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, 2006

or

¨

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

For the transition period from                      to                      

Commission file number 333-110979

SOUTHERN STAR CENTRAL CORP.

(Exact name of registrant as specified in its charter)

Delaware	04-3712210
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
4700 Highway 56, Owensboro, Kentucky	42301
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:  (270) 852-5000

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:  None

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Exchange Act Rule 12b-2).    

Large accelerated filer ¨  Accelerated filer ¨  Non-accelerated filer x

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.  None

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date. 100 shares of common stock as of March 14, 2007.

TABLE OF CONTENTS

2006 FORM 10-K

SOUTHERN STAR CENTRAL CORP.

Forward-Looking Statements		1
	PART I.
Item 1.	Business	2
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	15
Item 2.	Properties	15
Item 3.	Legal Proceedings	16
Item 4.	Submission of Matters to a Vote of Security Holders	17
	PART II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6.	Selected Financial Data	18
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	19
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 8.	Financial Statements and Supplementary Data	28
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	28
Item 9A.	Controls and Procedures	28
Item 9B.	Other Information	28
	PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	29
Item 11.	Executive Compensation	32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	36
Item 13.	Certain Relationships and Related Transactions, and Director Independence	36
Item 14.	Principal Accountant Fees and Services	37
	PART IV.
Item 15.	Exhibits and Financial Statement Schedules	37

FORWARD-LOOKING STATEMENTS

The information in this report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify some of the statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statement s, factors that could cause actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

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future utilization of pipeline capacity, which can depend on energy prices and the prices for natural gas available on our system, competition from other pipelines and alternative fuels, the general level of natural gas demand, decisions by customers not to renew expiring natural gas transportation contracts, adequate supplies of natural gas, the construction or abandonment of natural gas customer facilities, weather conditions and other factors beyond our control;

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operational risks and limitations of our pipeline system and of interconnected pipeline systems;

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the ability to raise capital and fund capital expenditures in a cost-effective manner;

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changes in federal, state or local laws and regulations to which we are subject, including allowed rates of return and related regulatory matters, regulatory disclosure obligations, the regulation of financial dealings between us and our affiliates, and tax, environmental and employment laws and regulations;

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the ability to manage costs;

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the ability of our customers to pay for services;

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environmental liabilities that are not covered by an indemnity or insurance;

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the ability to expand into new markets as well as the ability to maintain existing markets;

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the ability to obtain governmental and regulatory approval of various expansion projects;

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the cost and effects of legal and administrative proceedings;

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the effect of accounting interpretations and changes in accounting policies;

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restrictive covenants contained in various instruments applicable to us and our subsidiaries which may restrict our ability to pursue our business strategies;

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changes in general economic, market or business conditions; and

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economic repercussions from terrorist activities and the government’s response to such terrorist activities.

Other factors and assumptions not identified above, including without limitation, those described under the heading “Risk Factors” below may also impact these forward-looking statements. The failure of those other assumptions to be realized, as well as other factors, which may or may not occur, may also cause actual results to differ materially from those projected. Except as required by law, we assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.

PART I.

Item 1. Business

General

References to “Southern Star” refer to Southern Star Central Corp. and references to “we,” “us,” “our,” and “the Company,” refer to Southern Star Central Corp. and to its wholly-owned subsidiary, Southern Star Central Gas Pipeline, Inc., or Central.

Southern Star Central Corp.

On August 11, 2005, GE Energy Financial Services, Inc., or GE, and Caisse de depot et placement du Quebec, or CDP, through their indirect ownership of EFS-SSCC Holdings, LLC, or Holdings, acquired all of the outstanding capital stock of Southern Star Central Corp., or Southern Star, owned by AIG Highstar Capital L.P., or Highstar, for $389.1 million in cash, plus the assumption of $467.9 million in long-term debt, including current maturities and Series A Preferred Stock, such that following the transaction Holdings owned all of the outstanding capital stock of Southern Star. This transaction is hereinafter referred to as the acquisition.

Southern Star was incorporated in Delaware in September 2002 and operates as a holding company for its regulated natural gas pipeline operations and development opportunities. Central was incorporated in Delaware in January 1922 and is Southern Star’s only operating subsidiary and the sole source of its operating revenues and cash flows. Southern Star also owns the development rights for a natural gas pipeline in the Rocky Mountain region, which could be developed in the future.

Southern Star Central Gas Pipeline, Inc.

Central is an interstate natural gas transportation company that owns and operates a natural gas pipeline system, including facilities for natural gas transmission and natural gas storage with office headquarters in Owensboro, Kentucky. The pipeline system operates in Colorado, Kansas, Missouri, Nebraska, Oklahoma, Texas and Wyoming, and serves customers in these seven states, including major metropolitan areas in Kansas and Missouri, its main market areas. As of December 31, 2006, Central’s natural gas pipeline system had a mainline delivery capacity of approximately 2.4 billion cubic feet, or Bcf, of natural gas per day and is composed of approximately 6,000 miles of mainline and branch transmission and storage pipelines.

The pipeline system has a mainline that extends from gas-producing regions in Kansas, Oklahoma, Wyoming and Texas to Central’s major markets in Kansas and Missouri. Many segments of the pipeline have bi-directional flow capability. This flexibility allows Central to respond to regional supply and demand fundamentals and to optimize the utilization of Central’s pipeline infrastructure. The pipeline system has direct access to major supply basins in Kansas, Oklahoma, Texas, Colorado and Wyoming and has approximately 21 receipt and/or delivery points with major interstate and intrastate pipelines giving customers access to other supply basins and markets.

Central operates eight underground storage fields, seven in Kansas and one in Oklahoma, with an aggregate natural gas storage capacity of approximately 43 Bcf and an aggregate delivery capacity of approximately 1.2 Bcf of natural gas per day. The combination and market proximity of Central’s integrated transportation and storage system allow it to provide multiple, high-value services to its customers. Central’s service offerings include combined transportation/storage, transportation, storage, park and loan, and pooling. For the year ended December 31, 2006, 92% of Central’s operating revenues were obtained through monthly firm reservation charges (“rent” charges under firm contracts) and 8% through commodity charges (“usage” charges based on volumes actually transported under firm and interruptible contracts).

Central’s principal service is the delivery of natural gas to local natural gas distribution companies in the major metropolitan areas it serves. At December 31, 2006, Central had transportation customer contracts with approximately 131 shippers. Central transports natural gas to approximately 582 delivery points, including natural gas distribution companies and municipalities, power plants, interstate and intrastate pipelines, and large and small industrial and commercial customers. The substantial majority of Central’s business is conducted under long-term contracts ranging from one to 30 years. At December 31, 2006, the average remaining contract life on a volume-weighted basis was approximately six years.

For the year ended December 31, 2006, approximately 83% of the Company’s total operating revenues were generated from long-term contracts with its top ten customers. Natural gas transportation services for the two largest customers, Missouri Gas Energy, or MGE, a division of Southern Union Company (approximately 31%), and Kansas Gas Service Company, or KGS, a division of ONEOK, Inc. (approximately 27%), accounted for 58% of operating revenues for the year ended December 31, 2006. MGE sells or resells natural gas to residential, commercial and industrial customers principally in certain major metropolitan areas of Missouri. KGS sells or resells natural gas to residential, commercial and industrial customers principally in certain major metropolitan areas of Kansas. Central has had significant business relationships with both of these customers or their predecessors for more than 20 years. No other customer accounted for more than 10% of the Company’s revenues in 2006.

As with all interstate natural gas pipelines, Central’s transmission, storage, and related activities are subject to regulation by the Federal Energy Regulatory Commission, or FERC, and, as such, rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and its accounting, among other things, are subject to regulation.

Pipeline Operations

The system receives natural gas supplies from the major production areas of the Kansas Hugoton region, Oklahoma producing region, Wyoming Rocky Mountain region and Texas panhandle producing region. The Kansas Hugoton region is a mature basin with substantial reserves. We expect that gradual production declines in this area will be offset by new supplies from other regions, particularly the Rocky Mountain region. Southern Star believes that the Rocky Mountain region has substantial potential for future drilling and production. Central’s Rawlins-Hesston line, which extends from Wyoming to Kansas, generally operates at full capacity. We believe that the strategic location of our pipeline system will continue to provide access to abundant natural gas supplies in the future.

The system has 21 pipeline interconnects with major interstate and intrastate pipelines that provide customers the opportunity to access natural gas from a variety of U.S. basins. Of the 21 interconnects, six are delivery points; nine are receipt points; and six are bi-directional (both receipt and delivery) points. The large number and geographic diversity of interconnects provide Central’s customers with a high degree of flexibility in sourcing natural gas supplies and independence from any single interconnect. These interconnects allow the interaction of Central’s system with a substantial portion of the midwestern natural gas market, as well as access to major domestic pricing hubs.

Central currently has 40 compressor stations with approximately 206,000 certificated horsepower. Twenty-eight of Central’s compressor stations are controlled remotely by its Supervisory, Control and Data Acquisition, or SCADA, and station automation systems. The SCADA system gathers data from various points on the pipeline such as compressor stations, chromatographs and metering stations. Central’s Gas Control Center remotely controls the operation of the automated engines at the compressor stations.

Central has experienced average daily transportation throughput volumes as indicated in the tables below:

	Trillion British thermal units (TBtu) per day
Transportation Volumes:
	2006	2005	2004
Market area	0.5	0.6	0.5
Production area	0.3	0.2	0.2
Production market interface	0.4	0.5	0.4

This compares to Central’s average daily firm reserved capacity indicated below:

	TBtu per day
Reserved Capacity:
	2006	2005	2004
Market area	1.9	1.9	1.9
Production area	0.4	0.4	0.5
Production market interface	0.8	0.8	0.8

In addition, Central’s firm storage deliverability capacity has been 1.2 TBtu/day for each of these three years.

Storage Operations

Central’s storage facilities are strategically located in close proximity to its key markets. Central operates eight underground storage fields, seven in Kansas and one in Oklahoma, with an aggregate natural gas storage capacity of approximately 43 Bcf and an aggregate delivery capacity of approximately 1.2 Bcf of natural gas per day.

Central’s storage services are a key component of its service offerings. During periods of peak demand, approximately 50% of the natural gas delivered to customers is supplied from Central’s storage fields. Central’s customers inject natural gas into these fields in warm months, when natural gas demand is often lower, and withdraw natural gas during colder, peak demand months. Storage also provides flexibility to manage weather sensitive loads, such as residential heating, with no disruption in service. Storage capacity enables Central’s system to operate uniformly and efficiently during the year, as well as allowing it to offer storage services in addition to its transportation services. Central is the only interstate natural gas pipeline serving major metropolitan areas in its main market area that offers customers integrated on-system storage and transportation services.

Services

Transportation/Storage. Central offers a no-notice service that combines its firm transportation and firm storage services to enable its customers to manage their weather sensitive needs. No-notice service allows customers to pull their gas from storage with little or no notice and requires Central to reserve a specified amount of capacity for those customers. This service has a fixed charge based upon the capacity reserved plus a small commodity charge and fuel retention charge based on the volume of the gas actually transported. The storage component of this service provides the customer with the flexibility to inject natural gas supplies into storage during the non-winter months when the cost of natural gas supplies is generally lower. During the winter months, the customer withdraws the stored natural gas supplies as needed to satisfy its weather sensitive needs. On peak days, customers rely on the storage component of this fi rm transportation and firm storage service to satisfy up to two-thirds of their natural gas supply needs. No-notice service accounted for approximately 65% of our 2006 operating revenues, and as of December 31, 2006, accounted for approximately 74% of Central’s firm market area capacity, 42% of its firm production area capacity and 88% of its firm storage deliverability.

Transportation. Central offers both firm and interruptible transportation service. Firm transportation service requires Central to reserve pipeline capacity at certain receipt and delivery points on its system. Firm customers generally pay based on the quantity of capacity reserved regardless of use plus a small commodity and fuel retention charge paid on the volume of gas actually transported. Firm transportation revenues tend not to vary over the term of the contract, except to the extent that Central’s rates for firm transportation services change. Under Central’s interruptible transportation service, Central agrees to transport gas for customers on a daily basis but does not reserve pipeline capacity for these services. Interruptible service customers pay only for the transportation of the volume of gas actually transported. Central transports natural gas from a receipt point to a delivery point principally under con tracts with local natural gas distribution companies, power generators, industrials, marketers and producers. This service accounted for approximately 30% of our 2006 operating revenues, and as of December 31, 2006, comprised approximately 26% of Central’s firm market area capacity and 58% of its firm production area capacity.

Storage. Central provides both firm and interruptible storage service. Similar to Central’s transportation services, customers choose firm or interruptible storage services based on the importance of factors such as availability, price of service and the amount of storage capacity needed. Firm storage customers receive a specific amount of storage capacity including injection and withdrawal rights, while interruptible customers receive storage capacity when it is available. Central has approximately 1.2 TBtu/day of firm storage deliverability capacity and 43 TBtu of on-system natural gas storage capacity. Central’s storage service allows shippers to store natural gas close to their customers. Central’s storage facilities are strategically located in close proximity to its key market areas. The majority of the firm storage capacity is contracted as a component of the transportation/storage service (approximately 88% of the firm storage deliverability). The stand alone firm storage service (approximately 12% of firm storage deliverability) and interruptible storage service accounted for approximately 2% of our operating revenues for the year ended December 31, 2006.

Park and Loan. Central’s “park and loan” service is an interruptible service that provides customers with the flexibility to balance their supplies with market demand. Parking allows customers to store delivered natural gas on the pipeline on a temporary basis. Loaning permits a shipper to borrow natural gas from Central’s system on a temporary basis and later return an identical quantity of natural gas at a designated point on the pipeline. This service accounted for approximately 3% of our operating revenues for the year ended December 31, 2006.

Pooling. Central’s pooling service allows customers to aggregate natural gas from many receipt points into a pool before selling the natural gas into the market and provides them with access to natural gas at competitive prices. This is a service offered by interstate pipelines to eligible customers at no additional charge over regular applicable rates. Central’s ability to provide this service from multiple supply regions distinguishes its pooling service, providing it with a competitive advantage.

Recent Market Initiatives

We actively pursue new markets for our services and the ability to enhance our deliverability to existing customers.  In many cases, the customer reimburses us for the cost of the facilities required to serve these markets.  The following is a summary of recent market initiatives:

Ozark Trails – Central placed the Ozark Trails expansion project in service on December 1, 2006.  The project cost approximately $11.4 million through December 31, 2006 and provides an incremental 24,592 dekatherms, or Dths, per day of gas for Southern Missouri Natural Gas and Missouri Gas Energy in the Southwestern portion of Missouri.  We expect that this expansion will result in an incremental $1.6 million in annual revenues.

City of Mulvane Delivery Point – The City of Mulvane, Kansas reimbursed Central for the cost of facilities designed to deliver approximately 6,000 Dths/day of the city’s gas requirements. The facilities were placed in service in the third quarter of 2006.

Current Market Initiatives

Bio-diesel/Ethanol Plants – Central is aggressively pursuing ethanol and bio-diesel locations that are targeted within the vicinity of its pipeline system.  There are currently six requests from interested parties to serve their proposed facilities.  These plants range from 600 Dths/day to 10,400 Dths/day of incremental volumes.

Recent Supply Initiatives

We actively pursue new gas supply connections to our system to provide customers additional supply options and flexibility to meet their demands.  In many cases, the operator of the gas supply point reimburses us for the cost of the facilities required to receive gas into our system.  The following is a summary of the recent gas supply points Central has added to its system:

KMIGT Grant Interconnect – This existing interconnect, located in Grant County, Kansas was converted to a system receipt point to allow incremental volumes to be received from the Kinder Morgan Interstate Gas Transmission pipeline system.  This location is designed for up to 60,000 Dths/day of incremental volumes to be received into the system.  This interconnect was placed in service in the second quarter of 2006.

Southeastern Kansas Pipeline – The operator for this receipt point located in Wilson County, Kansas reimbursed Central for the cost of facilities designed to receive approximately 50,000 Dths/day of gas into its system.  This location was placed in service in the first quarter of 2006.

BP Jayhawk/NNG – Northern Natural Gas installed a lateral to provide incremental volumes to the BP Jayhawk processing facility located in Grant County, Kansas.  This installation provided an incremental 48,000 Dths/day of supply to our system.  This project was placed in service in the fourth quarter of 2006.

Bluestem Operating Receipt Point – The operator of the Bluestem Operating receipt point located in Wilson County, Kansas reimbursed Central for the cost of facilities designed to receive 15,000 Dths/day of gas into Central’s pipeline system.  This project was placed in service in the second quarter of 2006.

Double Eagle Receipt Point – The operator of the Double Eagle receipt point located in Carbon County, Wyoming reimbursed Central for the cost of facilities designed to receive approximately 50,000 Dths/day of gas into Central’s pipeline system.  This project was placed in service in the first quarter of 2006.

SemGas Receipt Point – The operator of the SemGas receipt point located in Grant County, Oklahoma reimbursed Central for the cost of facilities designed to receive approximately 10,000 Dths/day of gas into Central’s pipeline system.  This project was placed in service in the first quarter of 2006.

Various Other Receipt Points – During 2006, nine other receipt point operators in Kansas reimbursed Central for the cost of facilities designed to receive approximately 64,000 Dths/day of gas into Central’s system.

Current Supply Initiatives

Waynoka Supply Project – This project will connect Central’s system to the Anadarko gas processing plant in Woods County, Oklahoma.  This facility will have a nominal processing capacity of approximately 200,000 Dths/day.  Construction will include 14 miles of 20-inch pipeline and a measurement setting.  This project is scheduled to be placed in service in the third quarter of 2007 at an estimated total cost of $11.5 million.

Various Other Receipt Points – Five other receipt point operators will reimburse us for the cost of facilities designed to receive a combined total of approximately 33,000 Dths/day.  These projects are anticipated to be in service by the second quarter of 2007.

Expansion Projects

We generally undertake expansion projects only when we have firm transportation and/or storage commitments from customers that we believe will provide revenues sufficient for us to earn our regulated allowed return on investment.  These customer commitments may take the form of actual reimbursement to us for the cost of the project or long-term firm capacity contracts for increased transportation or storage

Prairie Pride – Central has executed an agreement with Prairie Pride, Inc. to serve a new bio-diesel/cogeneration facility located in Vernon County, Missouri.  This project will require construction of approximately two miles of eight-inch lateral pipeline and a delivery station at an estimated project cost of $1.3 million.  These facilities will deliver up to 5,400 Dths/day of firm transportation that are expected to generate annual revenues of approximately $0.2 million.  The in-service date is targeted for June 1, 2007.

Westar Emporia – Westar Energy, Inc., or Westar, has announced a new 600 megawatt, or MW, natural gas-fired power generation plant in Lyon County, Kansas.  Westar has signed a letter of intent for Central to serve the plant.  The construction project will be completed in phases during 2007 and 2008 with an initial in-service date of April 1, 2008.  The project will require construction of approximately five miles of 24-inch lateral pipeline, measurement facilities and the addition of horsepower at Central’s Hesston, Kansas compressor station at a total estimated cost of $13.2 million, approximately $5.9 million of which will be spent in 2007.  The project is anticipated to ultimately generate annual revenues of $3.6 million.  

Midwest Goodman – Midwest Energy, Inc., or Midwest, is installing a new 75 MW natural gas power generation peaking facility in Ellis County, Kansas.  Midwest has a signed letter of intent for Central to serve the plant.  This project requires construction of 12 miles of six-inch lateral pipeline and measurement facilities at an estimated total cost of $5.0 million, the majority of which will be spent in 2007.  The in-service date of this project is February 15, 2008 and is expected to generate average annual revenues of approximately $0.5 million.

Competition

Central competes primarily with other interstate and intrastate pipelines for the transportation of natural gas, and natural gas competes with other forms of energy available to Central’s customers, including electricity, coal, and fuel oils. The principal elements of competition among pipelines are rates, terms of service, access to supply basins, and flexibility and reliability of services. Central competes primarily with other interstate pipelines in the Kansas City metropolitan area and in Wichita, Kansas. One of the interstate pipelines is an affiliated company with one of Central’s largest customers, MGE. Central’s primary competitors in these markets are Kansas Pipeline Company and Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline.

Seasonality

Substantially all of Central’s operating revenues are generated from the collection of fixed monthly reservation fees for transportation and/or storage services. As a result, fluctuations in natural gas prices and actual volumes transported and stored have a limited impact on Central’s operating revenues. Since the fixed monthly reservation fees are generally consistent from month to month, Central’s operating revenues do not fluctuate materially from season to season.

Generally, construction and maintenance on Central’s pipeline occurs during May through October when volume throughput is usually lower than during the winter heating season. As such, operating and maintenance expenses are generally higher in the second and third quarters and the majority of our capital expenditures are incurred during this time.

Regulation

FERC Regulation. The siting of Central’s pipeline system and its transportation and storage of natural gas in interstate commerce for its customers and certain related customer services is subject to regulation by the FERC under the Natural Gas Act, or NGA, of 1938 and under the Natural Gas Policy Act, or NGPA, of 1978, and as such, its rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and its accounting, among other things, are subject to regulation. Central holds certificates of public convenience and necessity issued by the FERC authorizing the siting, ownership and operation of its pipelines and related facilities, including storage fields, which are considered jurisdictional and for which certificates are required under the NGA. The pipeline’s tariff—a compilation of the pipeline’s rules, and operating and commercial practices which are binding on the pipeline and its customers—is a regulatory document and cannot be modified without public notice and FERC approval.

Central’s rates and charges for the transportation of natural gas and related services in interstate commerce are subject to regulation by the FERC. FERC regulations and Central’s FERC-approved tariff allow it to establish and collect rates designed to give it an opportunity to recover all actually and prudently incurred operations and maintenance costs of its pipeline system, taxes, interest, depreciation and amortization and a regulated equity return.

Generally, rates charged by interstate natural gas companies may not exceed the just and reasonable rates approved by the FERC. In addition, interstate natural gas companies are prohibited from granting any undue preference to any person, or maintaining any unreasonable difference in their rates or terms and conditions of service. FERC regulations also generally prohibit Central from preventing shippers from freely assigning their capacity to other parties, provided that the assignee meets the credit rating standards imposed by Central’s FERC tariff and that the assignment is operationally feasible to accommodate.

The FERC was recently given additional regulatory authority under the Public Utility Holding Company Act of 2005, or PUHCA 2005. PUHCA 2005 was enacted in August 2005 as part of the Energy Policy Act of 2005 and became effective in February 2006. Among other things, PUHCA 2005 gives the FERC access to the books and records of any holding company or affiliate of an electric or gas utility relevant to the rates of that electric or gas utility or any affiliated natural gas pipeline company subject to the FERC’s jurisdiction (such as Central). The FERC was also given authority to allocate costs within holding company systems, including where a service company is involved, and state utility regulatory authorities were given similar books and records access rights. Because parent companies of the Company may be holding companies for purposes of PUHCA 2005, Central could be affected by this new legislation. The FERC’s regulations implementin g PUHCA 2005 are presently subject to rehearing by the FERC, and the FERC’s PUHCA 2005 notification and related filing requirements were stayed by the FERC in a February 27, 2006 Order until 14 days after the FERC issued an Order on the rehearing of its PUHCA 2005 regulations. On July 20, 2006, the FERC issued its Order on Rehearing which adopted certain revisions to the PUHCA 2005 regulations, including a clarification requested by the interstate pipeline industry which effectively confirmed Central’s exemption from these new rules.

Rates. Natural gas pipeline companies subject to FERC jurisdiction may from time to time propose revised rates for their services in formal proceedings conducted by the FERC. Pipeline customers, state regulatory commissions and others are permitted to participate in the FERC rate case proceeding. In FERC rate case proceedings, the pipeline’s total cost of service is determined and is then divided among the various quantities and classes of service offered by the pipeline, resulting in a maximum rate for each type of service that the pipeline offers. For bona fide commercial reasons, a pipeline may offer customers discounts from the maximum rate if such discounts will increase the overall volumes shipped by the pipeline. Central provides no-notice service to local natural gas utilities, pursuant to which the utilities have flexible scheduling rights. In most locations, other than the Kansas City and Wichita metropolitan areas previously discussed under “Competition” above, there are presently no competitive pipeline alternatives. As a result, Central’s largest customers generally pay the maximum reservation rates for their firm service.

Central’s rates are categorized by area served, type of service and interruptibility. Central has divided its service territory into two discrete geographical areas for rate purposes: the production area and the market area. The production area is located generally in Wyoming, Colorado, Texas, Oklahoma and western Kansas. The market area is located generally in Missouri, Nebraska and eastern Kansas. Central’s rates are designed to create discrete transportation tariffs within the production area and the market area that are additive for the transportation of natural gas from the production area to the market area and vice versa. The FERC generally requires rates to reflect the distances that natural gas is transported, and Central’s separate, additive rates are designed to comply with this FERC requirement.

On April 30, 2004, Central filed a general rate case under FERC Docket No. RP04-276 which became effective November 1, 2004.  The case was settled and became final in 2005. The general rate proceeding increased Central’s transportation, storage, and related rates, and also provided for changes to a number of the terms and conditions of customer service in Central’s tariff. The terms of the settlement require Central to file a rate case to be effective no later than November 1, 2008.

Recent FERC Regulatory Orders. On November 17, 2005, the D.C. Court of Appeals vacated FERC Order 2004, or Order 2004, relating to Standards of Conduct for Transmission Providers and remanded the Order to the Commission. Order 2004 had expanded the Standards of Conduct to apply to all affiliates of transmission providers rather than just marketing affiliates who held capacity on the transmission provider.  The court found that there was no evidence of abuse by non-marketing affiliates to justify the Standards of Conduct being applied to those entities.  As opposed to requesting rehearing of the Order, on January 9, 2007, the FERC issued an interim rule (Order No. 690) reinstating the Standard of Conduct rules that were in effect under Order 497, prior to the issuance of Order 2004, and on January 18, 2007, issued a Notice of Proposed Rule Making proposing to make the interim rule permanent and seeking comments on various issues related to marketing affiliates and the Standards of Conduct that should apply to all transmission providers.   

Safety Regulations. Central is subject to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The NGPSA requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and to comply with such plans. Inspections and tests are performed at prescribed intervals to ensure the integrity of the pipeline system. These inspections, for example, include periodic corrosion surveys, testing of relief and over-pressure devices and periodic aerial inspections of the rights-of-way.

In 2002, the U.S. Congress enacted the Pipeline Safety Improvement Act, or PSIA, with final regulations implementing the PSIA issued in December 2003. The PSIA makes numerous changes to pipeline safety law, the most significant of which is the requirement that operators of pipeline facilities implement written integrity management programs. Such programs include a baseline integrity assessment of each facility located in high consequence areas that must be completed within ten years of the enactment of the PSIA. The PSIA and regulations will impose increased costs associated with new pipeline inspection and pipeline integrity program requirements; however, based on current information, we do not expect these costs to have a material adverse effect upon our earnings.

In 2002, the Kansas Corporation Commission, or KCC, promulgated the Kansas Underground Porosity Gas Storage Regulations to establish natural gas storage regulations for porosity natural gas storage fields located in the state of Kansas. These regulations impose numerous requirements including a geologic and hydro-geologic evaluation of storage fields, monitoring and reporting requirements and periodic inspections and testing of wells. Seven of the eight storage fields Central operates are located in the state of Kansas.

Central was granted “Provisional Operating Permits” for its seven Kansas storage facilities on October 15, 2003. The Provisional Operating Permits were to expire on October 15, 2005; however, Central requested and received extensions for the Provisional Operating Permits from the KCC pending completion of the applications for “Fully Authorized Operating Permits.” The Provisional Operating Permit extensions and Fully Authorized Operating Permit application due dates approved by the KCC are:

Field	Docket #	Fully Authorized Operating Permit Submittal Date	Provisional Operating Permit Extension Date
Elk City	S-013	1/31/2006	10/31/2007
Colony	S-014	6/12/2006	11/30/2007
Piqua	S-016	7/31/2006	1/31/2008
North Welda	S-019	10/31/2006	2/28/2008
Alden	S-018	1/31/2007	7/31/2008
McLouth	S-015	4/30/2007	5/31/2008
So. Welda	S-020	7/31/2007	4/30/2008

As of March 1, 2007, Central had submitted applications for Fully Authorized Permits for five of the seven Kansas storage facilities and is preparing the applications for Fully Authorized Permits for the remaining two storage facilities. Central has identified storage reservoir parameters at six of its Kansas storage fields that require updates to its existing FERC certificates. These updated certificates are being submitted to the FERC for approval as part of obtaining the Fully Authorized Operating Permits for those fields. The FERC approved the Colony Gas Storage Field application on May 19, 2006. The FERC certificate application for the Piqua Gas Storage Field was filed October 31, 2006 and the application for North Welda Storage Field was filed February 23, 2007. The information and data for the remaining FERC filings is being compiled. Central anticipates filing the three remaining FERC certificate applications in 2007 and 2008.

The Company anticipates that the Kansas Underground Porosity Gas Storage Regulations will result in increased costs to operate Central’s storage fields; however, based on current information, we do not expect the costs to have a material adverse effect upon earnings. Central’s capital expenditure program and maintenance budget includes estimated expenditures required to comply with these regulations.

Historically, with respect to those capital expenditures required to meet applicable safety standards and regulations, the FERC has granted the requisite rate relief so that, for the most part, such expenditures and a return thereon have been allowed to be recovered, to the extent that Central requests such recovery in a rate case before the FERC. The Company has no reason to believe the FERC will change that position. We believe that compliance with applicable safety requirements is not likely to have a material adverse effect upon our financial condition or results of operations.

Environmental Matters

Central is subject to federal, state and local statutes, rules and regulations relating to environmental protection, including the National Environmental Policy Act, the Clean Water Act, the Clean Air Act and the Resource Conservation and Recovery Act. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally subject Central to inspections and require it to obtain and comply with a wide variety of environmental licenses, permits and other approvals. Under the Clean Air Act, the U.S. Environmental Protection Agency, or EPA, has recently promulgated regulations addressing emissions from equipment present at typical natural gas compressor stations. These regulations include National Emission Standards for Hazardous Air Pollutants, or NESHAPs, for reciprocating internal combustion engines, stationary turbines, and glycol dehydration equipment in addition to regulations that address r egional transport of ozone (i.e. NOx SIP Call). There is no impact anticipated to Central’s existing operations based on an analysis of these regulations. The EPA has also promulgated a new ambient air quality standard for ozone, or the eight-hour standard, which is generally more stringent than the one-hour standard it replaces. Presently, all of Central’s facilities are located in areas designated as in “attainment” for compliance with the eight-hour standard. Therefore, the new standard does not impact Central’s existing operations at this time.

Central considers environmental assessment, remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, as they are prudent costs incurred in the ordinary course of business. The actual costs incurred will depend on the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors. Central has identified polychlorinated biphenyl, or PCB, contamination in air compressor systems, soils and related properties at certain compressor station sites and has been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, negotiations with certain environmental agencies concerning investigative and remedial actions relative to potential mercury contamination at certain natural gas metering sites have commenced. Central had accrued a liability o f approximately $4.6 million at December 31, 2005 and $3.7 million at December 31, 2006 representing the current estimate of future environmental cleanup costs, most of which is expected to be incurred over the next three to four years. Central currently plans to spend an estimated $1.0 million annually to remediate the PCB/mercury contamination. Central recovers approximately the same amount in its current rates each year. Central has environmental insurance, which provides an aggregate $25.0 million in coverage (subject to certain exclusions, limits and deductibles) for certain cleanup and remediation obligations. The policy covers, among other things, up to $10.0 million for costs incurred above the estimated cleanup cost of $8.6 million at the inception of the policy for PCB contamination at 19 compressor stations for a period of five years ending November 15, 2007. The Company currently does not expect the clean-up costs to be in excess of its estimate; therefore, we do not intend to renew the port ion of the policy covering expenses above the estimated clean-up cost that expires on November 15, 2007.

Central may be responsible for environmental cleanup and other costs at sites that it formerly or currently owns or operates and at third-party waste disposal sites. Central cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating cleanup costs at sites not yet identified. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liabilities on all potentially responsible parties. Environmental regulations may also require Central to install pollution control equipment at, or perform environmental remediation on, its facilities.

Historically, with respect to any capital expenditures required to meet applicable standards and regulations, the FERC has granted the requisite rate relief so that, for the most part, such expenditures and a return thereon have been allowed to be recovered pursuant to a general rate case. We have no reason to believe the FERC will change that position. We believe that compliance with applicable environmental requirements is not likely to have a material adverse effect upon our financial condition or results of operations.

Insurance

We maintain insurance coverage for our Company and our pipeline system in such amounts and covering such risks as is typically carried by companies engaged in similar businesses and owning similar properties in the same general areas in which we operate. Our insurance program includes general liability insurance, auto insurance, workers’ compensation insurance, non-owned aviation insurance, environmental insurance, all-risk property and business interruption insurance, terrorism insurance, employment practices liability, and excess liability insurance.

Employees  

As of December 31, 2006, the Company had 456 employees at Central and none at Southern Star. Central has a collective bargaining agreement with the International Union of Operating Engineers Local No. 647, or the Union, covering approximately 184 field employees. This agreement was renegotiated during 2004 for a four-year term to expire July 15, 2008. No strike or work stoppage has occurred at any of Central’s facilities during the last 20 years. We believe that the relationship between Central and the Union is positive. Central provides competitive benefits including medical, 401(k) and pension benefits for all employees.

Reports

We file annual, quarterly and current reports with the Securities and Exchange Commission, or SEC. Our SEC filings are available free of charge to the public over the Internet at the SEC’s website at www.sec.gov and on our website at www.southernstarcentralcorp.com as soon as reasonably practicable following the time that the documents are filed with or furnished to the SEC. You may also read and copy any document we file with the SEC at its public reference rooms at 450 Fifth Street, NW, Washington D.C. 20549, and in New York, NY and Chicago, IL. Please call the SEC at (800) 732-0330 for further information on the public reference rooms.

 Item 1A. Risk Factors

The Company faces certain risks in conducting its business that may impact our future results of operations, financial position, or cash flows.  Major risks that management has identified are as follows:

Risks Related to Our Business

Changes in our regulatory environment and recent events in the energy markets that are beyond our control may significantly affect our costs and access to capital markets.

Our rates and operations are subject to regulation by Federal regulators as well as the actions of the Federal and state legislatures and, in some respects, state and local regulators. Additionally, because of the volatility of natural gas prices in North America, the bankruptcy filings by certain energy companies and investigations by governmental authorities into energy trading activities, many energy and utility businesses have generally been under an increased amount of scrutiny by the public, state and Federal regulators, the capital markets, government anti-trust agencies and the rating agencies. Furthermore, the nature and degree of regulation of natural gas companies has changed significantly during the past 25 years and any further additional changes in regulations or new interpretation of existing regulations may result in increased costs or impede our ability to access capital markets.

We are subject to numerous environmental and safety laws and regulations that may increase our cost of operations, or expose us to liabilities, which are not recoverable through rates or insurance.

Laws and regulations relating to environmental protection and pipeline safety can result in increased capital expenditures required for compliance, operating costs and other expenditures. These laws and regulations generally subject us to inspections and require us to obtain and comply with a wide variety of licenses, permits and other approvals. Such environmental laws impose restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes. We cannot predict the initiation, outcome or effect of any action or litigation that may arise from applicable environmental or safety regulations. Existing environmental and safety regulations may be revised or new regulations may be adopted or become applicable to us. Revised or additional regulations imposed on us, which may result in increased compliance costs or additional operating restrictions, could have a material adverse effect on our busine ss, financial condition and results of operations, particularly if those costs are not fully recoverable from customers. Environmental regulations may also require us to install pollution control equipment at, or perform environmental remediation on, our facilities.

In July 1997, the Environmental Protection Agency, or EPA, promulgated a more stringent national ambient air quality standard for ozone. Subsequently, the EPA issued attainment designations on April 15, 2004, for all areas in the United States with respect to the new ozone standard. These designations are generally based on ambient air data collected during 2001, 2002 and 2003 and state recommendations. None of our compressor stations are located in areas currently designated as ozone nonattainment areas by the EPA. Therefore, we believe that the implementation of the new standard will not have an impact on our operations at this time. However, the EPA will reevaluate the attainment status of all areas each year based on continued ambient monitoring data and it is not possible to predict whether any areas where our compressor stations are located could become nonattainment areas in the future.

We have an active program to identify and clean up contamination at our facilities and have either entered, or plan to enter, into consent orders with the EPA for voluntary cleanup of about 30 compressor sites. As of December 31, 2006, we were aware of polychlorinated biphenyl, or PCB, and/or mercury contamination that requires remediation at 10 of our compressor sites and 530 of our meter sites. In general, the known contamination is limited to soils within the property boundaries of the sites. We have an accrued liability of $3.7 million as of December 31, 2006, representing the estimate of future cleanup costs to be incurred at these facilities over the next three to four years. However, unanticipated future costs could have a material adverse effect on our financial condition should these costs exceed our estimate, not be recoverable through rates or be uninsured.

Furthermore, we may be identified as a responsible party for environmental cleanup at contaminated sites which we do not own or operate or have not owned or operated. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Accordingly, in addition to being liable for environmental costs relating to properties we currently own, we may be liable for costs of cleaning up or remediating contamination caused by releases of hazardous substances at properties that we do not own or operate or have not owned or operated, or at properties to which hazardous substances were transported.

Furthermore, in certain instances we may not be able to obtain all environmental regulatory approvals in the future that are necessary for our business. If there is a delay in obtaining any required environmental regulatory approval, including for future expansion projects, or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be temporarily limited or subjected to additional costs, which could have a material adverse effect on our business, financial condition and results of operations.

We do not control the rates that we are allowed to charge for our services and those rates may be decreased at any time, thereby decreasing our revenues and operating results.

Our rates and the terms and conditions of our transportation and storage services are subject to regulation and approval by the FERC. The FERC regulatory process affords customers and state regulatory commissions the opportunity to take an active role in advising the FERC as to our rates and terms and conditions. We periodically file general rate cases with the FERC. In 2004, we filed and settled a general rate case, in which the settlement established, among other things, an allowed rate of return on common equity, an overall rate of return, depreciation rates and a total cost of service. When we elect to file a general rate case, unfavorable rulings by the FERC could adversely impact our results of operations.

Our ability to obtain rate increases in future rate cases in order to maintain our current rate of return depends upon regulatory discretion. Under cost-of-service ratemaking, the amount we may collect from customers, decreases over time as the rate base declines as a result of, among other things, depreciation and amortization. In order to avoid a reduction in the level of our earnings, we must maintain or increase our rate base, through projects that maintain or add to our existing pipeline facilities. There can be no assurance that we will be able to obtain rate increases, recover all costs we incur through our rates or continue receiving our current authorized rates. An unfavorable ruling by the FERC could adversely impact our results of operations.

Under Section 5 of the Natural Gas Act of 1938, or NGA, on its own motion or based on a complaint filed by a customer of the pipeline or other interested person, the FERC may initiate a proceeding seeking to compel a pipeline to prospectively change any filed rate and, under some circumstances, may seek refunds of previously paid amounts found to be in excess of then-effective FERC-filed rates. If the FERC determines that an existing rate or condition is unjust, unreasonable, unduly discriminatory or preferential, then any rate reduction that is ordered at the conclusion of such a proceeding is generally effective from the date of the order requiring this change. Such an order could have a material adverse effect on our business, financial condition and results of operations.

Substantial operational risks are involved in operating a natural gas pipeline system that could result in unanticipated expense or financial liability which may not be fully covered by insurance.

There are risks associated with the operation of a complex pipeline system, such as operational hazards and unforeseen interruptions caused by events beyond our control. 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 our pipeline facilities (which may occur if a third party were to perform excavation or construction work near our facilities), and catastrophic events such as explosions, fires, earthquakes, floods, landslides or other similar events beyond our control. It is also possible that our infrastructure facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred, and interruptions to the operation of our pipe line caused by such an event, could reduce revenues generated by us and increase expenses, thereby impairing our ability to meet our obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost.

Reduction in firm reservation agreements and the demand for interruptible services could cause significant reductions in our revenues and operating results.

For the year ended December 31, 2006, approximately 97% of our firm contracted market area capacity, 89% of our firm contracted production area capacity and 100% of our firm contracted storage capacity are under long-term contracts (i.e. contracts with terms longer than one year). A decision by customers upon the expiration of long-term agreements to substantially reduce or cease to ship or store volumes of natural gas on our pipeline system could cause a significant decline in our revenues. Our results of operations could also be adversely affected by decreased demand for interruptible services.

Decreases in the availability of natural gas supplies could have a significant negative impact on our revenues and results of operations.

Our operating results are dependent upon our customers having access to adequate supplies of natural gas. We depend on having access to multiple sources of gas production so that customers can satisfy their total gas requirements and have the opportunity to source gas at the lowest overall delivered cost. Moreover, we do not have the ability to operate our pipeline system at full capacity without access to multiple gas sources. The ability of producers to maintain production is dependent on the prevailing market price of natural gas, the exploration and production budgets of the major and independent gas companies, the depletion rate of existing sources, the success of new sources, environmental concerns, regulatory initiatives and other matters beyond our control. Additionally, some of our customers deliver gas to our pipeline system through other pipelines. Operational failures on those other pipelines, such as reductions in pressure or volum e, or interruptions in service due to maintenance activities or unanticipated emergencies, could result in lower volumes of gas being available to us for transportation. We cannot assure that production or supplies of natural gas available to our customers will be maintained at sufficient levels to sustain our expected volume of transportation commitments on our pipeline system or that multiple sources of gas will remain available to provide our customers with access to sufficient low cost supplies. If the availability of natural gas supplies decreases, our revenues and results of operations could be adversely affected.

Operational limitations of the pipeline system could cause a significant decrease in our revenues and operating results.

In order to satisfy firm transportation commitments, our customers must nominate and schedule, and we must be able to receive, required volumes of gas in accordance with contract terms, and must be able to reliably and safely deliver those volumes. Our customers’ ability to schedule natural gas transportation to certain locations is constrained by the physical limitations of our pipeline system. These physical limitations can be significant during periods of peak demand because many sections of our pipeline do not have redundant or looped lines and do not have additional available compression. During peak demand periods, failures of compression equipment or pipelines could limit our ability to meet firm commitments and, therefore, limit our ability to collect reservation charges from our customers, which could negatively impact our revenues.

Due to our lack of asset diversification, adverse developments in our pipeline business could negatively affect our business, financial condition or results of operations.

We rely exclusively on the revenues generated from our pipeline business. Due to our lack of asset diversification, an adverse development in this business could have a significantly greater adverse effect on our business, financial condition and results of operations than if we maintained more diverse assets.

 Department of Transportation regulations may impose significant costs and liabilities on us.

The U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration, has regulations that govern all aspects of the design, construction, operation and maintenance of pipeline facilities. These regulations require, among other things, that pipeline operators engage in a regular program of pipeline integrity testing to assess, evaluate, repair and validate the integrity of their pipelines within areas of high consequence. Determination of such high consequence areas, for natural gas transmission pipelines, is primarily based on population. In response to these regulations, we have developed a pipeline integrity program to conduct pipeline integrity tests on a risk prioritized basis. Depending on the results of these integrity tests and other integrity program activities, we could incur significant and unexpected capital and operating expenditures, not included in our current budgets, in order to conduct reme dial activities on our pipeline to ensure our continued safe and reliable operation. Currently, we estimate that the cost to perform required assessments and remedial activities during 2007 will be approximately $5.9 million and will be charged to capital or expense as appropriate.

Storage limitations may impact our ability to recover our costs.

Our storage fields are subject to many of the same operational limitations as our pipeline system. The economical and efficient operation of our storage fields depends on the continuing stability of the underground reservoirs in which the natural gas is stored, which is affected by numerous environmental and geological factors that are beyond our control. Storage gas losses occur as a normal part of underground storage operations and are caused by cumulative measurement inaccuracies, the slow migration of natural gas from a storage field into the surrounding underground areas and other causes associated with storage operations. We file our cumulative calculated natural gas loss measurements annually with the FERC to recover such natural gas losses from customers. However, if the FERC were to deny recovery of any such losses, it could result in unrecoverable costs for us.

Decreases in demand for natural gas may reduce our revenues and operating results.

Demand for our services depends on the ability and willingness of customers with access to our facilities to store natural gas on, and deliver natural gas through, our system. Demand for natural gas is dependent upon the impact of weather, industrial and economic conditions, fuel conservation measures, alternative fuel availability and requirements, market price of gas, fuel taxes, price competition, drilling activity and supply availability, governmental regulation and technological advances in fuel economy and energy generation devices. Any decrease in demand for our services could result in a significant reduction in our revenues.

Competitive pressures could reduce our revenues and operating results.

Although most of our pipeline system’s current transportation and storage capacity is contracted under long-term firm reservation agreements, the market for the transportation and storage of natural gas is competitive. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer services that are more desirable to customers because of locations, facilities or other factors. These new pipelines could charge rates or provide service to locations that could result in savings for shippers and producers and thereby force us to lower the rates charged for services on our pipeline in order to extend existing service agreements or to attract new customers. New pipeline projects are always possible in the future and proposals are made from time to time. An increase in the availability of competing alternative facilities or services could result in a significant reduction in our revenue.

We compete with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. Major competitors include Kansas Pipeline Company, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipeline Company. We compete with these pipelines in Wichita and Kansas City, Kansas and Kansas City, Missouri. One of the interstate pipelines with which we compete is an affiliated company with one of our largest customers, MGE. We have the majority of market share in these areas.

Natural gas also competes with other forms of energy available to our customers, including electricity, coal, hydroelectric power, nuclear power and fuel oil. The impact of competition on us could be significantly increased as a result of factors that have the effect of significantly decreasing demand for natural gas in the markets served by our pipeline, such as competing or alternative forms of energy; adverse economic conditions; weather; higher fuel costs; and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

Federal and state regulation of natural gas interstate pipelines has changed dramatically in the last 25 years and could continue to change over the next several years. These regulatory changes have resulted and will continue to result in increased competition in the pipeline business. In order to meet competitive challenges, we will need to adapt our marketing strategies and the type of transportation services we offer to our customers and to adapt our pricing and rates in response to competitive forces. We are not able to predict the financial consequences of these changes at this time, but they could have a material adverse effect on our business, financial condition and results of operations.

We are dependent on a limited number of customers for a significant percentage of our revenues.

Operating revenues related to transportation and storage contracts with our ten largest customers accounted for approximately 86% of operating revenue during the year ended December 31, 2006. Approximately 58% of our operating revenues during the year ended December 31, 2006 were generated from transportation and storage services to our two largest customers, KGS and MGE. We have multiple service contracts for the delivery and storage of natural gas with both KGS and MGE. The largest KGS contract by volume extends into 2013 and the largest MGE contract by volume extends into 2013. Accordingly, a decision by KGS or MGE, or other principal customers, not to renew or extend their contracts or to reduce firm reservation capacity upon renewal or extension of their contracts could cause a significant reduction in our revenues and could have a material adverse effect on our business, financial condition and results of operations.

We are exposed to the credit risk of our customers in the ordinary course of our business.

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

Generally, our customers are rated investment grade or are required to make pre-payments, deposits, or provide security to satisfy credit concerns. However, declines in customer creditworthiness could prevent us from collecting amounts owed to us and require us to incur credit losses.

Reductions in our credit ratings may negatively affect our cost of, and possibly access to, capital.

Any downgrades in our credit ratings may increase our borrowing costs and limit our access to capital. This could significantly limit our ability to fund our operations or pursue opportunities to expand our pipeline system.

Recent terrorist activities and the potential for military and other actions could adversely affect our business, financial condition and results of operations.

The continued threat of terrorism and the impact of retaliatory military and other action against the United States and its allies might lead to increased political, economic and financial market instability and volatility in prices for natural gas, which could affect the market for our pipeline services. In addition, future acts of terrorism could be directed against companies operating in the United States, and it has been reported that terrorists might be targeting domestic energy facilities, specifically our nation’s pipeline infrastructure. While we are taking steps we believe are appropriate to increase the security of our energy assets, there is no assurance that we can completely secure our assets or completely protect them against a terrorist attack, or obtain adequate insurance coverage for such acts at reasonable rates. These developments have subjected our operations to increased risks and, depending on their ultimate magnitude , could have a material adverse effect on our business, financial condition and results of operations. In particular, we might experience increased capital or operating costs to implement increased security.

Our current debt instruments contain restrictive covenants that may restrict our ability to pursue our business strategies.

The covenants limit our ability, among other things, to:

•

make investments;

•

incur or guarantee additional indebtedness;

•

pay dividends or make other distributions on capital stock or redeem or repurchase capital stock;

•

create liens;

•

incur dividend or other payment restrictions affecting subsidiaries;

•

merge or consolidate with other entities; and

•

enter into transactions with affiliates.

Our ability to comply with these covenants may be affected by many events beyond our control. Failure to comply with these covenants could result in an event of default, which could cause the notes (and by reason of cross-default provisions, other indebtedness) to become immediately due and payable. In addition, complying with these covenants may also cause us to take actions that are not favorable to the equity holders and may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Ownership of Property

Central’s pipeline system includes approximately 6,000 miles of mainline and branch transmission and storage pipelines, eight storage fields and 40 compressor stations located in Colorado, Kansas, Missouri, Nebraska, Oklahoma, Texas and Wyoming. The system is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned in fee by others. Most of these easements and rights-of-way are perpetual in nature and any term leases are effective as long as the appropriate payments are made. Central’s compressor stations with appurtenant facilities are located in whole or in part upon lands owned by Central in fee, or held under the same type of term lease as described above, pursuant to permits issued or approved by public authorities, or pursuant to perpetual easements granted by priv ate landowners. Central’s pipeline, storage and compressor facilities are all subject to FERC certificates, the issuance of which provides Central with eminent domain rights to occupy its right-of-way for certain pipeline-related purposes.

In 2004, Central entered into a 20-year capital lease with the Owensboro-Daviess County Industrial Authority for use of a headquarters building in Owensboro, Kentucky. Ownership of the facility will transfer to Central for a nominal fee upon expiration of the lease.

Central also has leases covering office space located in Lenexa, Kansas; Hesston, Kansas; Bartlesville, Oklahoma; and Woodward, Oklahoma. These leases are not for substantial space and have an aggregate annual rent of less than $0.2 million.

We believe that our properties are adequate and suitable to conduct our ongoing business.

Item 3. Legal Proceedings  

United States ex rel. Grynberg v. Williams Natural Gas Company, et al., MDL Docket No. 1293 (99 MD 1614), Civil Action No. 97 D 1478, (District of Colorado), or Grynberg Litigation

In 1998, Jack Grynberg, an individual, sued Central and approximately 300 other energy companies, purportedly on behalf of the federal government, or qui tam. Invoking the False Claims Act, Grynberg alleged that the defendants had mismeasured the volume and wrongfully analyzed the heating content of natural gas, causing underpayments of royalties to the United States. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, or civil penalty, attorney fees and costs. Thus far, the Department of Justice has declined to intervene in Grynberg’s qui tam cases, which were consolidated for pretrial purposes before a single judge in the United States District Court, or Trial Court, for the District of Wyoming. Initial discovery was limited to public disclosure/original source jurisdictional issues. On June 4, 2004, motions, with supporting briefs, were filed by the Joint Defendants requesting the Trial Court to dismiss Grynberg’s claims based on lack of subject matter jurisdiction. Those motions were fully briefed and oral arguments occurred on March 17 and 18, 2005. On May 13, 2005, the Special Master appointed to adjudicate procedural issues and help manage the consolidated litigation for the Trial Court Judge, issued his “Report and Recommendations” addressing which Grynberg claims against which defendants should be dismissed. Central was one of the defendants as to which the Special Master recommended that Grynberg's claims be dismissed on jurisdictional grounds. Both Grynberg and a number of the defendants filed objections to the Special Master’s report. On October 20, 2006, the Trial Court Judge entered his “Order on Report and Recommendations of Special Master” dismissing Grynberg's claims against Central and substantially all of the other defendants.  The relator’s counsel has fi led notices of appeal with the trial court for the Tenth Circuit, and the clerk’s office has indicated that it will be entering a preliminary case management order in the near future. In the meantime, the trial court has scheduled an April 24, 2007 hearing on various motions pertaining to attorneys’ fees and costs.

Will Price, et al. v. El Paso Natural Gas Co., et al., Case No. 99 C 30, District Court, Stevens County, Kansas, or Price Litigation I

In this putative class action filed May 28, 1999, the named plaintiffs, or Plaintiffs, have sued over 50 defendants, including Central. Asserting theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment, their Fourth Amended Class Action Petition alleges that the defendants have undermeasured the volume of, and therefore have underpaid for, the natural gas they have obtained from or measured for Plaintiffs. Plaintiffs seek unspecified actual damages, attorney fees, pre- and post-judgment interest, and reserved the right to plead for punitive damages. On August 22, 2003, an answer to that pleading was filed on behalf of Central. Despite a denial by the court on April 10, 2003 of their original motion for class certification, the Plaintiffs continue to seek the certification of a class. The Plaintiffs’ motion seeking class certification for a second time was fully briefed and the court heard oral arg ument on this motion on April 1, 2005. In January 2006, the court heard oral argument on a motion to intervene filed by a third party who is claiming entitlement to a portion of any recovery obtained by Plaintiffs. It is unknown when the court will rule on the pending motions.

Will Price, et al. v. El Paso Natural Gas Co., et al., Case No. 03 C 23, District Court, Stevens County, Kansas, or Price Litigation II

In this putative class action filed May 12, 2003, the named Plaintiffs from Case No. 99 C 30 (discussed above) have sued the same defendants, including Central. Asserting substantially identical legal and/or equitable theories, as in Price Litigation I, this petition alleges that the defendants have undermeasured the British thermal units, or Btu, content of, and therefore have underpaid for, the natural gas they have obtained from or measured for Plaintiffs. Plaintiffs seek unspecified actual damages, attorney fees, pre- and post-judgment interest, and reserved the right to plead for punitive damages. On November 10, 2003, an answer to that pleading was filed on behalf of Central. The Plaintiffs’ motion seeking class certification, along with Plaintiff’s second class certification motion in Price Litigation I, was fully briefed and the court heard oral argument on this motion on April 1, 2005. In January 2006, the court heard oral argument on a motion to intervene filed by a third party who is claiming entitlement to a portion of any recovery obtained by Plaintiffs. It is unknown when the court will rule on the pending motions.

Item 4. Submission of Matters to a Vote of Security Holders  

None.

PART II.

Item 5. Market for Registrant’s Common Equity, and Related Stockholder Matters and Issuer Purchases of Equity Securities

There is no established public trading market for the common stock of the Company. As of December 31, 2006, all of our common stock was held by one holder of record.

In connection with the acquisition, we entered into a Recapitalization Agreement with Holdings. Pursuant to the Recapitalization Agreement, Holdings surrendered to us for cancellation all of our Series A Preferred Stock, and all rights therein, in exchange for the reissuance of 20.633 treasury common shares to Holdings. The remaining 1.587 treasury common shares were cancelled pursuant to the Recapitalization Agreement.

In connection with the Recapitalization Agreement, we amended and restated our Certificate of Incorporation to eliminate all authorized preferred stock and reduce the authorized number of shares of capital stock to 100 shares of common stock. We have issued all 100 shares of common stock to Holdings. The Amended and Restated Certificate of Incorporation was filed with the Secretary of State of Delaware on August 11, 2005.

We have outstanding $200.0 million 6.75% Senior Notes due March 1, 2016, or 6.75% Notes. The declaration and payments of dividends or distributions to equity holders, under our 6.75% Notes Indenture, is subject to, with certain limited exceptions, a minimum fixed charge coverage ratio and cumulative available cash flows from operations or a leverage ratio, subject to certain conditions, as defined in the indenture. Dividends declared during the years 2006 and 2005 were $56.2 million and $13.9 million, respectively. We expect to continue to pay dividends as permitted under the 6.75% Notes Indenture on a quarterly basis.

 Item 6. Selected Financial Data

We were formed on September 11, 2002 but undertook no financial activity until November 16, 2002. Therefore, the financial data presented below for the period ending November 15, 2002 reflects the operations of Williams Gas Pipelines Central, Inc., our predecessor entity. Financial data presented below for the periods after November 15, 2002 through August 11, 2005 reflect the operations of the Company prior to the acquisition by Holdings. Hence, there are blackline divisions on the selected historical financial data, which are intended to signify that the reporting entities shown are not comparable.

You should read these tables in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements, related notes and other financial information included elsewhere in this report.

Southern Star Central Corp. and Subsidiaries

Selected Historical Financial Data

(In thousands)

	Post -acquisition						Pre-acquisition												Predecessor
	For the Year Ended December 31, 2006			For the Period August 12 through December 31, 2005			For the Period January 1 through August 11, 2005			For the Year Ended December 31, 2004			For the Year Ended December 31, 2003			For the Period November 16 through December 31, 2002			For the Period January 1 through November 15, 2002
Statement of Operations Data:
Operating Revenues	$	187,246		$	70,769		$	111,168		$	164,332		$	158,598		$	20,454		$	139,504
Operating Costs and Expenses:
Operations and maintenance		41,030			14,702			23,568			37,508			34,398			3,622			30,349
Administrative and general		34,939			13,809			25,688			37,026			40,989			3,775			35,304
Depreciation and amortization		26,881			10,884			17,299			27,781			29,279			3,758			28,408
Taxes, other than income taxes		13,349			4,745			7,573			10,831			10,994			1,196			8,279
Total Operating Costs and
Expenses		116,199			44,140			74,128			113,146			115,660			12,351			102,340
Operating Income		71,047			26,629			37,040			51,186			42,938			8,103			37,164
Interest Charges (Income):
Interest expense		29,964			11,337			25,169			40,856			42,396			3,727			11,710
Interest income		(2,401	)		(737	)		(719	)		(651	)		(705	)		(204	)		(1,011	)
Loss on Sale of Assets		—			—			2			—			—			—			5
Miscellaneous Other (Income)
Expense, Net		(445	)		(121	)		111			2,401			(3,392	)		3,303			2,382
Income Before Income Taxes		43,929			16,150			12,477			8,580			4,639			1,277			24,078
Provision for Income Taxes		17,558			6,399			7,074			6,511			4,804			535			13,383
Net Income (Loss)	$	26,371		$	9,751		$	5,403		$	2,069		$	(165	)	$	742		$	10,695
Balance Sheet Data (end of period):
Cash and Cash Equivalents	$	37,989		$	62,287		$	44,525		$	41,702		$	65,887		$	42,408		$	9,800
Property, Plant & Equipment, Net		544,270			527,707			524,029			528,075			514,891			524,492			621,953
All Other Assets		442,065			426,309			154,588			132,772			167,603			157,465			93,618
Total Assets	$	1,024,324		$	1,016,303		$	723,142		$	702,549		$	748,381		$	724,365		$	725,371
Capitalization:
Bridge Loan	$	—		$	—		$	—		$	—		$	—		$	200,000		$	—
Current Maturities of Long-Term
Debt		765			225,647			50,735			730			—			—			—
Total Long-Term Debt, Net of
Current Portion		438,946			202,344			362,777			413,093			404,740			174,664			174,654
Mandatorily Redeemable Preferred Stock		—			—			52,760			51,184			48,265			-			-
Common Stockholder’s Equity		434,695			464,514			122,923			131,277			141,259			225,742			449,248
Total Capitalization	$	874,406		$	892,505		$	589,195		$	596,284		$	594,264		$	600,406		$	623,902

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This management’s discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with “Selected Historical Financial Data” and the Company’s consolidated financial statements and the related notes thereto. This discussion contains forward-looking statements about our business, operations and industry that involve risks and uncertainties such as statements regarding our plans, objectives, expectations and intentions. Our future results and financial condition may differ materially from those we currently anticipate as a result of the factors we describe under “Forward Looking Statements,” “Risk Factors” and elsewhere in this document.

Comparisons to prior periods have been made for discussion purposes; however, periods prior to August 12, 2005 reflect the financial condition and results of operations of Southern Star prior to its acquisition by Holdings, which are not comparable to the post-acquisition periods presented for the Company. Although pre-and post- acquisition periods are not comparable, activity for both periods in 2005 have been combined to provide a basis for discussion. Major differences are noted in the discussions below.

The Acquisition

On August 11, 2005, GE and CDP, through their indirect ownership of Holdings, acquired all of our outstanding capital stock owned by Highstar for a purchase price of $389.1 million in cash, plus the assumption of $467.9 million in long-term debt, including current maturities, and Series A Preferred Stock, such that following the transaction Holdings owned all of our outstanding capital stock.  This transaction is hereinafter referred to as the acquisition. Following the acquisition, our capital stock was immediately recapitalized and the Series A Preferred Stock was converted into common stock. We acquired Central, our only operating subsidiary, in 2002.

The acquisition has been accounted for under the purchase method of accounting, as required by Statement of Financial Accounting Standards, or SFAS, 141, “Business Combinations.”  The purchase price of the acquisition has been “pushed down” and allocated to our assets and liabilities.

As Central’s rates are regulated by the FERC and the FERC does not allow recovery in rates of amounts in excess of original cost, Central’s historical assets and liabilities equaled fair value at the acquisition date. The final purchase price including acquisition costs exceeded the fair value of our net assets and liabilities, including a working capital settlement, by $324.6 million. This excess has been classified as “Goodwill” on the accompanying Consolidated Balance Sheets. The goodwill is not amortized and is subject to an annual impairment test in accordance with SFAS 142, “Goodwill and Other Intangible Assets.”

All accounting and reporting policies contained herein conform with accounting principles generally accepted in the United States, or GAAP. The financial information contained herein has been prepared in accordance with the rules and regulations of the SEC.

 The Business

We are the parent company of Central, our only operating subsidiary and the sole source of our operating revenues and cash flows. Central owns and operates an approximately 6,000 mile natural gas pipeline and associated natural gas storage facilities in the Midwest. Central’s primary markets are regulated local natural gas distribution companies, municipalities, intrastate pipelines, electric generation plants and industrial customers in Missouri, Kansas, Oklahoma, and parts of Colorado, Nebraska, Wyoming, and Texas.

Central is an interstate natural gas pipeline engaged in the transportation and storage of natural gas. As such, Central’s rates, facilities and services are regulated by the FERC. Central’s services are provided under both short-term and long-term contracts, subject to a FERC-accepted tariff which governs substantially all terms and conditions of service. The substantial majority of Central’s business is conducted under long-term contracts ranging from one to 30 years. Total average remaining contract life on a volume-weighted basis at December 31, 2006 was approximately six years.

On April 30, 2004, Central filed a general rate case under FERC Docket No. RP04-276 which became effective November 1, 2004. The case was settled and became final in 2005. The general rate proceeding increased Central’s transportation, storage, and related rates, and also provided for changes to a number of the terms and conditions of customer service in Central’s tariff. Pursuant to the terms of its settlement, Central is required to file a new rate case to be effective on or before November 1, 2008.

Central’s rates are regulated by the FERC and are designed to provide an allowed rate of return on equity after recovering its costs of service, assuming that its service and contract levels remain constant. As such, Central’s opportunities to grow profits and cash flows are generally limited to its ability to acquire new business on its existing pipeline system or expand into new areas or services. Expansion of its pipeline system or provision of new services generally requires authorization from the FERC. Our risk of declining profits or cash flows are primarily related to Central’s ability to maintain its current service levels at its current rates, including the renewal of long-term contracts on substantially equivalent terms, and our ability to prudently manage our costs. We expect to continue to manage our operating costs and to renew expiring contracts on favorable terms.

Pipeline and storage integrity regulations continue to increase our operating costs for integrity testing, permitting, and other compliance with new regulations.  Central remains on schedule to meet all compliance regulations and expects that operating costs associated with such regulations will continue to be recovered in the rates it charges for its services.

Central’s ability to maintain current service levels at its current rates is impacted by both its access to natural gas supplies and competition. Central’s access to multiple sources of natural gas supply and its unique storage capabilities, due to the strategic location of its storage facilities within its major market areas, are strengths that aid in limiting our downside risks. Central’s focus on offering customers flexibility in regard to supply access is evidenced by its recent and current supply initiatives. The competing interstate pipelines generally offer less diverse geographic access to natural gas supply and less competitively priced, flexible on-system storage.

We proactively seek growth opportunities that will further strengthen our financial position and results of operations. The costs we incur for many of our growth opportunities are reimbursed by the operator of the gas supply or delivery point. Expansion projects are generally supported through cost reimbursement or through long-term firm contract commitments.  The Ozark Trails Expansion Project was placed in service December 1, 2006 at a cost of approximately $11.4 million through December 31, 2006.  The Company anticipates investing an aggregate of approximately $25.2 million during 2007 and 2008 for planned market expansion projects.

Critical Accounting Policies

Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources is based on our financial statements, which have been prepared in accordance with GAAP. GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. We base these estimates on historical experience and on various other assumptions that we consider reasonable under the circumstances. We evaluate our estimates on an on-going basis. Actual results may differ from these estimates. We believe that, of our significant accounting policies, the following may involve a higher degree of judgment or complexity.

Accounting for the Effects of Regulation

Like all interstate natural gas pipeline operators, Central is subject to regulation by the FERC. SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it reasonable to assume that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of SFAS 71 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, and the deferral of employee related benefits a nd other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, we have determined that it is appropriate to apply the accounting prescribed by SFAS 71 to the operations of Central and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements.

Goodwill

We have recorded $324.6 million of Goodwill, as a result of our 2005 acquisition, as discussed in Note 3 of the accompanying Notes to the Consolidated Financial Statements. Goodwill is not amortized and is subject to an annual impairment test in accordance with SFAS 142.

Revenues Subject to Refund

The FERC regulatory processes and procedures govern, among other matters, Central’s tariff and rates that Central is permitted to charge to customers for its services. Key determinants in the ratemaking process are (1) contracted capacity assumptions, (2) costs of providing service, including depreciation expense, and (3) allowed rate of return, including the equity component of a pipeline’s capital structure and related income taxes. Accordingly, at any given time, some of the collected revenues may be subject to possible refunds required by final order of the FERC. Central records estimates of rate refund liabilities based on its and other third-party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted. If the actual refunds differ from the estimated refund liability, revenues would be impacted by the difference between estimated and actual refunds.

Loss Contingencies and Operating Expenses

We establish reserves for estimated loss contingencies when assessments determine that a loss is probable and the amount of the loss can be reasonably estimated. Adjustments to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect previous assumptions with respect to the likelihood or estimation of loss. Reserves for contingent liabilities are based upon our assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcome. Should the outcome differ from the assumptions and estimates, revisions to estimated reserves for contingent liabilities would be required, which may impact our results of operations.

We also estimate accruals for certain operating expenses, primarily depreciation, employee benefit costs, unbilled professional fees, and ad valorem taxes. The estimates are based on historical experience, our assumptions about current period activities, and other information gathered within an accounting period. Actual results could differ from those estimated. Such estimates are adjusted as facts become known or circumstances change that affect the assumptions used or amounts accrued. See the accompanying Notes to the Consolidated Financial Statements for further discussion of our accounting policies and methods that may include estimates.

Other

Please refer to the accompanying Notes to the Consolidated Financial Statements for a complete discussion of significant accounting policies and recent accounting standards.

 Results of Operations

Results of operations for all periods presented include the operations of Central, our only operating subsidiary.  All periods include the application of purchase accounting.  The periods subsequent to August 11, 2005 reflect the impact of the acquisition by Holdings.  For the purpose of comparing operations for 2006 and 2005, the pre-acquisition and post-acquisition periods in 2005 have been combined in the discussions below.  The combined year ended December 31, 2005 results of operations presented below represents two different bases of accounting, which qualifies as a non-GAAP measure.  However, due to the fact that our purchase price allocation takes into account that Central’s historical book value is equal to fair value and Central owns substantially all of our assets, there are no significant differences between the two presentations.  As the excess of fair value paid over net book value was primarily allocated to goodwill, which is non-amortizable, there is no impact on results of operations from that allocation.  Pro forma results of operations are not presented; any impacts are noted in the variance discussions below.

The following table sets forth our selected results of operations data for the years ended December 31, 2006, 2005 and 2004 (in thousands):

		For the Year Ended December 31, 2006		Combined Year Ended December 31, 2005		For the Year Ended December 31, 2004
			(In thousands)
Operating revenues	$	187,246	$	181,937	$	164,332
Operations and maintenance		41,030		38,270		37,508
Administrative and general		34,939		39,497		37,026
Depreciation and amortization		26,881		28,183		27,781
Taxes, other than income taxes		13,349		12,318		10,831
Operating income		71,047		63,669		51,186
Other (Income) Deductions:
Interest expense		29,964		36,506		40,856
Interest income		(2,401)		(1,456)		(651)
Miscellaneous other (income) expenses, net		(445)		(8)		2,401
Total Other Deductions		27,118		35,042		42,606
Income before income taxes		43,929		28,627		8,580
Provision for income taxes		17,558		13,473		6,511
Net Income	$	26,371	$	15,154	$	2,069

Comparison of the Years Ended December 31, 2006 and 2005

Operating revenues were $187.2 million for the year ended December 31, 2006, a $5.3 million, or 2.9%, increase from $181.9 million in the prior year. The increase is primarily due to increased demand for Central's park and loan service and increased customer inventories in storage due to mild climate conditions.

Operations and maintenance expenses increased by $2.8 million, or 7.2%, to $41.0 million for year ended December 31, 2006 from $38.3 million for the prior year, principally due to increased integrity management costs and increased pipeline repairs and maintenance. The increase was partially offset by lower labor costs primarily due to timing of filling vacancies.

Administrative and general expenses were $34.9 million and $39.5 million for the years ended December 31, 2006 and 2005, respectively, a $4.6 million, or 11.5%, decrease. The decrease is primarily attributable to lower 2006 employee retention payments related to agreements entered into in August 2005, favorable settlements in 2006 of two prior year customer bankruptcies, discontinuation of mainframe computer usage at the end of 2005 and lower employee benefit costs.

Depreciation expense was $26.9 million for the year ended December 31, 2006 as compared to $28.2 million in 2005, a $1.3 million, or 4.6%, decrease. The change is primarily due to a decrease in the depreciable base for software and SCADA equipment from the prior year, and a software depreciation adjustment in 2006.

Taxes, other than income taxes, increased by $1.0 million, or 8.4%, to $13.3 million for the year ended December 31, 2006. The increase was mainly the result of increased state property tax expense after giving effect to a full year’s increase in revenues resulting from Central’s RP04-276 rate proceedings.

Interest expense was $30.0 million for the year ended December 31, 2006 as compared to $36.5 million for 2005, a $6.5 million, or 17.9%, decrease. The decrease is primarily attributable to $4.6 million lower Series A Preferred Stock dividend expense due to the recapitalization of our stock in August 2005 which eliminated this dividend requirement. The decrease was also due in part to lower interest rates resulting from our debt refinancing in 2006. See below and Note 5 of the accompanying Notes to the Consolidated Financial Statements for further discussion of our long-term debt.

Interest income increased by $0.9 million, or 64.9%, to $2.4 million for the year ended December 31, 2006. The increase is primarily due to higher cash balances and higher interest rates in 2006 than in 2005.

The provision for income taxes was $17.6 million for 2006, an increase of $4.1 million, or 30.3%, from $13.5 million in 2005, commensurate with higher pre-tax income. Dividends and other costs associated with our Series A Preferred Stock in 2005 were not tax deductible. Excluding these costs in 2005, our effective tax rate for 2006 was 40.0% as compared to 40.6% for 2005.

Comparison of the Years Ended December 31, 2005 and 2004

Operating revenues were $181.9 million for the year ended December 31, 2005, a $17.6 million, or 10.7%, increase from the prior year, primarily due to an expansion which was placed in service on September 1, 2004 and increased revenues resulting from the RP04-276 rate proceeding, which became effective, subject to refund, on November 1, 2004. The increase was partially offset by the discontinuation of Gas Research Institute, or GRI, funding beginning with Central’s August 2004 billings. As GRI funding represented costs flowed through to customers, the associated revenues were offset by corresponding operating expenses.

Operations and maintenance expenses increased by $0.8 million, or 2.0%, from $37.5 million for 2004, to $38.3 million for 2005, principally due to increased labor costs. This increase was partially offset by higher 2004 maintenance and repair expenses at the Grabham Compressor Station.

Administrative and general expenses were $39.5 million and $37.0 million, for the years ended December 31, 2005 and 2004, respectively, a $2.5 million, or 6.7%, increase. The increase was primarily attributable to $3.9 million in additional salary costs, paid or accrued, associated with employee retention agreements entered into in 2005. The increase was partially offset by lower employee benefits and GRI costs.

 Depreciation expense was $28.2 million in 2005 as compared to $27.8 million in 2004, a $0.4 million, or 1.4%, increase. The change was primarily attributable to adjustments to decrease depreciation expense related to the retirement of SCADA equipment in the fourth quarter of 2004. The increase was partially offset by a 2005 depreciation adjustment related to the RP04-276 rate settlement that approved a lower depreciation rate on transmission assets.

Taxes, other than income taxes increased by $1.5 million, or 13.7%, to $12.3 million for the year ended December 31, 2005. The increase was mainly the result of increases in state property tax assessments after giving effect to Central’s increase in revenues resulting from its RP04-276 rate proceedings.

Interest expense was $36.5 million for the year ended December 31, 2005 as compared to $40.9 million for 2004, a $4.4 million, or 10.6%, decrease. The decrease was primarily attributable to $3.3 million lower Series A Preferred Stock dividend expense due to the recapitalization of our stock in August 2005 and the $1.2 million amortization of a premium resulting from the fair valuing of the $180.0 million Senior Secured Notes due August 1, 2010, or 8.5% Notes, at the date of the acquisition.

Interest income increased by $0.8 million, or 123.7%, to $1.5 million for the year ended December 31, 2005. The increase was primarily due to higher cash balances and higher interest rates in 2005 than in 2004.

Miscellaneous other income was minimal in 2005 compared to miscellaneous other expense of $2.4 million in 2004. The change was primarily due to a 2004 reduction of $4.7 million in the carrying value of a segment of Central’s pipeline resulting from its RP04-276 rate proceeding, partially offset by a 2004 reduction of $1.8 million in a reserve for settlement of the Kansas Ad Valorem Tax Reimbursement.

The provision for income taxes was $13.5 million for 2005, an increase of $7.0 million, or 106.9%, from $6.5 million in 2004, commensurate with higher pre-tax income. Dividends and other costs associated with our Series A Preferred Stock are not tax deductible. Excluding these costs, our effective tax rate for 2005 was 40.6% as compared to 39.5% in the prior year.

Liquidity and Capital Resources

We believe we have sufficient liquidity to satisfy our capital and other liquidity requirements over the next 12 to 18 months. We expect to fund our capital and other liquidity requirements with cash flows from operating activities and by accessing capital markets as needed to support operations and capital expenditures.

As of March 1, 2007, we had senior long-term debt ratings of Ba2 from Moody’s Investors Service and BB+ from Standard & Poor’s, and Central had senior long-term debt ratings of Baa3 from Moody’s Investors Service and BBB- from Standard & Poor’s. Any downgrades in these ratings may increase our borrowing costs or limit our access to capital.

Net cash provided by operating activities for the years ended December 31, 2006 and 2005 was $79.2 million and $65.6 million, respectively. Cash from operating activities was higher in 2006 primarily due to an increase in revenues and reimbursements from Highstar for pre-acquisition taxes paid in 2005.  The increase in revenues stems from increased demand for Central's park and loan service and higher volumes of customer gas kept in storage in 2006.  The increase was also due in part to lower disbursements for interest on our long-term debt due to our 2006 debt refinancing, lower employee retention payments in 2006, and increased interest income.  

Net cash used in investing activities for the years ended December 31, 2006 and 2005 was $41.3 million and $28.4 million, respectively.  Cash used in investing activities was higher in 2006 primarily due to higher capital expenditures.

Net cash used in financing activities was $62.2 million for the year ended December 31, 2006, as compared to $16.6 million for the same period in 2005. Cash used for financing activities was higher in 2006 primarily due to $42.3 million higher dividend payments to common equity holders, a $2.0 million working capital settlement paid to Highstar, and payment of the $7.3 million notes payable to Highstar. The increase was partially offset by net proceeds associated with our debt refinancing in 2006 and $2.3 million for the discontinuation of dividend payments to our Series A Preferred Stockholder as a result of the recapitalization of our stock in 2005. Our financing activities are further discussed below.

Net cash provided by operating activities for the year ended December 31, 2005 and 2004 was $65.6 million and $40.3 million, respectively. Cash from operating activities was higher in 2005 primarily as a result of an increase in revenues collected pursuant to the RP04-276 rate proceeding and lower 2005 payments for pension and postretirement medical benefits. The increase in cash activity in 2005 was also due in part to 2004 activity, including $2.0 million to settle Central’s remaining commitment for the reformation or termination of its natural gas supply contracts and approximately $2.8 million in net payments for various Kansas Ad Valorem Tax Reimbursement settlements, partially offset by $3.2 million of employee retention payments in 2005, as discussed in Note 15 of the accompanying Notes to the Consolidated Financial Statements.

Net cash used in investing activities for the years ended December 31, 2005 and 2004 was $28.4 million and $34.0 million, respectively. Cash used in investing activities was lower in 2005 primarily due to higher capital expenditures in 2004 resulting from an expansion project. The 2004 construction costs associated with the new headquarters building were fully financed by economic development bonds and, therefore, were excluded from the Statements of Consolidated Cash Flows as non-cash activity.

Net cash used in financing activities was $16.6 million for the year ended December 31, 2005 as compared to $30.5 million for the same period in 2004. Cash used for financing activities was lower in 2005 primarily due to lower dividend payments to common equity holders. The decrease was also due in part to lower dividend payments to the Company’s Series A Preferred Stockholder as result of the recapitalization of our stock.

 8.5% Notes

Prior to April 13, 2006, we had outstanding $180.0 million of 8.5% Notes.  Interest on the 8.5% Notes is payable semi-annually in February and August. The 8.5% Notes were subject to certain covenants that restricted, among other things, our or our subsidiaries’ ability to make investments; incur additional indebtedness; pay dividends on, or redeem capital stock; create liens; sell assets; or engage in certain other business activities. See Note 9 of the accompanying Notes to the Consolidated Financial Statements for further discussion of dividends and related restrictions.

As a result of the acquisition, the value of the 8.5% Notes was calculated at fair value and a premium of $15.7 million was recorded in Long-term debt on the accompanying Consolidated Balance Sheet. This premium was being amortized over the remaining life of the 8.5% Notes, and associated unamortized debt issuance expenses were valued at zero.

On March 23, 2006, we launched a tender offer pursuant to which we offered to purchase all of our outstanding 8.5% Notes. As part of this tender offer, we solicited consents to amend the indenture governing the 8.5% Notes to eliminate substantially all of the covenants and certain events of default contained in the indenture.

As a result of the tender, we accepted for payment $176.9 million principal amount of the 8.5% Notes, which represented 98.29% of the outstanding aggregate principal amount of the 8.5% Notes. We paid $190.7 million to reacquire the debt, which had a carrying value of $190.5 million; and a loss of $0.2 million was recorded. Fees of approximately $0.5 million associated with the tender were also charged to expense. In addition, we entered into a Supplemental Indenture for the 8.5% Notes on April 10, 2006, which eliminated substantially all of the original covenants and certain events of default.  At December 31, 2006, our outstanding balance of the 8.5% Notes was $3.1 million. The 8.5% Notes are callable on or after August 1, 2007.

6.75% Notes

On April 13, 2006, we completed a private offering of $200.0 million aggregate principal amount of 6.75% Notes, the proceeds of which were used to retire the 8.5% Notes tendered, including related premiums and expenses, and to pay the issuance costs of the new offering. In connection with the offering, we entered into a 6.75% Notes Indenture, dated April 13, 2006 by and between us and The Bank of New York Trust Company, N.A., as trustee.    

Interest is payable semi-annually on March 1 and September 1 of each year, and began on September 1, 2006.  The 6.75% Notes mature on March 1, 2016. The 6.75% Notes are our senior unsecured obligations and rank equal in right of payment to all of our existing and future unsecured indebtedness, including our 8.5% Notes that remain outstanding following our tender offer and are effectively junior to any secured indebtedness of ours to the extent of the value of the assets securing such indebtedness, if any.

In connection with the issuance of the 6.75% Notes, we entered into a registration rights agreement dated as of April 13, 2006, whereby we agreed to offer to exchange the 6.75% Notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended.  The registration statement was filed on June 30, 2006 and was declared effective on August 2, 2006.  The exchange offer was consummated on September 11, 2006, at which time all notes were accepted for exchange.

The declaration and payments of dividends or distributions to equity holders, under the 6.75% Notes Indenture, is subject to, with certain limited exceptions, a minimum fixed charge coverage ratio and cumulative available cash flows from operations or a leverage ratio, subject to certain conditions, as defined in the indenture.

Central Credit Facility

Prior to April 13, 2006, Central had in place a secured credit facility, or Central Credit Facility, with Union Bank of California, providing for, among other things, a term loan of $50.0 million that matured on May 1, 2006. The Central Credit Facility was secured by certain customer contracts and physical assets of Central.

In connection with Central’s 2006 refinancing discussed below, the term loan was repaid in full on April 13, 2006 and the related agreements were terminated.

Central’s 7.375% Notes

Prior to April 13, 2006, Central had outstanding $175.0 million of 7.375% Senior Notes due November 15, 2006, or 7.375% Notes.  

On March 23, 2006, Central launched a tender offer pursuant to which it offered to purchase all of its outstanding 7.375% Notes. As a result of the tender offer, Central accepted for payment $155.1 million aggregate principal amount of the 7.375% Notes.  On April 25, 2006, Central called for redemption the remainder of its 7.375% Notes, settlement of which was made on May 1, 2006. Central paid $177.6 million to reacquire the debt, which had a carrying value of $174.9 million.  The premiums and expenses related to the tender and call will be amortized over the life of the new debt, as permitted by FERC accounting regulations.

Central’s 6.0% Notes

On April 13, 2006, Central completed a private offering of $230.0 million aggregate principal amount of 6.0% Senior Notes due 2016, or 6.0% Notes, the proceeds of which were used to pay issuance costs of the offering, to pay amounts outstanding under the Central Credit Facility, and to retire its 7.375% Notes, including related premiums and expenses. In connection with the offering, Central entered into an indenture, or 6.0% Notes Indenture, dated April 13, 2006 by and between Central and The Bank of New York Trust Company, N.A., as trustee.  The 6.0% Notes Indenture contains customary restrictive covenants and events of default.  

Interest on the 6.0% Notes is payable on June 1 and December 1 of each year, and began on December 1, 2006. The 6.0% Notes mature on June 1, 2016. The 6.0% Notes are Central’s senior unsecured obligations and rank equal in right of payment to all of its existing and future unsecured indebtedness and are effectively junior to any secured indebtedness of Central to the extent of the value of the assets securing such indebtedness, if any.  

Capital Lease

Central has a 20-year capital lease with the Owensboro-Daviess County Industrial Development Authority for use of a headquarters building. Ownership of the facility will transfer to Central for a nominal fee upon expiration of the lease in 2024. The overall effective interest rate on the obligation is 6.29%. Principal and interest are paid semi-annually in January and July. Principal payments began July 1, 2005.

Other

A Tax Sharing Agreement is in place by and among Southern Star and Central. Pursuant to this agreement, we operate under a Federal and State Income Tax Policy which provides that Southern Star will file consolidated tax returns on behalf of ourselves and Central and pay all taxes shown thereon to be due. Central makes payments to Southern Star as though it were filing a separate return for its federal income tax liability. Southern Star has an obligation to indemnify Central for any liability that Central incurs for taxes of the affiliated group of which we are members under Treasury Regulations Section 1.1502-6.

On April 30, 2004, Central filed a general rate case under FERC Docket No. RP04-276 which became effective November 1, 2004. The case was settled and became final in 2005. The terms of the settlement require Central to file a rate case to be effective no later than November 1, 2008.

Prior to the acquisition, we entered into employee retention agreements with the officers of Central. Pursuant to the agreements, initial payments of approximately $3.2 million were made in August 2005 to the officers and were recorded in Administrative and general expenses on the accompanying Consolidated Statement of Operations for the period ended August 11, 2005. These agreements require annual payments to those employees totaling $9.3 million over a five-year period for their continued employment. We are accruing the expenses associated with these payments ratably over the period services are being provided. We recorded expenses totaling $1.9 million and $0.7 million in 2006 and for the period from August 12, 2005 through December 31, 2005, respectively, for such annual payments

At December 31, 2006, we were in compliance with the covenants of all outstanding debt instruments. See Note 5 of the accompanying Notes to the Consolidated Financial Statements for further discussion of our debt instruments.

Other

Contractual Obligations and Commitments

The table below summarizes our significant contractual obligations and commitments for the years indicated as of December 31, 2006:

Payments Due by Period

(In thousands)

	Long-Term Debt		Capital Leases1		Purchase Obligations		Operating Leases		Capital Expenditure Commitments2		Total Contractual Obligations
2007		—		765		6,197		205		13,863		21,030
2008		—		690		—		179		11,303		12,172
2009		—		720		—		158		1,578		2,456
2010		3,080		745		—		97		1,578		5,500
2011		—		235				33		708		976
After 2011		430,000		4,745		—		76		—		434,821
Total	$	433,080	$	7,900	$	6,197	$	748	$	29,030	$	476,955

(1)

Principal payments on capital lease for the headquarters building. See discussion in “Liquidity and Capital Resources” above.

(2)

Capital Expenditure commitments represent estimated commitments to third parties to construct facilities in future periods.

We have estimated capital expenditures of $50.3 million in 2007 including $11.0 million for the Waynoka Supply Project and approximately $9.9 million for the Westar Emporia and the Midwest Goodman Expansion Projects. The two expansion projects will be completed at an additional estimated cost of $8.0 million to be incurred in 2008.

In addition to the contractual obligations and commitments listed above, Central expects to contribute $7.5 million to its Union and Non-Union Retirement Plans in 2007. See Note 10 of the accompanying Notes to the Consolidated Financial Statements for further discussion of our employee benefit plans.

Contractual obligations and commitments are expected to be funded with cash flows from operating activities, and by accessing capital markets as needed.

Contingencies

See Note 7 of the accompanying Notes to the Consolidated Financial Statements for further information that may cause operating and financial uncertainties.

Effects of Inflation

Central generally has experienced increased costs in recent years due to the effect of inflation on the cost of labor, materials and supplies, and property, plant and equipment. A portion of the increased labor, materials and supplies costs can directly affect income through increased operating and administrative costs. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of Central’s property, plant, equipment and inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to authorized historical costs. While amounts in excess of historical cost are not recoverable under current FERC practices, we believe Central will be allowed to recover and earn a return based on the increased actual costs incurred when existing facilities are replaced. Cost-based regulation, along with competition and other market factors, limits Central’s ability to price services or products based upon the effect of inflation on costs.

Seasonality

Substantially all of Central’s operating revenues are generated from the collection of fixed monthly reservation fees for transportation and/or storage services. As a result, fluctuations in natural gas prices and actual volumes transported and stored have a limited impact on Central’s operating revenues. Since the fixed monthly reservation fees are generally consistent from month to month, Central’s operating revenues do not fluctuate materially from season to season.

Generally, construction and maintenance on Central’s pipeline occurs during May through October when volume throughput is usually lower than during the winter heating season. As such, operating and maintenance expenses are generally higher in the second and third quarters and the majority of our capital expenditures are incurred during this time.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Our market risk is limited to interest rate risk on our long-term debt. All interest is fixed. Our long-term debt at December 31, 2006, had a carrying value of $431.8 million and a fair value of $431.1 million. The weighted-average interest rate of our long-term debt was 6.60%. Our $200.0 million (6.75%) and $230.0 million (6.0%) long-term debt issues mature in 2016 and the $3.1 million of 8.5% Notes outstanding at December 31, 2006 matures in 2010.

The $7.9 million balance of our capital lease obligation matures serially through 2024 and carries a fixed effective interest rate of 6.29%.

Item 8. Financial Statements and Supplementary Data  

Our accompanying consolidated financial statements presented in this annual report on Form 10-K are listed in the index on page F-1.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Our management, with the participation of our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2006. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2006. There were no material changes in our internal control over financial reporting during 2006 that have materially affected, or are 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

Management

Directors and Officers of Southern Star Central Corp.

The following is a list of Southern Star’s directors and officers, their ages and their positions as of March 1, 2007.

Name	Age		Position
Robert P. Hadden	45	Director
Vandana McCaw	41	Director
Renaud Faucher	42	Director
Yves Rheault	62	Director
Jerry L. Morris	51		President and CEO
Susanne W. Harris	48		Vice President, CFO and Treasurer
Beverly H. Griffith	52		Vice President and Secretary

Directors and Officers of Southern Star Central Gas Pipeline, Inc.

The following is a list of Central’s directors and officers, their ages and their positions as of March 1, 2007.

Name	Age	Position
Robert P. Hadden	45	Director
Vandana McCaw	41	Director
Renaud Faucher	42	Director
Yves Rheault	62	Director
Jerry L. Morris	51	President and CEO
Robert S. Bahnick	47	Senior Vice President of Operations and Technical Services
Robert W. Carlton	46	Vice President of Human Resources and Administration
Chris W. Ellison	52	Vice President of Operations-Hesston Division
David L. Finley	42	Vice President of Information Technology
Beverly H. Griffith	52	Senior Vice President, General Counsel and Corporate Secretary
James L. Harder II	60	Vice President of Customer Services and Business Development
Susanne W. Harris	48	Vice President, CFO and Treasurer
Daryl R. Johnson	53	Vice President of Rates and Regulatory Affairs
Richard J. Reischman	51	Vice President of Operations-Kansas City Division

Robert P. Hadden was appointed to the Board of Directors effective February 6, 2006. Mr. Hadden currently serves as Managing Director of Portfolio Equity at GE Energy Financial Services in Stamford, CT, a position he assumed in April 2006. From September 2002 to April 2006, he was Senior Vice President of Portfolio Equity at GE Energy Financial Services in Stamford, CT. From March 2001 to September 2002, he was a Managing Director of new business initiatives, developing GE Structured Finance’s strategy for entering the gas pipeline sector. Mr. Hadden worked as a Managing Director/Vice President of Risk in GE Capital Structured Finance Group from 1994 to February 2001. Mr. Hadden joined the General Electric Company’s Energy business in 1982 and transitioned to GE Capital in 1994. During his 24 years with GE, he has held a variety of positions, including risk management, portfolio and business development. Whi le at GE Energy, Mr. Hadden held engineering and general management roles in GE Energy’s International Services Business. Mr. Hadden received a Bachelor of Science degree, or B.S., in Mechanical Engineering from University College, Dublin, Ireland in 1982 and a Master of Business Administration, or M.B.A., from Rensselaer Polytechnic Institute, Albany, NY in 1994.

Vandana (Vann) McCaw became a director of our company on April 28, 2006. Ms. McCaw currently serves as Managing Director of Portfolio at GE Energy Financial Services in Stamford, CT, a position she was promoted to in April 2006 from Senior Vice President. Ms. McCaw joined GE in May 2003 as Director of Business Development and subsequently was appointed Managing Director—Acquisitions at GE Energy Financial Services in February 2004. Prior to joining GE, Ms. McCaw worked in Morgan Stanley’s Global Energy Group for nearly nine years, where she was Executive Director responsible for originations and a number of energy client relationships. Ms. McCaw received a B.S. in Business Administration, magna cum laude, from the State University of New York at Albany in 1987, and a Juris Doctor, or J.D., from Columbia School of Law in 1990.

Renaud Faucher became a director of our company on May 1, 2006. Mr. Faucher joined CDP in April 2006 as Director in the private equity group in the Infrastructure and Energy team. He is responsible for the management and optimization of the large investments of the portfolio. From November 1998 to April 2006, Mr. Faucher held different positions within wholly owned subsidiaries of Hydro-Québec, developing and managing their international portfolio of projects. He started as Manager, International Financing from 1998 to 2000 and then moved to Director International Investments for North America for the development of high voltage transmission lines. From January 2003 until April 2006, he also held the position of CFO of TransÉnergie US, a wholly owned subsidiary of Hydro-Québec. From 1992 to 1998, Mr. Faucher worked on the financing and management of independent power plants throughout Canada. From 1986 to 1990, Mr. Faucher worked as a project engineer on the construction of large infrastructure projects in Canada and Europe. Mr. Faucher holds a B.S. from École Polytechnique de Montréal, an M.B.A. from Concordia University and is also a Certified Management Accountant.

Yves Rheault was elected to the Board of Directors effective May 26, 2006. Mr. Rheault currently serves as advisor within the private equity group in the Infrastructure and Energy team at CDP, a function he assumed in October of 2002. From 2000 to October 2002, Mr. Rheault was Vice Chairman of the Board and Vice President of Business Development of Boralex, Inc. Prior to joining CDP, Mr. Rheault held various senior positions in several different companies (besides Boralex, Inc.) involved in the energy sector, and has been Chairman of the Board of Gaz Métro, the third largest gas distributor in Canada, for ten years. Mr. Rheault also currently serves on the Board of Directors of Vermont Gas, Inc., Boralex, Inc., and Intragas, Inc. Mr. Rheault holds a Bachelor in Commerce and a Masters in Administration from the University of Montreal.

Jerry L. Morris became President and CEO of Southern Star and Central in August 2005. He had been president and Chief Operating Officer, or COO, of Central since February 13, 2004. Previously, he served as Central’s Vice President/Director of Business Development since 2001, and held the position of Director of Rates and Strategic Planning for Central and/or its predecessors or affiliates since 1987. Mr. Morris has held a variety of positions in accounting, business development and rates during his 29 years in the interstate natural gas pipeline industry. He received his B.S. in Accounting from Murray State University in 1977, and his M.B.A. from the same institution in 1985. He is active in several industry organizations.

Robert S. Bahnick, Senior Vice President of Operations and Technical Services for Central since July 2003, served as Vice President of Operations and Technical Services since November 2002, served as Vice President of Operations for Central since 1998, and prior to that time, served in a similar position for either predecessors and/or affiliates of Central since 1996, with a total of 25 years in the interstate natural gas pipeline industry. Mr. Bahnick earned his B.S. in Mechanical Engineering from Pennsylvania State University in 1981. Mr. Bahnick is a registered Professional Engineer, a member of the Southern Gas Association, and a member of American Society of Mechanical Engineers and Interstate Natural Gas Association of America Operations, Safety and Environmental Committee.

Robert W. Carlton, Vice President of Human Resources and Administration for Central since July 2003, served as Central’s Director of Human Resources since 1997, and prior to that time served as the Director of Human Resources for Central’s predecessors and/or affiliates since 1992, holding various positions in human resources, rates, and accounting during his 23 years in the interstate natural gas pipeline industry. Mr. Carlton earned his B.S. in Accounting from Murray State University in 1983. He is a member of the Southern Gas Association.

Chris W. Ellison, Vice President of Operations-Hesston Division for Central since July 2003, served as Central’s Director of Operations for both the Kansas City and Hesston divisions since 1996, holding various other positions at Central, and/or its predecessors in engineering, operations, and natural gas control during his 28 years in the interstate natural gas pipeline industry. He earned his B.S. in Civil Engineering from the University of Oklahoma in 1978 and is a registered Professional Engineer.

 David L. Finley, Vice President of Information Technology for Central since July 2003, served as Central’s Director of Information Technology since November 2002, and prior to that time served as manager of Operations and Engineering systems for Central and/or its affiliates since 1998, holding a variety of positions in Information Technology during his 20 years in the interstate natural gas pipeline industry. He earned his B.S. in Geology from Murray State University in 1986.

Beverly H. Griffith became Vice President and Secretary of Southern Star in August 2005. She has been Senior Vice President, General Counsel and Corporate Secretary for Central since July 2003. Previously, she served as Corporate Secretary since November 2002, and served as Central’s General Counsel since 1998, holding a similar position for Central or its predecessors and/or its affiliates since 1995. Ms. Griffith has held a variety of positions in the legal area, including Assistant General Counsel and Senior Attorney, during her 27 years in the interstate natural gas pipeline industry. She received her Bachelor of Arts degree in History from the University of Mississippi in 1976 and her J.D. from the University of Kentucky College of Law in 1979. Ms. Griffith is a member of the Kentucky Bar Association and the Energy Bar Association.

James L. Harder II, Vice President of Customer Services and Business Development for Central since February 2004, served as Vice President of Customer Services for Central since July 2003, and served as Director of Customer Services and Business Development or Director of Gas Management for Central since 1996. Mr. Harder has held a variety of positions in accounting, contract administration, gas management and marketing during his 31 years at Central. He earned his B.S. in Accounting from Oklahoma State University in 1969 and has served in a variety of industry organizations including the Southern Gas Association and the Interstate Natural Gas Association of America.

Susanne W. Harris became Vice President, CFO, and Treasurer of Southern Star and Central in August 2005. She had been Vice President of Finance and Accounting for Central since July 2003, has served as Assistant Treasurer for Central since November 2002, and has served as Central’s Controller and Chief Accounting Officer since March 2000, serving in a similar position for its affiliates since 1997. Ms. Harris has held a variety of positions in finance and accounting during her 27 years in the interstate natural gas pipeline industry. Ms. Harris earned her B.S. in Accounting from Brescia College in 1979 and her M.B.A. from Murray State University in 1989. She is a member of accounting committees for the American Gas Association and the Interstate Natural Gas Association of America.

Daryl R. Johnson, Vice President of Rates and Regulatory Affairs for Central since July 2003, served as Manager of Rates for Central since 1990. Mr. Johnson has held a variety of positions in accounting and rates during his 31 years at Central or its predecessors. He earned his B.S. in Accounting from Southwestern Oklahoma State University in 1975. Mr. Johnson is a current member and the past chairman of the Rates Committee for the Southern Gas Association.

Richard J. Reischman, Vice President of Operations-Kansas City Division for Central since July 2003, served as Central’s Director of Operations for the Kansas City Division since 2001 and Manager of Operations for various regions of the Central system since 1993. Mr. Reischman has served in a variety of positions in engineering and operations during his 28 years at Central or its predecessors. He received his B.S. in Electrical Engineering from Kansas University in 1978.

There are no family relationships among Southern Star’s or Central’s directors or the officers listed. Directors serve one-year terms with elections held at each annual meeting or until their successors have been elected and qualified or until their earlier resignation or removal. Officers serve for such term as shall be determined from time to time by the Board of Directors, or until successors have been elected and qualified, or until their death, resignation or removal.

We have appointed certain officers and directors as members of our Disclosure Committee, with the responsibility of ensuring the adequacy of our disclosure controls and procedures and assessing the quality of disclosures made in public filings with the SEC. Assessments are reviewed with the CEO and CFO prior to filings being submitted to the SEC. Furthermore, we have established a “Code of Ethics for CEO and Senior Financial Officers” applicable to officers and directors residing in certain positions defined therein. This Code is posted on our website at www.southernstarcentralcorp.com. Any amendments or waivers thereto will also be posted to the website.

We are not required to establish an audit committee since we do not have securities traded on a national securities exchange. Due to the small size of our Board of Directors, the full Board acts in the capacity of an audit committee. None of the Board’s members are financial experts, and they are not, nor are they required to be, “independent” within the meaning of Federal securities laws.

Item 11. Executive Compensation

Compensation Discussion and Analysis

The following discussion and analysis of compensation arrangements of our named executive officers for fiscal year ended December 31, 2006 should be read together with the compensation tables and related disclosures set forth below.   This discussion contains forward-looking statements that are based on our current plans, considerations, expectations and determinations regarding future compensation programs.  Actual compensation programs that we adopt may differ materially from currently planned programs as summarized in this discussion.

The primary objectives of the Board of Directors, or the Board, with respect to executive compensation are to attract and retain the best possible executive talent, to tie annual incentives to the achievement of measurable Company and individual performance targets, and to align executive incentives with the creation of shareholder value.  The method of determining compensation varies from case to case based on a discretionary and subjective determination of what is appropriate at the time.  When establishing salaries and bonus levels, the Board considers individual experience and performance, along with the salaries of executive officers in similar positions with companies of comparable size within the gas pipeline industry.  With respect to officers other than the CEO, the Board also takes into consideration the recommendations of the CEO.  

Compensation Components

The Company’s compensation program for its named executive officers, or officers, consists of four primary elements: (1) base salary; (2) a performance-based annual bonus; (3) employment agreements and the retention payments being made thereunder; and (4) retirement benefits.

Base Salary:  Base salaries for the officers take into account such factors as competitive industry salary ranges, an officer’s scope of responsibilities, and individual performance and contribution to the Company.  To the extent appropriate, the Board also considers general economic conditions for the geographic location of the officer and economic factors within the gas pipeline industry.  

Annual Bonus:  Officers participate in the Company’s Annual Bonus Plan, or the Bonus Plan, along with all other employees, at levels established by the Board.  The purpose of the Bonus Plan is to motivate employees to actively participate in the achievement of annual Company goals, as established by management and the Board, by putting a portion of employee compensation “at risk”.  Awards are based on the successful attainment of specific Company and individual performance targets.  Targets may include such factors as improved earnings; on-time, on-budget capital project execution; operational safety measures; and successful pursuit of business growth strategies.  

The size of the bonus pool is based on the achievement of established targets.  Once the bonus pool is determined, the CEO makes individual bonus recommendations to the Board for each officer, based on the achievement of Company goals and an evaluation of each officer’s individual performance. Award recommendations for all other employees are approved by the CEO.   The Board makes the final determination of awards for all officers, including the CEO.

Employment Agreements and Retention Payments:  During the course of the acquisition of Southern Star in 2005, all officers entered into employment agreements with the Company to ensure the stability and strength of the Company’s management team.  The agreements, which are further described below, provide for Base Salaries and Annual Bonuses as described above and provide terms for severance payments under certain conditions.  The agreements also provide for annual payments over a five-year period to each officer for his continued employment.  

Retirement Benefits: We offer a Non-Union Retirement Plan and a 401(k) Plan, as further described below, to all of our employees who meet certain age and service requirements.  Our officers may participate in these plans up to the maximum limits allowed by law.  

The Company does not presently offer any long-term performance incentives, equity-based compensation, or supplemental retirement benefits to its officers, directors, or any other employees.   Directors do not receive any compensation for their services and are not currently eligible to participate in the above-described plans.

Summary Compensation Table

The following table sets forth certain summary compensation information as to the CEO and CFO of Central, our operating entity, during the fiscal year 2006, and the other three most highly compensated executive officers of Central as of December 31, 2006. The table below indicates for each of the named executive officers salary, bonus, and all other compensation for the fiscal years of Southern Star and Central ended December 31, 2004, 2005 and 2006 (expressed in thousands):

SUMMARY COMPENSATION TABLE

Name and Principal Position(1)	Year	Salary $	Bonus $	Change in Pension Value and Nonqualified Deferred Compensation Earnings* $	All Other Compensation $**	Total $
Jerry L. Morris	2004	196,222	76,731	N/A	12,085	285,038
President, CEO of Central	2005	211,454	210,000	N/A	1,062,600	1,484,054
(from 8/11/2005, was COO from 2/13/2004)	2006	218,147	216,300	28,152	643,200	1,105,799
Susanne W. Harris	2004	136,168	67,500	N/A	11,909	215,577
Vice President, Finance and Accounting, and CFO	2005	141,517	70,031	N/A	246,975	458,523
of Central	2006	147,804	73,183	25,777	153,111	399,875
Beverly H. Griffith	2004	198,172	144,300	N/A	12,300	354,772
Senior Vice President, General Counsel	2005	197,210	144,300	N/A	218,148	559,658
and Corporate Secretary of Central	2006	198,376	144,300	31,752	136,950	511,378
Robert S. Bahnick	2004	206,000	145,455	N/A	12,300	363,755
Senior Vice President of Operations	2005	205,000	150,000	N/A	278,225	633,225
and Technical Services of Central	2006	202,155	159,375	18,584	160,385	540,499
James L. Harder II	2004	145,815	72,324	N/A	12,300	230,439
Vice President of Customer Services	2005	151,301	74,855	N/A	302,546	528,702
and Business Development of Central	2006	155,673	76,726	49,479	218,200	500,078

*

See Note 10 of the accompanying Notes to the Consolidated Financial Statements for discussion of assumptions used in determining these present values at December 31, 2005 and December 31, 2006.

** 

All Other Compensation for 2004, 2005 and 2006 represents matching contributions by Central under the Southern Star Investment Plan, Central’s broad-based 401(k) plan. For 2005, it contains the amounts of $12,600 for Mr. Morris, $12,600 for Mr. Bahnick, $11,898 for Mrs. Griffith, $12,546 for Mr. Harder, and $12,600 for Mrs. Harris. For 2006, it contains the amounts of $13,200 for Mr. Morris, $10,385 for Mr. Bahnick, $13,200 for Mrs. Griffith, $13,200 for Mr. Harder, and $12,486 for Mrs. Harris.  These amounts are to be paid out to the named executives only upon retirement, termination, disability or death.  For 2005, it also includes amounts of $1,050,000 to Mr. Morris, $265,625 to Mr. Bahnick, $206,250 to Mrs. Griffith, $290,000 to Mr. Harder, and $234,375 to Mrs. Harris, and for 2006 the amounts of $630,000 for Mr. Morris, $150,000 for Mr. Bahn ick, $123,750 for Mrs. Griffith, $205,000 for Mr. Harder, and $140,625 for Mrs. Harris in respect to the retention bonuses described below.

(1)

Each of these officers is compensated by Central.

For a description of the terms of each named executive officer’s employment agreement, see “Employment Agreements and Potential Payments Upon Termination or Change-In-Control.”

Options/SAR Grants, Exercises and Year-End Value and Long-Term Incentive Plans

We do not offer stock options, share appreciation rights, restricted stock or any other stock-based awards or any long-term incentive programs to our employees.

Pension Benefits

Central is the sponsor of the Southern Star Retirement Plan (Non-Union Plan), a defined benefit pension plan established effective January 1, 2003. All named executive officers are covered under the Non-Union Plan. Benefits under the Non-Union Plan are based on a participant’s years of service (retroactive to November 15, 2002) and his/her final average pay, broadly defined as the highest three years of covered compensation in the last ten years of employment.  The table below indicates for each of the named executive officers the number of years of service credited under the plan, the actuarial present value of the named executive officer’s accumulated benefit under the plan and the dollar amount of any payments and benefits paid to the named executive officers during 2006 (expressed in thousands):

Name	Number of Years of Credited Service	Present Value of Accumulated Benefit***	Payments During Last Fiscal Year
Jerry L. Morris	4.167	$ 96,336	$ —
Susanne W. Harris	4.167	79,296	—
Beverly H. Griffith	4.167	111,874	—
Robert S. Bahnick	4.167	69,271	—
James L. Harder	4.167	188,767	—

***

See Note 10 of the accompanying Notes to the Consolidated Financial Statements for discussion of assumptions used in determining these present values at December 31, 2006.

Normal retirement age is the later of age 65 and five years of plan participation. The amounts shown in the table above are based on a straight-life annuity commencing at normal retirement age and are not offset by Social Security benefits or other offset amounts.

The compensation covered by the Non-Union Plan is total salary, including any overtime, salary reduction amounts and bonus awards (unless specifically excluded under a written bonus or incentive-pay arrangement), but excluding severance pay, cost-of-living pay, housing pay, relocation pay, taxable and non-taxable fringe benefits and all other extraordinary pay. Pursuant to the Internal Revenue Code, or IRC, covered compensation is presently limited to $210,000 per year for 2005 and $220,000 for 2006. Aside from the IRC limitation, the covered compensation of each named executive officer is approximately equal to the sum of salary and bonus as shown under the Summary Compensation Table above.

401(k) Plan

In addition to pension benefits, the Company provides a 401(k) Plan whereby employee contributions are matched by the Company up to established limits.

Compensation of Directors

No director of Southern Star or Central receives any remuneration for serving on the Boards of Directors or any committee thereof.

Employment Agreements and Potential Payments Upon Termination or Change-in-Control

On May 13, 2005, we entered into an employment agreement with Jerry L. Morris, Central’s President and CEO, which was subsequently amended on August 11, 2005 and November 20, 2006.  The primary term of the three-year employment agreement was set to expire on February 12, 2007; however the term was extended to August 11, 2010.  Thereafter, the employment agreement will be extended automatically in one-year increments unless 90 days notice of termination is given by the Board of Directors prior to the end of the applicable employment period.  The employment agreement provides for an annual base salary subject to upward adjustments with an annual incentive bonus in an amount up to 100% of Mr. Morris’ base salary based on certain allocations and targets.  The calculation of the incentive payments to be made to Mr. Morris conform with the calculation of such payments made under the company-wide incentive plan applicable to other executives and employees, as that plan may exist from time to time. In addition, Mr. Morris’ employment agreement provides for severance benefits under the same terms as the employee agreements of the other officers as described below.  In addition to the salary provided to Mr. Morris, he will receive an aggregate five-year retention bonus of $4.2 million payable in annual installments over the five-year term of the employment agreement.  

If Mr. Morris is terminated without cause or resigns for Good Reason (as defined in the employment agreement), or if his employment is not continued after the initial term of the employment agreement or any one-year renewal period, the Company must pay Mr. Morris a severance benefit equal to two times his annual base salary plus an amount equal to his average annual incentive bonus paid during the most recent three-year period under the employment agreement, expressed as a percentage of his annual base salary, times his annual base salary then in effect.  

On August 11, 2005, in connection with a change in control, we entered into employment agreements with each of Robert S. Bahnick, Senior Vice President, Operations and Technical Services; Robert W. Carlton, Vice President, Human Resources and Administration; Chris W. Ellison, Vice President, Operations; David L. Finley, Vice President, Information Technology; Beverly H. Griffith, Senior Vice President, General Counsel and Corporate Secretary; James L. Harder, Vice President, Customer Services and Business Development; Susanne W. Harris, Vice President, CFO and Treasurer; Daryl R. Johnson, Vice President, Rates and Regulatory; and Richard J. Reischman, Vice President, Operations. Each of the employment agreements provides for a five-year term and an annual base salary, which is subject to upward adjustments, and aggregate five-year retention bonuses, payable in annual installments over the five-year term of the employment agreemen ts, as follows: Mr. Bahnick, $1,062,500; Mr. Carlton, $937,500; Mr. Ellison, $700,000; Mr. Finley, $825,000; Ms. Griffith, $825,000; Mr. Harder, $1,062,500; Ms. Harris, $937,500; Mr. Johnson, $1,250,000; and Mr. Reischman, $700,000. In addition to salary and retention bonus, each of the employment agreements provides for an annual incentive bonus of up to 50% of the employee’s annual salary, except for the employment agreements of Mr. Bahnick and Ms. Griffith, whose agreements provide for annual incentive bonuses of up to 75% of their annual salaries.

In addition, each employee is entitled to receive severance payments if (i) his or her employment is involuntarily terminated for any reason other than death, disability or Cause (as defined in the agreements) or (ii) if his or her employment is terminated by the employee for Good Reason (as defined in the agreements). Such severance payments consist of an amount equal to two times the sum of the employee’s salary then in effect plus an amount equal to the average bonus percentage that had been paid to the employee during the course of the agreement applied to the employee’s salary then in effect. The severance payment will be paid to the employee in one lump sum payment within 30 days of the termination of employment. Each agreement also provides that, during the course of the agreement and for one year following the termination of employment, the employee may not solicit employees or contractors away from Central or solici t the business of any client or customer of Central in any territory, state or country where Central conducts business.

Compensation Committee Interlocks and Insider Participation

We are not required to establish a compensation committee since we do not have securities traded on a national securities exchange.  Due to the small size of our Board of Directors, the full Board acts in the capacity of a compensation committee.

None of our executive officers served as a member of the compensation committee (or other board or board committee performing equivalent functions) of another entity, one of whose executive officers served on our compensation committee. None of our executive officers served as a director of another entity, one of whose executive officers served on our compensation committee. None of our executive officers served as a member of the compensation committee (or other board or board committee performing equivalent functions) of another entity, one of whose executive officers served as our director.

Indemnification of Executive Officers and Directors

Section 145 of the Delaware General Corporation Law provides that a company may indemnify any persons who were, or are threatened to be made, parties to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such company), by reason of the fact that such person is or was an officer, director, employee or agent of such company, or is or was serving at the request of such company as a director, officer, employee or agent of another company, partnership, joint venture, trust or other enterprise.  The indemnity may include expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such person acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the company’s best interests a nd, with respect to any criminal action or proceeding, had no reasonable cause to believe that his or her conduct was unlawful.

Section 145 of the Delaware General Corporation Law further authorizes a company to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the company, or is or was serving at the request of the company as a director, officer, employee or agent of another company or enterprise, against any liability asserted against him or her and incurred by him or her in any such capacity, arising out of his or her status as such, whether or not the company would otherwise have the power to indemnify him or her under Section 145 of the Delaware Corporation Law.

Pursuant to Section 102(b)(7) of the Delaware General Corporation Law, Southern Star’s Amended and Restated Certificate of Incorporation eliminates the personal liability of a director or officer to the company or its stockholders for monetary damages for breach of fiduciary duty as a director or officer, as applicable, except for liabilities arising (a) from any breach of the duty of loyalty to the company or its stockholders; (b) from acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law; (c) under Section 174 of the Delaware General Corporation Law; or (d) from any transaction from which such person derived an improper personal benefit.  In addition, Southern Star’s bylaws provide for indemnification of directors, officers, employees and agents to the fullest extent permitted by Delaware law.  We maintain directors’ and officers’ liability insurance for the benefit of our directors a nd officers.

The bylaws of Central provide for the indemnification of a director, officer, employee or agent by the Company in a suit by or in the right of the Company unless such person has been adjudged to be liable to the company and the Court of Chancery in the State of Delaware has not determined that indemnification of such person is appropriate.  Furthermore, the bylaws provide for indemnification of directors, officers, employees and agents if such person acted in good faith and in a manner such person reasonably believed to be in, or not opposed, to the best interests of the Company.  Central maintains directors’ and officers’ liability insurance for the benefit of its directors and officers.  

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth certain information, as of March 14, 2007, with respect to the beneficial ownership of our common stock by (1) each person who beneficially owns more than 5% of such shares, (2) each of the named executive officers, (3) each director of the Company and (4) all of the named executive officers and directors of the Company as a group.

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class
EFS-SSCC Holdings, LLC(1)	100 shares	100%
120 Long Ridge Road
Stamford, CT   06927
All named executive officers and directors as a group (five total)	0 shares	0%

(1)

EFS-SSCC Holdings, LLC is indirectly owned 60% by GE and 40% by CDP, each of which has 50% voting control.

We do not maintain or offer our employees or non-employees any stock option, warrant, restricted stock or other compensation plan or arrangement under which our equity securities are authorized for issuance.

Item 13. Certain Relationships and Related Transactions, and Director Independence

On August 11, 2005, Central and Western Frontier entered into an Operating Company Services Agreement, or Operating Services Agreement, with EFS Services, LLC, an affiliate of GE. Pursuant to the Operating Services Agreement, EFS Services, LLC will provide certain consulting services to Central and Western Frontier for a service fee of $1.0 million per year, plus the reimbursement of reasonable expenses up to $0.2 million in a 12-month period incurred by EFS Services, LLC in providing such services. During December 31, 2006 and 2005, we paid approximately $1.0 million and $0.4 million, respectively, for service fees and expenses to EFS Services, LLC. The Operating Services Agreement terminates at such time as GE or any of its affiliates ceases to beneficially own any securities of Holdings. In addition, on August 11, 2005, we entered into an Administrative Services Agreement, or Services Agreement, w ith EFS Services, LLC to provide certain administrative services to us and Holdings. Pursuant to the terms of the Services Agreement, EFS Services, LLC is not paid a fee for its services; however, it is entitled to be reimbursed for the reasonable expenses it incurs in providing such services.

We are not subject to Section 13 or 15(d) of the Securities Exchange Act of 1934, as we do not have securities traded on a national securities exchange.  Therefore, our Board of Directors is not subject to independence requirements and none of our directors are independent.

Central makes purchases of goods and services from various affiliates of GE on an arms-length basis in the normal course of its operations.

Item 14. Principal Accountant Fees and Services

Audit Fees

The aggregate fees paid or accrued for professional services rendered by Ernst & Young, LLP, or E&Y, in connection with the audit of our annual consolidated financial statements for the years ended December 31, 2006 and 2005, and in connection with statutory and regulatory filings for such fiscal periods, were $624,668 and $539,769, respectively.

Audit-Related Fees

The aggregate fees for services rendered by E&Y in connection with audit-related services, primarily for the audits of certain of Central’s benefit plans, for each of the fiscal years ended December 31, 2006 and 2005 were $91,195 and $85,000, respectively.

Tax Fees

No tax compliance, tax advice or tax planning services were provided by E&Y for the fiscal years ended December 31, 2006 and 2005.

All Other Fees

No other services were provided by E&Y for the fiscal years ended December 31, 2006 and 2005.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services

All auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for us by our independent auditor must be pre-approved by the Board of Directors. All audit and non-audit services provided by E&Y, an Independent Registered Public Accounting Firm, during 2006 were pre-approved by the Board of Directors.

PART IV.

Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as part of this report

1. Consolidated Financial Statements

Included in Item 8, listed in the Index on page F-1 of this report:
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets at December 31, 2006 and 2005	F-3
Consolidated Statements of Operations for the year ended December 31, 2006, the period August 12 through December 31, 2005, the period January 1 through August 11, 2005, and the year ended December 31, 2004	F-5
Consolidated Statements of Cash Flows for the year ended December 31, 2006, the period August 12 through December 31, 2005, the period January 1 through August 11, 2005, and the year ended December 31, 2004	F-6
Consolidated Statements of Stockholder’s Equity for the year ended December 31, 2006, the period August 12 through December 31, 2005, the period January 1 through August 11, 2005, and the year ended December 31, 2004	F-7
Notes to the Consolidated Financial Statements	F-8

2. Financial Statement Schedules

Schedules have been omitted because of the absence of conditions under which they are required or because the information required is provided in the Consolidated Financial Statements or Notes thereto.

3. Exhibits

(a) Exhibits.

Exhibit Number		Description of Document
1.16		Purchase Agreement, dated April 6, 2006, between Southern Star Central Corp. and Lehman Brothers Inc. and Credit Suisse Securities (USA) LLC (the “Initial Purchasers”).
3.11		Amended and Restated Certificate of Incorporation of Southern Star Central Corp., dated August 11, 2005.
3.22		Bylaws of Southern Star Central Corp.
3.42		Restated Certificate of Incorporation of Southern Star Central Gas Pipeline, Inc., as amended.
3.52		Bylaws of Southern Star Central Gas Pipeline, Inc.
4.11		Indenture, dated August 8, 2003, by and among Southern Star Central Corp. and Deutsche Bank Trust Company Americas, as Trustee.
4.23		8 1/2% Senior Secured Note Due 2010.
4.32		Stock Pledge Agreement, dated as of August 8, 2003, by and among Southern Star Central Corp. and Deutsche Bank Trust Company Americas, as Trustee and Collateral Agent.
4.44		Indenture, dated April 13, 2006, between Southern Star Central Corp. and The Bank of New York Trust Company, N.A. (the “Trustee”).
4.54		Registration Rights Agreement, dated April 13, 2006, between Southern Star Central Corp. and the Initial Purchasers.
4.66		Form of Certificate of 6 3/4% Senior Notes due 2016.
4.7		Reimbursement and Credit Agreement, dated January 1, 2004, between Southern Star Central Gas Pipeline, Inc. and U.S. Bank, N.A.
4.8		Trust Indenture, dated January 1, 2004, between Industrial Development Authority and U.S. Bank.
4.9		Loan Agreement, dated January 1, 2004, between Industrial Development Authority and Southern Star Central Gas Pipeline, Inc.
4.10		Recapitalization Agreement, dated as of August 11, 2005, between EFS-SSCC Holdings, LLC and Southern Star Central Corp.
4.11		Indenture, dated April 13, 2006, between Central and The Bank of New York Trust Company, N.A.
4.12		Supplemental Indenture, dated April 10, 2006, by and between Southern Star Central Corp. and Deutsche Bank Trust Company Americas, as Trustee.
10.12		Trans-Storage Service Agreement under Rate Schedule TSS, dated October 3, 1994 (as amended), by and among Southern Star Central Gas Pipeline, Inc. (f/k/a Williams Natural Gas Company) and Kansas Gas Service Company, a division of ONEOK (f/k/a Western Resources, Inc.).
10.22		Trans-Storage Service Agreement under Rate Schedule TSS, dated June 15, 2001 (as amended), by and among Southern Star Central Gas Pipeline, Inc. (f/k/a Williams Gas Pipelines Central, Inc.) and Missouri Gas Energy, a division of Southern Union Company.
10.32		Tax Sharing Agreement, dated November 3, 2003 by and among Southern Star Central Corp. and Southern Star Central Gas Pipeline, Inc.
10.43		Lease Agreement, dated January 1, 2004 between Industrial Development Authority and Southern Star Central Gas Pipeline, Inc.
10.51		Operating Company Services Agreement, dated as of August 11, 2005, among Central, Western Frontier Pipeline Company, L.L.C. and EFS Services, LLC.
10.61		Administrative Services Agreement, dated as of August 11, 2005, among EFS Services, LLC, EFS-SSCC Holdings, LLC and Southern Star Central Corp.
10.71		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and Robert S. Bahnick.
10.81		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and Robert W. Carlton.
10.91		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and Chris W. Ellison.
10.101		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and David L. Finley.
10.111		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and Beverly H. Griffith.
10.121		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and James L. Harder.
10.131		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and Susanne W. Harris.
10.141		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and Daryl R. Johnson.
10.151		Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and Richard J. Reischman.
10.165		Employment Agreement, dated as of May 13, 2005, between Southern Star Central Corp., Central and Jerry L. Morris.
10.171		Amendment to Employment Agreement, dated as of August 11, 2005, among Southern Star Central Corp., Central and Jerry L. Morris.
10.186		Amendment No. 2 to Employment Agreement, dated as of November 20, 2006, among Southern Star Central Corp., Central and Jerry L. Morris.
12.1		Ratio of Earnings to Fixed Charges.
21.12		Subsidiaries of Southern Star Central Corp.
31.1		Certificate of Jerry L. Morris, Chief Executive Officer of Southern Star Central Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certificate of Susanne W. Harris, Chief Financial Officer of Southern Star Central Corp., pursuant to Section 302 of the Sarbanes-Oxley Act 2002
32.0		Certificate of Jerry L. Morris, Chief Executive Officer of Southern Star Central Corp., and Susanne W. Harris, Chief Financial Officer of Southern Star Central Corp., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1)

Incorporated by reference from Exhibits 99 to Southern Star Central Corp.’s Report on Form 8-K filed with the SEC on August 11, 2005.

(2)

Incorporated by reference from Southern Star Central Corp.’s Registration Statement on Form S-4, as amended (Registration No. 333-135512).

(3)

Incorporated by reference from Southern Star Central Corp.’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 18, 2004.

(4)

Incorporated by reference from Southern Star Central Corp.’s Report on Form 8-K filed with the SEC on April 18, 2006.

(5)

Incorporated by reference from Exhibit 99.1 to Southern Star Central Corp.’s Report on Form 8-K filed with the SEC on May 16, 2005.

(6)

Incorporated by reference from Southern Star Central Corp.’s Report on Form 8-K Filed with the SEC on November 20, 2006.

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 STAR CENTRAL CORP.
March 14, 2007	By:	/s/    JERRY L. MORRIS
		Jerry L. Morris President and Chief Executive Officer
March 14, 2007	By:	/s/    SUSANNE W. HARRIS
		Susanne W. Harris Vice President, Chief Financial Officer & Treasurer

Pursuant to the requirements of the Securities Act of 1933, this report has been signed below by the following persons in the capacities and on the dates indicated:

	Signature	Title	Date
By:	/s/    VANDANA MCCAW         Vandana McCaw	Director	March 14, 2007
By:	/s/    ROBERT P. HADDEN         Robert P. Hadden	Director	March 14, 2007
By:	/s/    YVES RHEAULT         Yves Rheault	Director	March 14, 2007
By:	/s/   RENAUD FAUCHER        Renaud Faucher	Director	March 14, 2007

No annual report or proxy material has been sent to security holders.

Item 8. Consolidated Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Financial Statements:
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-5
Consolidated Statements of Cash Flows	F-6
Consolidated Statements of Stockholder’s Equity	F-7
Notes to the Consolidated Financial Statements	F-8

Schedules have been omitted because of the absence of the conditions under which they are required or because the information required is provided in the Consolidated Financial Statements or the Notes thereto.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

SOUTHERN STAR CENTRAL CORP.

We have audited the consolidated balance sheets of Southern Star Central Corp. and subsidiaries, or the Company, as of December 31, 2006 and 2005 and the related consolidated statements of operations, stockholder’s equity, and cash flows for the year ended December 31, 2006 and for the period August 12, 2005 through December 31, 2005 (post-acquisition). We have also audited the consolidated statements of operations, stockholder’s equity, and cash flows for the period from January 1, 2005 through August 11, 2005, and for the year ended December 31, 2004 (pre-acquisition). These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purposes of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evalua ting the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Southern Star Central Corp. and subsidiaries at December 31, 2006 and 2005 and the consolidated results of its operations and cash flows for the year ended December 31, 2006, the period from August 12 through December 31, 2005 (post-acquisition), the period January 1 through August 11, 2005, and for the year ended December 31, 2004 (pre-acquisition) in conformity with accounting principles generally accepted in the United States.

As discussed in Note 4 to the accompanying consolidated financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of FASB Statements  No. 87, 88, 106 and 132(R).”  Also discussed in Note 4 to the accompanying consolidated financial statements, in 2006 the Company adopted the Federal Energy Regulatory Commission’s “Order on Accounting for Pipeline Assessment Costs.”

/s/ ERNST & YOUNG LLP

Louisville, Kentucky

March 13, 2007

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31, 2006			December 31, 2005
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	37,989		$	62,287
Receivables:
Trade		16,700			15,948
Income taxes		591			285
Transportation, exchange and fuel gas		5,425			3,660
Other		523			7,334
Inventories		6,458			5,741
Deferred income taxes		7,876			1,375
Costs recoverable from customers		10,589			1,000
Prepaid expenses		3,951			4,519
Derivative instrument asset – hedges		—			460
Other		643			493
Total current assets		90,745			103,102
Property, Plant and Equipment, at cost:
Natural gas transmission plant		535,034			506,223
Other natural gas plant		25,743			22,280
		560,777			528,503
Less – Accumulated depreciation and amortization		(16,507	)		(796	)
Property, plant and equipment, net		544,270			527,707
Other Assets:
Goodwill		324,580			324,366
Costs recoverable from customers		44,007			48,585
Prepaid expenses		1,327			1,551
Postretirement benefits other than pensions		10,165			7,027
Other deferred and noncurrent assets		9,230			3,965
Total other assets		389,309			385,494
Total Assets	$	1,024,324		$	1,016,303

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31, 2006		December 31, 2005
	(In thousands)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Payables:
Notes	$	—	$	7,250
Trade		4,834		2,497
Transportation, exchange and fuel gas		15,014		1,919
Other		9,245		5,274
Accrued taxes, other than income taxes		5,733		5,067
Accrued interest		5,927		8,548
Accrued payroll and employee benefits		11,809		12,113
Costs refundable to customers		—		1,741
Current maturities of long-term debt		—		224,912
Capitalized lease obligation due in one year		765		735
Other accrued liabilities		3,914		7,529
Total current liabilities		57,241		277,585
Long-Term Debt:
Capitalized lease obligation		7,135		7,900
Other long-term debt		431,811		194,444
Total long-term debt		438,946		202,344
Other Liabilities and Deferred Credits:
Deferred income taxes		43,328		18,695
Postretirement benefits other than pensions		9,437		10,165
Asset retirement obligations		2,299		2,157
Costs refundable to customers		10,279		7,143
Environmental remediation		2,736		3,598
Accrued pension		25,234		28,941
Other		129		1,161
Total other liabilities and deferred credits		93,442		71,860
Stockholder’s Equity:
Common stock, $.01 par value, 100 shares issued,
100 shares outstanding, December 31, 2006 and 2005		—		—
Premium on capital stock and other paid-in capital		426,895		454,721
Retained earnings		7,800		9,751
Accumulated other comprehensive income		—		42
Total stockholder’s equity		434,695		464,514
Total Liabilities and Stockholder’s Equity	$	1,024,324	$	1,016,303

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Post-acquisition						Pre-acquisition
	For the Year Ended December 31, 2006			For the Period August 12 through December 31, 2005			For the Period January 1 through August 11, 2005			For the Year Ended December 31, 2004
		(In thousands)						(In thousands)
Operating Revenues:
Transportation	$	164,073		$	61,144		$	100,002		$	146,127
Storage		22,375			9,371			10,772			17,458
Other revenue		798			254			394			747
Total operating revenues		187,246			70,769			111,168
Operating Costs and Expenses:
Operations and maintenance		41,030			14,702			23,568			37,508
Administrative and general		34,939			13,809			25,688			37,026
Depreciation and amortization		26,881			10,884			17,299			27,781
Taxes, other than income taxes		13,349			4,745			7,573			10,831
Total operating costs and expenses		116,199			44,140			74,128
Operating Income		71,047			26,629			37,040			51,186
Other (Income) Deductions:
Interest expense		29,964			11,337			25,169			40,856
Interest income		(2,401	)		(737	)		(719	)		(651	)
Miscellaneous other (income) expenses, net		(445	)		(121	)		113			2,401
Total other deductions		27,118			10,479			24,563			42,606
Income Before Income Taxes		43,929			16,150			12,477			8,580
Provision for Income Taxes		17,558			6,399			7,074			6,511
Net Income	$	26,371		$	9,751		$	5,403		$	2,069

Reconciliation of net income to total comprehensive income:

	Post-acquisition						Pre-acquisition
	For the Year Ended December 31, 2006			For the Period August 12 through December 31, 2005			For the Period January 1 through August 11, 2005			For the Year Ended December 31, 2004
		(In thousands)						(In thousands)
Net income	$	26,371		$	9,751		$	5,403		$	2,069
Change in value of interest rate swaps		(68	)		68			179			737
Related tax benefit (provision)		26			(26	)		(69	)		(288	)
Total comprehensive income	$	26,329		$	9,793		$	5,513		$	2,518

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Post-acquisition						Pre-acquisition
	For the Year Ended December 31, 2006			For the Period August 12 through December 31, 2005			For the Period January 1 through August 11, 2005			For the Year Ended December 31, 2004
		(In thousands)						(In thousands)
OPERATING ACTIVITIES:
Net income	$	26,371		$	9,751		$	5,403		$	2,069
Adjustments to reconcile to net cash provided from         operations:
Depreciation and amortization		26,881			10,884			17,299			27,781
Deferred income taxes		17,144			6,295			6,723			6,572
Provision for loss on property, plant and equipment		33			—			—			4,694
Credit for Kansas Ad Valorem tax reimbursement		—			—			—			(1,784	)
Loss on sale of property, plant and equipment		—			—			2			—
Amortization of debt discount/premium and expense		1,070			(626	)		1,545			2,431
Termination of interest rate swaps		240			—			—			—
Provision for dividends on mandatorily redeemable   preferred stock		—			—			4,065			7,078
Receivables		5,065			4,851			(4,182	)		37,307
Inventories		(717	)		74			(120	)		(251	)
Other current assets		419			(2,432	)		2,176			(104	)
Payables and accrued liabilities		1,141			3,574			(704	)		(46,024	)
Other, including changes in noncurrent assets and     liabilities		1,576			(502	)		1,568			580
Net cash provided by operating activities	79,223			31,869			33,775			40,349
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of allowance for funds
used during construction	(41,342		)	(13,756		)	(13,579		)	(31,083		)
Proceeds from sales and salvage values, net of costs of       removal		53			(331	)		(759	)		(3,166	)
Advances to affiliates, net		—			—			—			247
Net cash used in investing activities	(41,289		)	(14,087		)	(14,338		)	(34,002		)
FINANCING ACTIVITIES:
Proceeds from long-term debt issuance		428,634			—			5,000			—
Payments of notes payable		(7,250	)		—			—			—
Early retirement of debt		(418,706	)		—			(5,000	)		—
Common dividends/return of capital		(56,201	)		—			(13,867	)		(25,000	)
Debt issuance costs		(5,998	)		(20	)		(100	)		(730	)
Capital lease payments		(735	)		—			(365	)		—
Mandatorily redeemable preferred stock dividends		—			—			(2,282	)		(4,802	)
Other financing		(1,976	)		—			—			—
Net cash used in financing activities		(62,232	)		(20	)		(16,614	)		(30,532	)
Increase (decrease) in cash and cash equivalents		(24,298	)		17,762			2,823			(24,185	)
Cash and cash equivalents at beginning of period		62,287			44,525			41,702			65,887
Cash and cash equivalents at end of period	$	37,989		$	62,287		$	44,525		$	41,702
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (net of amounts capitalized)	$	31,276		$	7,008		$	26,234		$	34,678
Income tax, net		720			466			25			25

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

	Premium on Capital Stock and Other Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholder’s Equity
	(In thousands)
Pre-acquisition
Balance, January 1, 2004	$	141,001		$	577		$	(319	)	$	141,259
Add (deduct):
Net income		—			2,069			—			2,069
Return of capital		(12,500	)		—			—			(12,500	)
Change in value of interest rate swap, net of taxes		—			—			449			449
Balance, December 31, 2004		128,501			2,646			130			131,277
Add (deduct):
Net income		—			5,403			—			5,403
Common dividends/return of capital		(8,278	)		(5,589	)		—			(13,867	)
Change in value of interest rate swaps, net of taxes		—			—			110			110
Balance, August 11, 2005		120,223			2,460			240			122,923
Post-acquisition
Add (deduct):
Acquisition adjustment to eliminate retained earnings		2,460			(2,460	)		—			—
Acquisition adjustment to eliminate accumulated other
comprehensive income (loss)		240			—			(240	)		—
Acquisition adjustment to record assets and liabilities at
fair value		331,798			—			—			331,798
Net income		—			9,751			—			9,751
Change in value of interest rate swaps, net of taxes		—			—			42			42
Balance, December 31, 2005		454,721			9,751			42			464,514
Add (deduct):
Net income		—			26,371			—			26,371
Common dividends/return of capital		(27,879	)		(28,322	)		—			(56,201	)
Additional acquisition adjustment		53			—			—			53
Change in value of interest rate swaps, net of taxes		—			—			(80	)		(80	)
Termination of interest rate swaps		—			—			38			38
Balance, December 31, 2006	$	426,895		$	7,800		$	—		$	434,695

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business

Southern Star

On August 11, 2005, GE Energy Financial Services, Inc., or GE, and Caisse de depot et placement du Quebec, or CDP, through their indirect ownership of EFS-SSCC Holdings, LLC, or Holdings, acquired all of the outstanding capital stock of Southern Star Central Corp., or Southern Star, owned by AIG Highstar Capital L.P., or Highstar, for $389.1 million in cash, plus the assumption of $467.9 million in long-term debt, including current maturities and Series A Preferred Stock, such that following the transaction Holdings owned all of the outstanding capital stock of Southern Star.  This transaction is hereinafter referred to as the acquisition.

Southern Star was incorporated in Delaware in September 2002 and operates as a holding company for its regulated natural gas pipeline operations and development opportunities. Southern Star Central Gas Pipeline, Inc., or Central, is Southern Star’s only operating subsidiary and the sole source of its operating revenues and cash flows. Southern Star also owns the development rights for the Western Frontier project, which could be developed in the future.

The term “the Company” denotes Southern Star Central Corp. and its subsidiaries.

Central

Central is an interstate natural gas transportation company that owns and operates a natural gas pipeline system located in Colorado, Kansas, Missouri, Nebraska, Oklahoma, Texas and Wyoming. The system serves customers in these seven states, including major metropolitan areas in Kansas and Missouri, its main market areas.

Central’s system has a mainline delivery capacity of approximately 2.4 billion cubic feet, or Bcf, of natural gas per day and is composed of approximately 6,000 miles of mainline and branch transmission and storage pipelines including 40 compressor stations with approximately 206,000 certificated horsepower.

Central’s principal service is the delivery of natural gas to local natural gas distribution companies in the major metropolitan areas it serves. At December 31, 2006, Central had transportation customer contracts with approximately 131 shippers. Transportation shippers include natural gas distribution companies, municipalities, intrastate pipelines, direct industrial users, electrical generators and natural gas marketers and producers. Central transports natural gas to approximately 582 delivery points, including distribution companies and municipalities, power plants, interstate and intrastate pipelines, and large and small industrial and commercial customers.

Central operates eight underground storage fields with an aggregate natural gas storage capacity of approximately 43 Bcf and aggregate delivery capacity of approximately 1.2 Bcf of natural gas per day. Central’s customers inject natural gas into these fields when demand is low and withdraw it to supply their peak requirements. During periods of peak demand, approximately 50% of the natural gas delivered to customers is supplied from these fields. Storage capacity enables Central’s system to operate more uniformly and efficiently during the year, as well as allowing it to offer storage services in addition to its transportation services.

Central is subject to regulation by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act, or NGA, of 1938 and under the Natural Gas Policy Act, or NGPA, of 1978, and as such, its rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and its accounting, among other things, are subject to regulation. Central holds certificates of public convenience and necessity issued by the FERC authorizing the siting, ownership and operation of its pipelines and related facilities, including storage fields, which are considered jurisdictional and for which certificates are required or available under the NGA.

2. Basis of Presentation

The acquisition of Southern Star was accounted for under the purchase method of accounting, as required by Statement of Financial Accounting Standards, or SFAS, 141, “Business Combinations.” The purchase price has been “pushed down” and allocated to the assets and liabilities of the Company. Accordingly, the post-acquisition consolidated financial statements reflect a new basis of accounting. The Company’s Consolidated Statements of Operations and Cash Flows for the periods prior to August 12, 2005 reflect the operations of the Company prior to the acquisition. Hence, there is a blackline division on the financial statements, which is intended to signify that the reporting entities shown are not comparable.

All accounting and reporting policies contained herein conform with accounting principles generally accepted in the United States, or GAAP. The financial information contained herein has been prepared in accordance with rules and regulations of the Securities and Exchange Commission, or SEC.

3. Acquisition

On August 11, 2005, GE and CDP, through their indirect ownership of Holdings, acquired all of the outstanding capital stock of Southern Star owned by Highstar for $389.1 million in cash, including a preliminary working capital settlement, plus the assumption of $413.5 million of long-term debt, including current maturities, and $54.4 million of Series A Preferred Stock. The stock of Southern Star was immediately recapitalized and the Series A Preferred Stock, which was owned by a GE affiliate, was converted to common stock. See Note 6 for further discussion of the recapitalization. In March 2006, the Company paid approximately $2.0 million to Highstar as a final working capital settlement.  

The total purchase price was $454.8 million, including the $389.1 million paid in cash and acquisition costs of $1.2 million. Additionally, a GE affiliate contributed all of Southern Star’s Series A Preferred Stock and its 2% common stock ownership to Holdings at a total market value of $64.5 million.

The purchase price allocation is reflected on the accompanying Consolidated Balance Sheets. The acquisition adjustments indicated below include costs related solely to the acquisition by Holdings.

 The following summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition (expressed in thousands):

Cash and cash equivalents	$  42,549
Receivables	52,755
Inventories	5,815
Other current assets	12,227
Regulatory assets—current	14,630
Property, plant and equipment	527,556
Regulatory assets—noncurrent	40,473
Postretirement benefits other than pensions asset	6,620
Other assets	5,779
Current maturities of long-term debt	(50,000 )
Capitalized lease obligation due in one year	(735 )
Current liabilities—other	(88,937 )
Long-term debt	(370,547 )
Capitalized lease obligation	(7,900 )
Regulatory liabilities—noncurrent	(7,030 )
Deferred tax liability	(15,208 )
Postretirement benefits other than pensions liability	(9,232 )
Accrued pension liability	(23,468 )
Other long-term liabilities	(5,153 )
Goodwill	324,580
Net purchase price, including related acquisition costs	$ 454,774

As Central’s rates are regulated by the FERC, and the FERC does not generally allow recovery in rates of amounts in excess of original cost, Central’s historical assets and liabilities equaled fair value at the acquisition date. The total purchase price including acquisition costs exceeded the fair value of the Company’s net assets and liabilities by $324.6 million, after giving effect to the $2.0 million working capital settlement discussed above and to the purchase accounting adjustment relating to Property, plant and equipment in 2006 as discussed in Note 4. This excess has been classified as “Goodwill” on the accompanying Consolidated Balance Sheets. The goodwill is not amortized and is subject to an annual impairment test in accordance with SFAS 142, “Goodwill and Other Intangible Assets.”

Under the terms of the acquisition agreement, Highstar is generally liable for the net current taxes through the acquisition date.

See Note 5 and Note 6 for discussion of the impact of the acquisition on the Company’s debt and preferred stock.

4. Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Southern Star and its subsidiaries, all of which are wholly-owned. All material intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported on the accompanying consolidated financial statements and notes. Actual results could differ from those estimates.

Reclassifications

Certain prior period amounts have been reclassified to conform with current period presentation with no effect on previously reported earnings or equity.

Revenue Recognition

Revenues for sales of products are recognized in the period of delivery and revenues from services are recognized in the period the service is provided based on contractual terms and related volumes. The FERC regulatory processes and procedures govern the tariff and rates that Central is permitted to charge to customers for its services. Key determinants in the ratemaking process are (1) contracted capacity assumptions, (2) costs of providing service, including depreciation expense, and (3) allowed rate of return, including the equity component of a pipeline’s capital structure and related income taxes. Accordingly, at any given time, some of the collected revenues may be subject to possible refunds required by final order of the FERC. Central records estimates of rate refund liabilities based on its and other third-party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted.

Regulatory Assets and Liabilities

As a rate regulated enterprise, Central meets the requirements for accounting under SFAS 71, “Accounting for the Effects of Certain Types of Regulation.” As such, costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be recognized in income are deferred as regulatory liabilities pending refunds or returned to customers through future rates. Recognition of regulatory assets or liabilities is generally based on specific regulatory requirements or precedent for each such matter.

The following regulatory assets or liabilities are included on the accompanying Consolidated Balance Sheets as Costs recoverable from customers or Costs refundable to customers at December 31, 2006 and 2005 and classified as current or noncurrent depending on the expected timing of recovery (expressed in thousands):

	2006			2005
Current Assets:
Environmental costs	$	1,000		$	1,000
Fuel costs		9,589			—
Total Current Assets		10,589			1,000
Noncurrent Assets:
Environmental costs		2,736			3,598
Income taxes on AFUDC equity		4,152			4,143
Gas imbalance cash cost recoverable		84			11
Postretirement benefits		9,437			10,165
Pension		25,234			28,398
Asset retirement obligations		2,214			2,067
Long-term disability		150			203
Total Noncurrent Assets		44,007			48,585
Total Assets		54,596			49,585
Current Liabilities:
Fuel costs		—			(1,741	)
Total Current Liabilities		—			(1,741	)
Noncurrent Liabilities:
Gas imbalance cash cost refundable		(114	)		(116	)
Postretirement benefits		(10,165	)		(7,027	)
Total Noncurrent Liabilities		(10,279	)		(7,143	)
Total Liabilities		(10,279	)		(8,884	)
Net Regulatory Assets	$	44,317		$	40,701

These amounts are either included in Central’s current rate filing or covered by specific rate mechanisms, which govern the timing of refunds or recovery.

Property, Plant, and Equipment

Depreciation is provided primarily on the straight-line method over estimated useful lives, generally 40 to 50 years on new property, pursuant to rates authorized by the FERC, or on remaining lives generally averaging 20 to 25 years for property in service prior to the acquisition. Gains or losses from the ordinary sale or retirement of property, plant and equipment generally are credited or charged to accumulated depreciation; other gains or losses are recorded in net income. Depreciation for the year ended December 31, 2006, the period August 12 through December 31, 2005, the period January 1 through August 11, 2005, and the year ended December 31, 2004, was approximately $26.9 million, $10.9 million, $17.3 million and $27.8 million, respectively.

In the fourth quarter 2006, Central determined that it had over-depreciated in prior periods certain software assets.  As such, Central reduced depreciation expense by $0.8 million in the fourth quarter of 2006 for amounts related to prior quarters and increased its Property, plant and equipment as of the date of acquisition. The adjustment resulted in a decrease to goodwill of $1.8 million.

Goodwill

The Company has recorded $324.6 million of Goodwill as discussed in Note 3. Goodwill is not amortized and is subject to an annual impairment test in accordance with SFAS 142.

Provision for Uncollectible Accounts

The Company’s trade receivables are primarily due from local natural gas distribution companies and other pipelines whose creditworthiness is periodically evaluated and financial conditions monitored. Security is generally required if a customer fails to meet the Company’s creditworthiness tests. If a current customer’s financial condition deteriorates to a point where the Company deems there is a likelihood of a current receivable being uncollected, it will record a provision for uncollectible accounts. The Company’s trade receivables reflected on the accompanying Consolidated Balance Sheets are net of its provision for uncollectible accounts of less than $0.03 million at December 31, 2006 and 2005.

Repair and Maintenance Costs

Central accounts for repair and maintenance costs under the guidance of FERC regulations. The FERC identifies installation, construction, and replacement costs that are to be capitalized. All other costs are expensed as incurred.

On June 30, 2005, the FERC issued its “Order on Accounting for Pipeline Assessment Costs.” The Order requires companies to expense certain pipeline safety assessment costs, which may have historically been capitalized. The Order became effective January 1, 2006. Amounts capitalized in periods prior to that date are permitted to remain as recorded.  Central recorded Operations & maintenance expenses related to pipeline safety assessment of $2.4 million during 2006.

Income Taxes

Deferred taxes are recorded under the liability method and are provided on all temporary differences between the book and tax basis of the assets and liabilities pursuant to SFAS 109, “Accounting for Income Taxes.”

A Tax Sharing Agreement is in place by and among Southern Star and Central. Pursuant to this agreement, Southern Star and Central adopted a Federal and State Income Tax Policy which provides that Southern Star will file consolidated tax returns on behalf of itself and Central and pay all taxes shown thereon to be due. Central makes payments to Southern Star as though it were filing a separate return for its federal income tax liability. Southern Star has an obligation to indemnify Central for any liability that Central incurs for taxes of the affiliated group of which Southern Star and Central are members under Treasury Regulations Section 1.1502-6.

Dividends and Returns of Capital

Dividends declared in excess of Retained Earnings balances are deemed to be returns of capital.

Capitalized Interest

The allowance for funds used during construction represents Central’s cost of funds applicable to the regulated natural gas transmission plant under construction as permitted by FERC regulatory practices. The allowances for borrowed and equity funds used during construction for the year ended December 31, 2006 were $0.2 million and $0.5 million, respectively, for the post-acquisition period ended December 31, 2005 were approximately $0.05 million and $0.1 million, respectively; for the pre-acquisition period ended August 11, 2005 were approximately $0.03 million and $0.06 million, respectively; and for the year ended 2004 were approximately $0.5 million and $0.6 million, respectively.

Gas Receivables/Payables

In the course of providing transportation and storage services to customers, Central may receive different quantities of natural gas from a shipper than quantities delivered on behalf of that shipper. These transactions result in imbalances, which are repaid or recovered in cash or through the receipt or delivery of natural gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded in Transportation, exchange and fuel gas receivables/payables on the accompanying Consolidated Balance Sheets. Settlement of imbalances requires agreement between the pipeline and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of natural gas based on operational conditions.

Central also uses gas from its system for compressor fuel and incurs gas losses during its normal course of operations.  This gas is repaid in-kind from customers via a fuel reimbursement charge placed on the volume of gas transported through the system.  Volumes due to or from the system as a result of fuel use or gas loss are also included in Transportation, exchange and fuel gas receivables/payables on the accompanying Consolidated Balance Sheets.

Natural gas receivables/payables are valued using a current published natural gas index price.

Inventory Valuation

Inventory consists primarily of materials and supplies and is valued using the lower of average-cost or market method.

Cash Equivalents

The Company includes in cash equivalents any short-term highly-liquid investments that have an original maturity of three months or less when acquired.

Cash Flows from Operating Activities

The Company uses the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile net cash flows provided by operating activities.

Asset Retirement Obligations

In March 2005, the Financial Accounting Standards Board, or FASB, issued Interpretation 47, or FIN 47, “Accounting for Conditional Asset Retirement Obligations,” to clarify the requirement to record liabilities stemming from a legal obligation to retire fixed assets when a retirement depends on a future event. FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. However, the obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. FIN 47 requires that the uncertainty about the timing and (or) method of settlement of a conditional asset retiremen t obligation be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

In 2005, in accordance with FIN 47, Central recorded an asset retirement obligation, or ARO, for the remediation of asbestos existing on its system. The asbestos existing on Central’s system is primarily in building materials and pipe coatings used prior to the Clean Air Act of 1973 that established the National Emission Standard for Hazardous Air Pollutants, or NESHAPs, that regulated the use of asbestos. The initial recognition of the ARO in 2005 resulted in an increase in net Property, plant and equipment of $0.1 million, an increase in regulatory assets of $2.1 million, and the recognition of an ARO liability of $2.2 million on the accompanying Consolidated Balance Sheets. The amount of the regulatory asset related to the ARO liability on the accompanying Consolidated Balance Sheets at December 31, 2006 was $2.2 million and $2.3 million, respectively.

Long-Lived Assets

Consistent with SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company evaluates long-lived assets for impairment and assesses their recoverability based upon anticipated future cash flows. If facts and circumstances lead management to believe that the cost of an asset may be impaired, the Company will evaluate the extent to which that cost is recoverable by comparing the future undiscounted cash flows estimated to be associated with that asset to the asset’s carrying amount and write down the carrying amount to market value to the extent necessary.

Recent Accounting Standards

In September 2006, the FASB released SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).”  Under the new standard, companies must recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit plans.  Central adopted SFAS 158 at December 31, 2006 and recognized approximately $3.7 million of previously unrecognized net gains from its pension and other welfare benefit plans. Since the FERC allows Central to recover prudently incurred pension and postretirement benefit costs through its rates, the assets and liabilities recognized, as related to the Union or Non-Union portions of Central’s defined benefit pension and other postretirement benefits plans, have been offset by a corresponding regulatory liability or regulatory asset.  See Note 10 for further discussion.

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes.”  This interpretation clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS 109.  FIN 48 prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return.  The Company will adopt the provisions of this interpretation during the first quarter of 2007, as required.  The Company is currently evaluating the requirements of FIN 48 and does not expect that FIN 48 will have a material impact on its consolidated financial condition or results of operations.

5. Financing

At December 31, 2006 and 2005, long-term debt consisted of the following (expressed in thousands):

	December 31, 2006			December 31, 2005
8.5% Senior Secured Notes due 2010	$	3,080		$	180,000
6.75% Senior Notes due 2016		200,000			—
Term Loan (LIBOR + 1.75%) due 2006		—			50,000
7.375% Senior Notes due 2006		—			175,000
6.0% Senior Notes due 2016		230,000			—
Capitalized lease obligation		7,900			8,635
Unamortized (discount) premium, net		(1,269	)		14,356
Total long-term debt	$	439,711		$	427,991

8.5% Notes

Prior to April 13, 2006, Southern Star had outstanding $180.0 million of 8.5% Senior Secured Notes due August 1, 2010, or 8.5% Notes. Interest on the 8.5% Notes is payable semi-annually in February and August. The 8.5% Notes were subject to certain covenants that restricted, among other things, the Company or its subsidiaries’ ability to make investments; incur additional indebtedness; pay dividends on, or redeem capital stock; create liens; sell assets; or engage in certain other business activities.

As a result of the acquisition, the value of the 8.5% Notes was calculated at fair value and a premium of $15.7 million was recorded in Long-term debt on the accompanying December 31, 2005 Consolidated Balance Sheet. This premium was being amortized over the remaining life of the 8.5% Notes, and associated unamortized debt issuance expenses were valued at zero.

On March 23, 2006, Southern Star launched a tender offer pursuant to which it offered to purchase all of its outstanding 8.5% Notes. As part of this tender offer, Southern Star solicited consents to amend the indenture governing the 8.5% Notes to eliminate substantially all of the covenants and certain events of default contained in the indenture.

As a result of the tender, Southern Star accepted for payment $176.9 million principal amount of the 8.5% Notes, which represented 98.29% of the outstanding aggregate principal amount of the 8.5% Notes.  Southern Star paid $190.7 million to reacquire the debt, which had a carrying value of $190.5 million; a loss of $0.2 million was recorded. Fees of approximately $0.5 million associated with the tender were also charged to expense. In addition, Southern Star entered into a supplemental indenture for the 8.5% Notes on April 10, 2006, which eliminated substantially all of the original covenants and certain events of default.  At December 31, 2006, Southern Star’s outstanding balance of the 8.5% Notes was $3.1 million.   The 8.5% Notes are callable on or after August 1, 2007.

6.75% Notes

On April 13, 2006, Southern Star completed a private offering of $200.0 million aggregate principal amount of 6.75% Senior Notes due 2016, or 6.75% Notes, the proceeds of which were used to retire the 8.5% Notes tendered, including related premiums and expenses, and to pay the issuance costs of the new offering.  In connection with the offering, Southern Star entered into an indenture, or 6.75% Notes Indenture, dated April 13, 2006 by and between Southern Star and The Bank of New York Trust Company, N.A., as trustee.    

Interest is payable semi-annually on March 1 and September 1 of each year, and began on September 1, 2006. The 6.75% Notes mature on March 1, 2016. The 6.75% Notes are Southern Star’s senior unsecured obligations and rank equal in right of payment to all of its existing and future unsecured indebtedness, including Southern Star’s 8.5% Notes that remain outstanding following Southern Star’s tender offer and are effectively junior to any secured indebtedness of Southern Star to the extent of the value of the assets securing such indebtedness, if any.

In connection with the issuance of the 6.75% Notes, Southern Star entered into a registration rights agreement dated as of April 13, 2006, whereby Southern Star agreed to offer to exchange the 6.75% Notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended.  The registration statement was filed on June 30, 2006 and was declared effective on August 2, 2006.  The exchange offer was consummated on September 11, 2006, at which time all notes were accepted for exchange.

The declaration and payments of dividends or distributions to equity holders, under the 6.75% Notes Indenture, is subject to, with certain limited exceptions, a minimum fixed charge coverage ratio and cumulative available cash flows from operations or a leverage ratio, subject to certain conditions, as defined in the indenture.

Central Credit Facility

Prior to April 13, 2006, Central had in place a secured credit facility, or Central Credit Facility, with Union Bank of California, providing for, among other things, a term loan of $50.0 million that matured on May 1, 2006. The Central Credit Facility was secured by certain customer contracts and physical assets of Central.

In connection with Central’s 2006 refinancing discussed below, the term loan was repaid in full on April 13, 2006 and the related agreements were terminated.

Central’s 7.375% Notes

Prior to April 13, 2006, Central had outstanding $175.0 million of 7.375% Senior Notes due November 15, 2006, or 7.375% Notes.  

On March 23, 2006, Central launched a tender offer pursuant to which it offered to purchase all of its outstanding 7.375% Notes. As a result of the tender offer, Central accepted for payment $155.1 million aggregate principal amount of the 7.375% Notes.  On April 25, 2006, Central called for redemption the remainder of its 7.375% Notes, settlement of which was made on May 1, 2006. Central paid $177.6 million to reacquire the debt, which had a carrying value of $174.9 million. The premiums and expenses related to the tender and call will be amortized over the life of the new debt, as permitted by FERC accounting regulations.

Central’s 6.0% Notes

On April 13, 2006, Central completed a private offering of $230.0 million aggregate principal amount of 6.0% Senior Notes due 2016, or 6.0% Notes, the proceeds of which were used to pay issuance costs of the offering, to pay amounts outstanding under the Central Credit Facility, and to retire its 7.375% Notes, including related premiums and expenses. In connection with the offering, Central entered into an indenture, or 6.0% Notes Indenture, dated April 13, 2006 by and between Central and The Bank of New York Trust Company, N.A., as trustee. The 6.0% Notes Indenture contains customary restrictive covenants and events of default.  

Interest on the 6.0% Notes is payable on June 1 and December 1 of each year, and began on December 1, 2006. The 6.0% Notes mature on June 1, 2016. The 6.0% Notes are Central’s senior unsecured obligations and rank equal in right of payment to all of its existing and future unsecured indebtedness and are effectively junior to the secured indebtedness of Central to the extent of the value of the assets securing such indebtedness, if any.  

Capital Lease

In 2004, Central entered into a 20-year capital lease with the Owensboro-Daviess County Industrial Development Authority for use of a headquarters building. Ownership of the facility will transfer to Central for a nominal fee upon expiration of the lease. The assets are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets as a capital lease and are being amortized over the same life as similar assets. Amortization of the assets is included in Depreciation and amortization on the accompanying Consolidated Statements of Operations. The overall effective interest rate on the obligation is 6.29%. Principal and interest are paid semi-annually in January and July. Principal payments began July 1, 2005.

Other

In connection with the acquisition, Southern Star issued a non-interest bearing promissory note to Highstar in the aggregate principal amount of approximately $7.3 million, classified in Current liabilities on the accompanying Consolidated Balance Sheet as of December 31, 2005. The promissory note was paid in full by Southern Star on March 30, 2006.

As of December 31, 2006, the Company was in compliance with the covenants of all outstanding debt instruments.

The following table summarizes the Company’s long-term debt payments due by period:

	Long-Term Debt Maturities		Capital Lease
	(In thousands)
2007	$	—	$	765
2008		—		690
2009		—		720
2010		3,080		745
2011		—		235
After 2011		430,000		4,745
Total	$	433,080	$	7,900

6. Recapitalization of Stock

In January 2003, Southern Star authorized and issued 500 shares of non-voting Series A Preferred Stock at $0.1 million per share for a total of $50.0 million. The proceeds were used by Southern Star to repurchase 22.22 shares of its common stock owned by Highstar.

Concurrent with the Series A Preferred Stock issuance, Southern Star also issued a warrant for the purchase of two shares of common stock to the Series A Preferred Stockholder, or Warrant, which represented 2% of the then outstanding common shares. On August 8, 2003, the Warrant was amended to 1.587 shares of common stock, or 2% of the then outstanding common shares. The Warrant was exercised in full on August 15, 2003 at the exercise price.

The holder of the outstanding Series A Preferred Stock was entitled to receive Series A Cash Dividends and Series A Paid In Kind, or PIK, Dividends. The Series A Cash Dividends were cumulative and payable semi-annually, in arrears on May 15 and November 15 of each year. The cash dividend rate was 9.25% per annum until January 21, 2005, and 8.25% thereafter.

The Series A PIK Dividend was cumulative and payable in kind in additional shares of Series A Preferred Stock at the rate of 4% per annum on the outstanding Series A Preferred Stock. Dividends accrued on shares of Series A Preferred Stock issued pursuant to a PIK dividend from the first day of the quarter following the applicable dividend payment date.

In connection with the acquisition, Southern Star entered into a Recapitalization Agreement with Holdings. Pursuant to the Recapitalization Agreement, Holdings surrendered to Southern Star for cancellation all of the Series A Preferred Stock of Southern Star, and all rights therein, in exchange for the reissuance of 20.633 treasury common shares to Holdings. The remaining 1.587 treasury common shares were cancelled pursuant to the Recapitalization Agreement. As a result of the recapitalization, the book value of the Series A Preferred Stock and all accrued dividends at the date of acquisition were transferred to Premium on capital stock and other paid-in capital on the accompanying Consolidated Balance Sheet.

In connection with the Recapitalization Agreement, Southern Star amended and restated its Certificate of Incorporation to eliminate all authorized preferred stock and reduce the authorized number of shares of capital stock to 100 shares of common stock. Southern Star has issued all 100 shares of common stock to Holdings. The Amended and Restated Certificate of Incorporation was filed with the Secretary of State of Delaware on August 11, 2005.

7. Commitments and Contingencies

Regulatory and Rate Matters and Related Litigation

General Rate Issues

On April 30, 2004, Central filed a general rate case under FERC Docket No. RP04-276 which became effective November 1, 2004.  The case was settled and became final in 2005. The terms of the settlement require Central to file a rate case to be effective no later than November 1, 2008. The general rate proceeding increased Central’s transportation, storage, and related rates, and also provided for changes to a number of the terms and conditions of customer service in Central’s tariff.

Environmental and Safety Matters

Environmental

Central has identified polychlorinated biphenyl, or PCB, contamination in air compressor systems, soils and related properties at certain compressor station sites and has been involved in negotiations with the U.S. Environmental Protection Agency, or EPA, and state agencies to develop screening, sampling and cleanup programs. In addition, negotiations with certain environmental agencies concerning investigative and remedial actions relative to potential mercury contamination at certain natural gas metering sites have commenced. Central had accrued a liability of approximately $4.6 million at December 31, 2005 and $3.7 million at December 31, 2006 representing the current estimate of future environmental cleanup costs, most of which is expected to be incurred over the next three to four years.

Central is subject to federal, state and local statutes, rules and regulations relating to environmental protection, including the National Environmental Policy Act, the Clean Water Act, the Clean Air Act and the Resource Conservation and Recovery Act. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally subject Central to inspections and require it to obtain and comply with a wide variety of environmental licenses, permits and other approvals. Under the Clean Air Act, the EPA has recently promulgated regulations addressing emissions from equipment present at typical natural gas compressor stations. These regulations include NESHAPs for reciprocating internal combustion engines, stationary turbines, and glycol dehydration equipment in addition to regulations that address regional transport of ozone (i.e. NOx SIP Call). There is no impact anticipated to Central’s existin g operations based on an analysis of these regulations. The EPA has also promulgated a new ambient air quality standard for ozone, or the eight-hour standard, which is generally more stringent than the one-hour standard it replaces. Presently, all of Central’s facilities are located in areas designated as in “attainment” for compliance with the eight-hour standard. Therefore, the new standard does not impact Central’s existing operations at this time.

Central considers environmental assessment, remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, as they are prudent costs incurred in the ordinary course of business. The actual costs incurred will depend on the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

Legal Issues

United States ex rel, Grynberg v. Williams Natural Gas Company, et al., MDL Docket No. 1293 (99 MD 1614), Civil Action No. 97 D 1478, (District of Colorado), or Grynberg Litigation

In 1998, Jack Grynberg, an individual, sued Central and approximately 300 other energy companies, purportedly on behalf of the federal government, or qui tam. Invoking the False Claims Act, Grynberg alleged that the defendants had mismeasured the volume and wrongfully analyzed the heating content of natural gas, causing underpayments of royalties to the United States. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, or civil penalty, attorney fees and costs. Thus far, the Department of Justice has declined to intervene in Grynberg’s qui tam cases, which were consolidated for pretrial purposes before a single judge in the United States District Court, or Trial Court, for the District of Wyoming. Initial discovery was limited to public disclosure/original source jurisdictional issues. On June 4, 2004, motions, with supporting briefs, were filed by the Joint Defendants requesting the Trial Court to dismiss Grynberg’s claims based on lack of subject matter jurisdiction. Those motions were fully briefed and oral arguments occurred on March 17 and 18, 2005. On May 13, 2005, the Special Master appointed to adjudicate procedural issues and help manage the consolidated litigation for the Trial Court Judge, issued his “Report and Recommendations” addressing which Grynberg claims against which defendants should be dismissed. Central was one of the defendants as to which the Special Master recommended that Grynberg's claims be dismissed on jurisdictional grounds. Both Grynberg and a number of the defendants filed objections to the Special Master’s report. On October 20, 2006, the Trial Court Judge entered his “Order on Report and Recommendations of Special Master” dismissing Grynberg's claims against Central and substantially all of the other defendants.  The relator’s counsel has fi led notices of appeal with the trial court for the Tenth Circuit, and the clerk’s office has indicated that it will be entering a preliminary case management order in the near future. In the meantime, the trial court has scheduled an April 24, 2007 hearing on various motions pertaining to attorneys’ fees and costs.

Will Price, et al. v. El Paso Natural Gas Co., et al., Case No. 99 C 30, District Court, Stevens County, Kansas, or Price Litigation I

In this putative class action filed May 28, 1999, the named plaintiffs, or Plaintiffs, have sued over 50 defendants, including Central. Asserting theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment, their Fourth Amended Class Action Petition alleges that the defendants have undermeasured the volume of, and therefore have underpaid for, the natural gas they have obtained from or measured for Plaintiffs. Plaintiffs seek unspecified actual damages, attorney fees, pre- and post-judgment interest, and reserved the right to plead for punitive damages. On August 22, 2003, an answer to that pleading was filed on behalf of Central. Despite a denial by the court on April 10, 2003 of their original motion for class certification, the Plaintiffs continue to seek the certification of a class. The Plaintiffs’ motion seeking class certification for a second time was fully briefed and the court heard or al argument on this motion on April 1, 2005. In January 2006, the court heard oral argument on a motion to intervene filed by a third party who is claiming entitlement to a portion of any recovery obtained by Plaintiffs. It is unknown when the court will rule on the pending motions.

Will Price, et al. v. El Paso Natural Gas Co., et al., Case No. 03 C 23, District Court, Stevens County, Kansas, or Price Litigation II

In this putative class action filed May 12, 2003, the named Plaintiffs from Case No. 99 C 30 (discussed above) have sued the same defendants, including Central. Asserting substantially identical legal and/or equitable theories, as in Price Litigation I, this petition alleges that the defendants have undermeasured the British thermal units, or Btu, content of, and therefore have underpaid for, the natural gas they have obtained from or measured for Plaintiffs. Plaintiffs seek unspecified actual damages, attorney fees, pre- and post-judgment interest, and reserved the right to plead for punitive damages. On November 10, 2003, an answer to that pleading was filed on behalf of Central. The Plaintiffs’ motion seeking class certification, along with Plaintiff’s second class certification motion in Price Litigation I, was fully briefed and the court heard oral argument on this motion on April 1, 2005. In January 200 6, the court heard oral argument on a motion to intervene filed by a third party who is claiming entitlement to a portion of any recovery obtained by Plaintiffs. It is unknown when the court will rule on the pending motions.

Summary of Commitments and Contingencies

In connection with the purchase of Central by Southern Star from The Williams Companies, Inc., or Williams, in 2002, a Litigation Cooperation Agreement was executed pursuant to which Williams agreed to cooperate in and assist with the defense of Central with respect to the Grynberg Litigation and the Price Litigation. Pursuant to that agreement, Williams agreed to provide information and data to Central, make witnesses available as necessary, assist Central in becoming a party to certain Joint Defense Agreements, and to cooperate in general with Central in the preparation of its defense.

 The Company is subject to claims and legal actions in the normal course of business in addition to those disclosed above. While no assurances can be given, management believes, based on advice of counsel and after consideration of amounts accrued, insurance coverage, potential recovery from customers and other indemnification arrangements, that the ultimate resolution of these matters will not have a material adverse effect upon the Company’s future financial position, results of operations, or cash flow requirements. Costs incurred to date of defending pending cases have not been material.

Other Commitments

Commitments for Construction

We have estimated capital expenditures of $50.3 million in 2007 including $11.0 million for the Waynoka Supply Project and approximately $9.9 million for the Westar Emporia and the Midwest Goodman Expansion Projects. The two expansion projects will be completed at an additional estimated cost of $8.0 million to be incurred in 2008.  

8. Income Taxes

A summary of the provision for income taxes is as follows (expressed in thousands):

		Post-acquisition					Pre-acquisition
	For the Year Ended December 31, 2006			For the Period August 12 through December 31, 2005		For the Period January 1 through  August 11,  2005		For the Year Ended December 31, 2004
Current provision (benefit):
Federal	$	(81	)	$	73	$	232	$	—
State		495			31		119		(61	)
		414			104		351		(61	)
Deferred provision:
Federal		14,437			5,236		5,478		5,366
State		2,707			1,059		1,245		1,206
		17,144			6,295		6,723		6,572
Income tax provision	$	17,558		$	6,399	$	7,074	$	6,511

Reconciliation of the normal statutory federal income tax rate to the Company’s effective income tax provision is as follows:

		Post-acquisition				Pre-acquisition
	For the Year Ended December 31, 2006		For the Period August 12 through December 31, 2005		For the Period January 1 through August 11, 2005		For the Year Ended December 31, 2004
U.S. statutory rate		35.0%		35.0%		35.0%		35.0%
State income taxes, net of federal taxes benefits		4.7		4.4		7.1		8.7
Permanent items:
Nondeductible preferred stock expenses		—		—		12.9		32.3
Other, net		0.2		0.2		1.7		(0.1)
Income tax provision		39.9%		39.6%		56.7%		75.9%

Significant components of deferred tax assets and liabilities as of December 31, 2006 and 2005 are as follows (expressed in thousands):

		2006			2005
Deferred tax assets:
Tax benefit carryforwards	$	19,967		$	20,110
Accrued environmental costs		1,461			1,751
Accrued employee benefits		19,422			20,389
Acquisition adjustments		—			7,110
Intangibles		3,964			4,262
Other		1,339			743
Total deferred tax assets		46,153			54,365
Deferred tax liabilities:
Property, plant and equipment		48,132			39,556
Intangibles		13,079			13,080
Regulatory assets		19,032			17,442
Other		1,362			1,607
Total deferred tax liabilities		81,605			71,685
Net deferred tax liabilities	$	(35,452	)	$	(17,320	)
Classification:
Net current assets	$	7,876		$	1,375
Net long-term liabilities		43,328			18,695
Net deferred tax liabilities	$	(35,452	)	$	(17,320	)

Tax benefit carryforwards approximating $20.0 million consist principally of the tax benefit of net operating losses for federal purposes of $17.6 million with the remainder applicable for state income tax purposes. Federal net operating losses have a carryforward period of 20 years, while such carryforwards in the principal filing states vary from 10 to 20 years. As such, these carryforward benefits will begin expiring in 2012 to the extent not used by that date.

The use of net operating loss carryforwards occurring prior to the acquisition has annual limitations under Section 382 of the Internal Revenue Code, based upon the product of the value of Southern Star at the date of acquisition times the federal long-term tax-exempt interest rate (4.2%), as generally defined under Section 1274(d) of the Internal Revenue Code. The limitation on the use of pre-acquisition net operating losses is $18.6 million computed on an annual basis.

9. Dividends and Related Restrictions

Certain notes of the Company contain restrictions on declaration and payments of dividends or distributions to equity holders, subject to a minimum fixed charge coverage ratio and cumulative available cash flows from operations or a leverage ratio, subject to certain conditions, as defined in the indenture.

10. Employee Benefit Plans

The Company adopted SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” in December 2006. SFAS 158 requires companies to recognize the funded status of their defined benefit pension and other postretirement benefit plans as a net liability or asset in their balance sheets and to recognize changes in that funded status in the year in which changes occur through comprehensive income. As it is appropriate for Central to apply the accounting prescribed by SFAS 71, the Company will not recognize changes in the funded status in comprehensive income but as changes to the related regulatory asset or liability, pending future recovery or refund through its rates. Pursuant to SFAS 158, the Company recognized the previously unrecognized gains and losses of its pension and welfare benefit plans. The impact of adoption of SFAS 158 is as follows:

	Before Application of Statement 158		Adjustments		After Application of Statement 158
Assets:
Current:
Costs recoverable from customers	$	18,089	$	(7,500)	$	10,589
Non-current:
Costs recoverable from customers		38,241		5,766		44,007
Postretirement benefits other than pensions		8,159		2,006		10,165
Total assets		1,024,052		272		1,024,324
Liabilities:
Current:
Accrued payroll and employee benefits		(19,309)		7,500		(11,809)
Non-current:
Costs refundable to customers		12,285		(2,006)		10,279
Postretirement benefits other than pensions		(10,921)		1,484		(9,437)
Accrued pension		(17,984)		(7,250)		(25,234)
Total liabilities		(589,357)		(272)		(589,629)

Pursuant to SFAS 158, no portion of the pension liability is classified as a current liability because plan assets exceed the value of benefit obligations expected to be paid within the 12 months ending December 31, 2007.  No plan assets are expected to be returned to the Company during the 12 months ending December 31, 2007.

In 2005, the Company recognized its net actuarial gains/losses at the date of acquisition for each of its pension and welfare benefit plans pursuant to the requirements of SFAS 87, “Employers’ Accounting for Pensions,” and SFAS 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” As such, amortization of those amounts is not included in net periodic expenses discussed below for periods after the date of acquisition. The previously unrecognized amounts have been included in regulatory assets/liabilities on the accompanying Consolidated Balance Sheets, which will be amortized as recovered through rates.

Pursuant to the terms of Central’s RP04-276 rate settlement, Central recovers $7.5 million annually to fund pension and postretirement benefits for all eligible participants. This amount must be funded no less frequently than quarterly into irrevocable trusts. This amount also includes a recovery for the amortization of the regulatory asset related to the difference in prior period costs and corresponding funding amounts.

Union Retirement Plan

Central maintains a separate non-contributory defined benefits pension plan, which covers union employees, or Union Plan. The Union Plan covers 40% of the 456 total current employees of Central.

The following table depicts the annual changes in benefit obligation and plan assets for pension benefits for the Union Plan for the periods indicated. The table also presents a reconciliation of the funded status of these benefits to the amount recognized on the accompanying Consolidated Balance Sheets at December 31, 2006 and 2005 (expressed in thousands):

		2006			2005
Change in benefit obligation:
Benefit obligation at beginning of year	$	41,520		$	41,334
Service cost		1,451			1,512
Interest cost		2,050			2,161
Actuarial loss		1,404			620
Benefits paid		(585	)		(3,826	)
Settlements		(8,782	)		—
Transfers to non-union plan		(320	)		(281	)
Benefit obligation at end of year		36,738			41,520
Change in plan assets:
Fair value of plan assets at beginning of year		16,988			15,469
Actual return on plan assets		1,429			635
Employer contributions		6,005			4,810
Benefits paid		(585	)		(3,826	)
Transfers to non-union plan		(119	)		(100	)
Settlements		(8,782	)		—
Fair value of plan assets at end of year		14,936			16,988
Funded status		(21,802	)		(24,532	)
Unrecognized net actuarial gain		—			(1,056	)
Accrued benefit cost	$	(21,802	)	$	(25,588	)

As a result of the acquisition, the December 31, 2005 accrued benefit cost includes $8.7 million of previously unrecognized net losses. Pursuant to SFAS 158, the 2006 accrued benefit cost includes $0.2 million of previously unrecognized net losses. The FERC allows Central to recognize allowances for these prudently incurred costs through recovery in its rates. As such, the change in the liability recognized was offset with a change in a corresponding regulatory asset. Accrued benefit costs reported above are reflected in Accrued pension on the accompanying Consolidated Balance Sheets. The accumulated benefit obligation for this defined benefit pension plan was $31.0 million and $35.8 million at December 31, 2006 and 2005, respectively.

In 2006, $8.8 million of lump sum distributions were paid to plan participants which exceeded the Union Plan’s 2006 service and interest cost, triggering settlement accounting under SFAS 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.”  The effects of the settlement were calculated as of April 30, 2006.  

Central’s net periodic pension expense attributable to the Union Plan consists of the following (expressed in thousands):

	Post-acquisition						Pre-acquisition
	For the Year Ended December 31, 2006			For the Period August 12 through December 31, 2005			For the Period January 1 through  August 11,  2005			For the Year Ended December 31, 2004
Components of net periodic pension expense:
Service cost	$	1,451		$	655		$	857		$	1,375
Interest cost		2,050			869			1,292			2,375
Expected return on plan assets		(1,338	)		(596	)		(835	)		(1,401	)
Amortization of net loss		—			—			21			—
Employee transfers		(198	)		—			(140	)		—
Acquisition loss recognition		—			—			8,657			—
Settlement recognition		64			—			—			—
Regulatory recovery (accrual) of costs		3,976			1,174			(7,144	)		511
Net periodic pension expense	$	6,005		$	2,102		$	2,708		$	2,860

The following are the weighted-average assumptions used to determine the benefit obligation for the periods indicated:

	Post-acquisition		Pre-acquisition
	For the Year Ended December 31, 2006	For the Period August 12 through December 31, 2005	For the Period January 1 through  August 11,  2005	For the Year Ended December 31, 2004
Discount rate	5.69%	5.25%	5.00%	5.75%
Rate of compensation increase	3.75%	3.40%	3.35%	3.65%

The following are the weighted-average assumptions used to determine net periodic benefit cost for the periods indicated:

	Post-acquisition			Pre-acquisition
	For the Period May 1  through December 31, 2006*	For the Period January 1 through    April 30,    2006	For the Period August 12 through December 31, 2005	For the Period January 1 through  August 11,  2005	For the Year Ended December 31, 2004
Discount rate	6.00%	5.25%	5.00%	5.75%	6.25%
Expected return on plan assets	8.50%	8.50%	8.50%	8.50%	8.50%
Rate of compensation increase	4.10%	3.40%	3.35%	3.65%	4.00%

____________________

*

Change in 2006 weighted-average assumptions related to settlement accounting under SFAS 88.

The Union Plan sponsor, Central, employs a building block approach in determining the expected long-term rate of return on plan assets. Historical markets are studied and long-term historical relationships between equities and fixed-income securities are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. The long-term portfolio return is established with proper consideration of diversification and re-balancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

The Union Plan’s weighted-average asset allocations by asset category are as follows:

	December 31, 2006		December 31, 2005
Equity securities		61%		47%
Fixed income securities		26%		20%
Cash equivalents		13%		33%
Total		100%		100%

The investment objectives of the Plan are as follows:

(1) To fully fund the Accumulated Benefit Obligation for the Union Plan;

(2) To maximize returns with reasonable and prudent levels of risk associated with long-term investment objectives;

(3) To minimize fluctuations in dollar contributions from year to year, but this objective is subordinate to the other objectives; and

(4) To accommodate the short-term liquidity requirements of the Union Plan.

A formal bi-annual review of these investment objectives will be performed by the Investment Committee. These objectives will remain in effect unless they are deemed inappropriate by the Investment Committee. The Investment Committee will also re-examine the applicability of these objectives in the event of significant changes in Company structure, actuarial assumptions, contribution levels, economic conditions or any event which may significantly alter the Union Plan’s characteristics.

All investments, unless specifically approved by the Investment Committee, will be readily marketable and of suitable investment quality.

The policy of the Union Plan is to invest assets in accordance with the maximum and minimum range for each asset class as stated below.

Percent of Total Assets at Market Value

Asset Class	Minimum	Target	Maximum
U.S. equities	35%	45%	65%
Non-U.S. equities	5%	10%	15%
Total equities	40%	55%	70%
Fixed income and cash	30%	45%	60%
Special situations	0%	0%	5%

The asset allocation range established by this Investment Policy Statement is based upon a long-term investment perspective. As such, rapid unanticipated market shifts or changes in economic conditions may cause the asset mix to fall outside the policy range. The Investment Committee will be responsible for rebalancing the assets and ensuring that the Trustee and the Investment Managers, as applicable, minimize deviations from their target asset allocation mixes.

Common stock investments shall be restricted to high quality, readily marketable securities of corporations actively traded on the major U.S. and foreign national exchanges, including the NASDAQ. Investment in securities issued by (1) the Company, (2) an entity in which the Company has a majority ownership interest, or (3) an entity that has a majority ownership interest in the Company, is prohibited.

The Company expects to contribute an estimated $6.0 million to this plan in 2007.

The following table illustrates the estimated pension benefit payments, which reflect expected future service, as appropriate, that are projected to be paid (expressed in thousands):

2007	$ 2,640
2008	2,975
2009	3,587
2010	4,145
2011	3,983
Years 2012 through 2016	23,146

Non-Union Retirement Plan

The following table depicts the annual changes in benefit obligations and plan assets for pension benefits for the Non-Union Plan for the periods indicated. The table also presents a reconciliation of the funded status of these benefits to the amounts recognized on the accompanying Consolidated Balance Sheets at December 31, 2006 and 2005 (expressed in thousands):

	2006			2005
Change in benefit obligation:
Benefit obligation at beginning of year	$	7,736		$	4,780
Service cost		2,355			2,250
Interest cost		454			330
Actuarial (gain)/loss		(114	)		345
Benefits paid		(312	)		(250	)
Transfers from union plan		320			281
Benefit obligation at end of year		10,439			7,736
Change in plan assets:
Fair value of plan assets at beginning of year		4,693			3,104
Actual return on plan assets		469			207
Employer contributions		2,038			1,532
Benefits paid		(312	)		(250	)
Transfers from union plan		119			100
Fair value of plan assets at end of year		7,007			4,693
Funded status		(3,432	)		(3,043	)
Unrecognized net actuarial gain		—			(310	)
Accrued benefit cost	$	(3,432	)	$	(3,353	)

As a result of the acquisition, the 2005 accrued benefit cost includes $1.6 million of previously unrecognized net losses. Pursuant to SFAS 158, the 2006 accrued benefit cost includes $0.4 million of previously unrecognized net gains. The FERC allows Central to recognize allowances for these prudently incurred costs through recovery in its rates. As such, the change in the liability recognized was offset with a change in a corresponding regulatory asset. Accrued benefit costs reported above are reflected in Accrued pension on the accompanying Consolidated Balance Sheets. The accumulated benefit obligation for this defined benefit pension plan was $8.1 million and $6.0 million at December 31, 2006 and 2005, respectively.

Central’s net periodic pension expense attributable to the Non-Union Plan consists of the following (expressed in thousands):

	Post-acquisition						Pre-acquisition
	For the Year Ended December 31, 2006			For the Period August 12 through December 31, 2005			For the Period January 1 through  August 11,  2005			For the Year Ended December 31, 2004
Components of net periodic pension expense:
Service cost	$	2,355		$	972		$	1,278		$	1,910
Interest cost		454			153			177			151
Expected return on plan assets		(451	)		(139	)		(195	)		(155	)
Amortization of net loss		—			—			35			21
Employee transfers		198			—			140			—
Acquisition loss recognition		—			—			1,586			—
Regulatory accrual of costs		(1,061	)		(215	)		(1,857	)		(409	)
Net periodic pension expense	$	1,495		$	771		$	1,164		$	1,518

The following are the weighted-average assumptions used to determine benefit obligation:

	Post-acquisition				Pre-acquisition
	For the Year Ended December 31, 2006		For the Period August 12 through December 31, 2005		For the Period January 1 through   August 11,   2005		For the Year Ended December 31, 2004
Discount Rate		5.83%		5.50%		5.25%		5.75%
Rate of compensation increase		3.75%		3.50%		3.40%		3.65%

The following are the weighted-average assumptions used to determine net periodic benefit costs for the periods indicated:

	Post-acquisition				Pre-acquisition
	For the Year Ended December 31, 2006		For the Period August 12 through December 31, 2005		For the Period January 1 through   August 11,   2005		For the Year Ended December 31, 2004
Discount Rate		5.50%		5.25%		5.75%		6.25%
Expected return on plan assets		8.50%		8.50%		8.50%		8.50%
Rate of compensation increase		3.50%		3.40%		3.65%		4.00%

The Non-Union Plan sponsor, Central, employs a building block approach in determining the expected long-term rate on return on plan assets. Historical markets are studied and long-term historical relationships between equities and fixed-income securities are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. The long-term portfolio return is established with proper consideration of diversification and re-balancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

The Non-Union Plan’s weighted-average asset allocations by asset category are as follows:

	December 31, 2006		December 31, 2005
Equity securities		65%		70%
Fixed income securities		30%		30%
Other (cash)		5%		0%
Total		100%		100%

The investment objectives of the Non-Union Plan are as follows:

(1) To fully fund the Accumulated Benefit Obligation for the Non-Union Plan;

(2) To maximize returns with reasonable and prudent levels of risk associated with long-term investment objectives;

(3) To minimize fluctuations in dollar contributions from year to year, but this objective is subordinate to the other objectives; and

(4) To accommodate the short-term liquidity requirements of the Non-Union Plan.

A formal bi-annual review of these investment objectives will be performed by the Investment Committee. These objectives will remain in effect unless they are deemed inappropriate by the Investment Committee. The Investment Committee will also re-examine the applicability of these objectives in the event of significant changes in Company structure, actuarial assumptions, contribution levels, economic conditions or any event which may significantly alter the Non-Union Plan’s characteristics.

All investments, unless specifically approved by the Investment Committee, will be readily marketable and of suitable investment quality.

It shall be the policy of the Non-Union Plan to invest assets in accordance with the maximum and minimum range for each asset class as stated below.

Percent of Total Assets at Market Value

Asset Class	Minimum	Target	Maximum
U.S. equities	35%	45%	65%
Non-U.S. equities	5%	10%	15%
Total equities	40%	55%	70%
Fixed income and cash	30%	45%	60%
Special situations	0%	0%	5%

The asset allocation range established by this Investment Policy Statement is based upon a long-term investment perspective. As such, rapid unanticipated market shifts or changes in economic conditions may cause the asset mix to fall outside the policy range. The Investment Committee will be responsible for re-balancing the assets and ensuring that the Trustee and the Investment Managers, as applicable, minimize deviations from their target asset allocation mixes.

Common stock investments shall be restricted to high quality, readily marketable securities of corporations actively traded on the major U.S. and foreign national exchanges, including the NASDAQ. Investment in securities issued by (1) the Company, (2) an entity in which the Company has a majority ownership interest, or (3) an entity that has a majority ownership interest in the Company is prohibited.

In 2007, the Company expects to contribute an estimated $1.5 million to this plan.

The following table illustrates the estimated pension benefit payments, which reflect expected future service, as appropriate, that are projected to be paid (expressed in thousands):

2007	$ 354
2008	644
2009	869
2010	1,090
2011	1,259
Years 2012 through 2016	11,233

Postretirement Benefits Other than Pensions

Central’s Group Medical-Health Plan, or Welfare Plan, provides medical and life insurance benefits to certain employees who retire under Central’s retirement plans. The Welfare Plan is contributory for medical and contributory for some retired employees for life insurance benefits in excess of specified limits. Eligible employees under the Welfare Plan are those hired prior to various qualifying dates, the latest of which is December 31, 1995, who qualify for retirement benefits, and who meet certain service and other requirements.

The benefits for qualified union employees are funded through a trust agreement under the Southern Star Voluntary Employees’ Beneficiary Association for Collectively Bargained Employees, or Union VEBA, and the benefits for qualified non-union employees are funded through a separate trust agreement under the Southern Star Voluntary Employees’ Beneficiary Association for Non-Collectively Bargained Employees, or Non-Union VEBA. Funding is made in accordance with the requirements under Central’s latest rate settlement with the FERC.

The following table sets forth Central’s Welfare Plan’s obligations and funded status for the periods indicated reconciled with the accrued postretirement benefit cost included on the accompanying Consolidated Balance Sheets at December 31, 2006 and 2005 (expressed in thousands):

	2006			2005
Change in benefit obligation:
Benefit obligation at beginning of year	$	34,166		$	46,368
Service cost		467			564
Interest cost		1,796			1,844
Actuarial gain		(1,440	)		(6,797	)
Medicare Part D subsidy recognition		—			(6,764	)
Benefits paid		(1,594	)		(1,049	)
Benefit obligation at end of year		33,395			34,166
Change in plan assets:
Fair value of plan assets at beginning of year		32,007			30,435
Actual return on plan assets		3,710			1,853
Employer contributions		—			768
Benefits paid		(1,594	)		(1,049	)
Fair value of plan assets at end of year		34,123			32,007
Funded status		728			(2,159	)
Unrecognized net actuarial gain		—			(979	)
Prepaid (accrued) benefit cost	$	728		$	(3,138	)

As a result of the acquisition, the 2005 accrued benefit cost includes $7.5 million of previously unrecognized net gains. Pursuant to SFAS 158, the 2006 accrued benefit cost includes $3.5 million of previously unrecognized net gains. The FERC allows Central to recover these prudently incurred costs through its rate settlement. As such, the assets and liabilities recognized, as related to the Union or Non-Union portions of the Welfare Plan, were offset with a corresponding regulatory asset or regulatory liability. The net accrued benefit costs reported above are reflected in Postretirement benefits other than pensions, on the accompanying Consolidated Balance Sheets.

The following table sets forth the components of net periodic postretirement benefit costs, including amounts for the amortization of the transition obligation, for the periods indicated (expressed in thousands):

	Post-acquisition						Pre-acquisition
	For the Year Ended December 31, 2006			For the Period August 12 through December 31, 2005			For the Period January 1 through August 11, 2005			For the Year Ended December 31, 2004
Components of net periodic benefit expense:
Service cost	$	467		$	241		$	323		$	688
Interest cost		1,796			744			1,100			2,584
Expected return on plan assets		(2,637	)		(769	)		(1,050	)		(1,561	)
Recognized actuarial loss (gain)		(3	)		—			(338	)		23
Acquisition gain recognition		—			—			(7,483	)		—
Regulatory recovery (accrual) of costs		377			(186	)		8,173			2,842
Net periodic benefit expense	$	—		$	30		$	725		$	4,576

In addition, the Company reduced expense in the first quarter of 2005 by $0.4 million to reflect the new level of cost recovery related to pensions and other postretirement benefits resulting from its RP04-276 rate proceeding.

Approximately $0.03 million of amortization of net gains is expected to be reflected in expense in 2007.

The following are the weighted-average assumptions used to determine benefit obligations:

	Post-acquisition			Pre-acquisition
	For the Year Ended December 31, 2006	For the Period August 12 through December 31, 2005		For the Period January 1 through August 11, 2005	For the Year Ended December 31, 2004
Discount rate	5.84%		5.50%	5.25%		5.75%
Healthcare cost trend rate assumed for next year	11.00%		12.00%	12.00%		13.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)	4.85%		4.65%	4.65%		4.75%
Year that the rate reaches the ultimate trend	2012		2012	2012		2012

The following table summarizes the various assumptions used to determine the net periodic benefit cost:

	Post-acquisition			Pre-acquisition
	For the Year Ended December 31, 2006	For the Period August 12 through December 31, 2005		For the Period January 1 through August 11, 2005	For the Year Ended December 31, 2004
Discount rate	5.50%		5.25%	5.75%		6.25%
Expected return on plan assets (non-union/union)	6.67%/8.50%		3.90%/6.00%	3.90%/6.00%		3.90%/6.00%

Assumed health care cost trend rates for the periods indicated:

	December 31, 2006	December 31, 2005		December 31, 2004
Healthcare cost trend rate assumed for next year	11.00%		12.00%	13.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)	4.65%		4.65%	5.00%
Year that the rate reaches the ultimate trend	2012		2012	2012

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one percentage point change in assumed health care cost trend rates would have the following effects on the current year (expressed in thousands):

	One Percentage Point
	Increase		Decrease
Effect on total of service and interest cost components	$	324	$	(265)
Effect on accumulated postretirement benefit obligation	$	4,438	$	(3,671)

The Welfare Plan sponsor, Central, employs a building block approach in determining the expected long-term rate on return on plan assets. Historical markets are studied and the long-term historical relationship between equities and fixed-income securities is preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. The long-term portfolio return is established with proper consideration of diversification and re-balancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

The employer’s Welfare Plan weighted-average asset allocations by asset category are as follows:

	December 31, 2006		December 31, 2005
Equity securities		68%		68%
Fixed income Securities		29%		29%
Cash and cash equivalents		3%		3%
Total		100%		100%

The investment objectives of the Plan are as follows:

(1) To fully fund the Accumulated Post-retirement Benefit Obligation for the Welfare Plan subject to deductible limits of IRC Section 419A;

(2) To maximize returns with reasonable and prudent levels of risk associated with long-term investment objectives;

(3) To minimize fluctuations in dollar contributions from year to year, but this objective is subordinate to the other objectives; and

(4) To accommodate the short-term liquidity requirements of the Welfare Plan.

A formal bi-annual review of these investment objectives will be performed by the Investment Committee. These objectives will remain in effect unless they are deemed inappropriate by the Investment Committee. The Investment Committee will also re-examine the applicability of these objectives in the event of significant changes in Company structure, actuarial assumptions, contribution levels, economic conditions or any event which may significantly alter the Welfare Plan’s characteristics.

All investments, unless specifically approved by the Investment Committee, will be readily marketable and of suitable investment quality.

The policy of the Welfare Plan is to invest assets in accordance with the maximum and minimum range for each asset class as stated below.

Percent of Total Assets at Market Value

Asset Class	Minimum	Target	Maximum
U.S. equities	35%	45%	65%
Non-U.S. equities	5%	10%	15%
Total equities	40%	55%	70%
Fixed income and cash	30%	45%	60%
Special situations	0%	0%	5%

The asset allocation range established by this Investment Policy Statement is based upon a long-term investment perspective. As such, rapid unanticipated market shifts or changes in economic conditions may cause the asset mix to fall outside the policy range. The Investment Committee will be responsible for rebalancing the assets and ensuring that the Trustee and the Investment Managers, as applicable, minimize deviations from their target asset allocation mixes.

Common stock investments shall be restricted to high quality, readily marketable securities of corporations actively traded on the major U.S. and foreign national exchanges, including the NASDAQ. Investment in securities issued by (1) the Company, (2) an entity in which the Company has a majority ownership interest, or (3) an entity that has a majority ownership interest in the Company, is prohibited.

In 2007, the Company does not expect to make any contributions to its Welfare Plan.

The following table illustrates the estimated benefit payments for the other postretirement benefits, which reflect expected future services, as appropriate, that are projected to be paid (expressed in thousands):

	Non-Union	Union	Total
2007	$ 173	$ 1,301	$ 1,474
2008	240	1,465	1,705
2009	336	1,648	1,984
2010	420	1,761	2,181
2011	501	1,853	2,354
Years 2012 through 2016	4,068	10,164	14,232

 The following table illustrates the estimated Medicare Part D receipts, which reflect expected future service, as appropriate, that are projected to be paid to the Company (expressed in thousands):

	Non-Union	Union	Total
2007	$ 1	$ 167	$ 168
2008	3	187	190
2009	4	207	211
2010	8	230	238
2011	14	255	269
Years 2012 through 2016	194	1,602	1,796

 Other

Central maintains a defined contribution plan covering substantially all employees. Central’s costs related to this plan for the years ended December 31, 2006, 2005 and 2004 was $1.8 million, $1.8 million and $1.4 million, respectively.

11. Financial Instruments

The following methods and assumptions were used by the Company in estimating its fair-value disclosures for financial instruments:

Cash and Cash Equivalents: The carrying amount is a reasonable estimate of fair value due to the short maturity of instruments at December 31, 2006 and 2005.

Long-Term Debt: The estimated fair value of the Company’s debt is based on quoted market prices at December 31, 2006 and 2005.

Interest Rate Swaps Valuation: The estimated fair value of the Company’s interest rate swaps is based on quoted market prices at December 31, 2005.

The carrying amount and estimated fair values of the Company’s financial instruments as of December 31, 2006 and 2005 are as follows (expressed in thousands):

	Carrying Amount				Fair Value
	2006		2005		2006			2005
Financial Assets:
Cash and cash equivalents	$	37,989	$	62,287	$	37,989	$	62,287
Interest rate swaps		—		460		—		460
Financial Liabilities:
Long-term debt		431,811		419,356		431,099		424,243

Concentrations of Credit Risk

Central’s trade receivables are primarily due from local distribution companies and other pipeline companies predominantly located in the central United States. The Company’s credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. As a general policy, collateral is not required for receivables, but customers’ financial condition and creditworthiness are evaluated regularly.

12. Major Customers

Central’s two largest customers are Missouri Gas Energy, or MGE, a division of Southern Union Company, and Kansas Gas Service Company, or KGS, a division of ONEOK. Revenues received from MGE were $56.9 million, $22.2 million, $34.4 million, and $47.7 million for the year ended December 31, 2006, the period August 12 through December 31, 2005, the period January 1 through August 11, 2005 and the year ended December 31, 2004, respectively. Revenues received from KGS were $50.7 million, $19.9 million, $30.8 million, and $47.1 million for the year ended December 31, 2006, the period August 12 through December 31, 2005, the period January 1 through August 12, 2005 and the year ended December 31, 2004, respectively.

MGE had receivable balances of $4.7 million for each of the years ended December 31, 2006 and 2005. KGS had receivable balances of $4.7 million for each of the years ended December 31, 2006 and 2005.

13. Operating Leases

The Company leases certain office and pipeline facilities and equipment under various operating lease agreements. The annual future minimum rental commitments for non-cancelable operating leases are as follows (expressed in thousands):

2007	$	205
2008		179
2009		158
2010		97
2011		33
After 2011		76
Total	$	748

Total rental expense relating to operating leases was approximately $1.1 million, $0.4 million, $0.9 million, and $1.8 million for the year ended December 31, 2006, the period August 12 through December 31, 2005, the period January 1 through August 11, 2005, and the year ended December 31, 2004, respectively.

14. Related Party Transactions

On August 11, 2005, Central and Western Frontier entered into an Operating Company Services Agreement, or Operating Services Agreement, with EFS Services, LLC, an affiliate of GE. Pursuant to the Operating Services Agreement, EFS Services, LLC provides certain consulting services to Central and Western Frontier for a service fee of $1.0 million per year, plus the reimbursement of reasonable expenses up to $0.2 million in a 12-month period incurred by EFS Services, LLC in providing such services. During December 31, 2006 and 2005, Central paid approximately $1.0 million and $0.4 million, respectively, for service fees and expenses to EFS Services, LLC. The Operating Services Agreement terminates at such time as GE or any of its affiliates ceases to beneficially own any securities of Holdings.

In addition, on August 11, 2005, Southern Star entered into an Administrative Services Agreement, or Services Agreement, with EFS Services, LLC to provide certain administrative services to Southern Star and Holdings. Pursuant to the terms of the Services Agreement, EFS Services, LLC is not paid a fee for its services; however, it is entitled to be reimbursed for the reasonable expenses it incurs in providing such services.

Central makes purchases of goods and services from various affiliates of GE on an arms-length basis in the normal course of its operations.

15.  Employee Retention Agreements

Prior to the acquisition, the Company entered into employee retention agreements with the officers of Central. Pursuant to the agreements, initial payments of approximately $3.2 million were made in August 2005 to the officers and were recorded in Administrative and general expenses on the accompanying Consolidated Statement of Operations for the period ended August 11, 2005. These agreements also require annual payments to those employees totaling $9.3 million over a five-year period for their continued employment. The Company is accruing the expenses associated with these payments ratably over the period services are being provided. The Company recorded expenses totaling $1.9 million and $0.7 million in 2006 and for the period from August 12, 2005 through December 31, 2005, respectively, for such annual payments.

16. Quarterly Data (Unaudited)

The following summarizes selected quarterly financial data for 2006 and 2005 (expressed in thousands):

	2006
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Operating revenues	$	47,021		$	46,943		$	46,228		$	47,054
Operating costs and expenses		29,627			29,575			29,351			27,646	(2)
Operating income		17,394			17,368			16,877			19,408
Interest expense		7,333			8,259	(1)		7,248			7,124
Interest income		(564	)		(666	)		(562	)		(609	)
Miscellaneous other (income) expenses, net		(34	)		(132	)		(91	)		(188	)
Total other expense, net		6,735			7,461			6,595			6,327
Income (loss) before income taxes		10,659			9,907			10,282			13,081
Provision for income taxes		4,209			3,995			4,072			5,282
Net Income	$	6,450		$	5,912		$	6,210		$	7,799

__________________________

(1)  Interest expense for the second quarter includes costs related to the refinancing of long-term debt. See Note 5 for further discussion.

(2)  Depreciation expense was decreased by approximately $0.8 million for amounts related to prior periods.

	2005
	Pre-acquisition										Post-acquisition
										< /P>
	First Quarter			Second Quarter			For Period July 1 through August 11, 2005				For Period August 12 through September 30, 2005			Fourth Quarter
										< /P>
Operating revenues	$	44,494		$	46,177		$	20,497			$	24,776		$	45,993
Operating costs and expenses		28,134			29,237			16,757	(1)			15,369			28,771
Operating income		16,360			16,940			3,740				9,407			17,222
Interest expense		10,226			10,245			4,698	(2)			4,248			7,089
Interest income		(219	)		(344	)		(156	)			(201	)		(536	)
Miscellaneous other (income) expenses, net		35			(303	)		381				(86	)		(35	)
Total other expense, net		10,042			9,598			4,923				3,961			6,518
Income (loss) before income taxes		6,318			7,342			(1,183	)			5,446			10,704
Provision for income taxes		3,376			3,645			53				2,089			4,310
										< /P>
Net Income (Loss)	$	2,942		$	3,697		$	(1,236	)		$	3,357		$	6,394

(1)   Operating costs and expenses for the period July 1 through August 11, 2005 include employee retention payments of $3.2 million which were paid on August 11, 2005.

(2)

Interest expense in the Pre-acquisition periods includes Series A Preferred Stock expense. See Note 6 for further discussion.

Exhibit 12.1

Ratio of Earnings to Fixed Charges

(In thousands)

	Post-acquisition							Pre-acquisition											Predecessor (2)
	Year Ended December 31, 2006			For the Period August 12 through December 31, 2005			For the Period January 1 through August 11, 2005			Year  Ended December 31, 2004			Year Ended December 31, 2003			For the Period November 16 through December 31, 2002			For the Period January 1 through November 15, 2002
Fixed Charges:
Interest expense	$	29,964		$	11,337		$	25,169		$	40,856		$	42,396		$	3,727		$	11,710
Capitalized interest		222			50			31			511			209			(14	)		416
Fixed Charges	$	30,186		$	11,387		$	25,200		$	41,367		$	42,605		$	3,713		$	12,126
Earnings:
Add:
Income before income taxes	$	43,929		$	16,150		$	12,477		$	8,580		$	4,639		$	1,277		$	24,078
Fixed charges (calculated above)		30,186			11,387			25,200			41,367			42,605			3,713			12,126
Deduct:
Capitalized interest		(222	)		(50	)		(31	)		(511	)		(209	)		14			(416	)
Earnings	$	73,893		$	27,487		$	37,646		$	49,436		$	47,035		$	5,004		$	35,788
Ratio of Earnings to Fixed Charges1		2.45			2.41			1.49			1.20			1.10			1.35			2.95

 (1)

Ratio of Earnings to Fixed Charges is computed by dividing Earnings by Fixed Charges. For purposes of this calculation, “Earnings” is Income before income taxes plus Fixed Charges less Capitalized interest. “Fixed Charges” is Interest expense plus Capitalized interest. This calculation differs from the Fixed Charge Coverage Ratio as defined in the Indenture.

(2)

Periods ending prior to November 16, 2002 reflect the operations of Williams Gas Pipeline Central, Inc., the predecessor entity.

Exhibit 31.1

CERTIFICATION

Statement Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Executive Officer Regarding Facts and Circumstances Relating to Exchange Act Filings.

I, Jerry L. Morris, Chief Executive Officer of Southern Star Central Corp., certify that:

1.

I have reviewed this annual report on Form 10-K of Southern Star Central Corp.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13(a) - 15(e) and 15(d) - 15(e)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 (b)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	Signature	Title	Date
By:	/s/ Jerry L. Morris	Chief Executive Officer	March 14, 2007
	Jerry L. Morris

Exhibit 31.2

CERTIFICATION

Statement Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 by Chief Financial Officer Regarding Facts and Circumstances Relating to Exchange Act Filings.

I, Susanne W. Harris, Chief Financial Officer of Southern Star Central Corp., certify that:

1.

I have reviewed this annual report on Form 10-K of Southern Star Central Corp.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13(a) - 15(e) and 15(d) - 15(e)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 (b)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	Signature	Title	Date
By:	/s/ Susanne W. Harris	Chief Financial Officer	March 14, 2007
	Susanne W. Harris

Exhibit 32

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the Annual Report on Form 10-K of Southern Star Central Corp., or the Company, a Delaware corporation, for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof, or the Report, each of the undersigned, Jerry L. Morris, Chief Executive Officer of the Company, and Susanne W. Harris, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of and for the periods presented in the Report.

The foregoing certification is provided solely for purposes of complying with the provisions of Section 906 of the Sarbane-Oxley Act of 2002 and is not intended to be used or relied upon for any other purpose.

	Signature	Title	Date
By:	/s/ Jerry L. Morris	Chief Executive Officer	March 14, 2007
	Jerry L. Morris
By:	/s/ Susanne W. Harris	Chief Financial Officer	March 14, 2007
	Susanne W. Harris

A signed original of this written statement required by Section 906 has been provided to Southern Star Central Corp. and will be retained by Southern Star Central Corp. and furnished to the Securities and Exchange Commission or staff upon request.