread, SUGS is guaranteed a positive margin with a minimum unit margin or fee in low processing spread environments.

Keep-Whole and Wellhead.  A keep-whole arrangement allows SUGS to keep 100% of the NGL produced, but requires the return of the Btu or dollar value of the underlying natural gas to the producer or owner.  Since some of the natural gas is converted to NGL during processing, resulting in Btu shrinkage, SUGS must compensate the producer or owner for the Btu shrinkage by replacing the shrinkage in-kind or by paying an agreed, market-based value for the Btu shrinkage.  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 NGL.  As a result, SUGS benefits from these types of arrangements when the Btu value of the NGL is high relative to the Btu value of the natural gas and is disadvantaged when the Btu value of the natural gas is high relative to the Btu value of NGL.  Rather than incurring negative margins during an unfavorable processing spread environment, SUGS may have the ability to reduce its exposure to negative processing spreads by (i) treating, dehydrating and blending the wellhead natural gas with leaner natural gas in order to meet downstream transmission pipeline specifications rather than processing the natural gas or (ii) reducing the volume of ethane recovered at the processing facility.

Natural Gas Sales Contracts

SUGS’ natural gas sales contracts (physical) are consummated under North American Energy Standards Board or Gas Industry Standards Board contracts.  Pricing is predominately based on Platt’s Gas Daily at El Paso-Permian or Waha pricing points.  Some monthly baseload sales are made using FERC (Platt’s) pricing at El Paso-Permian or Waha pricing points.


8


NGL Sales Contracts

SUGS has contracted to sell its entire owned or controlled output of NGL to Conoco through December 31, 2014.  Pricing for the NGL volumes sold to Conoco throughout the contract period are based on OPIS pricing at Mont Belvieu, Texas delivery points.  SUGS has an option to extend the sales agreement for an additional five-year period.

For information related to SUGS’ use of various derivative financial instruments to manage its commodity price risk and related operating cash flows, see Note 11 to our consolidated financial statements.

NGL Fractionation

SUGS has a multi-year, firm agreement with Enterprise Products Operations, LLC (Enterprise) for the fractionation of its NGL.  Enterprise owns several fractionation facilities in the Gulf coast area.

Regulation

While FERC does not directly regulate SUGS’ facilities for cost-based ratemaking purposes, SUGS is subject to certain oversight by FERC and various other governmental agencies, primarily with respect to matters of asset integrity, safety and environmental protection.  The relevant agencies include the EPA 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 operations are in compliance, in all material respects, 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. Industry factors that typically affect SUGS’ ability to compete are:

contract fees charged;
capacity and pressures maintained on gathering systems;
location of its gathering systems relative to competitors and producer drilling activity;
capacity and type of processing and treating available to SUGS and its competitors;
efficiency and reliability of operations;
availability and cost of third-party NGL transportation, fractionation capacity and residual natural gas markets;
delivery capabilities in each system and plant location;
natural gas and NGL pricing available to SUGS; and
ability to secure rights-of-way and various facility sites.

Commodity prices for natural gas and NGL also play a major role in drilling activity on or near SUGS’ 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 array of services to accommodate the types and quality of natural gas produced in the region, while many competing systems provide only certain of these services.


9


Distribution Segment

Services

The Company’s Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, through its Missouri Gas Energy division, and in Massachusetts, through its New England Gas Company division.  These utilities serve residential, commercial and industrial customers through local distribution systems.  The distribution operations in Missouri and Massachusetts are regulated by the MPSC and the MDPU, respectively. The assets and liabilities of the Distribution segment were reflected as held for sale as of December 31, 2012.

The Distribution segment’s operations have historically been sensitive to weather and seasonal in nature, with the primary impact on operating revenues, which include pass through gas purchase costs that are seasonally impacted,  occurring in the traditional winter heating season during the first and fourth calendar quarters. For additional information related to rates, see Note 19 to our consolidated financial statements.

Operating Data

The following table provides a summary of miles of pipelines associated with the Distribution segment at the date indicated.

 
 
December 31, 2012
Approximate Miles of Pipelines
 
 
Mains
 
9,180

Service lines
 
5,990

Transmission lines
 
40



10


The following table sets forth the Distribution segment’s customers served, natural gas volumes sold or transported and weather-related information for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Period from Acquisition
(March 26, 2012) to
December 31,
2012
 
 
Period from January 1, 2012 to March 25, 2012
 
Year Ended December 31, 2011
Average number of customers:
 
 
 
 
 
 
 
Residential
 
477,211

 
 
487,009

 
480,356

Commercial
 
60,734

 
 
65,141

 
62,659

Industrial
 
95

 
 
94

 
97

 
 
538,040

 
 
552,244

 
543,112

Transportation
 
1,934

 
 
1,909

 
1,821

Total customers
 
539,974

 
 
554,153

 
544,933

 
 
 
 
 
 
 
 
Natural gas sales (MMcf):
 
 
 
 
 

 
 

Residential
 
15,286

 
 
14,085

 
38,897

Commercial
 
6,375

 
 
5,749

 
17,553

Industrial
 
104

 
 
122

 
393

Natural gas sales billed
 
21,765

 
 
19,956

 
56,843

Net change in unbilled natural gas sales
 
642

 
 
1

 
(1,720
)
Total natural gas sales
 
22,407

 
 
19,957

 
55,123

Natural gas transported
 
17,851

 
 
7,379

 
24,119

Total natural gas sales and gas transported
 
40,258

 
 
27,336

 
79,242

 
 
 
 
 
 
 
 
Natural gas sales revenues (in millions):
 
 
 
 
 

 
 

Residential
 
$
207

 
 
$
142

 
$
474

Commercial
 
69

 
 
54

 
177

Industrial
 
3

 
 
1

 
6

Natural gas revenues billed
 
279

 
 
197

 
657

Net change in unbilled natural gas sales revenues
 
4

 
 

 
(19
)
Total natural gas sales revenues
 
283

 
 
197

 
638

Natural gas transportation revenues
 
12

 
 
7

 
16

Other revenues
 
9

 
 
3

 
13

Total operating revenues
 
$
304

 
 
$
207

 
$
667

 
 
 
 
 
 
 
 
Weather:
 
 
 
 
 

 
 

Missouri Utility Operations:
 
 
 
 
 

 
 

Degree days (1)
 
2,040

 
 
1,898

 
5,183

Percent of 10-year measure (2)
 
82
%
 
 
70
%
 
100
%
Percent of 30-year measure (2)
 
52
%
 
 
146
%
 
100
%
 
 
 
 
 
 
 
 
Massachusetts Utility Operations:
 
 
 
 
 

 
 

Degree days (1)
 
2,542

 
 
2,170

 
5,162

Percent of 10-year measure (2)
 
42
%
 
 
35
%
 
85
%
Percent of 30-year measure (2)
 
42
%
 
 
36
%
 
84
%

(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.

11


(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 natural 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.

Natural Gas Supply

The cost and reliability of natural gas service are largely dependent upon the Company’s ability to achieve favorable mixes of long-term and short-term natural gas supply agreements and fixed and variable transportation contracts.  The Company acquires its natural gas supplies directly.  The Company has enhanced the reliability of the service provided to its customers by obtaining the ability to dispatch and monitor natural gas volumes on a daily, hourly or real-time basis.

For the year ended December 31, 2012, the majority of the natural gas requirements for the utility operations of Missouri Gas Energy were delivered under short- and long-term transportation contracts through four major pipeline companies and approximately fifty-four commodity suppliers.  For this same period, the majority of the natural gas requirements of New England Gas Company were delivered under long-term contracts through five major pipeline companies and contracts with three commodity suppliers.  These contracts have various expiration dates ranging from 2013 through 2036.  Missouri Gas Energy and New England Gas Company also have firm natural gas supply commitments under short-term and seasonal arrangements available for all of its service territories.  Missouri Gas Energy and New England Gas Company hold contract rights to over 17 Bcf and 1 Bcf of storage capacity, respectively, to assist in meeting peak demands.

Like the natural gas industry as a whole, Missouri Gas Energy and New England Gas Company utilize natural gas sales and/or transportation contracts with interruption provisions, by which large volume users purchase natural gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the natural 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 utility operations 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 Note 19 to our consolidated financial statements.

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 2020.  The franchises in Fall River, Massachusetts and St. Joseph, Missouri are perpetual. Regulatory authorities establish natural 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.  Natural gas costs are billed to customers through purchased natural gas adjustment clauses, which permit the Company to adjust its sales price as the cost of purchased natural 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 allows Missouri Gas Energy to make rate adjustments for purchased natural gas cost changes up to four times per year.  The MDPU requires New England Gas Company to file for purchased natural gas cost rate adjustments at any time its projected revenues and purchased natural gas costs vary by more than 5%.

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 and small general service customers, who are billed a fixed monthly charge for services provided and a charge for the amount of natural gas used, the Company’s monthly customer bills contain a fixed service charge, a usage charge for service to deliver natural 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 revenue and earnings in the traditional heating load months when usage of natural gas increases.

12



In addition to public service commission regulation, the Distribution segment is affected by certain 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 compliance, in all material respects, with applicable safety and environmental statutes and regulations.

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, NGL 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 natural gas and electric costs will not reduce the cost advantage of natural gas service.

Competition from the use of fuel oils 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 from the use of fuel oils 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 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.  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.  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 1A. Risk Factors” and Note 14 to our consolidated financial statements.

Insurance

The Company maintains insurance coverage provided under its policies similar to other comparable companies in the same lines of business.  This includes, but is not limited to, insurance for potential liability to third parties, worker’s compensation, automobile and property insurance.  The insurance policies are subject to terms, conditions, limitations and exclusions that do not fully compensate the Company for all losses.  Except for windstorm property insurance more fully described below, insurance deductibles range from $100,000 to $10 million for the various policies utilized by the Company.  As the Company renews its policies, it is possible that some of the current insurance coverage may not be renewed or obtainable on commercially reasonable terms due to restrictive insurance markets.

Oil Insurance Limited (OIL), the Company’s member mutual property insurer, revised its windstorm insurance coverage effective January 1, 2010.  Based on the revised coverage,  the per occurrence windstorm claims for onshore and offshore assets are limited to $250 million per member subject to a fixed 60% payout, up to $150 million per member, and are subject to the $750 million aggregate limit for total payout to members per incident and a $10 million deductible.  The revised windstorm coverage also limits annual individual member recovery to $300 million in the aggregate.  The Company has also purchased additional excess insurance coverage for its onshore assets arising from windstorm damage, which provides up to an additional $100 million of property insurance coverage over and above existing coverage or in excess of the base OIL coverage.  In the event windstorm damage claims are made by the Company for its onshore assets and such damage claims are subject to a scaled or aggregate limit reduction by OIL, the Company may have additional uninsured exposure prior to application of the excess insurance coverage. 


13


Employees

As of January 31, 2013, the Company employed 2,256 persons, of which 791 are represented by labor unions. None of the current contracts with the respective bargaining units expire within the next year. 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, 2012 and December 31, 2011.

SEC Reporting

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

We provide electronic access, free of charge, to our periodic and current reports on our internet website located at http://www.sug.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

ITEM 1A.  RISK FACTORS

The risks and uncertainties described below are not the only ones faced by the Company. Additional risks and uncertainties that the Company is unaware of, or that it currently deems immaterial, may become important factors that affect it. If any of the following risks occurs, 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 may not be able to obtain funding or obtain funding on acceptable terms because of deterioration in the credit and capital markets.  This may hinder or prevent Southern Union from meeting its future capital needs.

Southern Union has a significant amount of debt outstanding.  As of December 31, 2012, consolidated debt on the consolidated balance sheet totaled $3.28 billion outstanding, compared to total capitalization (long- and short-term debt plus stockholders’ equity) of $7.31 billion.

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.  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- and long-term credit as a significant source of liquidity for capital requirements not satisfied by the cash flow from its operations.  A deterioration in the Company’s financial condition could hamper its ability to access the capital markets.

Global financial markets and economic conditions have been, and may continue to be, disrupted and volatile.  The current weak economic conditions have made, and may continue to make, obtaining funding more difficult. 

Due to these factors, the Company cannot be certain that funding will be available if needed and, to the extent required, on acceptable terms.  If funding is not available when needed, or is available only on unfavorable terms, the Company may be unable to grow its existing business, complete acquisitions, refinance its debt or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the Company’s revenues and results of operations.

Further, in order for the Company to receive equity contributions or loans from its parent or incur long-term debt, certain state regulatory approvals are required. This may limit the Company’s overall access to sources of capital otherwise available.

14


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.

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

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, nor would a reduction in any credit rating, by itself, cause an event of default under any of the Company’s lending agreements.  However, if its current credit ratings were downgraded below investment grade the Company could be negatively impacted as follows:

Borrowing costs associated with existing debt obligations could increase in the event of a credit rating downgrade;
The costs of refinancing debt that is maturing or any new debt issuances could increase due to a credit rating downgrade;
The costs of maintaining certain contractual relationships could increase, primarily related to the potential requirement for the Company to post collateral associated with its derivative financial instruments; and
Regulators may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

The financial soundness of the Company’s customers could affect its business and operating results and the Company’s credit risk management may not be adequate to protect against customer risk.

As a result of macroeconomic challenges that have impacted the economy of the United States and other parts of the world, the Company’s customers may experience cash flow concerns.  As a result, if customers’ operating and financial performance deteriorates, or if they are unable to make scheduled payments or obtain credit, customers may not be able to pay, or may delay payment of, accounts receivable owed to the Company.  The Company’s credit procedures and policies may not be adequate to fully eliminate customer credit risk.  In addition, in certain situations, the Company may assume certain additional credit risks for competitive reasons or otherwise.  Any inability of the Company’s customers to pay for services could adversely affect the Company’s financial condition, results of operations and cash flows.

The Company depends on distributions from its subsidiaries 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 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.

Some of our executive officers and directors face potential conflicts of interest in managing our business.
Certain of our executive officers and directors are also officers and/or directors of ETE and/or ETP. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our Unitholders' best interests. In addition, these overlapping executive officers and directors allocate their time among us and ETE and/or ETP. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.
Our affiliates may compete with us.
Our affiliates and related parties are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

The Company’s growth strategy entails risk for investors.

The Company may 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.


15


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 valuing and 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 largely 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:

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.

The consideration paid in connection with an investment or acquisition also affects the Company’s financial results. In addition, acquisitions or expansions may result in the incurrence of additional debt.

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 NGL, including adverse weather conditions, 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. While the Company maintains insurance against many of these risks to the extent and in amounts that it believes are reasonable, the Company’s insurance coverages have significant deductibles and self-insurance levels, limits on maximum recovery, and do not cover all risks.  There is also the risk that the coverages will change over time in light of increased premiums or changes in the terms of the insurance coverages that could result in the Company’s decision to either terminate certain coverages, increase deductibles and self-insurance levels, or decrease maximum recoveries.  In addition, there is a risk that the insurers may default on their coverage obligations. As a result, the Company’s results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

Terrorist attacks, such as the attacks that occurred on September 11, 2001, have resulted in increased costs, and the consequences of terrorism 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.

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.  Additionally, third parties produce all of the natural gas gathered and processed by SUGS, and third parties provide all of the NGL transportation and fractionation services for SUGS.  As a result, the volume of natural gas or NGL transported, stored, gathered, processed or fractionated depends on the actions of those third parties and is beyond the Company’s control.  Further, other factors beyond the Company’s and those third parties’ control may unfavorably impact the Company’s ability to maintain or increase current transmission, storage, gathering or processing rates, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity.  High utilization of contracted capacity by firm customers reduces capacity available for interruptible transportation and parking services.

16


 
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 sources connected to their systems.

The amount of revenue generated by Panhandle 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 gathered and processed and NGL extracted.  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. If production from these natural gas reserves is substantially reduced and not replaced with other sources of natural gas, such as new wells or interconnections with other pipelines, and certain of the Company’s assets are consequently not utilized, the Company may have to accelerate the recognition and settlement of AROs.  Investments by third parties in the development of new natural gas reserves or other sources of natural gas in proximity to the Company’s facilities depend on many factors beyond the Company’s control.  Revenue reductions or the acceleration of AROs resulting from the decline of natural gas reserves and the lack of new sources of natural gas may have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

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

The revenues of Panhandle and SUGS are generated under contracts that expire periodically and must be replaced.  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 Company’s pipeline and gathering and processing businesses.

The Company may expand the capacity of its existing pipeline, storage, LNG, and gathering and processing facilities by constructing additional facilities.  Construction of these facilities is subject to various regulatory, development and operational risks, including:

the Company’s ability to obtain necessary approvals and permits from FERC and other regulatory agencies on a timely basis and on terms that are acceptable to it;
the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when the Company may be unable to access capital markets;
the availability of skilled labor, equipment, and materials to complete expansion projects;
adverse weather conditions;
potential changes in federal, state and local statutes, regulations, and orders, including environmental requirements that delay or prevent a project from proceeding or increase the anticipated cost of the project;
impediments on the Company’s ability to acquire rights-of-way or land rights or to commence and complete construction on a timely basis or on terms that are acceptable to it;
the Company’s ability to construct projects within anticipated costs, including the risk that the Company may incur cost overruns, resulting from inflation or increased costs of equipment, materials, labor, contractor productivity, delays in construction or other factors beyond its control, that the Company may not be able to recover from its customers;
the lack of future growth in natural gas supply and/or demand; and
the lack of transportation, storage or throughput commitments or gathering and processing commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs.  There is also the risk that a downturn in the economy and its potential negative impact on natural gas demand may result in either slower development in the Company’s expansion projects or adjustments in the contractual commitments supporting such projects.  As a result, new facilities could be delayed or may not achieve the Company’s expected investment return, which may adversely affect the Company’s business, financial condition, results of operations and cash flows.


17


The inability to continue to access lands owned by third parties could adversely affect the Company’s ability to operate and/or expand its pipeline and gathering and processing businesses.

The ability of Panhandle or SUGS to operate in certain geographic areas will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way. Securing additional rights-of-way is also critical to the Company’s ability to pursue expansion projects.  Even for Panhandle, which generally has the right of eminent domain, the Company cannot assure that it will be able to acquire all of the necessary new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current rights-of-way or that all of the rights-of-way will be obtainable in a timely fashion. The Company’s financial position could be adversely affected if the costs of new or extended rights-of-way materially increase or the Company is unable to obtain or extend the rights-of-way timely.

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 challenged successfully by federal, state and local jurisdictions.

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, change from time to time and have tended to become increasingly strict. 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 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 several of its facilities and at 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 PRPs.

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.

An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2012, our consolidated balance sheet reflected $2.36 billion of goodwill. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners' capital and balance sheet leverage as measured by debt to total capitalization.
The use of derivative financial instruments could result in material financial losses by us.
From time to time, we have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by our trading, marketing and/or system optimization activities. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.

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The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

In addition, even though monitored by management, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.
The adoption of the Dodd-Frank Act could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business, resulting in our operations becoming more volatile and our cash flows less predictable.

Congress has adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), a comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation was signed into law by President Obama on July 21, 2010 and requires the U.S. Commodity Futures Trading Commission (CFTC), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.

The Dodd-Frank Act expanded the types of entities that are required to register with the CFTC and the SEC as a result of their activities in the derivatives markets or otherwise become specifically qualified to enter into derivatives contracts. We will be required to assess our activities in the derivatives markets, and to monitor such activities on an ongoing basis, to ascertain and to identify any potential change in our regulatory status.

Reporting and recordkeeping requirements also could significantly increase operating costs and expose us to penalties for non-compliance. Certain CFTC recordkeeping requirements became effective on October 14, 2010, and additional recordkeeping requirements will be phased in through April 2013. Beginning on December 31, 2012, certain CFTC reporting rules became effective, and additional reporting requirements will be phased in through April 2013. These additional recordkeeping and reporting requirements may require additional compliance resources. Added public transparency as a result of the reporting rules may also have a negative effect on market liquidity which could also negatively impact commodity prices and our ability to hedge.

The CFTC has also issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC's position limits rules were to become effective on October 12, 2012, but a United States District Court vacated and remanded the position limits rules to the CFTC. The CFTC has appealed that ruling and it is uncertain at this time whether, when, and to what extent the CFTC's position limits rules will become effective.

The new regulations may also require us to comply with certain margin requirements for our over-the-counter derivative contracts with certain CFTC- or SEC-registered entities that could require us to enter into credit support documentation and/or post significant amounts of cash collateral, which could adversely affect our liquidity and ability to use derivatives to hedge our commercial price risk; however, the proposed margin rules are not yet final and therefore the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation also requires that certain derivative instruments be centrally cleared and executed through an exchange or other approved trading platform. Mandatory exchange trading and clearing requirements could result in increased costs in the form of additional margin requirements imposed by clearing organizations. On December 13, 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants, the earliest of which is March 11, 2013. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps. Although there may be an exception to the mandatory exchange trading and clearing requirement that applies to our trading activities, we must obtain approval from the board of directors of our General Partner and make certain filings in order to rely on this exception. In addition,

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mandatory clearing requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

Rules promulgated under the Dodd-Frank Act further defined forwards as well as instances where forwards may become swaps. Because the CFTC rules, interpretations, no-action letters, and case law are still developing, it is possible that some arrangements that previously qualified as forwards or energy service contracts may fall in the regulatory category of swaps or options. In addition, the CFTC's rules applicable to trade options may further impose burdens on our ability to conduct our traditional hedging operations and could become subject to CFTC investigations in the future.

The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through restrictions on the types of collateral we are required to post), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, if we fail to comply with applicable laws, rules or regulations, we may be subject to fines, cease-and-desist orders, civil and criminal penalties or other sanctions.

The Company’s business could be affected adversely by union disputes and strikes or work stoppages by its unionized employees.

As of December 31, 2012, approximately 791 of the Company’s 2,256 employees were represented by collective bargaining units under collective bargaining agreements.  Any future work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on the Company’s business, financial position, results of operations or cash flows.

The Company is subject to risks associated with climate change.

It has been advanced that emissions of “greenhouse gases” (GHGs) are linked to climate change. Climate change and the costs that may be associated with its impact and the regulation of GHGs have the potential to affect the Company’s business in many ways, including negatively impacting (i) the costs it incurs in providing its products and services, including costs to operate and maintain its facilities, install new emission controls on its facilities, acquire allowances to authorize its GHG emissions, pay any taxes related to GHG emissions, administer and manage a GHG emissions program, pay higher insurance premiums or accept greater risk of loss in areas affected by adverse weather and coastal regions in the event of rising sea levels, (ii) the demand for and consumption of its products and services (due to change in both costs and weather patterns), and (iii) the economic health of the regions in which it operates, all of which could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows.

Recently proposed rules regulating air emissions from natural gas operations could cause us to incur increased capital expenditures and operating costs, which may be significant.
On April 17, 2012, the EPA issued final rules that would establish new air emission controls for natural gas production and processing operations. Specifically, the EPA's proposed rule package includes New Source Performance Standards (NSPS) to address emissions of sulfur dioxide and volatile organic compounds (VOCs), and a separate set of emission standards to address hazardous air pollutants frequently associated with natural gas production and processing activities. The EPA's proposal would require the reduction of VOC emissions from natural gas production facilities by mandating the use of "green completions" for hydraulic fracturing by January 2015, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. These rules will require us to modify certain of our operations, including the possible installation of new equipment. Compliance with such rules will be required within three years of their effective date, and it could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas that we transport, store or otherwise handle.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The

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EPA has recently adopted rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and another which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. In November 2011, the EPA also adopted rules requiring companies with facilities that emit over 25,000 metric tons or more of carbon dioxide to report their greenhouse gas emissions to the EPA by September 30, 2012, a requirement with which we timely complied.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase may be reduced over time in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, natural gas, NGLs, crude oil and refined products. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.
Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our fuels is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
The Company is subject to risks resulting from the moratorium in 2010 on and the resulting increased costs of offshore deepwater drilling.

The United States Department of Interior (DOI) implemented a six-month moratorium on offshore drilling in water deeper than 500 feet in response to the blowout and explosion on April 20, 2010 at the British Petroleum Plc deepwater well in the Gulf of Mexico.  The offshore drilling moratorium was implemented to permit the DOI to review the safety protocols and procedures used by offshore drilling companies, which review will enable the DOI to recommend enhanced safety and training needs for offshore drilling companies.  The moratorium was lifted in October 2010.  Additionally, the United States Bureau of Ocean Energy Management, Regulation and Enforcement (formerly the United States Mineral Management Service) has been fundamentally restructured by the DOI with the intent of providing enhanced oversight of onshore and offshore drilling operations for regulatory compliance enforcement, energy development and revenue collection.   Certain enhanced regulatory mandates have been enacted with additional regulatory mandates expected.  The new regulatory requirements will increase the cost of offshore drilling and production operations.  The increased regulations and cost of drilling operations could result in decreased drilling activity in the areas serviced by the Company.  Furthermore, the imposed moratorium did result in some offshore drilling companies relocating their offshore drilling operations for currently indeterminable periods of time to regions outside of the United States.   Business decisions to not drill in the areas serviced by the Company resulting from the increased regulations and costs could result in a reduction in the future development and production of natural gas reserves in the vicinity of the Company’s facilities, which could adversely affect the Company’s business, financial condition, results of operations and cash flows.

The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on the Company’s financial results.  In addition, the passage of the Health Care Reform Act in 2010 could significantly increase the cost of providing health care benefits for Company employees.

The Company provides pension plan and other postretirement healthcare benefits to certain of its employees.  The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Company’s future financial results.  In addition, the passage of the Health Care Reform Act of 2010 could significantly

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increase the cost of health care benefits for its employees.  While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Company’s regulated businesses, the Company may not recover all of its costs and those rates are generally not immediately responsive to current market conditions or funding requirements.  Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.

The Company is subject to risks related to cybersecurity.

The Company is subject to cybersecurity risks and may incur increasing costs in connection with its efforts to enhance and ensure security and in response to actual or attempted cybersecurity attacks.

Substantial aspects of the Company’s business depend on the secure operation of its computer systems and websites. Security breaches could expose the Company to a risk of loss, misuse or interruption of sensitive and critical information and functions, including its own proprietary information and that of its customers, suppliers and employees and functions that affect the operation of the business.  Such losses could result in operational impacts, reputational harm, competitive disadvantage, litigation, regulatory enforcement actions, and liability. While the Company devotes substantial resources to maintaining adequate levels of cybersecurity, there can be no assurance that it will be able to prevent all of the rapidly evolving types of cyber attacks. Actual or anticipated attacks and risks may cause the Company to incur increasing costs for technology, personnel and services to enhance security or to respond to occurrences.

If the Company’s security measures are circumvented, proprietary information may be misappropriated, its operations may be disrupted, and its computers or those of its customers or other third parties may be damaged. Compromises of the Company’s security may result in an interruption of operations, violation of applicable privacy and other laws, significant legal and financial exposure, damage to its reputation, and a loss of confidence in its security measures.

Risk That Relate to the Company’s Transportation and Storage Business

The 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 has authority to regulate rates charged by Panhandle for the transportation and storage of natural gas in interstate commerce.  FERC also has authority over the construction, acquisition, operation and disposition of these pipeline and storage assets.  In addition, the U.S. Coast Guard has oversight over certain issues including the importation of LNG.

The Company’s rates and operations are subject to extensive 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 several decades 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 and more stringent regulatory requirements be imposed, the Company’s business could be unfavorably impacted and the Company could be subject to additional costs that could adversely affect its financial condition or results of operations if these costs are not ultimately recovered through rates.

The Company’s transportation and storage business is also influenced by fluctuations in costs, including operating costs such as insurance, postretirement and other benefit costs, wages, outside contractor services costs, asset retirement obligations for certain assets and other operating costs.  The profitability of regulated operations depends on the business’ ability to collect such increased costs as a part of the rates charged to its customers.  To the extent that such operating costs increase in an amount greater than that for which revenue is received, or for which rate recovery is allowed, this differential could impact operating results.  The lag between an increase in costs and the ability of the Company to file to obtain rate relief from FERC to recover those increased costs 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, FERC may prevent the business from passing along certain costs in the form of higher rates. Competition may prevent the recovery of increased costs even if allowed in rates.

FERC may also exercise its Section 5 authority to initiate proceedings to review rates that it believes may not be just and reasonable.  FERC has recently exercised this authority with respect to several other pipeline companies, as it had in 2007 with respect to Southwest Gas.  If FERC were to initiate a Section 5 proceeding against the Company and find that the Company’s rates at that time were not just and reasonable due to a lower rate base, reduced or disallowed operating costs, or other factors, the applicable maximum rates the Company is allowed to charge customers could be reduced and the reduction could potentially have a material

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adverse effect on the Company’s business, financial condition, results of operations or cash flows.  In 2010, in response to an intervention and protest filed by BG LNG Services (BGLS) regarding its rates with Trunkline LNG applicable to certain LNG expansions, FERC determined that there was no reason at that time to expend FERC’s resources on a Section 5 proceeding with respect to Trunkline LNG even though cost and revenue studies provided by the Company to FERC indicated Trunkline LNG’s revenues were in excess of its associated cost of service.  However, since the current fixed rates expire at the end of 2015 and revert to tariff rate for these LNG expansions as well as the base LNG facilities for which rates were set in 2002, a Section 5 proceeding could be initiated at that time and result in significant revenue reductions if the cost of service remains lower than revenues.  For additional related information, see “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations – Other Matters – Rate Matters – Trunkline LNG Cost and Revenue Study.”

A rate reduction is also a possible outcome with any Section 4 rate case proceeding for the regulated entities of Panhandle, including any rate case proceeding required to be filed as a result of a prior rate case settlement.  A regulated entity’s rate base, upon which a rate of return is allowed in the derivation of maximum rates, is primarily determined by a combination of accumulated capital investments, accumulated regulatory basis depreciation, and accumulated deferred income taxes.  Such rate base can decline due to capital investments being less than depreciation over a period of time, or due to accelerated tax depreciation in excess of regulatory basis depreciation.

The pipeline businesses are subject to competition.

The interstate pipeline and storage businesses of Panhandle competes 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.

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.  A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Insurance proceeds may not be adequate 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 are higher than prices in other natural gas producing regions able to serve the Company’s customers, the volume of natural gas transported by the Company may be negatively impacted.  Natural gas prices can also affect customer demand for the various services provided by the Company.

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

Panhandle’s top two customers accounted for 43% of its 2012 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.

Risks That Relate to the Company’s Gathering and Processing Business

The Company’s gathering and processing business is unregulated.

Unlike the Company’s returns on its regulated transportation and distribution businesses, the natural gas gathering and processing operations conducted at SUGS are not regulated for cost-based ratemaking purposes and may potentially have a higher level of risk in recovering incurred costs than the Company’s regulated operations.


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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 gathering and processing business is subject to competition.

The 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 strategies of competitors in the Company’s gathering region and the efficiency, quality and reliability of the Company’s plant and gathering system.

In addition to SUGS’ current competitive position in the 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.  Since the demand for natural gas or NGL is influenced by commodity prices (including prices for alternative energy sources), customer usage rates, weather, economic conditions, service costs and other factors beyond the control of the Company, volumes processed and/or NGL extracted during processing may, after analysis, be reduced from time to time based on existing market conditions.

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

SUGS’ gross margin is largely derived from (i) percentage of proceeds arrangements based on the volume and quality of natural gas gathered and/or NGL recovered through its facilities and (ii) specified fee arrangements for a range of services.  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 natural gas and NGL. 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, NGL and crude oil and their relationships to each other. 
 
The markets and prices for natural gas and NGL depend upon many factors beyond the Company’s control. These factors include demand for these commodities, which fluctuates 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 level of worldwide crude oil and NGL production and consumption;
the availability and level of natural gas and NGL storage;
the availability of imported natural gas, LNG, NGL and crude oil;
actions taken by foreign oil and natural gas producing nations;
the availability of local, intrastate and interstate transportation systems;
the availability of NGL transportation and fractionation capacity;
the availability and marketing of competitive fuels;
the impact of energy conservation efforts;
the extent of governmental regulation and taxation; and
the availability and effective liquidity of natural gas and NGL derivative counterparties.

To manage its commodity price risk related to natural gas and NGL, the Company uses a combination of puts, fixed-rate (i.e., receive fixed price) or floating-rate (i.e. receive variable price) index and basis swaps, NGL gross processing spread puts and fixed-rate swaps and exchange-traded futures and options.  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 physical market commodity prices and reducing basis risk.  Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations.  However, the Company does not fully hedge against commodity price changes, and therefore retains some exposure to market risk.  Accordingly, any adverse changes to commodity prices could result in decreased revenue and increased cost.  For information related to derivative financial instruments, see Note 11 to our consolidated financial statements.

A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect the Company’s gathering and processing business.

The NGL products the Company produces have a variety of applications, including for use as heating fuels, petrochemical feed stocks and refining blend stocks.  A reduction in demand for NGL products, whether because of general economic conditions, new

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government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather, severe weather such as hurricanes causing damage to Gulf Coast petrochemical facilities or other reasons, could result in a decline in the value of the NGL products the Company sells and/or reduce the volume of NGL products the Company produces.

Operational risks are involved in operating a 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 and fractionation 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. 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 does not obtain independent evaluations of natural gas reserves dedicated to its gathering and processing business, potentially resulting in future volumes of natural gas available to the Company being less than anticipated.

The Company does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information, as well as the cost of such evaluations.  Accordingly, the Company does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves.  If the total reserves or estimated lives of the reserves connected to the Company’s gathering systems are less than anticipated and the Company is unable to secure additional sources of natural gas, then the volumes of natural gas in the future and associated gross margin could be less than anticipated.  A decline in the volumes of natural gas and associated NGL in the Company’s gathering and processing business could have a material adverse effect on its business.

The Company depends on two natural gas producers for a significant portion of its supply of natural gas.  The loss of these producers or the replacement of its contracts on less favorable terms could result in a decline in the Company’s volumes and/or gross margin.

SUGS’ two largest natural gas suppliers for the year ended December 31, 2012 accounted for approximately 29% of the Company’s wellhead throughput under multiple contracts.  The loss of all or even a portion of the natural gas volumes supplied by these producers or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce the Company’s gross margin.  Although these producers represent a large volume of natural gas, the gross margin per unit of volume is significantly lower than the average gross margin per unit of volume on the Company’s gathering and processing system due to the lack of need for services required to make the natural gas merchantable (e.g. high pressure, low NGL content, essentially transmission pipeline quality natural gas).

The Company depends on one NGL customer for a significant portion of its sales of NGLs.  The loss of this customer or the replacement of its contract on less favorable terms could result in a decline in the Company’s gross margin.

Through December 31, 2014, SUGS has contracted to sell its entire owned or controlled output of NGL to Conoco Phillips Company (Conoco).  Pricing for the NGL volumes sold to Conoco throughout the contract period are based on OPIS pricing at Mont Belvieu, Texas delivery points.  For the period from March 26, 2012 to December 31, 2012, Conoco accounted for approximately 35% and 68% of the Company’s and SUGS’ operating revenues, respectively.

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 rate of return that the Company is allowed to realize. The ability to obtain rate increases 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 recover costs related to providing services to its customers. To the extent that such operating costs increase in an amount greater than that for which

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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 natural gas distribution business is a seasonal business with a significant percentage of annual operating revenues and EBITDA occurring in the traditional winter heating season in the first and fourth calendar quarters.  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 natural gas prices may have a significant effect on results of operations and cash flows.

Operational risks are involved in operating a 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. 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 distribution business has recorded certain assets that may not be recoverable from its customers.

The distribution business records certain assets on the Company’s balance sheet resulting from the regulatory process that could not be recorded under GAAP for non-regulated entities.  As of December 31, 2012, the Company’s regulatory assets recorded in its consolidated balance sheet as held-for-sale assets were $123 million, as the regulatory assets are included in the LDC Disposal Group. When establishing regulatory assets, the distribution business considers factors such as rate orders from its regulators, previous rate orders for substantially similar costs, written approval from the regulators and analysis of recoverability from legal counsel to determine the probability of future recovery of these assets.  The Company would be required to write-off any regulatory assets for which future recovery is determined not to be probable.

Cautionary Note Regarding Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.  Forward-looking statements are based on management’s beliefs and assumptions.  These forward-looking statements, which address the Company’s expected business and financial performance, among other matters, are identified by terms and phrases such as:  anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast and similar expressions.  Forward-looking statements involve risks and uncertainties that may or could cause actual results to be materially different from the results predicted.  Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
 
changes in demand for natural gas or NGL and related services by customers, in the composition of the Company’s customer base and in the sources of natural gas or NGL accessible to the Company’s system;
the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas or NGL as well as electricity, oil, coal and other bulk materials and chemicals;
adverse weather conditions, such as warmer or colder than normal weather in the Company’s service territories, as applicable, and the operational impact of natural disasters;
changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and/or governmental bodies affecting or involving the Company, 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, including competition from alternative forms of energy, is introduced to the Company’s business and the resulting effect on revenues;
the impact and outcome of pending and future litigation and/or regulatory investigations, proceedings or inquiries;
the ability to comply with or to successfully challenge existing and/or or new environmental, safety and other laws and regulations;
unanticipated environmental liabilities;
the uncertainty of estimates, including accruals and costs of environmental remediation;

26


the impact of potential impairment charges;
exposure to highly competitive commodity businesses and the effectiveness of the Company’s hedging program;
the ability to acquire new businesses and assets and to integrate those operations into its existing operations, as well as its ability to expand its existing businesses and facilities;
the timely receipt of required approvals by applicable governmental entities for the construction and operation of the pipelines and other projects;
the ability to complete expansion projects on time and on budget;
the 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, natural gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;
the performance of contractual obligations by customers, service providers and contractors;
exposure to customer concentrations 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 Company’s debt securities;
the risk of a prolonged slow-down in growth or decline in the United States economy or the risk of delay in growth or decline in the United States economy, including liquidity risks in United States credit markets;
the impact of unsold pipeline capacity being greater than expected;
changes in interest rates and other general market and economic conditions, and in the Company’s ability to continue to access its revolving credit facility and to obtain additional financing on acceptable terms, whether in the capital markets or otherwise;
declines in the market prices of equity and debt securities and resulting funding requirements for defined benefit pension plans and other postretirement benefit plans;
acts of nature, sabotage, terrorism or other similar acts that cause damage to the  facilities or those of the Company’s  suppliers’ or customers’ facilities;
market risks beyond the Company’s control affecting its risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness;
the availability/cost of insurance coverage and the ability to collect under existing insurance policies;
the risk that material weaknesses or significant deficiencies in internal controls over financial reporting could emerge or that minor problems could become significant;
changes in accounting rules, regulations and pronouncements that impact the measurement of the results of operations, the timing of when such measurements are to be made and recorded and the disclosures surrounding these activities;
the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives, authorized rates of recovery of costs (including pipeline relocation costs), and permitting for new natural gas production accessible to the Company’s systems;
market risks affecting the Company’s pricing of its services provided and renewal of significant customer contracts;
actions taken to protect species under the Endangered Species Act and the effect of those actions on the Company’s operations;
the impact of union disputes, employee strikes or work stoppages and other labor-related disruptions; and
other risks and unforeseen events, including other financial, operational and legal risks and uncertainties detailed from time to time in filings with the SEC.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of the Company’s forward-looking statements.  Other factors could also have material adverse effects on the Company’s future results.  In light of these risks, uncertainties and assumptions, the events described in forward-looking statements might not occur or might occur to a different extent or at a different time than the Company has described.  The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

See “Item 1. Business – Business Segments” for information concerning the general location and characteristics of the important physical properties and assets of the Transportation and Storage, Gathering and Processing and Distribution segments.


27


ITEM 3. LEGAL PROCEEDINGS

The Company and certain of its affiliates are occasionally parties to lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various tax matters, and rates and licensing.  The Company and its affiliates are also subject to various federal, state and local laws and regulations relating to the environment, as described in “Item 1. Business.” Several of these companies have been named parties to various actions involving environmental issues.  Based on the Company’s current knowledge and subject to future legal and factual developments, the Company’s management believes that it is unlikely that these actions, individually or in the aggregate, will have a material adverse effect on its consolidated financial position, results of operations or cash flows.  For additional information regarding various pending administrative and judicial proceedings involving regulatory, environmental and other legal matters, reference is made to Note 19 and Note 14 to our consolidated financial statements. Also see “Item 1A. Risk Factors.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

All of the interests in the Company are privately held by ETP Holdco Corporation, which is held by Energy Transfer Partners, L.P. through a 40% equity interest and Energy Transfer Equity, L.P., the parent of ETP, through the remaining 60% equity interest in Holdco. See Note 1 to our consolidated financial statements.

ITEM 6.  SELECTED FINANCIAL DATA

Item 6, Selected Financial Data, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar amounts are in millions, except per gallon and per MMBtu amounts)

INTRODUCTION

The information in Item 7 has been prepared pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K. Accordingly, this Item 7 includes only management’s narrative analysis of the results of operations and certain supplemental information.

RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is Segment Adjusted EBITDA.  For additional information related to the Company’s use of Segment Adjusted EBITDA as its primary financial measure for its reportable segments, see Note 18 to our consolidated financial statements.

The Merger, which was completed on March 26, 2012, was accounted for by ETE using business combination accounting.  By the application of “push-down” accounting, the Company allocated the purchase price paid by ETE to its assets, liabilities and equity as of the acquisition date based on preliminary estimates.  Accordingly, the successor financial statements reflect a new basis of accounting and predecessor and successor period financial results (separated by a heavy black line) are presented, but are not comparable.

The most significant impacts of the new basis of accounting going forward are expected to be (i) higher depreciation expense due to the step-up of depreciable assets and assignment of purchase price to certain amortizable intangible assets and (ii) lower interest

28


expense (though not cash payments) for the remaining life of the related long-term debt due to its revaluation and related debt premium amortization. 

The results of operations for the successor and predecessor periods reflect certain merger-related expenses, which are not expected to have a continuing impact on the results going forward, and those amounts are discussed in the segments results below. For information regarding expenses related to the merger, see Note 3 to our consolidated financial statements. The Holdco Transaction did not result in a new basis of accounting for Southern Union.

The Company previously reported segment earnings before interest and taxes (EBIT) as a measure of segment performance.  Subsequent to the ETE Merger, the chief operating decision maker assesses performance of the Company’s business based on Segment Adjusted EBITDA.  The Company defines Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, unrealized gains and losses on unhedged derivative activities, accretion expense and amortization of regulatory assets and other non-operating income or expense items.  Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.  Based on the change in its segment performance measure, the Company has recast the presentation of its segment results for the prior periods to be consistent with the current period presentation.

Segment Adjusted EBITDA 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 net cash flows provided by operating activities.

The following table provides a reconciliation of Segment Adjusted EBITDA (by segment) to net income for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Period from Acquisition
(March 26, 2012) to
December 31,
2012
 
 
Period from
January 1, 2012 to
March 25,
2012
 
Year Ended December 31, 2011
Segment Adjusted EBITDA:
 
 
 
 
 
 
 
Transportation and storage segment
 
$
326

 
 
$
186

 
$
778

Gathering and processing segment
 
40

 
 
25

 
125

Distribution segment
 
68

 
 
34

 
90

Corporate and other activities
 
8

 
 
(19
)
 
(6
)
Total Segment Adjusted EBITDA
 
442

 
 
226

 
987

Depreciation and amortization
 
(179
)
 
 
(49
)
 
(204
)
Interest expense
 
(131
)
 
 
(50
)
 
(218
)
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets
 
(4
)
 
 
(1
)
 
(9
)
Net gain on curtailment of OPEB plans
 
15

 
 

 

Other, net
 
2

 
 
(2
)
 

Earnings (losses) from unconsolidated investments
 
(7
)
 
 
16

 
99

Adjusted EBITDA attributable to unconsolidated investments
 
(5
)
 
 
(61
)
 
(262
)
Adjusted EBITDA attributable to discontinued operations
 
(83
)
 
 
(34
)
 
(99
)
Income from continuing operations before income tax expense
 
50

 
 
45

 
294

Income tax expense
 
39

 
 
12

 
80

Income from continuing operations
 
11


 
33

 
214

Income from discontinued operations
 
28

 
 
17

 
41

Net income
 
$
39

 
 
$
50

 
$
255



29


The segment analysis in the following section describes the significant items impacting the Segment Adjusted EBITDA amounts reflected above. In addition, as discussed in the “Overview” section above, the comparability of net income between predecessor and successor periods was impacted by the application of “push-down” accounting. The most significant impacts of this new basis of accounting were:

Incremental depreciation and amortization expense of approximately $13 million per quarter has been recognized in the successor periods subsequent to March 25, 2012 as a result of the application of the new basis of accounting.
The application of “push-down” accounting also resulted in the Company’s long-term debt being recorded at fair value, which impacted the amount of amortization recorded in interest expense. This change in the amount of amortization resulted in a net reduction within interest expense of approximately $10 million per quarter subsequent to March 25, 2012.

The Company’s consolidated net income was also impacted by changes in income taxes that were driven by the ETE Merger; those impacts were described in the “Federal and State Income Taxes” section below.
The “Supplemental Pro Forma Information” section, which follows the “Business Segment Results” section, provides additional analysis of the Company’s consolidated net income on a year-to-date basis, assuming the ETE Merger had been completed on January 1, 2011.
Federal and State Income Taxes

The following table sets forth the Company’s income taxes on continuing operations for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Period from Acquisition
(March 26, 2012) to
December 31,
2012
 
 
Period from
January 1, 2012 to
March 25,
2012
 
Year Ended December 31, 2011
Income tax expense
 
$
39

 
 
$
12

 
$
80

Effective tax rate
 
78
%
 
 
27
%
 
27
%

The increases in the effective tax rate during the successor period were primarily due to:
The impact of non-deductible executive compensation resulting from the Merger-related employee severance expenses in the successor periods; and,
Lower effective rates during the predecessor periods as a result of the dividend received deduction for the anticipated receipt of dividends associated with earnings from the Company’s unconsolidated investment in Citrus. The dividend received deduction was not applicable to the successor period as a result of the Company’s contribution of its investment in Citrus to ETP concurrent with the ETE Merger on March 26, 2012.

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, Gulf Coast and Midcontinent United States, and LNG terminalling and regasification services.  The Transportation and Storage segment’s operations, conducted through Panhandle and, through March 26, 2012 (the date of the Citrus Merger), Florida Gas Transmission Company, LLC (Florida Gas), are regulated as to rates and other matters by FERC. Demand for natural gas transmission services on Panhandle’s pipeline system is seasonal, with the highest throughput and a higher portion of annual total operating revenues and Segment Adjusted EBITDA occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters.  Florida Gas’ pipeline system experiences the highest throughput in the traditional summer cooling season during the second and third calendar quarters, primarily due to increased natural gas-fired electric generation loads.  See Note 3 to our consolidated financial statements for information related to the Citrus Merger.
  
The Company’s business within the Transportation and Storage segment is conducted through both short- and long-term contracts with customers.  Shorter-term contracts, both firm and interruptible, tend to have a greater impact on the volatility of revenues.  Short-term and long-term contracts are affected by changes in market conditions and competition with other pipelines,

30


changing supply sources and volatility in natural gas prices and basis differentials.  Since the majority of the revenues within the Transportation and Storage segment are related to firm capacity reservation charges, which customers pay whether they utilize their contracted capacity or not, volumes transported do not have as significant an impact on revenues over the short-term.  However, longer-term demand for capacity may be affected by changes in the customers’ actual and anticipated utilization of their contracted capacity and other factors.

The Company’s regulated transportation and storage businesses can file (or be required to file) for changes in their rates, which are subject to approval by FERC.  Although a significant portion of the Company’s contracts are discounted or negotiated rate contracts, changes in rates and other tariff provisions resulting from regulatory proceedings have the potential to impact negatively the Company’s results of operations and financial condition.

The following table illustrates the results of operations applicable to the Company’s Transportation and Storage segment for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Period from Acquisition
(March 26, 2012) to
December 31,
2012
 
 
Period from
January 1, 2012 to
March 25,
2012
 
Year Ended December 31, 2011
Operating revenues (1)
 
$
592

 
 
$
194

 
$
804

Operating, maintenance and general, net of non-cash compensation expense, accretion and gain on curtailment
 
(238
)
 
 
(60
)
 
(252
)
Taxes other than on income and revenues
 
(28
)
 
 
(9
)
 
(35
)
Adjusted EBITDA related to unconsolidated investments
 

 
 
61

 
261

Segment Adjusted EBITDA
 
$
326

 
 
$
186

 
$
778

 
 
 
 
 
 
 
 
Panhandle natural gas volumes transported (TBtu): (2)
 
 
 
 
 
 
 
PEPL
 
430

 
 
152

 
564

Trunkline
 
533

 
 
177

 
743

Sea Robin
 
91

 
 
20

 
113


(1) 
Reservation revenues comprised 87% in the successor period. Reservation revenues comprised 88% and 89% of total operating revenues in the 2012 and 2011 predecessor periods, respectively.
(2) 
Includes transportation deliveries made throughout the Company’s pipeline network.

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company’s Transportation and Storage segment.
Operating Revenues. Operating revenues were lower in the successor period primarily due to the impact of customer contract buyouts of $14 million in 2011.
Operating, Maintenance and General Expenses. The period from March 26, 2012 to December 31, 2012 included $48 million of merger-related employee severance expenses. The year ended December 31, 2011 reflected legal expenses that were lower than the legal expenses recorded during the predecessor and successor periods in 2012; this was due to settlement in 2011 of certain litigation with several contractors related to the Company’s East End projects. The successor period also reflected higher depreciation compared to the predecessor period, due to the step-up in depreciable assets in connection with the merger, offset by lower corporate allocations due to merger-related synergies.
Unconsolidated Investments. The primary driver for the reduction in Segment Adjusted EBITDA for the Company’s Transportation and Storage segment was the contribution of Citrus to ETP on March 26, 2012. Citrus was reflected in Adjusted EBITDA attributable to unconsolidated investments for all of the predecessor periods shown above but was not reflected in the successor periods. The predecessor periods reflected Adjusted EBITDA attributable to Citrus of $261 million for the year ended December 31, 2011, and $61 million for the period from January 1, 2012 to March 25, 2012.

31


Gathering and Processing Segment

The Gathering and Processing segment is primarily engaged in connecting producing wells of exploration and production companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets.  Its operations are conducted through SUGS.  SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds and margin sharing (conditioning fee and wellhead) purchase contracts.  These natural 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.  SUGS’ primary sales customers include exploration and production companies, power generating companies, electric and gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemical companies.  With respect to customer demand for the products and services it provides, SUGS’ business is not generally seasonal in nature; however, SUGS’ operations and the operations of its natural gas producers can be adversely impacted by severe weather.

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee-based services.  The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control.  The Company monitors these risks and manages the associated commodity price risk using both economic and accounting hedge derivative instruments.  For additional information related to the Company’s commodity price risk management, see Note 11 to our consolidated financial statements.

32



The following table presents the results of operations applicable to the Company’s Gathering and Processing segment for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Period from Acquisition
(March 26, 2012) to
December 31,
2012
 
 
Period from
January 1, 2012 to
March 25,
2012
 
Year Ended December 31, 2011
Operating revenues
 
$
663

 
 
$
246

 
$
1,180

Cost of natural gas and other energy (1)
 
(518
)
 
 
(196
)
 
(961
)
Gross margin (2)
 
145

 
 
50

 
219

Operating, maintenance and general, excluding non-cash compensation expense and accretion
 
(91
)
 
 
(23
)
 
(88
)
Taxes other than on income and revenues
 
(7
)
 
 
(2
)
 
(6
)
Adjusted EBITDA related to unconsolidated investments
 
(7
)
 
 

 

Segment Adjusted EBITDA
 
$
40

 
 
$
25

 
$
125

 
 
 
 
 
 
 
 
Operating Information:
 
 
 
 
 
 
 
Volumes:
 
 
 
 
 
 
 
Avg natural gas processed (MMBtu/d)
 
487,255

 
 
451,893

 
417,398

Avg NGL produced (gallons/d)
 
1,727,592

 
 
1,624,666

 
1,474,648

Avg natural gas wellhead volumes (MMBtu/d)
 
509,651

 
 
504,822

 
488,109

Natural gas sales (MMBtu)  
 
68,307,744

 
 
16,017,102

 
72,353,292

NGL sales (gallons)  
 
513,013,211

 
 
143,078,360

 
663,945,640

Average Pricing:
 
 
 
 
 
 
 
Realized natural gas ($/MMBtu)  (3)
 
$
2.76

 
 
$
2.44

 
$
3.86

Realized NGL ($/gallon)  (3)
 
0.93

 
 
1.17

 
1.33

Natural Gas Daily Waha ($/MMBtu)
 
2.77

 
 
2.43

 
3.91

Natural Gas Daily El Paso ($/MMBtu)
 
2.74

 
 
2.42

 
3.87

Estimated plant processing spread ($/gallon)
 
0.65

 
 
0.96

 
0.97


(1) 
Cost of natural gas and other energy consists of natural gas and NGL purchase costs, fractionation and other fees.
(2) 
Gross margin consists of operating revenues less cost of natural gas and other energy.  The Company believes that this measurement is 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.
(3) 
Excludes impact of realized and unrealized commodity derivative gains and losses.
Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company’s Gathering and Processing segment.
Gross Margin. Gross margin for the predecessor and successor periods in 2012 decreased compared to 2011 due to decreases in market-driven realized average natural gas and NGL prices. Realized average natural gas and NGL prices were $2.76 per MMBtu and $0.93 per gallon for the period from March 26, 2012 to December 31, 2012, $2.44 per MMBtu and $1.17 per gallon for the period from January 1, 2012 to March 25, 2012, versus $3.86 per MMBtu and $1.33 per gallon for the year ended December 31, 2011.
 
Operating, Maintenance and General Expenses. The period from March 26, 2012 to December 31, 2012 included $17 million of merger-related employee severance expenses. Operating, maintenance and general expenses have also increased between the end of the periods presented due to expansion of plant facilities.


33


Distribution Segment

The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts through the Company’s Missouri Gas Energy and New England Gas Company operating divisions, respectively.  The operations of the Distribution segment have been classified as discontinued operations as of December 31, 2012. The Distribution segment’s operations are regulated by the public utility regulatory commissions of the states in which each operates.  The Distribution segment’s operations have historically been sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues (which include pass-through gas purchase costs that are seasonally impacted) and Segment Adjusted EBITDA occurring in the traditional winter heating season during the first and fourth calendar quarters.  Most of Missouri Gas Energy’s revenues are based on a distribution rate structure that eliminates the impact of weather and conservations.  For additional information related to rate matters within the Distribution segment, see Note 19 to our consolidated financial statements.

The following table illustrates the results of operations applicable to the Company’s Distribution segment for the periods presented.
 
 
Successor
 
 
Predecessor
 
 
Period from Acquisition
(March 26, 2012) to
December 31,
2012
 
 
Period from
January 1, 2012 to
March 25,
2012
 
Year Ended December 31, 2011
Amounts reported within discontinued operations:
 
 
 
 
 
 
 
Net operating revenues  (1)
 
$
176

 
 
$
66

 
$
234

Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets
 
(97
)
 
 
(29
)
 
(132
)
Taxes other than on income and revenues
 
(11
)
 
 
(3
)
 
(12
)
Segment Adjusted EBITDA
 
$
68

 
 
$
34

 
$
90

 
 
 
 
 
 
 
 
Operating Information:
 
 
 
 
 
 
 
Natural gas sales volumes (MMcf)
 
22,407

 
 
19,957

 
55,123

Natural gas transported volumes (MMcf)
 
17,851

 
 
7,379

 
24,119

Weather – Degree Days: (2)
 
 
 
 
 
 
 
Missouri Gas Energy service territories
 
2,040

 
 
1,898

 
5,183

New England Gas Company service territories
 
2,542

 
 
2,170

 
5,162


(1) Operating revenues for the Distribution segment were reported net of cost of natural gas and other energy and revenue-related taxes, which are pass-through costs.
(2) “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.

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company’s Distribution segment.
Net Operating Revenues. The predecessor and successor periods in 2012 were higher compared to the year ended December 31, 2011 primarily due to new customer rates at New England Gas Company effective April 1, 2011.
 
Operating, Maintenance and General Expenses. The predecessor and successor periods in 2012 reflected lower uncollectible customer accounts as a result of lower gas costs and energy assistance payments compared to the year ended December 31, 2011.

Corporate and Other Activities

The period from January 1, 2012 to March 25, 2012 included $19 million of merger-related expenses.

See Note 3 to our consolidated financial statements for additional information related to the Company’s merger with ETE.
  

34


Supplemental Pro Forma Financial Information
The following unaudited pro forma consolidated financial information of the Company has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the ETE Merger for the years ended December 31, 2012 and 2011, giving effect to the ETE Merger as if it had occurred on January 1, 2011. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the ETE Merger had been consummated on January 1, 2011.
 
 
Successor
 
 
Predecessor
 
 
 
 
 
 
Period from Acquisition
(March 26, 2012) to
December 31,
2012
 
 
Period from January 1, 2012 to March 25, 2012
 
Pro forma adjustments
 
Pro forma year ended December 31, 2012
OPERATING REVENUES
 
$
1,263

 
 
$
443

 
$

 
$
1,706

OPERATING EXPENSES:
 
 
 
 
 

 
 
 
 

Cost of natural gas and other energy
 
521

 
 
197

 
 
 
718

Operating, maintenance and general
 
340

 
 
105

 
(81
)
(a)
364

Depreciation and amortization
 
179

 
 
49

 
6

(b)
234

Taxes, other than on income and revenues
 
37

 
 
11

 
 
 
48

Total operating expenses
 
1,077

 
 
362

 
(75
)
 
1,364

OPERATING INCOME
 
186

 
 
81

 
75

 
342

OTHER INCOME (EXPENSE):
 
 

 
 
 

 
 
 
 

Interest expense
 
(131
)
 
 
(50
)
 
9

(c)
(172
)
Earnings from unconsolidated investments
 
(7
)
 
 
16

 
(16
)
(d)
(7
)
Other, net
 
2

 
 
(2
)
 

 

Total other expenses, net
 
(136
)
 
 
(36
)
 
(7
)
 
(179
)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
 
50

 
 
45

 
68

 
163

Income tax expense
 
39

 
 
12

 
10

(e)
61

INCOME (LOSS) FROM CONTINUING OPERATIONS
 
11

 
 
33

 
58

 
102

Income from discontinued operations
 
28

 
 
17

 

 
45

NET INCOME
 
$
39

 
 
$
50

 
$
58

 
$
147



35


 
 
Predecessor
 
 
 
 
 
 
Year Ended December 31, 2011
 
Pro forma adjustments
 
Pro forma year ended December 31, 2011
OPERATING REVENUES
 
$
1,997

 
$

 
$
1,997

OPERATING EXPENSES:
 
 
 
 
 
 
Cost of natural gas and other energy
 
965

 

 
965

Operating, maintenance and general
 
373

 
(16
)
(a)
357

Depreciation and amortization
 
204

 
25

(b)
229

Taxes, other than on income and revenues
 
42

 

 
42

Total operating expenses
 
1,584

 
9

 
1,593

OPERATING INCOME
 
413

 
(9
)
 
404

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
Interest expense
 
(218
)
 
38

(c)
(180
)
Earnings from unconsolidated investments
 
99

 
(93
)
(d)
6

Other, net
 

 

 

Total other expenses, net
 
(119
)
 
(55
)
 
(174
)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
 
294

 
(64
)
 
230

Income tax expense
 
80

 
5

(e)
85

INCOME FROM CONTINUING OPERATIONS
 
214

 
(69
)
 
145

Income from discontinued operations
 
41

 

 
41

NET INCOME
 
$
255

 
$
(69
)
 
$
186


(a)
To eliminate the merger-related costs incurred by the Company in connection with the ETE Merger, including change in control and severance costs. These costs are eliminated from the Company’s pro forma income statement because such costs would not have a continuing impact on the Company’s results of operations.
(b)
To record incremental depreciation on the excess purchase price allocated to property, plant and equipment based on a weighted average useful life of 24 years.
(c)
To adjust amortization included in interest expense to (i) reverse historical amortization of financing costs and fair value adjustments related to debt and (ii) record pro forma amortization related to the pro forma adjustment of the Company’s debt to fair value.
(d)
To adjust earnings from unconsolidated investments to (i) eliminate historical earnings related to Citrus to give effect to the transfer of the Company’s interest in Citrus in connection with the ETE Merger and (ii) record incremental earnings from the Company’s investment in ETP common units received in connection with the transfer of Citrus.
(e)
To reflect income tax impacts from the pro forma adjustments to pre-tax income, including the elimination of the dividend received deduction recorded in the historical income tax provision for the predecessor periods in connection with the Company’s investment in Citrus.

Analysis of Supplemental Pro Forma Financial Information
Following is a discussion of the significant items impacting the pro forma results for the year ended December 31, 2012 compared to pro forma results for the year ended December 31, 2011.
Pro forma operating revenues and cost of natural gas and other energy decreased between periods primarily due to the actual results from the Company’s Gathering and Processing segment attributable to (i) lower throughput volumes in the 2012 period as a result of processing plant outages and producer well freeze-offs resulting from unusually cold weather in early 2012, and (ii) the impact of lower market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $2.70 per MMBtu and $0.98 per gallon in the 2012 period versus $3.86 per MMBtu and $1.33 per gallon in the 2011 period.
Pro forma interest expense decreased between periods primarily due to the term loan repayment in February 2012.


36


OTHER MATTERS

Off-Balance Sheet Arrangements and Aggregate Contractual Obligations

The Company does not have any material off-balance sheet arrangements other than that as noted in Note 8 to our consolidated financial statements.

The following table summarizes the Company’s expected contractual obligations by payment due date as of December 31, 2012, excluding those obligations of our disposal group.

 
 
Contractual Obligations
 
 
Total
 
2013
 
2014
 
2015
 
2016
 
2017
 
2018 and
thereafter
Long-term debt  (1) (2)
 
$
3,098

 
$
251

 
$
1

 
$
456

 
$
211

 
$
301

 
$
1,878

Natural gas purchases  (3)
 
31

 
3

 
3

 
3

 
3

 
3

 
16

Transportation contracts
 
31

 
2

 
7

 
7

 
7

 
7

 
1

Natural gas storage contracts   (4)
 
119

 
26

 
26

 
20

 
15

 
14

 
18

Operating lease payments
 
127

 
20

 
16

 
15

 
8

 
7

 
61

Interest payments on debt (5)
 
2,306

 
158

 
149

 
142

 
138

 
137

 
1,582

Fractionation contract
 
280

 
27

 
33

 
37

 
38

 
38

 
107

Other   (6)
 
39

 
5

 
4

 
4

 
5

 
5

 
16

 
 
$
6,031

 
$
492

 
$
239

 
$
684

 
$
425

 
$
512

 
$
3,679


(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, 2012, the Company was in compliance with all of its covenants.  See Note 8 to our consolidated financial statements.
(2) 
The long-term debt principal payment obligations exclude $185 million of unamortized debt premium as of December 31, 2012.
(3) 
The Company has tariffs in effect for all its utility service areas that provide for recovery of its purchased natural gas costs under defined methodologies.
(4) 
Represents charges for third party natural gas storage capacity.
(5) 
Interest payments on debt are based upon the applicable stated or variable interest rates as of December 31, 2012.  Includes approximately $1.12 billion of interest payments associated with the Junior Subordinated Notes due November 1, 2066.
(6) 
Various other contractual obligations. Excludes non-current deferred tax liabilities of $1.59 billion due to uncertainty of the timing of future cash flows for such liabilities

Contingencies

See Note 14 to our consolidated financial statements.

Inflation

The Company believes that inflation has caused, and may continue to cause, increases in certain operating expenses, and will continue to require higher capital replacement and construction costs.  In the Transportation and Storage and Distribution segments, the Company continually reviews the adequacy of its rates in relation to such increasing cost of providing services, the inherent regulatory lag experienced in adjusting its rates and the rates it is actually able to charge in its markets.

Regulatory

See Note 19 to our consolidated financial statements.


37


Rate Matters

Trunkline LNG Cost and Revenue Study.  On July 1, 2009, Trunkline LNG filed a Cost and Revenue Study with respect to the Trunkline LNG facility expansions completed in 2006, in compliance with FERC orders.  Such filing, which was as of March 31, 2009, reflected an annualized cost of service level for these expansions of $55 million, less than the associated actual revenues during the same period of $69 million.  BGLS filed a motion to intervene and protest on July 14, 2009.  By order dated July 26, 2010, FERC determined that since (i) Trunkline LNG has fixed negotiated rates with BGLS through 2015, which would be unaffected by any rate change that might be determined through hearing at this time, and (ii) current costs and revenues are not necessarily representative of Trunkline LNG’s costs and revenues at the termination of the negotiated rate period in 2015, there was no reason to expend FERC’s and the parties’ resources on a Natural Gas Act Section 5 proceeding at this time.  The order is final and not subject to rehearing.

See Note 19 to our consolidated financial statements for information related to the Company’s other rate matters.

LNG Export License.  On July 22, 2011, the United States Department of Energy, Office of Fossil Energy issued an order authorizing Lake Charles Exports, LLC, an entity owned by subsidiaries of the Company and BG Group plc, to export domestically produced LNG by vessel from Trunkline LNG’s Lake Charles LNG terminal.  The authorization, for a 25-year term beginning on the earlier of the date of first export or 10 years from the issuance of the order, permits export of up to approximately 2 Bcf/d to countries that have or will enter into a free trade agreement (FTA) with the United States that requires national treatment for trade in natural gas.  Lake Charles Exports, LLC is permitted to use the authorization to export LNG on its own behalf or as an agent for BGLS.  A proceeding for approval to export to non-FTA countries is ongoing. Another affiliate of the Company, Trunkline LNG Export, LLC has also filed with the United States Department of Energy, Office of Fossil Energy for LNG export authorization to export up to approximately 2 Bcf/d to FTA and non-FTA countries. This authorization is non-additive to the LCE authorization request, but is requested by Trunkline LNG Export, LLC to provide greater flexibility and optionality in their potential marketing of LNG. The companies are developing plans to install liquefaction facilities at the Lake Charles terminal to export LNG. Modifications to the Lake Charles terminal would be subject to approval by the FERC.  The Company and BG Group plc have not finalized the economic terms of their arrangement, but the Company expects that any such arrangement will take into account, among other things, the December 31, 2015 termination of certain contracted rates at the existing Trunkline LNG terminal, which otherwise revert to tariff rates in 2016, and the term of BGLS contracts related to the Trunkline LNG terminal, which otherwise all expire in 2030.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, 2012, the interest rate on 78% of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At December 31, 2012, $18 million was included in derivative instruments - liabilities and $59 million was included in deferred credits in the consolidated balance sheet related to the fixed-rate interest rate swaps on $525 million of the $600 million Junior Subordinated Notes due 2066.

At December 31, 2012, a 100 basis point change in the annual interest rate on all outstanding floating-rate debt would correspondingly change the Company’s interest payments by $7 million annually.  If interest rates change significantly, the Company may take actions to manage its exposure to the change.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the year ended December 31, 2012 was not material to the Company.

See Note 11 and Note 8 to our consolidated financial statements.

Commodity Price Risk

Gathering and Processing Segment.  The Company markets natural gas and NGL 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

38


also the risks associated with unmatched positions and market fluctuations.  The Company is required to record its commodity derivative financial instruments at fair value, which is affected by commodity exchange prices, over-the-counter quotes, volatility, time value, credit and counterparty credit risk 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 NGL, the Company may use a combination of (i) natural gas puts, price swaps and basis swaps, (ii) NGL price swaps, (iii) NGL processing spread puts and swaps, and (iv) other exchange-traded futures and options.  These derivative financial instruments allow the Company to preserve value and protect margins.

The Company realizes NGL, NGL processing spread and/or natural gas volumes from the contractual arrangements associated with the natural gas treating and processing services it provides.  Forecasted NGL, NGL processing spread 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;
limitations on treating capacity;
higher than anticipated fuel, flare and unaccounted-for natural gas levels;
impact of commodity prices in general;
decline in drilling and/or connections of new supply;
limitations in available natural gas and NGL take-away capacity;
reduction in NGL available from wellhead supply;
lower than expected recovery of NGL from the inlet natural gas stream;
lower than expected receipt of natural gas volumes to be processed;
limitations on NGL fractionation capacity;
renegotiation of existing contracts;
change in contracting practices vis-à-vis type(s) of processing contracts;
competition for new wellhead supplies; and
changes to environmental or other laws and regulations.

The following table summarizes SUGS’ principal commodity derivative instruments as of December 31, 2012 (all instruments are settled monthly), based upon historical and projected operating conditions and processable volumes.

Instrument Type
 
Index
 
Average Fixed Price (per MMBtu)
 
2013 Volumes (MMBtu/d) (2)
 
Fair Value of Assets (Liabilities)
 
 
 
 
 
 
 (in millions)
Natural Gas - Cash Flow Hedges:   (1)
 
 
 
 
 
 
Receive-fixed swap
 
NYMEX Swap
 
$
3.24

 
28

 
$
(3
)
Pay-fixed swap
 
NYMEX Swap
 
$
3.93

 
(15
)
 
(2
)
 
 
 
 
Total
 
13

 
$
(5
)

(1) 
The Company’s natural gas swap arrangements have been designated as cash flow hedges.  The effective portion of changes in the fair value of the cash flow hedges 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.
(2) 
All volumes are applicable to the period January 1, 2013 to December 31, 2013, with 72% of the volumes settled against Gas Daily - El Paso Permian and 28% of the volumes settled against Gas Daily – Waha.


At December 31, 2012, excluding the effects of hedging and assuming normal operating conditions, the Company estimates that a change in price of $0.01 per gallon of NGL and $1.00 per MMBtu of natural gas would impact annual gross margin by approximately $1 million and $14 million, respectively.  Such commodity price risk estimates do not include any effect on demand for the Company’s services that may be caused by, or arise in conjunction with, price changes.  For example, a change in the gross processing spread may cause some ethane to be sold in the natural gas stream, impacting gathering and processing margins, natural gas deliveries and NGL volumes shipped.

Transportation and Storage Segment.  The Company is exposed to some commodity price risk with respect to natural gas used in operations by its interstate pipelines.  Specifically, the pipelines receive natural gas from customers for use in generating

39


compression to move the customers’ natural gas.  Additionally, the pipelines may have to settle system imbalances when customers’ actual receipts and deliveries do not match.  When the amount of natural gas utilized in operations by the pipelines differs from the amounts provided by customers, the pipelines may use natural gas from inventory or may have to buy or sell natural gas to cover these or other operational needs, resulting in commodity price risk exposure to the Company.  In addition, there is other indirect exposure to the extent commodity price changes affect customer demand for and utilization of transportation and storage services provided by the Company.  At December 31, 2012, there were no hedges in place with respect to natural gas price risk associated with the Company’s interstate pipeline operations.

Distribution Segment Economic Hedging Activities.  The Company enters into financial instruments to mitigate price volatility of purchased natural gas passed through to customers in its Distribution segment. The cost of the derivative products and the settlement of the respective obligations are recorded through the natural 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 sheets.  As of December 31, 2012, the fair values of the contracts, which expire at various times through December 2013, were included in the consolidated balance sheet as liabilities held-for-sale, with matching adjustments to deferred cost of natural gas of $8 million.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements starting on page F-1 of this report are incorporated by reference.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE

None.

ITEM 9A.  CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2012.
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 GAAP, 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 GAAP, 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. Pursuant to the rules of the SEC, Management’s attestation report regarding internal control over financial reporting was not subject to attestation by the Company’s independent registered public accountant. As such, this Form 10-K does not contain an attestation report of the Company’s independent registered public accountant regarding internal control over financial reporting.

40


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. 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, 2012.

Changes In Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.  OTHER INFORMATION.

None.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Item 10, Directors, Executive Officers and Corporate Governance, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 11.  EXECUTIVE COMPENSATION.

Item 11, Executive Compensation, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Item 13, Certain Relationships and Related Transactions, and Director Independence, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.


41


ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES.
The Audit Committee of the Board of Directors of ETE appointed Grant Thornton LLP as our principal accountant to conduct the audit of our financial statements for the year ended December 31, 2012 on April 16, 2012.  PricewaterhouseCoopers LLC served as our independent registered public accountant for the year ended December 31, 2011.  The approval of Grant Thornton LLP occurred subsequent to the ETE merger but prior to the Holdco Transaction. 
The following table sets forth fees billed by Grant Thornton LLP and PricewaterhouseCoopers LLC for the audits of our annual financial statements and other services rendered:
 
Grant Thornton LLP
 
Pricewaterhouse-Coopers LLC
 
2012
 
2011
Audit fees (1)
$
1,475,000

 
$
2,965,000

Audit related fees (2)
25,000

 

Total
$
1,500,000

 
$
2,965,000

 
(1) 
Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting.
(2) 
Represents fees related to the service organization control report on the Company’s centralized data center.
Subsequent to the Holdco Transaction, the ETP Audit Committee is responsible for the oversight of our accounting, reporting and financial practices, pursuant to the charter of the ETP Audit Committee. The ETP Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The ETP Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The ETP Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the ETP Audit Committee.
The ETP Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
the auditors’ internal quality-control procedures;
any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
the independence of the external auditors;
the aggregate fees billed by our external auditors for each of the previous two years; and
the rotation of the lead partner.

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this Report:

1)
Financial Statements - see Index to Financial Statements appearing on page F-1.
2)
Financial Statement Schedules - None.
3)
Exhibits - see Index to Exhibits set forth on page E-1.



42


SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
SOUTHERN UNION COMPANY
 
 
(Registrant)
 
 
 
 
 
 
 
 
 
Date:
March 1, 2013
By:
 
 /s/   Martin Salinas, Jr.
 
 
 
 
Martin Salinas, Jr.
 
 
 
 
Chief Financial Officer (duly authorized to sign on behalf of the registrant)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated:
Signature
 
Title
 
Date
 
 
 
 
 
/s/ Kelcy L. Warren
     Kelcy L. Warren
 
Chief Executive Officer
(principal executive officer)
 
March 1, 2013
 
 
 
 
 
/s/ Martin Salinas, Jr.
     Martin Salinas, Jr.
 
Chief Financial Officer
(principal financial officer)
 
March 1, 2013
 
 
 
 
 
/s/ Marshall S. McCrea, III
     Marshall S. McCrea, III
<