UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x

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

For the fiscal year ended December 31, 2007

or

¨

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

For the transition period from                      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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.    

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

Smaller reporting company ¨

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

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 19, 2008.

TABLE OF CONTENTS

2007 FORM 10-K

SOUTHERN STAR CENTRAL CORP.

		Page
Forward-Looking Statements		1
	PART I.
Item 1.	Business	2
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	15
Item 2.	Properties	16
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	17
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	18
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	29
	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	37
Item 13.	Certain Relationships and Related Transactions, and Director Independence	37
Item 14.	Principal Accountant Fees and Services	38
	PART IV.
Item 15.	Exhibits and Financial Statement Schedules	38

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:

•

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;

•

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

•

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

•

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;

•

our ability to manage costs;

•

the ability of our customers to pay for services;

•

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

•

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

•

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

•

the cost and effects of legal and administrative proceedings;

•

the effect of accounting interpretations and changes in accounting policies;

•

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

•

changes in general economic, market or business conditions; and

•

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.

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.

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, 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. 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 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, 2007, 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 portions of the pipeline have bi-directional flow capability. This flexibility allows Central to respond to fluctuations in regional supply and demand and to optimize the utilization of Central’s pipeline infrastructure. The pipeline system has direct access to major supply basins in Kansas, Oklahoma, Texas 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, 2007, 93% of Central’s operating revenues were obtained through monthly firm reservation charges (“rent” charges under firm contracts) and 7% 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, 2007, Central had customer transportation contracts with approximately 138 shippers. Shippers include regulated natural gas distribution companies, municipalities, intrastate pipelines, direct industrial users, electrical generators and gas marketers and producers. Central transports natural gas to approximately 572 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 29 years. At December 31, 2007, the average remaining contract life on a vol ume-weighted basis was approximately six years.

For the year ended December 31, 2007, 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, 2007. 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 2007.

As with all interstate natural gas pipeline operators, 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

Central’s pipeline 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. We believe 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, seven are delivery points; eight 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, or TBtu, per day
Transportation Volumes:
	2007	2006	2005
Market area	0.6	0.5	0.6
Production area	0.3	0.3	0.2
Production market interface	0.4	0.4	0.5

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

	TBtu per day
Reserved Capacity:
	2007	2006	2005
Market area	1.9	1.9	1.9
Production area	0.4	0.4	0.4
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 requires Central to reserve a specified amount of capacity for customers and allows these customers to pull their gas from storage with little or no notice. 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 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 firm t ransportation and firm storage service to satisfy up to two-thirds of their natural gas supply needs. No-notice service accounted for approximately 64% of our 2007 operating revenues, and as of December 31, 2007, accounted for approximately 74% of Central’s firm market area capacity, 43% 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 2007 operating revenues, and as of December 31, 2007, comprised approximately 26% of Central’s firm market area capacity and 57% 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. Customers are charged based on storage capacity held. Central has approximately 1.2 TBtu/day of firm storage deliverability capacity and 43 Bcf 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 t he 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, 2007.

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. Charges are based on the volume of gas parked or loaned. This service accounted for approximately 3% of our operating revenues for the year ended December 31, 2007.

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.

 Market Expansions and 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. 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 Central’s 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.

The following is a summary of recent market expansion projects completed or in progress, as well as market initiatives Central is currently pursuing:

Prairie Pride, Inc. – Central recently completed this project to connect to Prairie Pride, Inc.’s new bio-diesel/cogeneration facility located in Vernon County, Missouri. The project cost was approximately $1.3 million and was placed in service in July 2007. Central’s new facilities are capable of delivering up to 5,400 dekatherms, or Dths, per day of firm transportation.

Show Me Ethanol – Central recently completed this project to serve Show Me Ethanol, LLC’s new ethanol facility located in Carroll County, Missouri. The project cost was approximately $0.2 million and was placed in service in February 2008.

Kansas Ethanol – Central recently completed this project to serve Kansas Ethanol, LLC’s new ethanol facility located in Rice County, Kansas. The project cost was approximately $0.3 million and was placed in service in March 2008.

Westar Emporia – Central recently completed installation of approximately five miles of 24-inch lateral pipeline and measurement facilities to provide service to Westar Energy’s 600 megawatt, or MW, natural gas-fired power generation plant in Lyon County, Kansas. The project is currently in its second phase, which is expected to be completed in 2008 and will involve adding incremental horsepower to existing units at Central’s Hesston, Kansas compressor station. The estimated in-service date of the project is December 2008. The total project cost for both phases is an estimated $13.2 million.

Midwest Goodman – Central recently completed the construction of 12 miles of six-inch lateral pipeline and measurement facilities to serve the Midwest Energy 75MW Goodman Energy Center natural gas powered generation peaking facility in Ellis County, Kansas. The project cost was approximately $5.0 million and was placed in service in February 2008.

Atmos Energy – Central has executed an agreement with Atmos Energy to add an incremental 20,000 Dths/day of service to the Olathe, Kansas area. Central will be installing the necessary facilities in 2008 to provide this service at an estimated cost of $3.2 million.

Highland Trails – In June 2007, we initiated the development of a major expansion project, known as “Highland Trails,” by soliciting interest from potential customers. Highland Trails, if fully developed, would be a new interstate natural gas pipeline project that will connect the developing Fayetteville Shale production basin in Central Arkansas to Kinder Morgan’s Rockies Express Pipeline, LLC in Audrain County, Missouri. We are currently evaluating the potential for this project, or portions thereof, based on interest expressed to date. The final cost of the project will be determined based on the demand for the project by solicited customers.

 Enogex Project – The “Perry Delivery Project” proposes to deliver up to 100,000 Dths/day to Enogex, Inc. in Noble County, Oklahoma. In January 2008, we made a public announcement requesting expressions of interest for the project from potential customers, via a non-binding open season. The open season began on January 11, 2008 and concluded on February 25, 2008. Central is currently evaluating the results of the open season. The final cost of the project will be determined based on the demand for the project by solicited customers.

Gas Supply Projects and 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 and supply initiatives Central is currently pursuing:

Waynoka Supply Project – Central recently completed this project to connect its Straight-Blackwell pipeline to the Atlas gas processing plant in Woods County, Oklahoma. The Atlas processing facility is capable of delivering approximately 200,000 Dths/day and the Central interconnect is designed to receive up to 175,000 Dths/day. These facilities were placed in service in September 2007.

Dart Cherokee Basin – These two completed projects are located in Southeastern Kansas. Central installed new facilities capable of receiving up to 10,000 Dths/day at a new interconnect point and upgraded existing facilities capable of receiving up to 20,000 Dths/day at an existing interconnect. The costs of these facilities and upgrades were reimbursable to Central.

SemGas Receipt Point – This receipt point located in Grant County, Oklahoma was originally placed in service in early 2006 with an initial design of 10,000 Dths/day. As a result of incremental production in the area, Central upgraded this facility to receive up to 26,000 Dths/day. The cost of the upgrade was reimbursable to Central.

Various Other Projects and Initiatives – During 2007, six other receipt point operators in Kansas reimbursed Central for the cost of expanding facilities designed to receive approximately 45,000 Dths/day of gas into Central’s system. Two other receipt point operators will reimburse Central for the cost of expanding facilities designed to receive a combined total of approximately 5,000 Dths/day. These projects are anticipated to be in service by the second quarter of 2008. We are also in the preliminary stages of evaluating six new supply receipt projects that would add approximately 62,000 Dths/day of incremental gas supply volumes into the pipeline system.

Competition

Central competes primarily with other interstate and intrastate pipelines for the transportation of natural gas. The principal elements of competition among pipelines are transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. Central competes primarily with other interstate pipelines in the Kansas City metropolitan area and in Wichita, Kansas. One of these interstate pipelines is an affiliated company of one of Central’s largest customers, MGE. Central’s primary competitors in these markets are Kansas Pipeline Company, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipeline Company.

Natural gas also competes with other forms of energy available to our customers, including electricity, coal, hydroelectric power, nuclear power and fuel oil. The principal elements of competition among alternative forms of energy are based on the existing infrastructure, rates, terms of services, access to supply and reliability. The impact of competition on us could decrease demand for natural gas in the markets served by our 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 of 1938, or NGA, and under the Natural Gas Policy Act of 1978, or NGPA,  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 operatin g 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 given additional regulatory authority under the Public Utility Holding Company Act of 2005, or PUHCA 2005. 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 regulate accounting matters and 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. One of the Company's indirect owners, the General Electric Company, is a holding company which has filed with the FERC a notification of exemption from PUHCA 2005 under the FERC's PUHCA 2005 regulations, and is exempt from PUHCA regulation except for disclosure and boo ks and records requirements, and regulations regarding exemption. Neither the Company, nor Central, is a "public-utility company" or "holding company" under PUHCA 2005. If a parent company of the Company were to become regulated as a holding company under PUHCA 2005, Central could become subject to PUHCA 2005's disclosure, accounting, and cost-allocation requirements.

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 services.

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 new rate case to be effective no later than November 1, 2008.

Central also charges its customers a fuel reimbursement charge based on the volume of gas transported through the system to recover in-kind the natural gas it uses for fuel on its operating system and gas losses it incurs on its system. The reimbursement charge is established through an annual fuel tracker based on actual losses for prior years filed with the FERC. Once the fuel tracker is filed, the FERC gives interested parties the opportunity to comment. On November 30, 2007, Central made its annual fuel filing to establish its transmission and storage fuel and loss reimbursement percentages for 2008 based on the actual fuel and loss for the twelve months ended September 30, 2007. Several customers and state commissions intervened, commenting on various aspects of the filing, including the level of gas losses Central had incurred as a result of a pipeline girth weld failure and a storage lateral line failure. On Decem ber 28, 2007, the FERC issued an Order accepting the filing, subject to refund, and directed its staff to convene a technical conference to discuss the issues raised in the comments. The technical conference was held on February 8, 2008, subsequent to which the parties submitted additional questions to Central.  Central responded to such questions on March 5, 2008. All parties will file Initial Comments with the FERC on March 19, 2008, and Reply Comments on April 2, 2008. The FERC will then issue an order based on Central’s filing and the comments received from all parties. Management believes its fuel and loss recovery mechanism provides for the recovery of the gas losses at issue and that such mechanism is well supported and has been consistently applied. Central does not anticipate any material adverse effect on its financial position or results of operations as a result of the resolution of this issue.

Recent FERC Regulatory Orders. On November 17, 2006, the D.C. Court of Appeals vacated FERC Order 2004, or Order 2004, relating to Standards of Conduct for Transmission Providers and remanded Order 2004 to the Commission. Order 2004 had expanded the Standards of Conduct to apply to a broad group of energy 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 encompassing those entities. As opposed to requesting rehearing of Order 2004, on January 9, 2007, the FERC issued an interim rule (Order No. 690) substantially reinstating the Standard of Conduct rules that were in effect under Order 497, the Order in effect prior to the issuance of Order 2004. On January 18, 2007, the FERC issued a Notice of Proposed Rule Making proposing to make the int erim rule permanent and seeking comments on various issues related to marketing affiliates and the Standards of Conduct that should apply to all transmission providers. The Commission has yet to issue a final order. Central does not anticipate any adverse effects from the issuance of a final order on this docket.

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 its applicable regulations have 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 on our financial position or results of operations.

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	Fully Authorized Operating Permit Receipt
Elk City	S-013	1/31/2006	10/31/2009	2/29/2008
Colony	S-014	6/12/2006	11/30/2009	—
Piqua	S-016	7/31/2006	1/31/2010	—
North Welda	S-019	10/31/2006	2/28/2008	—
Alden	S-018	1/31/2007	7/31/2008	—
McLouth	S-015	7/18/2007	5/31/2008	—
South Welda	S-020	12/28/2007	4/30/2008	—

As of December 31, 2007, Central had submitted applications for Fully Authorized Permits for all of the seven Kansas storage facilities. On February 29, 2008, Central received a Fully Authorized Permit for the Elk City Storage Field and expects an extension to be granted to the Provisional Operating Permit for the North Welda Storage Field beyond the current expiration date of February 28, 2008.

Central has identified storage reservoir parameters at six of its Kansas storage fields that require updates to its existing FERC certificates. The FERC approved the Colony Gas Storage Field application on May 19, 2006 and the Piqua Gas Storage Field on March 26, 2007. The application for North Welda Storage Field was filed February 23, 2007 and the application for South Welda Storage Field was filed October 5, 2007. The information and data for the remaining FERC filings is being compiled. Central anticipates filing the two remaining FERC certificate applications in 2008 and 2009.

We anticipate 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 on our results of operations or financial position. 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. We have 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 on our results of operations or financial position.

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 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 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 regional transport o f ozone. Based on analysis of these regulations, management does not expect there to be a material impact to Central’s existing operations. Additionally, all of Central’s facilities are located in areas currently designated as being in “attainment” of all National Ambient Air Quality Standards (NAAQS). However, on March 12, 2008, the EPA issued more stringent NAAQS for ozone. Certain of our facilities are located in areas that may not be in attainment with the revised ozone NAAQS. Management does not expect that these revisions to the ozone NAAQS will have a material impact to Central’s existing operations.

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 $3.1 million and $3.7 million at December 31, 2007 and 2006, respectively, 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 $0.8 million annually to remediate the PCB/mercury contamination. Central recovers approximately the same amount in its current rates each year.

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 position or results of operations.

Insurance

We maintain insurance coverage for our Company and our pipeline system in such amounts and covering such risks as are 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, all-risk property and business interruption insurance, terrorism insurance, employment practices liability, and excess liability insurance.

Employees  

As of December 31, 2007, the Company had 459 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 180 field employees. This agreement was renegotiated during 2004 for a four-year term to expire July 15, 2008. We will begin negotiations on a new agreement in the second quarter of 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

We face certain risks in conducting our 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 in recent years, 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 position or 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.

The EPA has promulgated NAAQS for several air pollutants. The EPA designates areas of the United States as being in “attainment” or “nonattainment” of these standards based on ambient monitoring data collected at sites around the country. Sources of air pollution operating in nonattainment areas may be required to reduce levels of air emissions to help an area attain compliance with a NAAQS. All of Central’s compressor stations are located in areas currently designated as being in attainment of the NAAQS. Therefore, we do not project any mandatory emission reductions at this time in order to help areas comply with a NAAQS. However, the EPA revisits attainment designations periodically based on actual ambient monitoring data and the EPA also has a statutory requirement to periodically review the NAAQS. As such, it is not possible to predict with certainty 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, 2007, we were aware of PCB and/or mercury contamination that requires remediation at six of our compressor sites and 500 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 $3.1 million as of December 31, 2007, representing the estimate of future cleanup costs, most of which is expected to be incurred over the next three to four years. However, should unanticipated future costs exceed our estimates, such costs could have a material adverse effect on our financial position, since such costs may not be recoverable.

Additionally, 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 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 position 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. We are required by the terms of that settlement to file a new general rate case in 2008. Whenever we 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 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 position 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, 2007, approximately 97% of our firm contracted market area capacity, 91% of our firm contracted production area capacity and 99% of our firm contracted storage capacity were 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 you 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 our 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 we 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 position 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 position 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 2008 will be approximately $8.1 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. Our 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 principal elements of competition among alternative forms of energy are based on the existing infrastructure, rates, terms of services, access to supply and reliability. The impact of competition on us could decrease demand for natural gas in the markets served by our pipeline.

Federal and state regulation of natural gas interstate pipelines has changed dramatically in the last 25 years and may continue to change. These regulatory changes have resulted and may 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 position 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, 2007. Approximately 58% of our operating revenues during the year ended December 31, 2007 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 position 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 future 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 position 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. 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 or at all. These developments have subjected our operations to increased risks and, depending on their ultimate mag nitude, could have a material adverse effect on our business, financial position and results of operations. In particular, we might experience increased capital or operating costs to implement increased security or interruptions in our ability to provide our services.

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

The covenants in our current debt agreements 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 our outstanding senior 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 our 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 for the District of Wyoming, or Trial Court. 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. Grynberg’s counsel file d notices of appeal with the United States Court of Appeals for the Tenth Circuit, where his appeals are now pending as In re Natural Gas Royalties Qui Tam Litigation, Case No. 06-8099. Appellate briefing is ongoing and oral argument is expected to be scheduled in September 2008. The parties are awaiting the Trial Court’s ruling(s) on the defendants’ motions for attorneys’ fees and costs, which were the subject of a hearing held on April 24, 2007.

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’ second motion seeking class certification was fully briefed and the court heard oral argument on th is 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, 2007, all of our common stock was held by one holder of record.

We have outstanding $200.0 million aggregate principal amount of 6.75% Senior Notes due 2016, or 6.75% Notes. Under the indenture for our 6.75% Notes, the declaration and payments of dividends or distributions to equity holders 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 2007 and 2006 were $25.8 million and $56.2 million, respectively. We expect to continue to pay dividends as permitted under the indenture on a quarterly basis.

 Item 6. Selected Financial Data

Financial data presented below for the periods after August 11, 2005 reflect the operations of the Company prior to the Acquisition. Hence, there is a blackline division on the selected historical financial data, which is 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
	For the Year Ended December 31, 2007			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
Statement of Operations Data:
Operating Revenues	$	188,081		$	187,246		$	70,769		$	111,168		$	164,332		$	158,598
Operating Costs and Expenses:
Operations and maintenance		45,085			41,030			14,702			23,568			37,508			34,398
Administrative and general		35,562			34,939			13,809			25,688			37,026			40,989
Depreciation and amortization		27,470			26,881			10,884			17,299			27,781			29,279
Taxes, other than income taxes		14,573			13,349			4,745			7,573			10,831			10,994
Total Operating Costs and
Expenses		122,690			116,199			44,140			74,128			113,146			115,660
Operating Income		65,391			71,047			26,629			37,040			51,186			42,938
Interest Expense (Income):
Interest expense		28,842			29,964			11,337			25,169			40,856			42,396
Interest income		(1,441	)		(2,401	)		(737	)		(719	)		(651	)		(705	)
Miscellaneous other (income)
expense, net		(516	)		(445	)		(121	)		113			2,401			(3,392	)
Income Before Income Taxes		38,506			43,929			16,150			12,477			8,580			4,639
Provision for Income Taxes		15,299			17,558			6,399			7,074			6,511			4,804
Net Income (Loss)	$	23,207		$	26,371		$	9,751		$	5,403		$	2,069		$	(165	)
Balance Sheet Data (end of period):
Cash and Cash Equivalents	$	20,025		$	37,989		$	62,287		$	44,525		$	41,702		$	65,887
Property, Plant & Equipment, Net		563,799			544,270			527,707			524,029			528,075			514,891
All Other Assets		473,521			442,065			426,309			154,588			132,772			167,603
Total Assets	$	1,057,345		$	1,024,324		$	1,016,303		$	723,142		$	702,549		$	748,381
Capitalization:
Current maturities of long-term
debt	$	690		$	765		$	225,647		$	50,735		$	730		$	—
Total long-term debt, net of
current portion		435,312			438,946			202,344			362,777			413,093			404,740
Mandatorily redeemable preferred stock		—			—			—			52,760			51,184			48,265
Common stockholder’s equity		432,082			434,695			464,514			122,923			131,277			141,259
Total Capitalization	$	868,084		$	874,406		$	892,505		$	589,195		$	596,284		$	594,264

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

This management’s discussion and analysis of our financial condition and results of operations should be read in conjunction with “Selected Historical Financial Data” and our 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 the Company prior to the Acquisition, 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

In 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. Following the transaction, Holdings owned all of our outstanding capital stock. Following the Acquisition, our capital stock was immediately recapitalized and the Series A Preferred Stock was converted into common stock. Southern Star 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 working capital and tax settlements, by $324.8 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

Southern Star is the parent company of Central, its 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 29 years. Total average remaining contract life on a volume-weighted basis at December 31, 2007 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 with respect to access to supplies is evidenced by its recent supply initiatives, including the Waynoka supply project placed in service during the third quarter of 2007. Through December 31, 2007, the cost attributable to this project was $9.8 million. The competing interstate pipelines generally offer less diverse geographic access to natural gas supply and less competitively priced, flexible on-system storage.

In addition, 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. In 2007, we began construction on the Westar Emporia and Midwest Goodman expansion projects at estimated total costs of $13.2 million and $5.0 million, respectively. The Company anticipates investing approximately $8.7 million during 2008 for planned expansion projects, which includes $5.3 million to complete the Westar Emporia project, $0.4 million to complete the Midwest Goodman project, and $2.9 million to complete the Atmos Energy project.

In June 2007, we initiated the development of a major expansion project, known as “Highland Trails,” by soliciting interest from potential customers. Highland Trails, if fully developed, would be a new interstate natural gas pipeline project that will connect the developing Fayetteville Shale production basin in Central Arkansas to Kinder Morgan’s Rockies Express Pipeline, LLC in Audrain County, Missouri. We will continue to evaluate this project, or portions of it, based on interest expressed to date.

The “Perry Delivery Project” proposes to deliver up to 100,000 Dths/day to Enogex, Inc. in Noble County, Oklahoma. In January 2008, we made a public announcement requesting expressions of interest for the project from potential customers, via a non-binding open season. The open season began on January 11, 2008 and concluded on February 25, 2008. Central is currently evaluating the results of the open season.

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 $324.8 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.

Income Taxes

We record deferred taxes under the liability method. Deferred taxes 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.”

In June 2006, the Financial Accounting Standards Board, or FASB, issued Interpretation, or 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. We adopted the provisions of this interpretation on January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company’s cumulative earnings, consolidated financial position, or results of operations.

Southern Star and Central operate under 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 us 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.

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. For the purpose of comparing operations for 2007, 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 i s non-amortizable, there is no impact on results of operations from that allocation.

The following table sets forth our selected results of operations data for the years ended December 31, 2007, 2006 and 2005 (in thousands):

		For the Year Ended December 31, 2007		For the Year Ended December 31, 2006		Combined Year Ended December 31, 2005 (unaudited)
		(In thousands)
Operating revenues	$	188,081	$	187,246	$	181,937
Operations and maintenance		45,085		41,030		38,270
Administrative and general		35,562		34,939		39,497
Depreciation and amortization		27,470		26,881		28,183
Taxes, other than income taxes		14,573		13,349		12,318
Operating income		65,391		71,047		63,669
Other (Income) Deductions:
Interest expense		28,842		29,964		36,506
Interest income		(1,441)		(2,401)		(1,456)
Miscellaneous other (income) expenses, net		(516)		(445)		(8)
Total Other Deductions		26,885		27,118		35,042
Income before income taxes		38,506		43,929		28,627
Provision for income taxes		15,299		17,558		13,473
Net Income	$	23,207	$	26,371	$	15,154

Comparison of the Years Ended December 31, 2007 and 2006

Operating revenues were $188.1 million for the year ended December 31, 2007, a $0.8 million, or 0.4%, increase from the prior year. The increase is primarily due to increased demand for Central's firm services offset partially by lower customer inventories in storage and decreased demand for interruptible services. The demand for firm services increased primarily due to the Ozark Trails expansion project that was placed in service in December 2006. Lower storage revenues in 2007 are the result of decreased inventories in storage resulting from climate conditions that were not as mild as in 2006 and the resulting increase in demand for natural gas.

Operations and maintenance expenses increased by $4.1 million, or 9.9%, to $45.1 million for the year ended December 31, 2007 from $41.0 million for the prior year, principally due to higher expenses in 2007 for labor, vehicle usage, materials and parts as a result of the disposal of obsolete material, inspections and pipeline repairs in the McLouth storage field, the engagement of storage consulting services and well testing for KCC storage permit compliance. The increase was partially offset by lower expenses for the pipeline and integrity management program resulting from fewer pipeline assessments needed to inspect the required pipeline mileage and the cancellation of a wireless communication lease.

Administrative and general expenses increased by $0.6 million, or 1.8%, to $35.6 million for the year ended December 31, 2007, principally due to higher expenses in 2007 for tax, accounting and audit services, group health insurance and the favorable settlement in 2006 of two customer bankruptcies. The increase was partially offset by lower contract programming costs, reductions in property and liability insurance premiums and lower labor costs primarily as the result of lower employee incentives.

Depreciation and amortization expense was $27.5 million for the year ended December 31, 2007 as compared to $26.9 million in 2006, a $0.6 million, or 2.2%, increase. The change is primarily due to an increase in the depreciable base due to timing of retirement job in-service dates and actual booking dates along with an increase in the depreciable base for underground storage.

Taxes, other than income taxes, increased by $1.2 million, or 9.2%, to $14.6 million for the year ended December 31, 2007. The increase was mainly the result of increases in state property tax assessments in Kansas, Oklahoma and Missouri.

Interest expense was $28.8 million for the year ended December 31, 2007, a $1.1 million, or 3.7%, decrease. The decrease is primarily due to lower interest rates in 2007 as compared to 2006 and lower amortization of the debt-related expenses resulting from the refinancing of our long term debt in April 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 decreased by $1.0 million, or 40.0%, to $1.4 million for the year ended December 31, 2007. The decrease is primarily due to lower cash balances held in 2007 than in 2006.

The provision for income taxes was $15.3 million for 2007, a decrease of $2.3 million, or 12.9%, from $17.6 million in 2006, commensurate with lower pre-tax income. Our effective tax rate for 2007 was 39.7% as compared to 40.0% for 2006.

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 in 2006.

Operations and maintenance expenses increased by $2.8 million, or 7.2%, to $41.0 million for year ended December 31, 2006, 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 delays in 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 employee retention payments in 2006 related to agreements entered into in August 2005, favorable settlements in 2006 of two customer bankruptcies, discontinuation of mainframe computer usage at the end of 2005 and lower employee benefit costs.

Depreciation and amortization 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 of $0.8 million 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 assessments 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 in 2006 as compared to 2005 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.

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 do not maintain a credit facility for working capital needs. We expect to fund our capital and other liquidity requirements with cash flows from operating activities and by accessing debt markets as needed to support operations and capital expenditures.

As of March 3, 2008, 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 future borrowing costs or limit our access to capital.

Net cash provided by operating activities for the years ended December 31, 2007 and 2006 was $59.1 million and $79.2 million, respectively. Cash from operating activities was lower in 2007 primarily due to lower interest income, higher operating expenses, increases in other receivables in 2007 and reimbursements in 2006 from Highstar for pre-acquisition taxes paid in 2005. The decrease was also due in part to a reduction in payables in 2007 compared to 2006 due to large construction expenditures in December 2006 that were paid in 2007. The decrease in cash from operating activities in 2007 was partially offset by higher revenues and lower interest expense and income taxes.  

Net cash used in investing activities for the years ended December 31, 2007 and 2006 was $47.2 million and $41.3 million, respectively. Cash used in investing activities was higher in 2007 primarily due to higher capital expenditures, primarily related to the Midwest Goodman and Westar Emporia expansion projects and the Waynoka supply project.

Net cash used in financing activities was $29.9 million for the year ended December 31, 2007, as compared to $62.2 million for the same period in 2006. Cash used for financing activities was lower in 2007 primarily due to $30.4 million in higher dividend payments to common equity holders in 2006, a $2.0 million working capital settlement paid to Highstar in 2006 as a result of the 2005 acquisition, and payment of the $7.3 million notes payable to Highstar in 2006. The decrease was partially offset by the net proceeds of our debt refinancing in 2006 and the 2007 retirement of the remaining balance of our 8.5% Notes due 2010. Our financing activities are further discussed below.

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 customer inventories in storage due to mild climate conditions in 2006. The increase was also due in part to lower disbursements for interest on our long-term debt resulting from 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 on our Series A Preferred Stock as a result of the recapitalization of our stock in 2005.

 8.5% Notes

Prior to April 2006, we had outstanding $180.0 million of 8.5% Notes due 2010. Interest on the 8.5% Notes was payable semi-annually in February and August.

As a result of the Acquisition, the fair value of the 8.5% Notes was calculated at fair value and a premium of $15.7 million was recorded in Long-term debt in 2005. This premium was being amortized over the remaining life of the 8.5% Notes.

In March 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. In April 2006, 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, which eliminated substantially all of the original covenants and certain events of default. On June 19, 2007, Southern Star issued a notice of full redemption to the holders of its 8.5% Notes, calling all remaining 8.5% Notes for redemption. On August 1, 2007, Southern Star paid $3.2 million to redeem all outstanding 8.5% Notes and recorded a loss of $0.1 million related thereto.

6.75% Notes

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

In connection with the issuance of the 6.75% Notes, we entered into a registration rights agreement, 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 exchange offer was consummated in September 2006, at which time all notes were accepted for exchange.

Interest is payable semi-annually on March 1 and September 1 of each year. The 6.75% Notes mature on March 1, 2016 and have an overall effective interest rate of 7.06%. 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 and are effectively junior to any secured indebtedness of ours to the extent of the value of the assets securing such indebtedness, if any.

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.

The 6.75% Notes are subject to certain covenants that restrict, among other things, our and our subsidiaries’ ability to make investments, incur additional indebtedness, pay dividends or make 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.

We may redeem, with the proceeds from an equity offering, up to 35% of the aggregate amount of the 6.75% Notes prior to March 1, 2009, at a premium defined in the indenture. Beginning March 1, 2009, we may redeem all or part of the 6.75% Notes at premiums defined in the indenture. At any time prior to March 1, 2011, we also have the right to redeem the 6.75% Notes in full at a make-whole premium as defined in the indenture.  

Central Credit Facility

Prior to April 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 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 retire 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

In April 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 as of 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 semi-annually on June 1 and December 1 of each year. The 6.0% Notes mature on June 1, 2016 and have an overall effective interest rate of 6.17%. 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. The 6.0% Notes are structurally senior to the 6.75% Notes.  

The 6.0% Notes are subject to certain covenants that restrict, among other things, Central’s ability to create liens, enter into sale and leaseback transactions or merge or consolidate with other entities.

Central has the option to call the 6.0% Notes at any time at a make-whole premium as defined in the indenture.

Capital Lease

Central has a 20-year capital lease with the Owensboro-Daviess County Industrial Development Authority, or the Authority, for use of a headquarters building in Owensboro, Kentucky.  Central is the borrower under a $9.0 million loan agreement dated as of January 1, 2004 between Central and the Authority pursuant to which the Authority financed the cost of Central’s office facility in Daviess County, Kentucky. In connection with this financing, the Authority issued Series 2004A and 2004B bonds under an indenture dated as of January 1, 2004 between the Authority and U.S. Bank, National Association, as trustee. 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. Central has the option to prepay all 2004A bonds on or after January 1, 2014 and all 2004B bonds on or after February 1, 2014.

Other

We operate under 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 we are members under Treasury Regulations Section 1.1502-6.

The terms of Central’s FERC Docket No. RP04-276 settlement require Central to file a rate case to be effective no later than November 1, 2008.

We have entered into employee retention agreements with the officers of Central. These agreements require annual payments to those employees for their continued employment. See “Executive Compensation – Employment Agreements and Potential Payments Upon Termination or Change in Control.” We are accruing the expenses associated with these payments ratably over the period services are being provided. We recorded $1.9 million in expenses for each of the years ended 2007 and 2006 for such annual payments. The current agreements are scheduled to expire in 2010 but may be renewed annually thereafter.

At December 31, 2007, 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, 2007:

Payments Due by Period

(In thousands)

	Long-Term Debt		Capital Leases1		Purchase Obligations		Operating Leases		Capital Expenditure Commitments2		Total Contractual Obligations
2008	$	27,300	$	1,069	$	3,105	$	182	$	16,437	$	48,093
2009		27,300		1,069		—		167		1,578		30,114
2010		27,300		1,062		—		96		1,578		30,036
2011		27,300		522		—		26		708		28,556
2012		27,300		526		—		11		—		27,837
After 2012		519,900		6,343		—		39		—		526,282
Total	$	656,400	$	10,591	$	3,105	$	521	$	20,301	$	690,918

(1)

Principal and interest 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 $69.9 million in 2008 including approximately $5.7 million for the Westar Emporia and Midwest Goodman expansion projects and approximately $2.9 million for the Atmos Energy expansion project, all of which are scheduled to be completed during 2008. We expect to fund 2008 capital expenditures from our cash from operations and by accessing debt markets as needed.

In addition to the capital expenditures listed above, Central expects to contribute between $7.6 million to $9.3 million to its Union and Non-Union Retirement Plans in 2008. 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, 2007, had a carrying value of $428.9 million and a fair value of $414.4 million. The weighted-average interest rate of our long-term debt was 6.58%. Our $200.0 million (6.75% Notes) and $230.0 million (6.0% Notes) long-term debt issues mature in 2016. On June 19, 2007, we issued a notice of full redemption to the holders of our 8.5% Notes, calling all remaining 8.5% Notes. On August 1, 2007, we paid $3.2 million to redeem all outstanding 8.5% Notes and recorded a loss of $0.1 million related thereto. The $7.1 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

Disclosure Controls and Procedures – As of December 31, 2007, we, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as defined in Exchange Act Rules 13a – 15(e) and 15d – 15 (e). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of December 31, 2007.

Management’s Report on Internal Control Over Financial Reporting – Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that compliance with the policies or procedures may deteriorate or be circumvented.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Based on management’s assessment and the criteria established by COSO, management believes that we maintained effective internal control over financial reporting as of December 31, 2007.

Changes in Internal Control Over Financial Reporting – There has been no change in our internal control over financial reporting during the year ended December 31, 2007, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the SEC that permit us to provide only management's report in this annual report.

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, 2008.

Name	Age		Position
Robert P. Hadden	46	Director
Kathy McGowan	46	Director
Renaud Faucher	43	Director
Yves Rheault	63	Director
Jerry L. Morris	52		President and CEO
Susanne W. Harris	49		Vice President, CFO and Treasurer
Beverly H. Griffith	53		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, 2008.

Name	Age	Position
Robert P. Hadden	46	Director
Kathy McGowan	46	Director
Renaud Faucher	43	Director
Yves Rheault	63	Director
Jerry L. Morris	52	President and CEO
Robert S. Bahnick	48	Senior Vice President of Operations and Technical Services
Robert W. Carlton	47	Vice President of Human Resources and Administration
Chris W. Ellison	53	Vice President of Operations-Hesston Division
David L. Finley	43	Vice President of Information Technology
Beverly H. Griffith	53	Senior Vice President, General Counsel and Corporate Secretary
James L. Harder II	61	Vice President of Customer Services and Business Development
Susanne W. Harris	49	Vice President, CFO and Treasurer
Daryl R. Johnson	54	Vice President of Rates and Regulatory Affairs
Richard J. Reischman	52	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 25 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.

Kathy McGowan was appointed to the Board of Directors effective May 22, 2007. Ms. McGowan currently serves as Senior Vice President at GE Energy Financial Services, a position she was promoted to in March 2007. She joined GE in June 2004 as Vice President. From 2003 to 2004, she was a Principal at Hopewell Partners, an energy advisory firm. From 1987 to 2003, Ms. McGowan worked for ABB in a variety of financial management positions of increasing responsibility, ultimately being named Director and Project Finance leader for the Global Power Group of ABB Equity Ventures, the project development and investment arm of ABB. Ms. McGowan received a B.S. in Mechanical Engineering with High Distinction from the University of Virginia in 1983 and an M.B.A. from the Darden School of Business in 1987.

Renaud Faucher was appointed to the Board of Directors effective 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 Cana da. 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 of Directors 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 Directors 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 30 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 became Senior Vice President of Operations and Technical Services for Central in July 2003. Previously he served as Vice President of Operations and Technical Services since November 2002, 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 26 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 became Vice President of Human Resources and Administration for Central in July 2003. Previously he 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 24 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 became Vice President of Operations-Hesston Division for Central in July 2003. Previously he  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 29 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 became Vice President of Information Technology for Central in July 2003. Previously he  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 21 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 28 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 became Vice President of Customer Services and Business Development for Central in February 2004. Previously he 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 32 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 28 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 became Vice President of Rates and Regulatory Affairs for Central in July 2003. Previously he served as Manager of Rates for Central since 1990. Mr. Johnson has held a variety of positions in accounting and rates during his 32 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 became Vice President of Operations-Kansas City Division for Central in July 2003. Previously he 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 29 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, 2007 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 are determined by the Board, taking into account such factors as market salaries for similar positions as compiled by the Natural Gas Transmission Industry (NGTI) consortium, an officer’s scope of responsibilities, and individual performance and contribution to the Company.   

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.  

Each of our executive officers is eligible to receive a discretionary annual bonus set at a targeted percentage of their base salary between 50% and 100%, as provided in each executive’s employment agreement. The discretionary annual bonus is intended to compensate executive officers for the strategic, operational and financial success of the Company, as a whole, as well as the individual performance of the executive officer. Bonuses are not triggered by achievement of pre-set standards and individual executives may not receive a discretionary bonus even though financial targets are achieved. When determining the annual bonus to be paid to an executive officer, our Board reviews the executive’s achievement of the executive’s stated goals (either individual or team goals), the overall performance of the Company, and the executive’s individual performance. Because the award of a bonus is at the complete discretion of our Board, the Board looks broad ly at the performance of the executive officer in making its determination of whether a bonus should be awarded.

The size of the bonus pool is dependent on the achievement of established targets based on components consisting of non-financial goals and objectives, the achievement of identified financial targets and successful completion of identified projects. Once the bonus pool has been determined by the Board, the CEO makes individual bonus recommendations to the Board for each officer, based on an evaluation of each officer’s individual performance.  The Board makes the final determination of awards for all executive officers, including the CEO, at its discretion. Award recommendations for all other employees are approved by the CEO. The 2007 bonus pool was funded at 66% of the maximum allowed by the Bonus Plan, and as a group, our executive officers received 22% of the bonus pool paid. For 2007, each named executive officer received the following percentage of their respective bonus potential: 61% for Mr. Morris, 58.5% for Mr. Bahnick, 60.5% for Mrs. Griffith, 63 .5% for Mr. Harder, and 62.5% for Mrs. Harris.

Employment Agreements and Retention Payments:  During the course of the Acquisition, 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 2007, and the other three most highly compensated executive officers of Central as of December 31, 2007. 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, 2005, 2006 and 2007 (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	2005	211,454	216,300	N/A	1,062,600	1,490,354
President, CEO of Central	2006	218,147	218,274	28,152	643,200	1,107,773
(from 8/11/2005, was COO from 2/13/2004)	2007	226,015	140,316	34,197	643,500	1,044,028
Susanne W. Harris	2005	141,517	73,183	N/A	246,975	461,675
Vice President, Finance and Accounting, and CFO	2006	147,804	74,207	25,777	153,111	400,899
of Central	2007	154,064	50,066	24,103	154,125	382,358
Beverly H. Griffith	2005	197,210	144,300	N/A	218,148	559,658
Senior Vice President, General Counsel	2006	198,376	140,702	31,752	136,950	507,780
and Corporate Secretary of Central	2007	198,172	88,023	38,545	137,250	461,990
Robert S. Bahnick	2005	205,000	159,375	N/A	278,225	642,600
Senior Vice President of Operations	2006	202,155	148,711	18,584	160,385	529,835
and Technical Services of Central	2007	210,841	90,383	22,067	170,199	493,490
James L. Harder II	2005	151,301	76,726	N/A	302,546	530,573
Vice President of Customer Services	2006	155,673	77,352	49,479	218,200	500,704
and Business Development of Central	2007	159,951	52,141	42,865	218,500	473,457

*

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

** 

All Other Compensation for 2005, 2006 and 2007 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. For 2007, it contains the amounts of $13,500 for Mr. Morris, $10,824 for Mr. Bahnick, $13,500 for Mrs. Griffith, $13,500 for Mr. Harder, and $13,500 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 t o Mrs. Griffith, $290,000 to Mr. Harder, and $234,375 to Mrs. Harris, for 2006 the amounts of $630,000 for Mr. Morris, $150,000 for Mr. Bahnick, $123,750 for Mrs. Griffith, $205,000 for Mr. Harder, and $140,625 for Mrs. Harris, and for 2007 the amounts of $630,000 for Mr. Morris, $159,375 for Mr. Bahnick, $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 2007 (expressed in thousands):

SOUTHERN STAR RETIREMENT PLAN
Name	Number of Years of Credited Service	Present Value of Accumulated Benefit*	Payments During Last Fiscal Year
Jerry L. Morris	5.167	$ 130,533	$ —
Susanne W. Harris	5.167	103,399	—
Beverly H. Griffith	5.167	150,419	—
Robert S. Bahnick	5.167	91,338	—
James L. Harder	5.167	231,632	—

*

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, 2007.

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 $220,000 per year for 2006 and $225,000 for 2007. 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. One year of credited service is credited to an employee for each calendar year during which he is a participant in the plan and receives compensation as an employee of the Company. If an employee works less than a full calendar year, he is credited wi th one-twelfth of a year of credited service for each month, or part thereof, which he is a participant and receives compensation as an employee of the Company. Credited service will not be counted for periods in which an employee does not receive compensation from the Company.

Further, any participant who first became a participant upon the effective date (January 1, 2003) will receive two-twelfths of a year of credited service for the period of employment from November 15, 2002 to December 31, 2002. Service prior to November 15, 2002 does not count as credited service under this plan for any of the named executive officers.  

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 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’s 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’s 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 the Acquisition, 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 agreements, 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. Each of the employment agreements will be extended automatically in one-year increments unless 90 days notice of termination is given by the Board or the employee prior to the end of the applicable employment period.

In addition, each employee, including Mr. Morris, 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 contractor s away from Central or solicit the business of any client or customer of Central in any territory, state or country where Central conducts business.

The table below sets forth the amounts payable to each executive officer assuming the executive officer’s employment had terminated on December 31, 2007.

Except as otherwise expressly indicated, the amounts set forth in the table below do not represent the actual amounts a Named Executive Officer would receive if his employment were terminated or there were a change of control of the Company, but generally represent only estimates, based on the assumptions provided in the footnotes to the table. The amounts set forth in the table are based upon the benefit plans and agreements that were in effect as of December 31, 2007. Payments that we may make in the future upon an employee’s termination or upon a change of control of the Company will be based upon benefit plans and agreements in effect at that time, and the terms of any such future plans and agreements may be materially different than the terms of our benefit plans and agreements as of December 31, 2007.

Name	Termination without Cause or for Good Reason(1)		Termination for Cause(2)		Termination Due to Death(3)		Termination Due to Disability(4)		Termination Due to Relocation(5)
Jerry L. Morris	$	2,565,272	$	—	$	2,104,858	$	2,104,858	$	2,120,207
Susanne W. Harris		814,771		—		494,349		494,349		582,086
Beverly H. Griffith		899,151		—		514,351		514,351		563,650
Robert S. Bahnick		1,039,695		—		627,695		627,695		684,125
James L. Harder II		767,257		—		438,811		438,811		526,723

(1)

Reflects cash severance including 24 months of base salary plus an amount equal to the average annual incentive bonus paid during the most recent three-year period under the employment agreement, expressed as a percentage of the employee’s annual base salary, times the annual base salary then in effect, which must be paid in one lump payment within thirty days of the effective date of termination and also includes retention bonuses not paid prior to termination. The employment agreements define “Good Reason” as (i) any material adverse change(s) in any of the employee’s position, duties, authority or responsibilities which are inconsistent in any material respect with the employee’s position, authority, duties or responsibilities as contemplated by the employee agreement, made without the employee’s express prior written consent and not remedied by the Company promptly after receipt of notice given b y the employee; (ii) a reduction in the employee’s base annual salary; (iii) any failure by the Company to allow the employee participation in and coverage under the medical insurance, dental insurance, retirement, 401(k) savings and other similar plans and programs; provide paid vacations and holidays in accordance with the Company’s policy; and reimbursement of all authorized, reasonable travel, entertainment and other expenses paid or incurred by the employee in the performance of his or her business obligations, other than an insubstantial and inadvertent failure remedied by the Company promptly after receipt of notice given by the employee; or (iv) any purported termination that is not communicated to the employee in writing and fails to provide the nature of the termination and discusses in reasonable detail the facts and circumstances claimed to provide a basis for such termination.

(2)

The employment agreements define “for Cause” as the employee  (i) intentionally refusing (except by reason of incapacity due to physical or mental illness or disability) to devote his or her entire business time to the performance of duties hereunder as provided in the employee agreement, (ii) causing a breach of the Company’s Trade Secret Agreement, (iii) being convicted of, or pleading guilty or nolo contendre to, a felony (iv) committing theft or misappropriation of assets of the Company, or any of its subsidiaries or affiliates, (v) committing any willful, intentional or grossly negligent act which injures the reputation or business of the Company, or any of its subsidiaries or affiliates, or (vi) failing to perform employee duties (including but not limited to failure to cooperate  with an investigation by an governmental authority).

(3)

Reflects cash severance equal to a prorated incentive bonus assuming the employee would have achieved the target bonus for the plan year in which the employee was terminated and unpaid retention bonuses.

(4)

Reflects cash severance equal to a prorated incentive bonus, assuming the employee would have achieved the target bonus for the plan year in which the employee was terminated, unpaid retention bonuses, and benefits paid under Southern Star Central Corp.’s long-term disability insurance program (or such other long term disability program as Southern Star Central Corp. or one of its affiliates maintains for the benefit of the employee). The employee agreements for Mr. Morris states that the Company may terminate Mr. Morris’s employment upon 10 days prior written notice, if he is absent or substantially unable to perform his employment obligations by reason of illness or other incapacity, or any other cause for more than ninety consecutive days during any twelve-month period, notwithstanding any reasonable accommodation as may be required by applicable law. The employee agreements for the named executive officers indicate they will de deemed terminated the first day the employee becomes eligible to receive benefits under the appropriate long-term disability program.

(5)

Reflects cash severance equal to any unpaid retention bonuses and benefits paid under the Southern Star Severance Pay Plan. The employee agreements allow the named executive officers to terminate his or her employee agreement if the employee’s principal place of employment is moved to a location more than 50 miles from the employee’s current place of employment.

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, 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 and officers.

The bylaws of Central provide for the indemnification of a director, officer, employee or agent by Central in a suit by or in the right of Central unless such person has been adjudged to be liable to Central 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 Central. 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 19, 2008, 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 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 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. For each of the years ended 2007 and 2006, we paid approximately $1.0 million 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, with 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 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, 2007 and 2006, and in connection with statutory and regulatory filings for such fiscal periods, were approximately $555,000 and $647,000, respectively.

Audit-Related Fees

The aggregate fees paid or accrued 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, 2007 and 2006 were approximately $96,000 and $91,000, respectively.

Tax Fees

The aggregate fees paid or accrued for services rendered by E&Y in connection with tax compliance, tax advice or tax planning services for the fiscal years ended December 31, 2007 and 2006 were $20,000 and zero, respectively.

All Other Fees

No other services were provided by E&Y for the fiscal years ended December 31, 2007 and 2006.

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 2007 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, 2007 and 2006	F-3
Consolidated Statements of Operations for the years ended December 31, 2007, 2006, the period August 12 through December 31, 2005, and the period January 1 through August 11, 2005	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006, the period August 12 through December 31, 2005, and the period January 1 through August 11, 2005	F-6
Consolidated Statements of Stockholder’s Equity for the years ended December 31, 2007, 2006, the period August 12 through December 31, 2005, and the period January 1 through August 11, 2005	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.
3.67		Amendment of Bylaws of Southern Star Central Corp., dated March 22, 2007.
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.
4.73		Reimbursement and Credit Agreement, dated January 1, 2004, between Southern Star Central Gas Pipeline, Inc. and U.S. Bank, N.A.
4.83		Trust Indenture, dated January 1, 2004, between Industrial Development Authority and U.S. Bank.
4.93		Loan Agreement, dated January 1, 2004, between Industrial Development Authority and Southern Star Central Gas Pipeline, Inc.
4.101		Recapitalization Agreement, dated as of August 11, 2005, between EFS-SSCC Holdings, LLC and Southern Star Central Corp.
4.114		Indenture, dated April 13, 2006, between Central and The Bank of New York Trust Company, N.A.
4.124		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 17, 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.

(7)

Incorporated by reference from Southern Star Central Corp.’s Report on Form 8-K filed with the SEC on March 23, 2007.

1

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 19, 2008	By:	/s/    JERRY L. MORRIS
		Jerry L. Morris President and Chief Executive Officer
March 19, 2008	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/    RENAUD FAUCHER        Renaud Faucher	Director	March 19, 2008
By:	/s/    ROBERT P. HADDEN         Robert P. Hadden	Director	March 19, 2008
By:	/s/    KATHY MCGOWAN Kathy McGowan	Director	March 19, 2008
By:	/s/   YVES RHEAULT         Yves Rheault	Director	March 19, 2008

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

2

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.

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

SOUTHERN STAR CENTRAL CORP.

We have audited the accompanying consolidated balance sheets of Southern Star Central Corp. and subsidiaries (the Company)  as of December 31, 2007 and 2006 and the related consolidated statements of operations, stockholder’s equity, and cash flows for the years ended December 31, 2007 and 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 (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, 2007 and 2006 and the consolidated results of their operations and their cash flows for the years ended December 31, 2007 and 2006, the period from August 12 through December 31, 2005 (post-acquisition), and for the period January 1 through August 11, 2005 (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 2007, the Company adopted Financial Accounting Statement Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.” As discussed in Note 10 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

February 29, 2008

F-2

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31, 2007		December 31, 2006
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	20,025	$	37,989
Receivables:
Trade		17,041		16,700
Income taxes		1,056		591
Transportation, exchange and fuel gas		19,869		5,425
Other		3,642		523
Inventories		6,361		6,458
Deferred income taxes		7,559		7,876
Costs recoverable from customers		25,446		10,589
Prepaid expenses		3,842		3,951
Other		1,110		643
Total current assets		105,951		90,745
Property, Plant and Equipment, at cost:
Natural gas transmission plant		587,241		535,034
Other natural gas plant		25,797		25,743
		613,038		560,777
Less – Accumulated depreciation and amortization		(49,239)		(16,507	)
Property, plant and equipment, net		563,799		544,270
Other Assets:
Goodwill		324,844		324,580
Costs recoverable from customers		42,762		44,007
Prepaid expenses		1,026		1,327
Postretirement benefits other than pensions		10,988		10,165
Other deferred and noncurrent assets		7,975		9,230
Total other assets		387,595		389,309
Total Assets	$	1,057,345	$	1,024,324

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, 2007		December 31, 2006
	(In thousands)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Payables:
Trade	$	3,407	$	4,834
Transportation, exchange and fuel gas		44,316		15,014
Other		7,598		9,245
Accrued taxes, other than income taxes		6,056		5,733
Accrued interest		5,980		5,927
Accrued payroll and employee benefits		10,248		11,809
Capitalized lease obligation due in one year		690		765
Other accrued liabilities		4,828		3,914
Total current liabilities		83,123		57,241
Long-Term Debt:
Capitalized lease obligation		6,445		7,135
Other long-term debt		428,867		431,811
Total long-term debt		435,312		438,946
Other Liabilities and Deferred Credits:
Deferred income taxes		57,258		43,328
Postretirement benefits other than pensions		10,188		9,437
Asset retirement obligations		2,450		2,299
Costs refundable to customers		11,054		10,279
Environmental remediation		2,093		2,736
Accrued pension		23,439		25,234
Other		346		129
Total other liabilities and deferred credits		106,828		93,442
Stockholder’s Equity:
Common stock, $.01 par value, 100 shares issued,
100 shares outstanding at December 31, 2007 and 2006		—		—
Premium on capital stock and other paid-in capital		426,895		426,895
Retained earnings		5,187		7,800
Total stockholder’s equity		432,082		434,695
Total Liabilities and Stockholder’s Equity	$	1,057,345	$	1,024,324

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, 2007			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
	(In thousands)									(In thousands)
Operating Revenues:
Transportation	$	166,599		$	164,073		$	61,144			$	100,002
Storage		20,824			22,375			9,371				10,772
Other revenue		658			798			254				394
Total operating revenues		188,081			187,246			70,769				111,168
Operating Costs and Expenses:
Operations and maintenance		45,085			41,030			14,702				23,568
Administrative and general		35,562			34,939			13,809				25,688
Depreciation and amortization		27,470			26,881			10,884				17,299
Taxes, other than income taxes		14,573			13,349			4,745				7,573
Total operating costs and expenses		122,690			116,199			44,140				74,128
Operating Income		65,391			71,047			26,629				37,040
Other (Income) Deductions:
Interest expense		28,842			29,964			11,337				25,169
Interest income		(1,441	)		(2,401	)		(737	)			(719	)
Miscellaneous other (income) expenses, net		(516	)		(445	)		(121	)			113
Total other deductions		26,885			27,118			10,479				24,563
Income Before Income Taxes		38,506			43,929			16,150				12,477
Provision for Income Taxes		15,299			17,558			6,399				7,074
Net Income	$	23,207		$	26,371		$	9,751			$	5,403

Reconciliation of net income to total comprehensive income:

	Post-acquisition								Pre-acquisition
	For the Year Ended December 31, 2007		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
		(In thousands)								(In thousands
Net income	$	23,207	$	26,371		$	9,751				$	5,403
Change in value of interest rate swaps		—		(68	)		68					179
Related tax benefit (provision)		—		26			(26	)				(69	)
Total comprehensive income	$	23,207	$	26,329		$	9,793				$	5,513

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, 2007			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
	(In thousands)										(In thousands)
OPERATING ACTIVITIES:
Net income	$	23,207		$	26,371		$	9,751			$	5,403
Adjustments to reconcile to net cash provided from         operations:
Depreciation and amortization		27,470			26,881			10,884				17,299
Deferred income taxes		14,247			17,144			6,295				6,723
Loss on property, plant and equipment		—			33			—				2
Amortization of debt discount/premium and expense		1,190			1,070			(626	)			1,545
Termination of interest rate swaps		—			240			—				—
Provision for dividends on mandatorily redeemable   preferred stock		—			—			—				4,065
Receivables		(4,096	)		5,065			4,851				(4,182	)
Inventories		97			(717	)		74				(120	)
Other current assets		(377	)		419			(2,432	)			2,176
Payables and accrued liabilities		(3,798	)		1,141			3,574				(704	)
Other, including changes in noncurrent assets and     liabilities		1,188			1,576			(502	)			1,568
Net cash provided by operating activities	59,128			79,223			31,869			33,775
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of allowance for funds
used during construction	(51,149		)	(41,342		)	(13,756		)	(13,579			)
Proceeds from sales and salvage values, net of costs of       removal		3,907			53			(331	)			(759	)
Net cash used in investing activities	(47,242		)	(41,289		)	(14,087		)	(14,338			)
FINANCING ACTIVITIES:
Proceeds from long-term debt issuance		—			428,634			—				5,000
Payments of notes payable		—			(7,250	)		—				—
Early retirement of debt		(3,080	)		(418,706	)		—				(5,000	)
Premium on early retirement of debt		(131	)		—			—				—
Common dividends/return of capital		(25,806	)		(56,201	)		—				(13,867	)
Debt issuance costs		(68	)		(5,998	)		(20	)			(100	)
Capital lease payments		(765	)		(735	)		—				(365	)
Mandatorily redeemable preferred stock dividends		—			—			—				(2,282	)
Other financing		—			(1,976	)		—				—
Net cash used in financing activities		(29,850	)		(62,232	)		(20	)			(16,614	)
Increase (decrease) in cash and cash equivalents		(17,964	)		(24,298	)		17,762				2,823
Cash and cash equivalents at beginning of period		37,989			62,287			44,525				41,702
Cash and cash equivalents at end of period	$	20,025		$	37,989		$	62,287			$	44,525
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (net of amounts capitalized)	$	27,666		$	31,276		$	7,008			$	26,234
Income tax, net		1,368			720			466				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, 2005	$	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
Add (deduct):
Net income		—			23,207			—			23,207
Common dividends		—			(25,806	)		—			(25,806	)
Adoption of FIN 48		—			(14	)		—			(14	)
Balance, December 31, 2007	$	426,895		$	5,187		$	—		$	432,082

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

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.

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.

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, 2007, Central had transportation customer contracts with approximately 138 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 572 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 requirements in times of peak demand. 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 of 1938, or NGA, and under the Natural Gas Policy Act of 1978, or NGPA, 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.

F-3

2. Basis of Presentation

The 2005 acquisition of Southern Star, discussed in Note 3 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. In our opinion all adjustments, consisting only of normal recurring accruals, necessary for fair presentation have been made to the accompanying consolidated financial statements.

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 from Highstar. The total purchase price was $454.8 million, including $389.1 million paid in cash and acquisition costs of $1.2 million. Additionally, a GE affiliate contributed all of its ownership in Southern Star to Holdings at a total market value of $64.5 million. The purchase price allocation is reflected on the accompanying Consolidated Balance Sheets.  

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 final purchase price including acquisition costs exceeded the fair value of the Company’s net assets and liabilities, including working capital and tax settlements, by $324.8 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.”

Under the terms of the acquisition agreement, Highstar is generally liable for the net current taxes through the acquisition date. Goodwill was adjusted by $0.3 million in 2007 related to differences between estimated and actual tax settlements for periods prior to 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 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 in the accompanying consolidated financial statements and notes. Actual results could differ from those estimates.

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, certain 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 refund or return 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, 2007 and 2006 and classified as current or noncurrent depending on the expected timing of recovery (expressed in thousands):

	2007			2006
Current Assets:
Environmental costs	$	1,000		$	1,000
Fuel costs		24,446			9,589
Total Current Assets		25,446			10,589
Noncurrent Assets:
Environmental costs		2,093			2,736
Income taxes on AFUDC equity		4,264			4,152
Gas imbalance cash cost recoverable		49			84
Postretirement benefits		10,188			9,437
Pension		23,439			25,234
Asset retirement obligations		2,371			2,214
Long-term disability		358			150
Total Noncurrent Assets		42,762			44,007
Total Assets		68,208			54,596
Noncurrent Liabilities:
Gas imbalance cash cost refundable		(66	)		(114	)
Postretirement benefits		(10,988	)		(10,165	)
Total Noncurrent Liabilities		(11,054	)		(10,279	)
Total Liabilities		(11,054	)		(10,279	)
Net Regulatory Assets	$	57,154		$	44,317

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 years ended December 31, 2007 and 2006, the period August 12 through December 31, 2005, and the period January 1 through August 11, 2005, was approximately $27.5 million, $26.9 million, $10.9 million, and $17.3 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 for amounts related to 2006 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 $324.8 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 and electric distribution companies 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 $0.02 million at December 31, 2007 and 2006.

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 $1.5 million and $2.8 million during 2007 and 2006, respectively.

Income Taxes

Southern Star and Central record deferred taxes under the liability method. Deferred taxes 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.”

In June 2006, the Financial Accounting Standards Board, or FASB, issued Interpretation, or 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 adopted the provisions of this interpretation during the first quarter of 2007. The adoption of FIN 48 did not have a material impact on the Company’s cumulative earnings, consolidated financial position, or results of operations.

Southern Star and Central operate under 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, 2007 were $0.3 million and $0.6 million, respectively; 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; and for the pre-acquisition period ended August 11, 2005 were approximately $0.03 million and $0.06 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 2005, in accordance with the FASB Interpretation 47, or FIN 47, “Accounting for Conditional Asset Retirement Obligations,” 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. The amount for both the regulatory asset and the related ARO liability on the accompanying Consolidated Balance Sheet at December 31, 2007 was $2.4 million. The amount of the regulatory asset and the related ARO lia bility on the accompanying Consolidated Balance Sheet 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 fair market value to the extent necessary.

Recent Accounting Standards

In September 2006, the FASB issued SFAS 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in accordance with GAAP, and expands disclosures about fair value measurements. The provisions of SFAS 157 are effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of the SFAS 157 provisions and does not expect that SFAS 157 will have a material impact on its consolidated financial position or results of operations.  

5. Financing

At December 31, 2007 and 2006, long-term debt consisted of the following (expressed in thousands):

	December 31, 2007			December 31, 2006
6.0% Senior Notes due 2016	$	230,000		$	230,000
6.75% Senior Notes due 2016		200,000			200,000
8.5% Senior Secured Notes due 2010		—			3,080
Capitalized lease obligation		7,135			7,900
Unamortized debt discount		(1,133	)		(1,269	)
Total debt		436,002			439,711
Less current capitalized lease obligation		690			765
Total long-term debt	$	435,312		$	438,946

8.5% Notes

Prior to April 2006, Southern Star had outstanding $180.0 million of 8.5% Notes due 2010. Interest on the 8.5% Notes was payable semi-annually in February and August.

As a result of the Acquisition, the fair value of the 8.5% Notes was calculated at fair value and a premium of $15.7 million was recorded in Long-term debt in 2005. This premium was being amortized over the remaining life of the 8.5% Notes.

In March 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. In April 2006, 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, which eliminated substantially all of the original covenants and certain events of default. On June 19, 2007, Southern Star issued a notice of full redemption to the holders of its 8.5% Notes, calling all remaining 8.5% Notes for redemption. On August 1, 2007, Southern Star paid $3.2 million to redeem all outstanding 8.5% Notes and recorded a loss of $0.1 million related thereto.

6.75% Notes

In April 2006, Southern Star completed a private offering of $200.0 million aggregate principal amount of 6.75% Notes due 2016, the proceeds of which were used to retire substantially all of the 8.5% Notes tendered pursuant to the tender offer described above, 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, dated as of April 13, 2006, by and between Southern Star and The Bank of New York Trust Company, N.A., as trustee.    

In connection with the issuance of the 6.75% Notes, Southern Star entered into a registration rights agreement, 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 exchange offer was consummated in September 2006, at which time all notes were accepted for exchange.

Interest is payable semi-annually on March 1 and September 1 of each year. The 6.75% Notes mature on March 1, 2016 and have an overall effective interest rate of 7.06%. 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 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.

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.

The 6.75% Notes are subject to certain covenants that restrict, among other things, Southern Star and its subsidiaries’ ability to make investments, incur additional indebtedness, pay dividends or make 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.

Southern Star may redeem, with the proceeds from an equity offering, up to 35% of the aggregate amount of the 6.75% Notes prior to March 1, 2009, at a premium defined in the indenture. Beginning March 1, 2009, Southern Star may redeem all or part of the 6.75% Notes at premiums defined in the indenture. At any time prior to March 1, 2011, Southern Star also has the right to redeem the 6.75% Notes in full at a make-whole premium as defined in the indenture.

Central Credit Facility

Prior to April 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 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 retire 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

In April 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 as of 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 semi-annually on June 1 and December 1 of each year. The 6.0% Notes mature on June 1, 2016 and have an overall effective interest rate of 6.17%. 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. The 6.0% Notes are structurally senior to the 6.75% Notes.  

The 6.0% Notes are subject to certain covenants that restrict, among other things, Central’s ability to create liens, enter into sale and leaseback transactions or merge or consolidate with other entities.

Central has the option to call the 6.0% Notes at any time at a make-whole premium as defined in the indenture.

Capital Lease

In 2004, Central entered into a 20-year capital lease with the Owensboro-Daviess County Industrial Development Authority, or the Authority, for use of a headquarters building in Owensboro, Kentucky. Central is the borrower under a $9.0 million loan agreement dated as of January 1, 2004 between Central and the Authority pursuant to which the Authority financed the cost of Central’s office facility in Daviess County, Kentucky. In connection with this financing, the Authority issued Series 2004A and 2004B bonds under an indenture dated as of January 1, 2004 between the Authority and U.S. Bank, National Association, as trustee. 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. Central has the option to prepay all 2004A bonds on or after January 1, 2014 and all 2004B bonds on or after February 1, 2014.

Other

In connection with the acquisition described in Note 3, Southern Star issued a non-interest bearing promissory note to Highstar in the aggregate principal amount of approximately $7.3 million. The promissory note was paid in full by Southern Star on March 30, 2006.

As of December 31, 2007, 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)
2008	$	—	$	690
2009		—		720
2010		—		745
2011		—		235
2012		—		250
After 2012		430,000		4,495
Total	$	430,000	$	7,135

6. Recapitalization of Stock

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 common stock. 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.

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

Fuel Filing

Central recovers the natural gas it uses for fuel on its operating system and gas losses it incurs on its system in-kind from its customers via a fuel reimbursement charge placed on the volumes of gas transported through the system. The reimbursement charge is established through an annual fuel tracker filed with the FERC. On November 30, 2007, Central made its annual fuel filing to establish its transmission and storage fuel and loss reimbursement percentages for 2008 based on the actual fuel and loss for the twelve months ended September 30, 2007. Several customers and state commissions intervened and some protested various aspects of the filing, including the level of gas losses Central had incurred as a result of a pipeline girth weld failure and a storage lateral line failure. On December 28, 2007, the FERC issued an Order accepting the filing, subject to refund, and directed its staff to convene a technical confere nce to discuss the issues raised in the protests and the technical conference was held on February 8, 2008. Subsequent to the technical conference, the parties submitted additional questions to Central and Central responded to their questions on March 5, 2008. All parties will file Initial Comments with the FERC on March 19, 2008, and Reply Comments on April 2, 2008. The FERC will then issue an order based on Central’s filing and the comments received from all parties. Management believes its fuel and loss recovery mechanism provides for the recovery of the gas losses at issue and that such mechanism is well supported and has been consistently applied; therefore, Central does not anticipate any material adverse impact to its financial position or results of operations to result from resolution of this issue.

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 $3.7 million at December 31, 2006 and $3.1 million at December 31, 2007 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 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 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). Based on analysis of these regulations, management does not expect there to be a material impact to Central’s existing operations. Additionally, all of Central’s facilities are located in areas currently designated as being in “attainment” of all National Ambient Air Quality Standards (NAAQS). However, on March 12, 2008, the EPA issued more stringent NAAQS for ozone. Certain of our facilities are located in areas that may not be in attainment of the revised ozone NAAQS. Management does not expect these revisions to the ozone NAAQS will have a material impact to Central’s existing operations.

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 for the District of Wyoming, or Trial Court. 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. Grynberg’s counsel filed noti ces of appeal with the United States Court of Appeals for the Tenth Circuit, where his appeals are now pending as In re Natural Gas Royalties Qui Tam Litigation, Case No. 06-8099. Appellate briefing is ongoing and oral argument is expected to be scheduled in September 2008. The parties are awaiting the Trial Court’s ruling(s) on the defendants’ motions for attorneys’ fees and costs, which were the subject of a hearing held on April 24, 2007.

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’ second motion seeking class certification 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.

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.

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, 2007		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
Current provision (benefit):
Federal	$	364	$	(81	)	$	73	$	232
State		539		495			31		119
		903		414			104		351
Deferred provision:
Federal		12,285		14,437			5,236		5,478
State		2,111		2,707			1,059		1,245
		14,396		17,144			6,295		6,723
Income tax provision	$	15,299	$	17,558		$	6,399	$	7,074

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, 2007		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
U.S. statutory rate		35.0%		35.0%		35.0%		35.0%
State income taxes, net of federal taxes benefits		4.5		4.7		4.4		7.1
Permanent items:
Nondeductible preferred stock expenses		—		—		—		12.9
Other, net		0.2		0.2		0.2		1.7
Income tax provision		39.7%		39.9%		39.6%		56.7%

Significant components of deferred tax assets and liabilities as of December 31, 2007 and 2006 are as follows (expressed in thousands):

		2007			2006
Deferred tax assets:
Tax benefit carryforwards	$	6,959		$	19,967
Accrued environmental costs		1,210			1,461
Accrued employee benefits		19,193			19,422
Intangibles		3,394			3,964
Other		1,313			1,339
Total deferred tax assets		32,069			46,153
Deferred tax liabilities:
Property, plant and equipment		47,668			48,132
Intangibles		13,079			13,079
Regulatory assets		19,663			19,032
Other		1,358			1,362
Total deferred tax liabilities		81,768			81,605
Net deferred tax liabilities	$	(49,699	)	$	(35,452	)
Classification:
Net current assets	$	7,559		$	7,876
Net long-term liabilities		(57,258	)		43,328
Net deferred tax liabilities	$	(49,699	)	$	(35,452	)

As of December 31, 2007, tax benefit carryforwards approximating $7.0 million consist of the tax benefit of net operating losses for federal purposes of $6.3 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 2013 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.

In June 2006, the FASB issued FIN 48 which established 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 adopted the provisions of this interpretation during the first quarter of 2007. The adoption of FIN 48 resulted in a $14,000 charge to retained earnings.

The Company has a net unrecognized tax benefit as follows (expressed in thousands):

Unrecognized Tax Benefits – January 1, 2007	$	132
Gross increases – tax positions in prior period		17
Gross decreases – tax positions in prior period		—
Gross increases – current period tax positions		—
Settlements		—
Lapse of statute of limitations		—
Unrecognized Tax Benefits – December 31, 2007	$	149

Pursuant to FIN 48, the Company also records interest related to uncertain tax positions as a part of Interest expense on the accompanying Statement of Operations. Any penalties are recognized as part of miscellaneous expense on the accompanying Statement of Operations. For both December 31, 2007 and January 1, 2007, the Company had an accrued liability for interest related to uncertain tax positions. The total amount of accrued interest from such unrecognized tax benefits was not material. The Company currently does not have a liability for tax penalties.

As of December 31, 2007, the Company remained subject to examination by Federal and State jurisdictions for the tax years beginning November 16, 2002 and forward, in some cases due to net operating losses carried forward. There are currently no income tax audits in process or scheduled in the future.

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, “Accounting for the Effects of Certain Types of Regulations,” the Company will not recognize changes in the funded status in comprehensive income but will recognize them as changes to the related regulatory asset or liability, pending future recovery or refund through its rates. Pursuant to SFAS 158, the Company recognized in its balance sheet the previously unrecognized gains and losses of its pension and welfare benefit plans. The impact of adoption of SFAS 158 to the Company’s Consolidated Balance Sheet at December 31, 2006 is as follows:

	Before Application of SFAS 158		Adjustments		After Application of SFAS 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, 2008. No plan assets are expected to be returned to the Company during the 12 months ending December 31, 2008.

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 39% of the 459 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 amounts recognized on the accompanying Consolidated Balance Sheets at December 31, 2007 and 2006 (expressed in thousands):

		2007			2006
Change in benefit obligation:
Benefit obligation at beginning of year	$	36,738		$	41,520
Service cost		1,269			1,451
Interest cost		1,838			2,050
Actuarial loss		525			1,404
Benefits paid		(572	)		(585	)
Settlements		(5,418	)		(8,782	)
Transfers to non-union plan		(448	)		(320	)
Benefit obligation at end of year		33,932			36,738
Change in plan assets:
Fair value of plan assets at beginning of year		14,936			16,988
Actual return on plan assets		1,002			1,429
Employer contributions		5,257			6,005
Benefits paid		(572	)		(585	)
Transfers to non-union plan		(180	)		(119	)
Settlements		(5,418	)		(8,782	)
Fair value of plan assets at end of year		15,025			14,936
Funded status/Accrued benefit cost	$	(18,907	)	$	(21,802	)

Pursuant to SFAS 158, the accrued benefit cost in 2007 and 2006 includes $0.9 million and $0.2 million, respectively, 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 related 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 $28.0 million and $31.0 million at December 31, 2007 and 2006, respectively.

Lump sum distributions of $5.4 million and $8.8 million were paid to plan participants in 2007 and 2006, respectively.  The Union Plan’s distributions in 2007 and 2006 exceeded each year’s respective 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 2007 settlement were calculated as of April 30, 2007 and as of December 31, 2007 and the effects of the 2006 settlement were calculated as of April 30, 2006 and as of December 31, 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, 2007			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
Components of net periodic pension expense:
Service cost	$	1,269		$	1,451		$	655		$	857
Interest cost		1,838			2,050			869			1,292
Expected return on plan assets		(1,211	)		(1,338	)		(596	)		(835	)
Amortization of net loss		—			—			—			21
Employee transfers		(263	)		(198	)		—			(140	)
Acquisition loss recognition		—			—			—			8,657
Settlement recognition		53			64			—			—
Regulatory recovery (accrual) of costs		3,571			3,976			1,174			(7,144	)
Net periodic pension expense	$	5,257		$	6,005		$	2,102		$	2,708

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, 2007	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
Discount rate	6.17%	5.69%	5.25%	5.00%
Rate of compensation increase	4.35%	3.75%	3.40%	3.35%

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, 2007 *	For the Period January 1 through    April 30,    2007	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
Discount rate	5.75%	5.69%	6.00%	5.25%	5.00%	5.75%
Expected return on plan assets	8.50%	8.50%	8.50%	8.50%	8.50%	8.50%
Rate of compensation increase	3.85%	3.75%	4.10%	3.40%	3.35%	3.65%

____________________

*

Changes in 2007 and 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 rebalancing. 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, 2007		December 31, 2006
Equity securities		65%		61%
Fixed income securities		30%		26%
Cash equivalents		5%		13%
Total		100%		100%

The investment objectives of the Union 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 is 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.

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 the plan’s 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 between $4.8 million and $6.5 million to its Union Plan in 2008.

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):

2008	$      2,112
2009	$      3,054
2010	$      3,512
2011	$      3,451
2012	$      4,243
Years 2013 through 2017	$    22,400

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, 2007 and 2006 (expressed in thousands):

	2007			2006
Change in benefit obligation:
Benefit obligation at beginning of year	$	10,439		$	7,736
Service cost		2,453			2,355
Interest cost		652			454
Actuarial (gain)/loss		373			(114	)
Benefits paid		(335	)		(312	)
Transfers from union plan		448			320
Benefit obligation at end of year		14,030			10,439
Change in plan assets:
Fair value of plan assets at beginning of year		7,007			4,693
Actual return on plan assets		403			469
Employer contributions		2,243			2,038
Benefits paid		(335	)		(312	)
Transfers from union plan		180			119
Fair value of plan assets at end of year		9,498			7,007
Funded status/Accrued benefit cost	$	(4,532	)	$	(3,432	)

Pursuant to SFAS 158, the accrued benefit cost includes $0.2 million of previously unrecognized net losses in 2007 and $0.4 million of previously unrecognized net gains in 2006. The FERC allows Central to recognize allowances for these prudently incurred costs through recovery in its rates. As such, the related 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 $10.7 million and $8.1 million at December 31, 2007 and 2006, 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, 2007			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
Components of net periodic pension expense:
Service cost	$	2,453		$	2,355		$	972		$	1,278
Interest cost		652			454			153			177
Expected return on plan assets		(665	)		(451	)		(139	)		(195	)
Amortization of net loss		—			—			—			35
Employee transfers		263			198			—			140
Acquisition loss recognition		—			—			—			1,586
Regulatory accrual of costs		(460	)		(1,061	)		(215	)		(1,857	)
Net periodic pension expense	$	2,243		$	1,495		$	771		$	1,164

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

	Post-acquisition						Pre-acquisition
	For the Year Ended December 31, 2007		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
Discount Rate		6.38%		5.83%		5.50%		5.25%
Rate of compensation increase		4.35%		3.75%		3.50%		3.40%

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

	Post-acquisition						Pre-acquisition
	For the Year Ended December 31, 2007		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
Discount Rate		5.83%		5.50%		5.25%		5.75%
Expected return on plan assets		8.50%		8.50%		8.50%		8.50%
Rate of compensation increase		3.75%		3.50%		3.40%		3.65%

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 rebalancing. 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, 2007		December 31, 2006
Equity securities		63%		65%
Fixed income securities		29%		30%
Cash equivalents		8%		5%
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 is 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.

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

F-4

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 the plan’s 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.

The Company expects to contribute an estimated $2.8 million to its Non-Union Plan in 2008.

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):

2008	$         671
2009	$         913
2010	$      1,144
2011	$      1,355
2012	$      1,912
Years 2013 through 2017	$    14,182

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, 2007 and 2006 (expressed in thousands):

	2007			2006
Change in benefit obligation:
Benefit obligation at beginning of year	$	33,395		$	34,166
Service cost		417			467
Interest cost		1,981			1,796
Actuarial (gain)/loss		340			(1,440	)
Medicare Part D subsidy recognition		105			—
Benefits paid		(2,129	)		(1,594	)
Benefit obligation at end of year		34,109			33,395
Change in plan assets:
Fair value of plan assets at beginning of year		34,123			32,007
Actual return on plan assets		2,915			3,710
Benefits paid		(2,129	)		(1,594	)
Fair value of plan assets at end of year		34,909			34,123
Funded status/Net prepaid benefit costs	$	800		$	728

Pursuant to SFAS 158, the net prepaid benefit costs in 2007 and 2006 include $3.3 million and $3.5 million, respectively, of previously unrecognized net gains. The FERC allows Central to recover these prudently incurred costs through recovery in its rate settlement. As such, the related assets and liabilities recognized, were offset with a corresponding regulatory asset or regulatory liability. The net prepaid benefit costs reported above are net of the asset and liability reflected as 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, 2007			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
Components of net periodic benefit expense:
Service cost	$	417		$	467		$	241		$	323
Interest cost		1,981			1,796			744			1,100
Expected return on plan assets		(2,808	)		(2,637	)		(769	)		(1,050	)
Recognized actuarial gain		—			(3	)		—			(338	)
Acquisition gain recognition		—			—			—			(7,483	)
Regulatory recovery (accrual) of costs		410			377			(186	)		8,173
Net periodic benefit expense	$	—		$	—		$	30		$	725

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 $0.04 million of amortization of net gains is expected to be reflected in expense in 2008.

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

	Post-acquisition				Pre-acquisition
	For the Year Ended December 31, 2007		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
Discount rate		6.39%	5.84%	5.50%		5.25%
Healthcare cost trend rate assumed for next year		9.75%	11.00%	12.00%		12.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		5.15%	4.85%	4.65%		4.65%
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 for the periods indicated:

	Post-acquisition			Pre-acquisition
	For the Year Ended December 31, 2007	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
Discount rate	5.84%	5.50%	5.25%		5.75%
Expected return on plan assets (non-union/union)	6.67%/8.50%	6.67%/8.50%	3.90%/6.00%		3.90%/6.00%

Assumed health care cost trend rates for the periods indicated:

	December 31, 2007		December 31, 2006		December 31, 2005
Healthcare cost trend rate assumed for next year		11.00%		11.00%		12.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		4.85%		4.65%		4.65%
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	$	334	$	(276)
Effect on accumulated postretirement benefit obligation	$	4,411	$	(3,666)

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 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 rebalancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.

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

	December 31, 2007		December 31, 2006
Equity securities		66%		68%
Fixed income Securities		30%		29%
Cash and cash equivalents		4%		3%
Total		100%		100%

The investment objectives of the Welfare Plan are as follows:

(1)  To fully fund the Accumulated Postretirement 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 is 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.

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 the plan’s 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 does not expect to make any contributions to its Welfare Plan in 2008.

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

	Non-Union	Union	Total
2008	$            228	$        1,522	$        1,750
2009	318	1,679	1,997
2010	400	1,764	2,164
2011	484	1,860	2,344
2012	574	1,898	2,472
Years 2013 through 2017	4,740	10,588	15, 328

The Company receives Medicare Part D payments, which effectively reduce the Company’s cost of estimated benefit payments listed above.

 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
2008	$                 3	$          192	$          195
2009	5	212	216
2010	8	237	245
2011	14	261	275
2012	23	286	309
Years 2013 through 2017	256	1,753	2,009

 Other

Central maintains a defined contribution plan covering substantially all employees. Central’s costs related to this plan for the years ended December 31, 2007, 2006, and 2005 were $1.8 million each year.

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, 2007 and 2006.

Long-Term Debt: The estimated fair value of the Company’s debt is based on quoted market prices at December 31, 2007 and 2006.

The carrying amount and estimated fair values of the Company’s financial instruments as of December 31, 2007 and 2006 are as follows (expressed in thousands):

	Carrying Amount				Fair Value
	2007		2006		2007			2006
Financial Assets:
Cash and cash equivalents	$	20,025	$	37,989	$	20,025	$	37,989
Financial Liabilities:
Long-term debt		428,867		431,811		414,423		431,099

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 position 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 $58.3 million, $56.9 million, $22.2 million, and $34.4 million for the years ended December 31, 2007 and 2006, the period August 12 through December 31, 2005, and the period January 1 through August 11, 2005, respectively. Revenues received from KGS were $50.5 million, $50.7 million, $19.9 million and $30.8 million for the years ended December 31, 2007 and 2006, the period August 11 through December 31, 2005, and the period January 1 through August 12, 2005, respectively.

MGE had receivable balances of $4.7 million for each of the years ended December 31, 2007 and 2006. KGS had receivable balances of $4.6 million and $4.7 million for the years ended December 31, 2007 and 2006, respectively.

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):

2008	$	182
2009		167
2010		96
2011		26
2012		11
After 2012		39
Total	$	521

Total rental expense relating to operating leases was approximately $1.0 million, $1.1 million, $0.4 million, and $0.9 million for the years ended December 31, 2007 and 2006, the period August 12 through December 31, 2005, and the period January 1 through August 11, 2005, 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. For each of the years ended 2007 and 2006, Central paid approximately $1.0 million 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 recognized $1.9 million in expenses for each of the years ended 2007 and 2006 for such annual payments.

16. Quarterly Data (Unaudited)

The following summarizes selected quarterly financial data for 2007 and 2006 (expressed in thousands):

	2007
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Operating revenues	$	47,018		$	45,884		$	46,398		$	48,781
Operating costs and expenses		28,095			29,488			31,632			33,475
Operating income		18,923			16,396			14,766			15,306
Interest expense		7,177			7,249			7,274			7,142
Interest income		(399	)		(417	)		(347	)		(278	)
Miscellaneous other (income) expenses, net		(160	)		(49	)		(101	)		(206	)
Total other expense, net		6,618			6,783			6,826			6,658
Income before income taxes		12,305			9,613			7,940			8,648
Provision for income taxes		4,867			3,813			3,158			3,461
Net Income	$	7,438		$	5,800		$	4,782		$	5,187

	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 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.

F-5

Exhibit 12.1

Ratio of Earnings to Fixed Charges

(In thousands)

	Post-acquisition									Pre-acquisition
	Year Ended December 31, 2007			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
Fixed Charges:
Interest expense	$	28,842		$	29,964		$	11,337		$	25,169		$	40,856		$	42,396
Capitalized interest		309			222			50			31			511			209
Fixed Charges	$	29,151		$	30,186		$	11,387		$	25,200		$	41,367		$	42,605
Earnings:
Add:
Income before income taxes	$	38,506		$	43,929		$	16,150		$	12,477		$	8,580		$	4,639
Fixed charges (calculated above)		29,151			30,186			11,387			25,200			41,367			42,605
Deduct:
Capitalized interest		(309	)		(222	)		(50	)		(31	)		(511	)		(209	)
Earnings	$	67,348		$	73,893		$	27,487		$	37,646		$	49,436		$	47,035
Ratio of Earnings to Fixed Charges1		2.31			2.45			2.41			1.49			1.20			1.10

 (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.

Exhibit 31.1

CERTIFICATION PURSUANT TO RULES 13a – 14(a) AND 15d – 14 (a)

UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) 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)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 (c)

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

(d)

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 19, 2008
	Jerry L. Morris

Exhibit 31.2

CERTIFICATION PURSUANT TO RULES 13a – 14(a) AND 15d – 14 (a)

UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) 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)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 (c)

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

(d)

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 19, 2008
	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, 2007 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 our knowledge, that:

(1)

The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and 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 Sarbanes-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 19, 2008
	Jerry L. Morris
By:	/s/ Susanne W. Harris	Chief Financial Officer	March 19, 2008
	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.