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, 2009

or

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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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  ¨    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

¨

(Do not check if a 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

Aggregate market value of registrant’s voting and non-voting common equity held by non-affiliates of the registrant – Not applicable as registrant’s stock is not publicly traded.

As of March 15, 2010, there were 100 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE - None

1

TABLE OF CONTENTS

2009 FORM 10-K

SOUTHERN STAR CENTRAL CORP.

		Page
Forward-Looking Statements		1
	PART I.
Item 1.	Business	2
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	17
Item 2.	Properties	17
Item 3.	Legal Proceedings	18
Item 4.	Reserved	19
	PART II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity  Securities	19
Item 6.	Selected Financial Data	20
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	21
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8.	Financial Statements and Supplementary Data	30
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	30
Item 9A.	Controls and Procedures	30
Item 9B.	Other Information	31
	PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	31
Item 11.	Executive Compensation	34
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	40
Item 13.	Certain Relationships and Related Transactions, and Director Independence	41
Item 14.	Principal Accountant Fees and Services	41
	PART IV.
Item 15.	Exhibits and Financial Statement Schedules	42

1

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 c onnection with such statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

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

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

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

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

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our ability to manage costs;

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the ability of our customers to pay for services;

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

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

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

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the cost and effects of legal and administrative proceedings;

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the effect of accounting interpretations and changes in accounting policies;

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

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changes in general economic, market or business conditions; and

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

Other factors and assumptions not identified above, including without limitation, those described under Item 1A. “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.

In 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 our outstanding capital stock.  Their ownership interests in Southern Star remained unchanged as of December 31, 2009. On February 10, 2010, CDP entered into an agreement to sell its 40 percent ownership interest in Holdings to Morgan Stanley Infrastructure Partners and certain other affiliated investment funds managed by Morgan Stanley Infrastructure, Inc., or MSIP. The sale became effective on March 9, 2010.

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, 2009, 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 23 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, 2009, 92% of Central’s operating revenues were obtained through monthly firm reservation charges (“rent” charges under firm contracts) and 8% were obtained through commodity charges (“usage” charges based on volumes actually transported under firm and interruptible c ontracts).

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, 2009, Central had customer transportation contracts with approximately 182 shippers. Shippers include regulated natural gas distribution companies, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Central transports natural gas to approximately 567 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 19 years. At December 31, 2009, the average remaining contract life on a volume- weighted basis was approximately five years.

For the year ended December 31, 2009, approximately 85% of our total operating revenues were generated from long-term contracts with our top ten customers. Natural gas transportation services for the two largest customers, Missouri Gas Energy, or MGE, a division of Southern Union Company (approximately 30%), and Kansas Gas Service Company, or KGS, a division of ONEOK, Inc. (approximately 26%), accounted for approximately 56% of operating revenues for the year ended December 31, 2009. 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 custo mer accounted for more than 10% of our revenues in 2009.

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 directly from the major production areas located in the Rocky Mountain, Anadarko, and Hugoton basins. The Hugoton region is a mature basin with declining production; however, we believe new supplies from other regions including the Rocky Mountain and Western Oklahoma areas will more than offset the projected declines. 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 23 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 23 interconnects, eight are delivery points; nine are receipt points; and six are bi-directional (both receipt and delivery) points. The large number and geographic diversity of interconnects provides 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. Thirty 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:
	2009	2008	2007
Market area	0.6	0.6	0.6
Production area	0.3	0.3	0.3
Production market interface	0.4	0.5	0.4

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

	TBtu per day
Reserved Capacity:
	2009	2008	2007
Market area	2.0	1.9	1.9
Production area	0.4	0.4	0.4
Production market interface	0.9	0.9	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 half 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 withdraw 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 transportation and firm storage service to satisfy up to two-thirds of their natural gas supply needs. No-notice service accounted for approximately 63% of our 2009 operating revenues, and as of December 31, 2009, accounted for approximately 71% of Central’s firm market area capacity, 46% 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 deliver y point principally under contracts with local natural gas distribution companies, power generators, industrials, marketers and producers. This service accounted for approximately 30% of our 2009 operating revenues, and as of December 31, 2009, comprised approximately 29% of Central’s firm market area capacity and 54% 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 TBtu of on-system natural gas storage capacity. Central’s storage service allows shippers to store natural gas close to their customers. Central’s storage facilities are strategically located in close proximity to its key market areas. The majority of the firm storage capaci ty is contracted as a component of the transportation/storage service (approximately 88% of the firm storage deliverability). The stand alone firm storage service (approximately 12% of firm storage deliverability) and interruptible storage service accounted for approximately 2% of our operating revenues for the year ended December 31, 2009.  

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 5% of our operating revenues for the year ended December 31, 2009.

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 opportunities 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 has recently pursued or is currently pursuing:

Northern Natural Gas Project – In March 2009, we initiated a binding open season for an expansion project to deliver up to 64,750 Dekatherms per day, or Dths/day to a proposed delivery facility with Northern Natural Gas located in Kiowa County, Kansas.  Northern Natural Gas held an open season concurrently with Central to allow customers access to firm capacity on both pipeline systems.  The open season period was from March 9, 2009 until March 27, 2009.   After much discussion with potential bidders, no bids were received in the open season due to changing gas price dynamics on the two pipelines.  The project has ongoing interest and we intend to re-evaluate it in the future.

Ozark Advance Expansion Project – In April 2009, we initiated a binding open season for the Ozark Advance Expansion Project.  The expansion involved expanding the capacity of part of Central’s system in Southeast Kansas and Southwest Missouri.  The target deliveries would be east of Joplin, Missouri to a terminus near Springfield, Missouri. The open season period was from April 13, 2009 until May 8, 2009.  Two binding bids were received for incremental contract demand of 9,000 Dths/day.  In conjunction with the open season, an existing customer agreed to realign its contracts which provided transportation capacity while reducing the incremental facilities required for the transportation service to the expansion customers.  This project will add incremental firm transportation capacity to our system to serve the growing region of Southwestern Missouri, including new n atural gas service to Branson, Buffalo and Bolivar.  Central is planning to install 0.7 miles of 20-inch loop and will also install a new delivery meter station.  Customers will enter into Firm Market Area Transportation Service agreements with us at contract demand levels of 5,000 Dths/day to be effective November 1, 2010, and 4,000 Dths/day to be effective August 1, 2011.  The estimated cost of the expansion facilities is approximately $2.0 million.

Sedalia Pipeline Expansion Project – In July 2009, we initiated a binding open season for the Sedalia Pipeline Expansion Project.  The expansion involved expanding the capacity on Central’s Sedalia system to serve the Central Western Missouri region.  The target deliveries would be along the Sedalia Line in Missouri. The open season period was from July 22, 2009 until August 4, 2009.   Two binding bids were received for incremental contract demand of 37,400 Dths/day.  This project added incremental firm transportation capacity on our system to serve this growing region of Missouri, including new natural gas service to Green Ridge, Cole Camp, Lincoln, Warsaw, and the surrounding areas in west central Missouri.  Central installed a new delivery meter station to facilitate this service at a cost of $0.4 million.  Customers entered into Firm Market Area Transportation Service agreemen ts with us at contract demand levels of 37,400 Dths/day, which became effective November 1, 2009.  

Storage Expansion Project – In 2009, we initiated two binding open seasons for the “Storage Expansion” Project.  The first open season began on January 12, 2009 and concluded on February 20, 2009.  The first open season proposed to increase Central’s existing storage capacity by a minimum of 5,000,000 Dths and increase delivery up to 50,000 Dths/day to the Mid-Continent region. After much discussion with potential bidders, we received six bids for a total of 6,936,203 Dths of capacity, but only one conforming and acceptable bid was received for 300,000 Dths.  The binding bids were reviewed and, based upon economic analysis, we determined that it was not economical to pursue the project as defined in the first binding open season and the bids were rejected.

Based on the results of the first open season and shipper feedback, we conducted a second binding open season for a modified Storage Expansion Project via two notices and bidding periods, May 12, 2009 to June 2, 2009 and June 29, 2009 to July 14, 2009.  This second open season was for a slightly smaller storage expansion project that would provide a minimum of 4,000,000 Dths of additional storage capacity and increase delivery by up to 40,000 Dths/day.  We received three conforming bids and awarded the 4,000,000 Dths of capacity to those bidders. Customers will enter into Firm Storage Service agreements with us at contract demand levels of 4,000,000 Dths/day to be effective April 1, 2011.  The estimated cost of the expansion facilities is approximately $23.2 million and it is expected to provide approximately $4.7 million in annual revenues.

Central plans to construct a compressor station adjacent to its existing Elk City Storage Field dehydration plant near Independence, Kansas.  We filed the FERC 7(c) application (Docket No. CP10-2) on October 9, 2009, acquired the compressor station site, initiated the process of obtaining environmental permits, ordered a turbine compressor, and secured air permits for the compressor. The Environmental Assessment was initiated by the FERC on November 16, 2009.  Bids for construction are anticipated to be issued in May 2010, with construction beginning in mid-July, pending FERC approval.

Gas Supply Projects and Initiatives

Central actively pursues new gas supply connections to our system to provide customers additional supply options and flexibility to meet their demands.  Our focus is targeted to direct connected supply opportunities, which provides the lowest cost alternative to our customers.  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:

Noble Energy – Central has installed a new receipt point in the Cheyenne County, Kansas area capable of receiving up to 60,000 Dths/day. The project facilities were placed in service during the first quarter of 2009, and the costs of the interconnect point are reimbursable to Central.

Frontier Field Services – Central has installed a new receipt point in the Hemphill County, Texas area capable of receiving up to 20,000 Dths/day. The project facilities were placed in service during the first quarter of 2009, and the costs of the interconnect point are reimbursable to Central.

Mustang Gas Products – Central has installed a new receipt point in the Garfield County, Oklahoma area capable of receiving up to 10,000 Dths/day. The project facilities were placed in service during the fourth quarter of 2009, and the costs of the interconnect point are reimbursable to Central.

IACX Energy – Central has installed a new receipt point in the Kay County, Oklahoma area capable of receiving up to 1,000 Dths/day. The project facilities were placed in service during the fourth quarter of 2009, and the costs of the interconnect point are reimbursable to Central.

Petro-Canada (Noble Energy) – Central is installing a new receipt point in the Weld County, Colorado area capable of receiving up to 12,000 Dths/day. The project facilities will be placed in service during the second quarter of 2010, and the costs of the interconnect point are reimbursable to Central.

Various Other Projects and Initiatives – In addition, we are in the preliminary stages of evaluating four new supply/receipt projects that would add approximately 60,000 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, fuel costs, 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 affiliate 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, and access to gas supply and reliability. Depending on the costs of alternative energy, 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 pipeli ne’s rules, and operating and commercial practices which are binding on the pipeline and its customers—is a regulatory document and cannot be modified without public notice and FERC approval.

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

Generally, rates charged by interstate natural gas companies may not exceed the just and reasonable rates approved by the FERC. In addition, interstate natural gas companies are prohibited from granting any undue preference to any person, or maintaining any unreasonable difference in their rates or terms and conditions of service. FERC regulations also generally prohibit Central from preventing shippers from freely assigning their capacity to other parties, provided that the assignee meets the credit 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 books and records requirements, and regulations regarding exemption. Neither the Company, nor Central, is a "public-utility company" or "holding company" under PUHCA 2005. Each of the Company's ultimate parents, GE and MSIP, is a holding company under PUHCA, but currently holds an exemption from PUHCA's accounting, cost allocation, and related regulations.

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 an d 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, 2008, Central filed a general rate case under FERC Docket No. RP08-350 which became effective November 1, 2008, subject to the condition that Central refund to customers any amounts it collects in excess of the rates ultimately allowed. This general rate proceeding increased Central’s transportation, storage and related rates, and also provided for various changes to a number of the terms and conditions of customer services which are provided for in Central’s tariff. On November 17, 2008, the parties reached a settlement to resolve all issues related to this proceeding. The settlement provided for Central to bill the settlement rates on an interim basis beginning November 1, 2008. The settlement was filed with the FERC on December 11, 2008, and all comments filed by various parties were in support of the settlement. On January 13, 2009, the Administrative Law Judge certified th e settlement to the FERC and on June 1, 2009, the FERC issued an Order approving the settlement without modification. The settlement rates were designed to increase Central’s annual revenues approximately $20.0 million above revenues for the 12 months ended January 31, 2008, the base period covered in its filing. Under the terms of the settlement, Central is required to file a new rate case to become effective no later than December 1, 2013.

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 12 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. O n December 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 the technical conference, Central settled all issues with all parties by agreeing to absorb a portion of the losses related to the girth weld failure and the storage lateral line failure. The settlement and insurance proceeds collected on the amount of losses absorbed by Central, resulted in no material adverse impact on its financial position or results of operations.

On November 26, 2008, Central made its annual fuel filing to establish its transmission and storage fuel and loss reimbursement percentages for 2009 based on the actual fuel and loss for the 12 months ended September 30, 2008. One party protested the inclusion of gas losses related to a storage lateral line failure. On December 30, 2008, the FERC issued an Order disallowing the recovery of the losses related to the storage lateral line failure in its annual fuel filing. Central has complied with the Order and in December 2008 charged to expense approximately $0.2 million related to the disallowance.

On October 22, 2008, the FERC issued an “Order Approving Audit Report and Directing Compliance and Other Corrective Actions,” or the Audit Order, in Docket No. PA08-1-000, as a result of a Compliance Audit conducted by the Division of Audits, or DA, within the Office of Enforcement of the FERC, pursuant to Section 8 of the NGA. This audit examined Central’s compliance with certain FERC accounting, reporting and transportation regulations, North American Energy Standards Board standards and provisions of Central’s FERC gas tariff.

The Audit Order found instances where Central did not comply with certain filing and electronic posting requirements of the FERC. The FERC imposed no penalty on Central, and instead imposed remedial requirements only. The Audit Order noted that the findings “implicated substantive non-compliance by [Central]” and that the FERC “seriously considered pursuing the imposition of penalties for the violations.” However, the FERC took into consideration Central’s “willingness to take corrective action” and its “exemplary cooperation during the audit” and the fact that a predecessor owner of Central was “responsible for most of the serious violations.” The FERC specified corrective actions to be taken by Central and issued the Audit Order publicly “to provide guidance to other companies similarly situated.” The Audit Order contains a list of remedies to address the DA’s findings, some of which Central has either already completed or is in the process of completing. The Audit Order also contained a number of recommendations for ensuring compliance, including the implementation of a comprehensive compliance program, consistent with recent FERC policy statements.

The Audit Order required Central to file a “compliance plan” outlining the steps it will take to implement the corrective actions recommended by November 20, 2008, which was filed on that date with quarterly reports to follow. The Audit Order also required certain information with respect to “non-conforming” shipper agreements to be filed within 120 days of the date of the Audit Order and directed Central to file within 150 days of the Audit Order all unfiled agreements that contain non-conforming terms and conditions. Central has made all of the required filings and continues to file quarterly reports on the status of its compliance plan. As there were no monetary penalties levied and although there will be costs and time spent by Central on implementing the Audit Order’s recommended corrective actions, we do not expect that this action by the FERC will have any material adverse effect on our future financial position, results of operations, or cash flows.

Recent FERC Regulatory Orders. On October 16, 2008, the FERC issued Order No. 717, or the Order, the final rule on “Standards of Conduct for Transmission Providers.” Because the new regulations adopted in the Order limit applicability to those interstate transmission providers who have “marketing affiliates shipping gas on their system,” Central is currently not subject to the rule, as no “marketing affiliate,” as defined in the Order, currently ships gas on Central’s system. However, Central will have to continue to monitor this situation in case there is a change in business circumstances that would cause Central to be subject to the Order’s requirements.  

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 in 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:

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Field	Docket #	Provisional Operating Permit Extension Date	Fully Authorized Operating Permit Receipt
Elk City	S-013	N/A	2/29/2008
Colony	S-014	12/31/2010	—
Piqua	S-016	6/30/2011	—
North Welda	S-019	12/31/2010	—
Alden	S-018	12/31/2010	—
McLouth	S-015	5/31/2011	—
South Welda	S-020	4/30/2012	—

Central submitted applications for Fully Authorized Permits for all of the seven Kansas storage facilities in 2006 and 2007. On February 29, 2008, Central received a Fully Authorized Permit for the Elk City Storage Field. Central continues to receive extensions to the Provisional Operating Permits for the other six storage facilities, pending issuance of Fully Authorized Permits by the KCC and expects an extension to be granted to the Provisional Operating Permit for these storage fields beyond their current expiration dates as necessary.

Central identified storage reservoir parameters at six of its Kansas storage fields that required updates to its existing FERC certificates. The FERC approved the Colony Gas Storage Field application on May 19, 2006, the Piqua Gas Storage Field application on March 26, 2007, the North Welda Storage Field application on July 16, 2008 and the South Welda Storage Field application on May 9, 2008 and amended on August 5, 2008. The information and data for the remaining FERC filings is being compiled. Central anticipates filing the two remaining FERC certificate applications in 2010.

In addition, Central identified storage reservoir parameters at its Oklahoma storage field that require its existing FERC certificate to be updated.  Central also anticipates filing this FERC certificate application in 2010.

The Kansas Underground Porosity Gas Storage Regulations have increased operational costs of Central’s storage fields.  We anticipate these costs will continue, 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 s afety 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 the National Emission Standards for Hazardous Pollutants, or NESHAPs, for reciprocating internal combustion engines, stationary turbines, and glycol dehydration equipment in addition to regulation s that address regional transport of ozone. Based on analysis of these regulations, management does not expect there to be a material impact to Central’s existing operations. On March 5, 2009, the EPA proposed new emission standards that could apply to certain of Central’s existing reciprocating engines. These regulations are scheduled to be finalized during 2010, and any compliance obligations would likely have to be completed during 2013.

Central has identified polychlorinated biphenyl contamination, or PCB, 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 of approximately $2.2 million at December 31, 2009 and $2.3 million at December 31, 2008 representing the current estimate of future environmental cleanup costs, most of which are expected to be incurred over the next two to three years.  Central currently plans to spend an estimated $0.7 million annually to remediate the PCB and/or mercury contamination. Central recovers approximately the same am ount 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.

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.

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, 2009, we had 480 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 170 field employees. This agreement was renegotiated during 2008 for a four-year term to expire July 15, 2012. 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 100 F Street, NE, 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.

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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

Current or future distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide.

          Some of our customers are experiencing, or may experience in the future, financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our services, which could have a material adverse effect on our results of oper ations and financial condition.

Current levels of market volatility are unprecedented.

          The capital and credit markets have been experiencing extreme volatility and disruption for more than 12 months. In some cases, the markets have exerted downward pressure on stock prices and credit capacity for certain issuers. Our plans for growth require periodic access to the capital and credit markets. If current levels of market disruption and volatility continue or worsen, access to capital and credit markets could be disrupted making growth through acquisitions and development projects difficult or impractical to pursue until such time as markets stabilize.

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 increased 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 business, financial position or results of operations, particularly if those costs are not fully recoverable from customers. Included in these regulations are the various initiatives concerning greenhouse gas currently under consideration at the Federal and State level. Environmental regulations may also require us to install pollution control equipment at, or perform environmental remediation on, our facilities.

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The EPA has promulgated the National Ambient Air Quality Standards, or 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 predic t with certainty whether any areas where our compressor stations are located could become nonattainment areas in the future.

As of December 31, 2009, we were aware of PCB and/or mercury contamination that requires remediation at three of our compressor sites and approximately 300 of our meter sites. 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. In general, the known contamination is limited to soils within the property boundaries of the sites. We have an accrued liability of $2.2 million as of December 31, 2009, representing the estimate of future cleanup costs, most of which is expected to be incurred over the next two to three 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 through our rates.

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.

Climate change regulation at the federal, state, provincial, or regional levels could result in increased operating and capital costs for us.

Studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere.  Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases.  On September 22, 2009, the EPA promulgated a mandatory greenhouse gas reporting rule that will impose requirements for some of Central’s existing operations.  While we do not expect that these requirements will have a material impact on Central’s existing operations during 2010, there are also other various proposed rules and possible federal legislation related to greenhouse gas emissions that could impact Central’s existing operations.  Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or t he adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions or greenhouse gases, in areas in which we conduct business could result in changes to the consumption and demand for natural gas and carbon dioxide produced from our source fields and could have adverse effects on our business, financial position, results of operations and prospects.

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 2008, we filed a general rate case and filed an unopposed settlement of the rate case with the FERC. 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 2013. 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, gas losses due to such failures, 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. Liabil ities incurred, and interruptions to the operation of our pipeline 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, 2009, approximately 97% of our firm contracted market area capacity, 95% 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 re ductions in pressure or volume, 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 budg ets, in order to conduct remedial 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 2010 will be approximately $11.8 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, the 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 altern ative 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. We have the majority of market share in these areas.  One of the interstate pipelines with which we compete is an affiliate of one of our largest customers, MGE.

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, and access to gas supply and reliability. Depending on the costs of alternative energy, 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 and the loss of a large customer could have a material adverse effect on our operating results.

Operating revenues related to transportation and storage contracts with our ten largest customers accounted for approximately 85% of operating revenue during the year ended December 31, 2009. Approximately 56% of our operating revenues during the year ended December 31, 2009 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 contracts by volume for each of these two customers extend 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.  However, we have not incurred any credit downgrades in the past.

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, de pending on their ultimate magnitude, 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 perpet ual easements granted by private 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 $0.3 million.

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

Item 3. Legal Proceedings  

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. The Department of Justice declined to intervene in Grynberg’s qui tam cases, which were consolidated for pretrial purposes before a single judge in the United States District Court, or Trial Court, for the District of Wyoming. Initial discovery was limited to public disclosure/original source jurisdictional issues. On June 4, 2004, motions, with supporti ng 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 co unsel filed notices of appeal with the United States Court of Appeals for the Tenth Circuit, or Appellate Court, where his appeals were docketed as In re Natural Gas Royalties Qui tam Litigation, Case No. 06-8099. Oral argument occurred on September 25, 2008. On March 17, 2009, the Appellate Court affirmed the Trial Court’s dismissal of Grynberg’s complaints on jurisdictional grounds related to the “original source” defense asserted by Central. On March 20, 2009, Grynberg filed a motion for an extension of time to file a petition for rehearing of the Appellate Court’s decision. The Court granted Grynberg’s motion and he subsequently filed his petition for rehearing on April 14, 2009. On May 4, 2009, the Appellate Court denied Grynberg’s petition for rehearing. On August 4, 2009, Grynberg filed a petition (Number 09-170) for certiorari review with the United States Supreme Court. On October 5, 2009, the Supreme Court denied Grynberg’s petition. The parties contin ue to await the Trial Court’s ruling on the defendants’ motion(s) for attorney’s 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 under measured 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 continued to seek the certification of a class. The Plaintiffs’ motion seeking class certification for a second time was fully briefed and the Court heard oral argument on the motion on April 1, 2005.  On September 18, 2009, the Court denied the Plaintiffs’ most recent motion for class certification. The Plaintiffs filed a motion to reconsider that ruling on October 2, 2009. The defendants, including Central, filed a response in opposition to the Plaintiffs’ motion for reconsideration on January 18, 2010.  The Plaintiffs filed a reply, and oral argument, which was presented before a different judge, was heard on February 10, 2010. It is unknown when the Court will rule on the pending motion, or whether the Plaintiffs will petition for an appeal if their motion for reconsideration is denied.   

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 under measured 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 Plaintiffs’ second class certification motion in Price Litigation I, was fully briefed and the Court heard oral argument on this motion on April&n bsp;1, 2005. On September 18, 2009, the Court denied the Plaintiffs’ motion for class certification. The Plaintiffs filed a motion to reconsider that ruling on October 2, 2009. The defendants, including Central, filed a response in opposition to the Plaintiffs’ motion for reconsideration on January 18, 2010.  The Plaintiffs filed a reply, and oral argument, which was presented before a different judge, was heard on February 10, 2010.  It is unknown when the Court will rule on the pending motion, or whether the Plaintiffs will petition for an appeal if their motion for reconsideration is denied.   

Item 4.  - Reserved

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, 2009, 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% Registered Notes, and $50.0 million aggregate principal amount of 6.75% Senior Notes due 2016, or 6.75% Unregistered Notes. Under the indentures for our 6.75% Registered Notes and 6.75% Unregistered 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 2009 and 2008 were approximately $30.6 million and $22.0 million, respectively. We expect to continue to pay dividends as permitted under the indenture on a quarterly basis.

4

Item 6. Selected Financial Data

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 Financial Data

(In thousands)

	Post-acquisition															Pre-acquisition *
	For the Year Ended December 31, 2009			For the Year Ended December 31, 2008			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
																			< /TD>
Statement of Operations Data:
Operating Revenues	$	220,801		$	196,788		$	188,081		$	187,246		$	70,769			$	111,168
Operating Costs and Expenses:
Operations and maintenance		50,135			49,064			45,085			41,030			14,702				23,568
Administrative and general		42,954			39,005			35,562			34,939			13,809				25,688
Depreciation and amortization		32,238			29,293			27,470			26,881			10,884				17,299
Taxes, other than income taxes		15,293			14,654			14,573			13,349			4,745				7,573
Total Operating Costs and
Expenses		140,620			132,016			122,690			116,199			44,140				74,128
Operating Income		80,181			64,772			65,391			71,047			26,629				37,040
Interest Expense (Income):
Interest expense		32,556			31,210			28,842			29,964			11,337				25,169
Interest income		(308	)		(877	)		(1,441	)		(2,401	)		(737	)			(719	)
Miscellaneous other (income)
expense, net		(49	)		(658	)		(516	)		(445	)		(121	)			113
Income Before Income Taxes		47,982			35,097			38,506			43,929			16,150				12,477
Provision for Income Taxes		19,010			13,838			15,299			17,558			6,399				7,074
Net Income	$	28,972		$	21,259		$	23,207		$	26,371		$	9,751			$	5,403
Balance Sheet Data (end of period):
Cash and Cash Equivalents	$	38,789		$	35,615		$	20,025		$	37,989		$	62,287			$	44,525
Property, Plant & Equipment, net		607,794			601,275			563,799			544,270			527,707				524,029
All Other Assets		438,671			424,541			473,521			442,065			426,309				154,588
Total Assets	$	1,085,254		$	1,061,431		$	1,057,345		$	1,024,324		$	1,016,303			$	723,142
Capitalization:
Current maturities of long-term
debt	$	745		$	720		$	690		$	765		$	225,647			$	50,735
Total long-term debt, net of
current portion		481,054			481,165			435,312			438,946			202,344				362,777
Mandatorily redeemable preferred stock		—			—			—			—			—				52,760
Common stockholder’s equity		429,730			431,341			432,082			434,695			464,514				122,923
Total Capitalization	$	911,529		$	913,226		$	868,084		$	874,406		$	892,505			$	589,195

(*)

Periods prior to August 12, 2005 reflect the financial condition and results of operations of the Company prior to its 2005 acquisition by Holdings, which are not comparable to the post-acquisition periods presented for the Company.

5

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 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.

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

Central is an interstate natural gas pipeline engaged in the transportation and storage of natural gas. As such, Central’s rates, facilities and services are regulated by the FERC. Central’s services are provided under both short-term and long-term contracts, subject to a FERC-accepted tariff which governs substantially all terms and conditions of service. The substantial majority of Central’s business is conducted under long-term contracts ranging from one to 19 years. Total average remaining contract life on a volume-weighted basis at December 31, 2009 was approximately five years.

On April 30, 2008, Central filed a general rate case under FERC Docket No. RP08-350 which became effective November 1, 2008. The case became final in 2009. 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 December 1, 2013.

Changes in environmental laws and regulations may also increase our operating costs and/or capital expenditures as required for monitoring or installation of new equipment. Central expects operating and capital costs associated with such regulations to be recovered in the rates it charges for its services.

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. 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.

In January 2009, we initiated a binding open season for a “Storage Expansion Project” to increase Central’s existing storage capacity by a minimum of 5,000,000 Dths and increase delivery up to 50,000 Dths/day. The expansion was restricted to our market area. The open season began on January 12, 2009 and concluded on February 20, 2009. The binding bids were reviewed and, based upon economic analysis, we determined that it was not economical to pursue this project as defined in that binding open season and the bids were rejected.

Based on the results of the first open season and shipper feedback, we conducted a second binding open season for a modified Storage Expansion Project via two notices and bidding periods, May 12, 2009 to June 2, 2009 and June 29, 2009 to July 14, 2009.  This second open season was for a slightly smaller storage expansion project that would provide a minimum of 4,000,000 Dths of additional storage capacity and increase delivery by up to 40,000 Dths/day.  We received three conforming bids and awarded the 4,000,000 Dths of capacity to those bidders. Customers will enter into Firm Storage Service agreements with us at contract demand levels of 4,000,000 Dths/day to be effective April 1, 2011.  The estimated cost of the expansion facilities is approximately $23.2 million and is expected to provide approximately $4.7 million in annual revenues.

Central plans to construct a compressor station adjacent to its existing Elk City Storage Field dehydration plant near Independence, Kansas.  We filed the FERC 7(c) application (Docket No. CP10-2) on October 9, 2009, acquired the compressor station site, initiated the process of obtaining environmental permits, ordered a turbine compressor, and secured air permits for the compressor.  The Environmental Assessment was initiated by the FERC on November 16, 2009.  Bids for construction are anticipated to be issued in May 2010, with construction beginning in mid-July, pending FERC approval.

In April 2009, we initiated a binding open season for the “Ozark Advance Expansion Project” to add incremental firm transportation capacity to our system to serve the southwestern portions of Missouri, which concluded on May 8, 2009.  Two binding bids were received for incremental contract demand of 9,000 Dths/day.  Precedent agreements have been finalized. We will seek regulatory approval from the FERC for the project in 2010 with services projected to begin at contract demand levels of 5,000 Dths/day to be effective November 1, 2010 and 4,000 Dths/day to be effective August 1, 2011. The project is expected to cost approximately $2.0 million.

In addition, we initiated a binding open season for the “Sedalia Pipeline Expansion Project” to add incremental capacity to Central’s Sedalia Line in Cass, Johnson and Pettis Counties of Missouri to serve the Central Western Missouri region. This project was developed based upon customer feedback and their growth expectations. This binding open season began on July 22, 2009 and concluded on August 4, 2009. Central received bids for 37,400 Dths/day starting on November 1, 2009 and future loads of 8,500 Dths/day by November 1, 2014. We will be able to meet incremental demand of 37,400 Dths/day from firm transportation shippers in this growing area of our pipeline system. Precedent agreements with contract terms ranging from two to ten years have been finalized and the expanded transportation service is scheduled to begin November 1, 2009. We installed a new delivery meter station to facilitate this service at the cost of $0.4 million.

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.

On June 3, 2009, the Financial Accounting Standards Board, or FASB, approved the Accounting Standards Codification, or ASC, in an effort to reduce the complexity of accounting standards and to facilitate international convergence. The implementation of the ASC has not changed GAAP, but has reorganized the literature and naming mechanism of existing topics. The Company’s consolidated financial statements and related footnotes have remained unchanged as a result of the Codification. We believe that, of our significant accounting policies, the following may involve a higher degree of judgment or complexity.

 Employee Benefit Plans

Assets and liabilities of our defined benefit plans are determined on an actuarial basis and are affected by the estimated market value of plan assets, estimates of the expected return on plan assets and discount rates. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets will affect the amount of our accrued benefit costs.  In addition, the asset or liability for post retirement medical benefits is also determined on an actuarial basis and is affected by assumptions including the discount rate and expected trends in health care costs.  As it is appropriate for Central to apply the accounting prescribed by the Accounting for the Effects of Certain Types of Regulations Topic of the ASC, the Company does not recognize changes in the funded status in comprehensive income but recognizes them as changes to the r elated regulatory asset or liability, pending future recovery or refund through its rates.  For further discussion of the Company’s employee benefit plans see Note 8 to the accompanying Notes to the Consolidated Financial Statements.

Accounting for the Effects of Regulation

Like all interstate natural gas pipeline operators, Central is subject to regulation by the FERC. The Accounting for the Effects of Certain Types of Regulation Topic of the ASC 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 Accounting for the Effects of Certain Types of Regulation 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 and 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 Accounting for the Effects of Certain Types of Regulation 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 by Holdings, as discussed in Note 2 of the accompanying Notes to the Consolidated Financial Statements. Goodwill is not amortized and is subject to an annual impairment test as of December 31 and whenever events or circumstances make it more likely than not that impairment may have occurred in accordance with Goodwill and Other Intangible Assets Topic of the ASC. Fair value is based on an income approach with an appropriate risk-adjusted discount rate. Significant assumptions inherent in the methodology are employed and include such estimates as discount rates.

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 actu al 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 the Accounting for Income Taxes.

Southern Star operates under a Federal and State Income Tax Policy that governs the allocation and payment of tax liabilities of Holdings, Southern Star and Central. This policy provides that Southern Star will file consolidated tax returns  on behalf of itself, Holdings and Central and will pay all taxes shown thereon to be due. Central generally 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.

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. The following table sets forth our selected results of operations data for the years ended December 31, 2009, 2008 and 2007:

		For the Year Ended December 31, 2009		For the Year Ended December 31, 2008		For the Year Ended December 31, 2007
		(In thousands)
Operating revenues	$	220,801	$	196,788	$	188,081
Operations and maintenance		50,135		49,064		45,085
Administrative and general		42,954		39,005		35,562
Depreciation and amortization		32,238		29,293		27,470
Taxes, other than income taxes		15,293		14,654		14,573
Operating income		80,181		64,772		65,391
Other (Income) Deductions:
Interest expense		32,556		31,210		28,842
Interest income		(308)		(877)		(1,441)
Miscellaneous other (income) expenses, net		(49)		(658)		(516)
Total Other Deductions		32,199		29,675		26,885
Income before income taxes		47,982		35,097		38,506
Provision for income taxes		19,010		13,838		15,299
Net Income	$	28,972	$	21,259	$	23,207

Comparison of the Years Ended December 31, 2009 and 2008

Operating revenues were $220.8 million for the year ended December 31, 2009, a $24.0 million, or 12.2%, increase from $196.8 million in the prior year. The increase is primarily due to the RP08-350 rate settlement, increases in Central’s firm transportation due to new contracts, incremental park and loan services, and storage revenues. Higher park and loan revenue is primarily due to futures pricing and available capacity on the pipeline in 2009 as compared to 2008. The higher storage revenues in 2009 are a result of higher reservation capacity balances in 2009 as compared to 2008.

Operations and maintenance expenses were $50.1 million for the year ended December 31, 2009, an increase of $1.1 million, or 2.2%, from 2008. The increase is principally due to higher expenses in 2009 for pipeline integrity management program costs and labor. The increase was partially offset by lower expenses in 2009 for employee relocations, vehicle usage, right-of-way clearing, supplies, inspectors, materials, parts and utilities.

Administrative and general expenses were $43.0 million for the year ended December 31, 2009, a $4.0 million, or 10.1%, increase from $39.0 million in 2008. The increase is principally due to higher expenses in 2009 for pension contributions, group medical insurance, property and liability insurance and employee incentives, offset partially by lower expenses related to outside legal services, professional services and third party damages.

Depreciation and amortization expenses were $32.2 million for the year ended December 31, 2009, a $2.9 million, or 10.1%, increase from $29.3 million in 2008. The increase is primarily due to higher depreciation recovery allowed in the RP08-380 rate settlement and the number of capital projects that have been placed in service since 2008.

Taxes other than income taxes were $15.3 million for the year ended December 31, 2009, a $0.6 million, or 4.4%, increase from $14.7 million in 2008. The increase was mainly the result of an increase in state property tax expense due to an increase in state assessments and an increase of various county tax levies in the state of Kansas for 2009.

Interest expenses were $32.6 million for the year ended December 31, 2009, an increase of $1.3 million, or 4.3%, from 2008. The increase is primarily due to the issuance of the 6.75% Unregistered Notes in April 2008. See Note 3 of the accompanying Notes to the Consolidated Financial Statements for further discussion of Central’s long-term debt. The increase is also due in part to lower income from the allowance for borrowed funds used during construction, or AFUDC debt, in 2009 resulting from the timing of construction in-service dates and the timing of the capital expenditures, along with the decrease in overall capital expenditures in 2009 versus 2008.  

Interest income was $0.3 million for the year ended December 31, 2009, a $0.6 million, or 64.9%, decrease from $0.9 million in 2008. The decrease is primarily due to lower interest rates in 2009 as compared to the same period in 2008.

Other income was $0.1 million for the year ended December 31, 2009, a $0.6 million, or 92.6%, decrease from $0.7 million in 2008. The decrease is primarily due to loss recognized from the sale of excess materials and lower AFUDC-equity in 2009 resulting from the timing of construction in-service dates and the timing of capital expenditures, along with the decrease in overall capital expenditures in 2009 versus 2008.

The provision for income taxes was $19.0 million for the year ended December 31, 2009, a $5.2 million, or 37.4%, increase from $13.8 million in 2008. The increase is commensurate with higher pre-tax income. Our effective tax rate for 2009 was 39.6% compared to 39.4% for the same period in 2008.

Comparison of the Years Ended December 31, 2008 and 2007

Operating revenues were $196.8 million for the year ended December 31, 2008, an $8.7 million, or 4.6%, increase from $188.1 million the prior year. The increase is primarily due to Central’s restructuring of certain firm transportation contracts, increases in Central’s firm transportation, interruptible transportation, incremental park and loan services and the RP08-350 rate settlement, offset partially by lower storage revenues. The lower storage revenues in 2008 are the result of decreased inventories in storage due to an increase in demand for natural gas, resulting from climate conditions that were colder in 2008 compared to 2007.

Operations and maintenance expenses increased by $4.0 million, or 8.8%, to $49.1 million for the year ended December 31, 2008 from $45.1 million from the prior year, principally due to higher expenses in 2008 for labor, employee relocations, pipeline integrity management program costs, lube oil, treating materials, utilities, pipeline inspections and engine repairs. The increase was partially offset by lower expenses for vehicle usage, environmental remediation and consultant fees for KCC permits.

Administrative and general expenses were $39.0 million for the year ended December 31, 2008, a $3.4 million, or 9.7%, increase from $35.6 million in 2007. The increase is primarily due to higher expenses in 2008 for labor, group health insurance, professional services, retirement plan contributions, 401(k) contributions, third party damages and fees and permits. The increase was partially offset by lower expenses in 2008 for independent audit services, property and liability insurance and higher operating expenses transferred to capital.

Depreciation and amortization expense was $29.3 million for the year ended December 31, 2008 as compared to $27.5 million in 2007, a $1.8 million, or 6.6%, increase. The change is primarily due to an increase in the depreciable base due to new capital projects placed in service in 2007 and 2008.

Interest expense was $31.2 million for the year ended December 31, 2008, a $2.4 million, or 8.2%, increase. The increase is primarily due to the issuance of the 6.75% Unregistered Notes in April 2008. See Note 3 of the accompanying Notes to the Consolidated Financial Statements for further discussion of our long-term debt.

Interest income decreased by $0.6 million, or 39.1%, to $0.9 million for the year ended December 31, 2008. The decrease is primarily due to lower interest rates in 2008 compared to the same period in 2007.

The provision for income taxes was $13.8 million for 2008, a decrease of $1.5 million, or 9.5%, from $15.3 million in 2007, commensurate with lower pre-tax income. Our effective tax rate for 2008 was 39.4% as compared to 39.7% for 2007.

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 on hand, cash flows from operating activities and by accessing debt markets, if needed, to support operations and capital expenditures. Funds may not, however, be readily available if and when we attempt to access the debt market.

As of March 1, 2010, 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, 2009 and 2008 was $73.7 million and $60.3 million, respectively. Cash from operating activities was higher in 2009 primarily due to higher 2009 operating income, excluding depreciation and an increase in 2009 account payables compared to 2008. The increase was partially offset by an increase in receivables for reimbursable projects, federal and state income taxes and increased funding to the Company’s pension plans discussed in Note 8 of the accompanying Notes to the Consolidated Financial Statements.

Net cash used in investing activities for the years ended December 31, 2009 and 2008 was $39.1 million and $66.9 million, respectively. Cash used in investing activities was lower in 2009 primarily due to lower maintenance capital expenditures.

Net cash used in financing activities was $31.4 million for the year ended December 31, 2009, as compared to net cash provided in financing activities of $22.2 million for the same period in 2008. The change is primarily due to the net cash provided by the issuance of the 6.75% Unregistered Notes in April 2008, and higher 2009 dividend payments. Our financing activities are further discussed below.

Net cash provided by operating activities for the years ended December 31, 2008 and 2007 was $60.3 million and $59.1 million, respectively. Cash from operating activities was higher in 2008 primarily due to the decline of other accounts receivable in 2008 as compared to their growth in 2007 and lower employee incentive payments. The increase was partially offset by lower operating income, excluding depreciation, in 2008, increased funding to the Company’s pension plans discussed in Note 8 of the accompanying Notes to the Consolidated Financial Statements and the replacement of lost natural gas discussed in Note 4 of the accompanying Notes to the Consolidated Financial Statements.

Net cash used in investing activities for the years ended December 31, 2008 and 2007 was $66.9 million and $47.2 million, respectively. Cash used in investing activities was higher in 2008 primarily due to higher maintenance capital expenditures.

Net cash provided in financing activities was $22.2 million for the year ended December 31, 2008, as compared to net cash used in financing activities of $29.9 million for the same period in 2007. The increase is primarily due to net cash provided by the issuance of the 6.75% Unregistered Notes in April 2008, lower 2008 dividend payments, and the 2007 redemption of all remaining 8.5% Notes. 

6

8.5% Notes

Prior to August 1, 2007, we had outstanding $3.1 million of 8.5% Notes due 2010, or 8.5% Notes. Interest on the 8.5% Notes was payable semi-annually in February and August. 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% Registered Notes

At December 31, 2009, we had outstanding $200.0 million of 6.75% Notes registered under the Securities Act of 1933 as amended, or 6.75% Registered Notes. The Bank of New York Trust Company, N.A. serves as trustee pursuant to the related Indenture. Interest is payable semi-annually on March 1 and September 1 of each year. The 6.75% Registered Notes mature on March 1, 2016 and have an overall effective interest rate of 7.06%. The 6.75% Registered 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% Registered 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% Registered 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.

Beginning March 1, 2009, we have the right to redeem all or part of the 6.75% Registered 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% Registered Notes in full at a make-whole premium as defined in the indenture.  

6.75% Unregistered Notes

On April 16, 2008, Southern Star completed the sale of $50.0 million aggregate principal amount of 6.75% Unregistered Notes in a private placement. In connection with the offering, the Company entered into an indenture dated April 16, 2008 by and between Southern Star and The Bank of New York Trust Company, N.A., as trustee.

Interest is payable semi-annually on March 1 and September 1 of each year, beginning on September 1, 2008. The 6.75% Unregistered Notes will mature on March 1, 2016 and have an overall effective interest rate of 8.55%. The 6.75% Unregistered Notes are senior unsecured obligations and rank equal in rights of payment to all of Southern Star’s 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 indenture governing the 6.75% Unregistered Notes, is subject to, with certain limited exceptions, a minimum fixed charge coverage ratio and cumulative available cash flows from operations or leverage ratio, subject to certain conditions, as defined in the indenture.

The 6.75% Unregistered 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.

Beginning March 1, 2009, we have the right to redeem all or part of the 6.75% Unregistered 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% Unregistered Notes in full at a make-whole premium as defined in the indenture.

7

Central’s 6.0% Notes

At December 31, 2009, Central had outstanding $230.0 million aggregate principal amount of 6.0% Senior Notes due 2016, or 6.0% Notes. The Bank of New York Trust Company, N.A. serves as trustee under the related indenture. The indenture governing the 6.0% Notes 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 the 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 20 04B bonds on or after February 1, 2014.

Other

We operate under a Federal and State Income Tax Policy that governs the allocation and payment of tax liabilities of Holdings, Southern Star and Central. This policy provides that we will file consolidated tax returns  on behalf of itself, Holdings and Central and will 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. We have 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. During the second quarter of 2009, remaining tax benefit carryforwards were substantially realized, resulting in cash outlays attributable to tax liabilities originating in the current period, as well as future periods.

On April 30, 2008, Central filed a general rate case under FERC Docket No. RP08-350 which became effective November 1, 2008. The case was approved without modification by the FERC on June 1, 2009. Pursuant to the terms of its settlement, Central is required to file a new rate case to be effective on or before December 1, 2013.

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 $1.7 million and $2.0 million in expenses for the years ended 2009 and 2008, respectively, for such annual payments. The current agreements are scheduled to expire in 2010 but may be renewed annually thereafter.

At December 31, 2009, we were in compliance with the covenants of all outstanding debt instruments. See Note 3 of the accompanying Notes to the Consolidated Financial Statements for further discussion of our debt instruments.

8

Other

Contractual Obligations and Commitments

The table below summarizes our significant contractual obligations and commitments for the years indicated as of December 31, 2009:

Payments Due by Period

(In thousands)

	Long-Term Debt1		Capital Leases1		Purchase Obligations		Operating Leases		Capital Expenditure Commitments2		Total Contractual Obligations
2010	$	30,675	$	1,062	$	102	$	282	$	23,236	$	55,357
2011		30,675		522		—		268		10,771		42,236
2012		30,675		526		—		268		4,720		36,189
2013		30,675		527		—		269		6,942		38,413
2014		30,675		528		—		236		—		31,439
After 2014		519,238		5,288		—		235		—		524,761
Total	$	672,613	$	8,453	$	102	$	1,558	$	45,669	$	728,395

(1)

Includes principal and interest payments.

(2)

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

We have estimated capital expenditures of $65.9 million in 2010 including approximately $16.1 million for the “Storage Expansion” project and approximately $11.6 million for projects under our pipeline integrity management program. We expect to fund 2010 capital expenditures from our cash from operations.

In addition to the capital expenditures listed above, Central expects to contribute a total of  $8.7 million to its Retirement and Post Retirement Medical Benefit Plans in 2010. See Note 8 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 4 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 and benefits, materials and supplies, and property, plant and equipment. A portion of the increased expenses resulting from labor, materials and supplies 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 repla ced. Cost-based regulation, along with competition and other market factors, limits Central’s ability to price services or products to reflect increased costs resulting from inflation.

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, 2009, had a carrying value of $476.1 million and a fair value of $475.2 million. The weighted-average interest rate of our long-term debt was 6.79%. Our $200.0 million (6.75% Registered Notes), $230.0 million (6.0% Notes) and $50.0 million (6.75% Unregistered Notes) long-term debt issues mature in 2016. The $5.7 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  

See our accompanying consolidated financial statements included in Item 15. “Exhibits and Financial Statement Schedules” of this annual report on Form 10-K.

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, 2009, 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, 2009.

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 ci rcumvented.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. 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, 2009.

Changes in Internal Control Over Financial Reporting – There has been no change in our internal control over financial reporting during the quarter ended December 31, 2009, 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

On March 9, 2010, Morgan Stanley Infrastructure Partners and certain other affiliated investment funds managed by Morgan Stanley Infrastructure, Inc., or MSIP, acquired Caisse de depot et placement du Quebec’s, or CDP’s, ownership interest in Holdings. Effective on that date, each of Pierre Lambert and Cyrille Vittecoq resigned as members of the Board of Directors, or the Board, of the Company, and Mr. John V. Veech and Mr. John B. Watt were elected as new directors. Based on their education and experience in the energy sector, the Board deemed both individuals to be qualified to serve as directors.

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 9, 2010.

Name	Age		Position
Robert P. Hadden	48	Director
Kathy McGowan	48	Director
John V. Veech	51		Director
John B. Watt	53		Director
Jerry L. Morris	54		President and CEO
Susanne W. Harris	51		Vice President, CFO and Treasurer
Beverly H. Griffith	55		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 9, 2010.

Name	Age	Position
Robert P. Hadden	48	Director
Kathy McGowan	48	Director
John V. Veech	51	Director
John B. Watt	53	Director
Jerry L. Morris	54	President and CEO
Robert S. Bahnick	50	Senior Vice President of Operations and Technical Services
Robert W. Carlton	49	Vice President of Human Resources and Administration
Chris W. Ellison	55	Vice President of Operations-Hesston Division
David L. Finley	45	Vice President of Information Technology
Beverly H. Griffith	55	Senior Vice President, General Counsel and Corporate Secretary
Susanne W. Harris	51	Vice President, CFO and Treasurer
Daryl R. Johnson	56	Vice President of Rates and Regulatory Affairs
Richard J. Reischman	54	Vice President of Operations-Kansas City Division

Robert P. Hadden was appointed to the Board of Directors, or the Board, 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 27 years with GE, he has held a variety of positions, including risk managem ent, portfolio and business development. While 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 effective May 22, 2007. Ms. McGowan currently serves as Senior Vice President at GE Energy Financial Services, a position to which she was promoted 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.

John V. Veech, 51, was elected to the Board on March 9, 2010 by written consent of the shareholder.  Mr. Veech has been a Managing Director and head of the Americas region for MSIP since February 1, 2009. Prior to joining MSIP, he was a Managing Director in the Investment Management Division of Lehman Brothers from December 1, 2007 until January 31, 2009 (which became Neuberger Investment Management in December 2008), and a partner in Lehman Brothers Global Infrastructure Partners. Prior thereto, he was the global head of Project Finance at Lehman Brothers from 1997 to November 2007, a Managing Director from December 2001 to November 2007, and a Senior Vice President from 1997 to November 2001. He was previously a Vice President in the Fixed Income Division of Salomon Brothers, and an attorney with Skadden, Arps, Slate, Meagher & Flom. Mr. Veech received a B.S., magna cum laude, in Accounting, from Lehigh University , in 1980, and a Jurist Doctorate, or J.D., cum laude, from Boston University School of Law, in 1983.

John B. Watt, 53, was elected to the Board on March 9, 2010 by written consent of the shareholder.  Mr. Watt currently serves as Head of Asset Management for MSIP in New York, NY, a position he assumed in July 2007. From May 2004 to June 2007 he was a Director in the Ontario Teachers' Pension Plan Infrastructure Group in Toronto, Canada where he was responsible for making investments primarily in the energy sector. From September 2000 to April 2004, he was Vice President of Strategic Initiatives for Ontario Power Generation in Toronto, Canada where he was responsible for divesting power plants and related businesses.  From 1996 to 2000, he was a Director in the Generation Group at TransAlta Corporation in Calgary, Alberta where he was responsible for the engineering and regulatory activities for the Alberta-based regulated power plants. He also held a position in the corporate development group where he was responsible fo r acquiring and divesting various power assets. From 1985 to 1996, Mr. Watt worked for Amoco Corporation in various roles in different groups and locations, including strategic planning, evaluations, treasury, financial management, and business development in Calgary, Chicago, and Houston. From 1981 to 1985, Mr. Watt worked as a Process Engineer for Union Carbide Canada in Alberta, Canada.  He received a Bachelor of Applied Science degree, or B.A.Sc., in Chemical Engineering from the University of Toronto in 1978 and his M.B.A. from the University of Western Ontario in Canada in 1981.

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 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 32 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 28 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 26 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 31 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 23 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 30 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 Juris Doctorate 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.

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 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 30 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, the Southern 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 34 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 31 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, or until successors have been elected and qualified, or until their death, resignation or removal.

To the best of our knowledge, during the past five years, none of the following occurred with respect to any present or former director or executive officer: (i) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time; (ii) any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offences); (iii) being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining , barring, suspending or otherwise limiting his or her involvement in any type of business, securities or banking activities; and (iv) being found by a court of competent jurisdiction (in a civil action), the SEC or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.

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, the full Board acts in the capacity of an audit committee. Furthermore, none of our Board members are required to be either “audit committee financial experts” or “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 the fiscal year ended December 31, 2009 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 following Compensation Discussion and Analysis describes the material elements of compensation for our named executive officers identified in the “Summary Compensation Table”. The Board makes all decisions for the total direct compensation of our named executive officers with the input of our chief executive officer.

The primary objectives of 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 compensation data for executive officers in similar positions with companies of comparable size within the gas pipeline industry.  The Board utilizes compensation data from an annual survey performed by the Southern Gas Association in which Central participates.  The data is a compilation derived from information provided by the following peer companies: Alliance Pipeline, Centerpoint Energy, CPS Energy, Entergy Corporation, Mid-America Holdings Company, Oneok, Inc., Questar Corporation, and Southern Union Company. With respect to officers other than the CEO, the Board also takes into consideration the recommendations of the CEO.  For executive compensation, the Board utilizes compensation data from a confidential annual survey performed by the American Gas Association, or AGA, in which the Company participates.  The 2009 AGA data is a compilation derived from information provided by its 62 member organizations, including peer pipeline companies Centerpoint Energy, Entergy Corporation, Oneok, Inc., Questar Corporation, Southern Union Company, Nisource, Inc., Transcanada Pipelines Limited, and the Williams Companies. With respect to officers other than the CEO, the Board also takes into consideration the recommendations of the CEO.  For 2009, there were no adjustments to the named executive officer salaries and no adjustment to the bonus level s at which they participate.

Compensation Components

Our compensation program for our 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 from regional and industry data, an officer’s scope of responsibilities, and individual performance and contribution to the Company. During 2009, there were no adjustments to officers’ base salaries.

Annual Bonus:  Officers participate in our 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. Specific Company targets for each year are recommended by the CEO with input from the Board and ultimately approved by the Board. Targets may include such factors as improved earnings; on-time, on-budget capital project execution; operational safety measures; and successful pursuit of business growth strategies.  

The Board-approved targets establish a pool of dollars that may be funded for Bonus Plan awards to employees each year, or the Bonus pool, based on each individual employee’s performance and achievement of goals set within each employee’s annual performance plans.  

For 2009, the Board established five components of the Bonus pool.

·

Up to 15% of the Bonus pool was apportioned to provide for the achievement of non-financial goals and objectives; this amount may be funded, at the discretion of the Board, whether or not any other targets are achieved. For 2009, this component was funded at 15%.

·

Up to 10% of the Bonus pool was attributed to the successful completion of capital projects on time and within approved budgets.  For 2009, this component was funded at 8%.

·

Up to 5% of the Bonus pool was attributed to the successful completion of all new and historical compliance activities.  For 2009, this component was funded at 4%.

·

Up to 45% of the Bonus pool was attributed to the achievement of specified earnings targets, as defined by the Board.  For 2009, this component was funded at 45%

·

Up to 25% of the Bonus pool was attributed to the achievement of specified free cash flow targets, as defined by the Board.  For 2009, this component was funded at 25%.

After the end of each year, the Board determines the level of funding for each component.  In total, the 2009 Bonus pool for all employees was funded at 97% of the maximum potential Bonus pool.

Each of our executive officers is eligible to receive a discretionary annual bonus set at a targeted percentage of his or her 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 o f our Board, the Board looks broadly at the performance of the executive officer in making its determination of whether a bonus should be awarded.

Once the Bonus pool funding 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. Individual performance is based on achievement of individual goals, including appropriate management of departmental budgets, and individual contributions to team and Company goals, as well as specified performance factors. The Board, after giving consideration to the CEO’s recommendations, 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 2009 bonus pool was funded at 97% of the maximum allowed by the Bonus Plan, and as a group, our executive officers received 19% of the bonus pool paid. For 2009, each named executive officer received the following percentage of their respective bonus potential: 92% for Mr. Morris, 93% for Mr. Bahnick, 90% for Mrs. Griffith, 90% for Mrs. Harris, and 96% for Mr. Johnson.

Employment Agreements and Retention Payments:  All of our officers entered into employment agreements with us during the course of our 2005 acquisition by Holdings to ensure the stability and strength of our management team. The agreements, which are further described below, under “Employment Agreement and Potential Payments Upon Termination or Change in Control”, provide for Base Salaries and Annual Bonuses as described above and provide terms for severance payments under certain conditions. The agreements have a five-year term expiring in 2010 and provide for annual payments over a five-year period to each officer for his or her continued employment.  The employment agreements will be extended automatically after 2010 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.

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.  

We do not presently offer any long-term performance incentives, equity-based compensation, or supplemental retirement benefits to our 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 during the fiscal year 2009, and for the top five compensated employees including the most highly compensated executive officers of Central, our operating entity, as of December 31, 2009. 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, 2009, 2008 and 2007 (expressed in thousands):

SUMMARY COMPENSATION TABLE

Name and Principal Position(3)	Year	Salary $	Bonus $	Change in Pension Value and Nonqualified Deferred Compensation Earnings(1) $	All Other Compensation(2) $	Total $
Jerry L. Morris	2009	247,235	219,032	142,935	644,700	1,253,902
President, CEO	2008	231,575	202,366	22,303	643,800	1,100,044
	2007	226,015	140,316	34,197	643,500	1,044,028
Susanne W. Harris	2009	173,586	74,907	82,719	155,325	486,537
Vice President, Finance and Accounting, and CFO	2008	161,413	71,578	21,662	154,425	409,078
	2007	154,064	50,066	24,103	154,125	382,358
Beverly H. Griffith	2009	200,524	129,870	122,732	138,450	591,576
Senior Vice President, General Counsel	2008	199,326	124,098	25,985	137,550	486,959
and Corporate Secretary	2007	198,172	88,023	38,545	137,250	461,990
Robert S. Bahnick	2009	213,923	143,685	95,958	169,724	623,290
Senior Vice President of Operations	2008	213,828	132,870	19,266	173,175	539,139
and Technical Services of Central	2007	210,841	90,383	22,067	170,199	493,490
Daryl R. Johnson	2009	172,427	79,700	165,002	202,200	619,329
Vice President, Rates and Regulatory Affairs of	2008	160,143	73,888	24,759	201,300	460,090
Central	2007	153,705	49,606	49,661	201,000	453,972

(1)

See Note 8 of the accompanying Notes to the Consolidated Financial Statements for discussion of assumptions used in determining these present values, except the retirement age assumption adheres to the requirements of U.S. SEC REGULATION S-K Subpart 229.402(h)(2).

(2) 

All Other Compensation for 2007, 2008 and 2009 includes matching contributions by Central under the Southern Star Investment Plan, Central’s broad-based 401(k) plan. For 2009, it contains the amounts of $14,700 for Mr. Morris, $10,349 for Mr. Bahnick, $14,700 for Mrs. Griffith, $14,700 for Mrs. Harris, and $14,700 for Mr. Johnson. For 2008, it contains the amounts of $13,800 for Mr. Morris, $13,800 for Mr. Bahnick, $13,800 for Mrs. Griffith, $13,800 for Mrs. Harris, and $13,800 for Mr. Johnson. 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 Mrs. Harris, and $13,500 for Mr. Johnson. These amounts are to be paid out to the named executives only upon retirement, termination, disability or death. All other compensation includes amounts paid as retention bonuses described under “Employment Agreements and Potential Payme nts Upon Termination or Change of Control” as follows: For 2009, the amounts of $630,000 to Mr. Morris, $159,375 to Mr. Bahnick, $123,750 to Mrs. Griffith, $140,625 to Mrs. Harris and $187,500 to Mr. Johnson.; for 2008, the amounts of $$630,000 to Mr. Morris, $159,375 to Mr. Bahnick, $123,750 to Mrs. Griffith, $140,625 to Mrs. Harris and $187,500 to Mr. Johnson; and for 2007, it contains the amounts of $630,000 for Mr. Morris, $159,375 for Mr. Bahnick, $123,750 for Mrs. Griffith, $140,625 for Mrs. Harris, and $187,500 for Mr. Johnson.

(3)

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 or 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 2009 (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	7.167	$        295,770	$ —
Susanne W. Harris	7.167	207,780	—
Beverly H. Griffith	7.167	299,136	—
Robert S. Bahnick	7.167	206,561	—
Daryl R. Johnson	7.167	347,005	—

*

See Note 8 of the accompanying Notes to the Consolidated Financial Statements for discussion of assumptions used in determining these present values at December 31, 2009, except the retirement age assumption adheres to the requirements of U.S. SEC REGULATIONS-K Subpart 229,302(h)(2).

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 $230,000 per year for 2008 and $245,000 per year for 2009. 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 or she is credited with one-twelfth of a year of credited service for each month, or part thereof, of which he or she 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 us.

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, Central provides a 401(k) Plan whereby employee contributions are matched by Central up to established limits.

Compensation of Directors

No director of Southern Star or Central receives any remuneration for serving on the Board 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 appli cable 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, we 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; 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. Ca rlton, $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 so licit employees or contractors away from Central or solicit the business of any client or customer of Central in any territory, state or country where Central conducts business.

Also, in December 2008, Central’s Board passed a resolution amending the employment agreements for all officers, effective January 1, 2009, to be in compliance with IRS Section 409A related to, among other things, setting the specific timing of certain payments upon termination should it occur during the term of the employment agreement.

The table below sets forth the amounts payable to each named executive officer assuming the named executive officer’s employment had terminated on December 31, 2009.

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, 2009. Payments that we may make in the future upon a named executive officer’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, 2009.

9

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	$	1,293,141	$	—	$	816,985	$	816,985	$	868,078
Susanne W. Harris		538,829		—		205,909		205,909		307,085
Beverly H. Griffith		626,158		—		241,358		241,358		316,150
Robert S. Bahnick		695,363		—		283,363		283,363		365,375
Daryl R. Johnson		585,478		—		253,396		253,396		353,541

(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 af ter receipt of notice given by 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 Central’s long-term disability insurance program (or such other long term disability program as Southern Star 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 12-month period, notwithstanding any reasonable accommodation as may be required by applicable law. The employee agreements for the named executive officers indicate they will be 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 because 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 Board. 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.

Compensation Committee Report

The Board, acting in the capacity of a compensation committee, has reviewed the preceding Compensation Discussion and Analysis and discussed it with management. Based on its review and discussion, the Board, acting in the capacity of a compensation committee, recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

10

Members of the Board:

Robert Hadden

Kathy McGowan

John V. Veech

John B. Watt

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 co mpany’s best interests and, 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 o f 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 15, 2010, 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 (seven total)	0 shares	0%

 (1)

EFS-SSCC Holdings, LLC is indirectly owned 60% by GE and 40% by MSIP, 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 2009, 2008 and 2007, 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, we entered into an Administrative Services Agreement, or Services Agreement, with EFS Services, LLC to provide ce rtain 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. These transactions are approved by the appropriate level of management in accordance with the Company’s written and Board-approved Delegation of Authority policy.  Because Southern Star is a closely-held company with no independent directors, we have no policy for Board review of related party transactions and the related approval thereof.

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, 2009 and 2008, and in connection with statutory and regulatory filings for such fiscal periods, were approximately $465,000 and $538,000, 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, 2009 and 2008 were approximately $62,000 and $101,000, 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, 2009 and 2008 were approximately $0.0 and $14,000, respectively.

All Other Fees

No other services were provided by E&Y for the fiscal years ended December 31, 2009 and 2008.

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. All audit and non-audit services provided by E&Y, an Independent Registered Public Accounting Firm, during 2009 were pre-approved by the Board.

11

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 46 of this report:
Report of Independent Registered Public Accounting Firm	47
Consolidated Balance Sheets at December 31, 2009 and 2008	48
Consolidated Statements of Operations for the years ended December 31, 2009, 2008, and 2007	50
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008, and 2007	51
Consolidated Statements of Stockholder’s Equity for the years ended December 31, 2009, 2008, and 2007	52
Notes to the Consolidated Financial Statements	53

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.
4.138			Indenture dated April 16, 2008, between Southern Star Central Corp. and The Bank of New York Trust Company, N.A., 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, Inc. (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.
10.199			Amendment to Employment Agreement, dated as of December 15, 2008, among Southern Star Central Corp., Central and Robert S. Bahnick.
10.209			Amendment to Employment Agreement, dated as of December 19, 2008, among Southern Star Central Corp., Central and Robert W. Carlton.
10.219			Amendment to Employment Agreement, dated as of December 16, 2008, among Southern Star Central Corp., Central and Chris W. Ellison.
10.229	Amendment to Employment Agreement, dated as of December 15, 2008, among Southern Star Central Corp., Central and David L. Finley.
10.239	Amendment to Employment Agreement, dated as of December 16, 2008, among Southern Star Central Corp., Central and Beverly H. Griffith.
10.249	Amendment to Employment Agreement, dated as of December 15, 2008, among Southern Star Central Corp., Central and Susanne W. Harris.
10.259	Amendment to Employment Agreement, dated as of December 15, 2008, among Southern Star Central Corp., Central and Daryl R. Johnson.
10.269		Amendment to Employment Agreement, dated as of December 15, 2008, among Southern Star Central Corp., Central and Richard J. Reischman.
10.279		Amendment No. 3 to Employment Agreement, dated as of December 19, 2008, 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.

(8)

Incorporated by reference from Southern Star Central Corp.’s Report on Form 8-K filed with the SEC on April 21, 2008.

(9)

Incorporated by reference from Southern Star Central Corp.’s Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 17, 2009.

12

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 15, 2010	By:	/s/    JERRY L. MORRIS
		Jerry L. Morris President and Chief Executive Officer
March 15, 2010	By:	/s/    SUSANNE W. HARRIS
		Susanne W. Harris Vice President, Chief Financial Officer & Treasurer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

	Signature	Title	Date
By:	/s/   JOHN B. WATT          John B. Watt	Director	March 15, 2010
By:	/s/    ROBERT P. HADDEN         Robert P. Hadden	Director	March 15, 2010
By:	/s/    KATHY MCGOWAN Kathy McGowan	Director	March 15, 2010
By:	/s/   JOHN V. VEECH         John V. Veech	Director	March 15, 2010

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

13

Item 7. Consolidated Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	47
Consolidated Financial Statements:
Consolidated Balance Sheets	48
Consolidated Statements of Operations	50
Consolidated Statements of Cash Flows	51
Consolidated Statements of Stockholder’s Equity	52
Notes to the Consolidated Financial Statements	53

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.

46

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 as of December 31, 2009 and 2008, and the related consolidated statements of income, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2009.  These consolidated financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits 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 purpose 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 m ade by management, and evaluating 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, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the accompanying consolidated financial statements, in 2007, the Company adopted new Financial Accounting Standards Board (FASB) authoritative guidance on accounting for uncertainty in income taxes.

/s/ Ernst & Young LLP

Louisville, Kentucky

March 15, 2010

47

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31, 2009			December 31, 2008
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	38,789		$	35,615
Receivables:
Trade		18,985			19,632
Income taxes		1,748			286
Transportation, exchange and fuel gas		11,605			1,100
Other		5,497			1,814
Inventories		6,910			6,956
Deferred income taxes		2,559			5,351
Costs recoverable from customers		750			2,343
Prepaid expenses		5,190			4,486
Other		678			687
Total current assets		92,711			78,270
Property, Plant and Equipment, at cost:
Natural gas transmission plant		662,316			642,800
Other natural gas plant		13,798			14,277
		676,114			657,077
Less – Accumulated depreciation and amortization		(68,320	)		(55,802	)
Property, plant and equipment, net		607,794			601,275
Other Assets:
Goodwill		324,844			324,844
Costs recoverable from customers		49,851			46,867
Prepaid expenses		485			755
Postretirement benefits other than pensions		1,398			—
Other deferred and noncurrent assets		8,171			9,420
Total other assets		384,749			381,886
Total Assets	$	1,085,254		$	1,061,431

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, 2009		December 31, 2008
	(In thousands)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Payables:
Trade	$	3,174	$	3,500
Transportation, exchange and fuel gas		10,019		2,694
Income Taxes		368		—
Other		8,039		4,837
Accrued taxes, other than income taxes		6,293		5,836
Accrued interest		6,938		6,954
Accrued payroll and employee benefits		11,645		10,608
Costs refundable to customers		1,674		—
Capitalized lease obligation due in one year		745		720
Other accrued liabilities		2,320		3,132
Total current liabilities		51,215		38,281
Long-Term Debt:
Capitalized lease obligation		4,980		5,725
Other long-term debt		476,074		475,440
Total long-term debt		481,054		481,165
Other Liabilities and Deferred Credits:
Deferred income taxes		76,128		67,887
Postretirement benefits other than pensions		15,212		14,302
Asset retirement obligations		2,782		2,611
Costs refundable to customers		2,067		438
Environmental remediation		1,403		1,555
Accrued pension		25,495		23,728
Other		168		123
Total other liabilities and deferred credits		123,255		110,644
Stockholder’s Equity:
Common stock, $.01 par value, 100 shares authorized and issued,
100 shares outstanding at December 31, 2009 and 2008		—		—
Premium on capital stock and other paid-in capital		423,869		423,869
Retained earnings		5,861		7,472
Total stockholder’s equity		429,730		431,341
Total Liabilities and Stockholder’s Equity	$	1,085,254	$	1,061,431

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

	For the Year Ended December 31, 2009			For the Year Ended December 31, 2008			For the Year Ended December 31, 2007
	(In thousands)
Operating Revenues:
Transportation	$	193,415		$	175,657		$	166,599
Storage		26,912			20,164			20,824
Other revenue		474			967			658
Total operating revenues		220,801			196,788			188,081
Operating Costs and Expenses:
Operations and maintenance		50,135			49,064			45,085
Administrative and general		42,954			39,005			35,562
Depreciation and amortization		32,238			29,293			27,470
Taxes, other than income taxes		15,293			14,654			14,573
Total operating costs and expenses		140,620			132,016			122,690
Operating Income		80,181			64,772			65,391
Other (Income) Deductions:
Interest expense		32,556			31,210			28,842
Interest income		(308	)		(877	)		(1,441	)
Miscellaneous other (income) expenses, net		(49	)		(658	)		(516	)
Total other deductions		32,199			29,675			26,885
Income Before Income Taxes		47,982			35,097			38,506
Provision for Income Taxes		19,010			13,838			15,299
Net Income	$	28,972		$	21,259		$	23,207
Total comprehensive income	$	28,972		$	21,259		$	23,207

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

	For the Year Ended December 31, 2009			For the Year Ended December 31, 2008			For the Year Ended December 31, 2007
	(In thousands)
OPERATING ACTIVITIES:
Net income	$	28,972		$	21,259		$	23,207
Adjustments to reconcile to net cash provided from         operations:
Depreciation and amortization		32,238			29,293			27,470
Deferred income taxes		11,033			12,688			14,247
Amortization of debt discount/premium and expense		1.688			1,534			1,190
Receivables		(4,496	)		15			(4,096	)
Inventories		46			(490	)		97
Other current assets		(493	)		(47	)		(377	)
Payables and accrued liabilities		4,063			(2,854	)		(3,798	)
Other, including changes in noncurrent assets and     liabilities		600			(1,064	)		1,188
Net cash provided by operating activities	73,651			60,334			59,128
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of allowance for funds
used during construction	(40,275		)	(65,622		)	(51,149		)
Proceeds from sales and salvage values, net of costs of       removal		1,156			(1,294	)		3,907
Net cash used in investing activities	(39,119		)	(66,916		)	(47,242		)
FINANCING ACTIVITIES:
Proceeds from long-term debt issuance		—			46,065			—
Early retirement of debt		—			—			(3,080	)
Premium on early retirement of debt		—			—			(131	)
Common dividends/return of capital		(30,583)			(22,000	)		(25,806	)
Debt issuance costs		(55	)		(1,203	)		(68	)
Capital lease payments		(720	)		(690	)		(765	)
Net cash provided by (used in) financing activities		(31,358	)		22,172			(29,850	)
Increase (decrease) in cash and cash equivalents		3,174			15,590			(17,964	)
Cash and cash equivalents at beginning of period		35,615			20,025			37,989
Cash and cash equivalents at end of period	$	38,789		$	35,615		$	20,025
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (net of amounts capitalized)	$	30,878		$	28,631		$	27,666
Income tax, net		9,071			380			1,368

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)
Balance, January 1, 2007	$	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
Add (deduct):
Net income		—			21,259			—		21,259
Common dividends/return of capital		(3,026	)		(18,974	)		—		(22,000	)
Balance, December 31, 2008		423,869			7,472			—		431,341
Add (deduct):
Net income		—			28,972			—		28,972
Common dividends/return of capital		—			(30,583	)		—		(30,583	)
Balance, December 31, 2009	$	423,869		$	5,861		$	—	$	429,730

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 is owned by 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. Holdings acquired Southern Star in 2005. Southern Star 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 February 10, 2010, CDP entered into an agreement to sell its 40 percent ownership interest in Holdings to Morgan Stanley Infrastructure Partners and certain other affiliated investment funds managed by Morgan Stanley Infra structure, Inc., or MSIP. The sale became effective on March 9, 2010.

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, 2009, Central had transportation customer contracts with approximately 182 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 567 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 half 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.

2. Accounting Policies

On June 3, 2009, the Financial Accounting Standards Board, or FASB, approved the Accounting Standards Codification, or ASC, in an effort to reduce the complexity of accounting standards and to facilitate international convergence. The implementation of the ASC has not changed GAAP, but has reorganized the literature and naming mechanism of existing topics. The Company’s consolidated financial statements and related footnotes have remained unchanged as a result of the Codification.

The Company believes that, of its significant accounting policies, the following may involve a higher degree of judgment or complexity.

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 accounting principles generally accepted in the United States, or GAAP, requires management to make estimates and assumptions that affect the amounts reported on the accompanying consolidated financial statements and notes. Actual results could differ from those estimates.

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 the Effects of Certain Types of Regulation Topic of the ASC. 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.

48

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, 2009 and 2008 and classified as current or noncurrent depending on the expected timing of recovery (expressed in thousands):

	2009			2008
Current Assets:
Environmental costs	$	750		$	750
Fuel costs		—			1,593
Total Current Assets		750			2,343
Noncurrent Assets:
Environmental costs		1,403			1,555
Income taxes on AFUDC equity		4,375			4,382
Gas imbalance cash cost recoverable		117			153
Postretirement benefits other than pensions		15,202			13,965
Pensions		26,307			23,995
Asset retirement obligations		2,390			2,491
Long-term disability		57			326
Total Noncurrent Assets		49,851			46,867
Total Assets		50,601			49,210
Current Liabilities:
Costs refundable to customers		(1,674	)		—
Total Current Liabilities		(1,674	)		—
Noncurrent Liabilities:
Gas imbalance cash cost refundable		(338	)		(438	)
Postretirement benefits other than pensions		(1,729	)		—
Total Noncurrent Liabilities		(2,067	)		(438	)
Total Liabilities		(3,741	)		(438	)
Net Regulatory Assets	$	46,860		$	48,772

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

Property, plant, and equipment are recorded at cost. 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 2005 acquisition of the Company. 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, 2009, 2008 and 2007 was approximately $32.2 million, $29.3 million, and $27.5 million, respectively.

Goodwill

The Company has recorded $324.8 million of Goodwill, a result of the 2005 acquisition of the Company. Goodwill is not amortized and is subject to an annual impairment test as of December 31, or more frequently if certain conditions exist in accordance with the Goodwill and Other Intangible Assets Topic of the ASC. In conducting the impairment test, the fair value of the Company is compared to its carrying value including goodwill. If the fair value exceeds the carrying amount, then no impairment exists. If the carrying amount exceeds the fair value, further analysis is performed to assess impairment.

The Company’s determination of fair value is based on an income approach with an appropriate risk-adjusted discount rate. Any identified impairment would result in an adjustment to the Company’s results of operations.

The Company performed its annual impairment test of goodwill in 2009, 2008 and 2007, none of which resulted in the recognition of an impairment loss.

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 uncollectible, 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 $0.01 million at December 31, 2009 and 2008.

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 the Accounting for Income Taxes.

The use of net operating loss carryforwards occurring prior to the acquisition of the Company by Holdings 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 accordance with the Accounting for Uncertainty in Income Taxes, the Company records interest related to uncertain tax positions as a part of Interest expense on the accompanying Statements of Operations. Any penalties are recognized as part of Miscellaneous expense on the accompanying Statements of Operations. The Company currently does not have a liability for tax penalties or interest related to uncertain tax positions. Comparable amounts for 2008 were not material.

Southern Star operates under a Federal and State Income Tax Policy that governs the allocation and payment of tax liabilities of Holdings, Southern Star and Central. This policy provides that Southern Star will file consolidated tax returns  on behalf of itself, Holdings and Central and will pay all taxes shown thereon to be due. Central generally 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, 2009 were $0.2 million and $0.4 million, respectively; for the year ended December 31, 2008 were $0.3 million and $0.6 million, respectively; and for the year ended December 31, 2007 were $0.3 million and $0.6 million, respectively.   

Gas Receivables/Payables

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

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

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

Inventory Valuation

Inventory consists primarily of materials and supplies and is accounted for 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 concerning Accounting for Conditional Asset Retirement Obligations, Central has 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 Standards for Hazardous Air Pollutants, or NESHAPs, that regulates the use of asbestos. The amount of the regulatory asset and the related ARO liability on the accompanying Consolidated Balance Sheet at December 31, 2009 was $2.4 million and $2.8 million respectively. The amount of the regulatory asset and the related ARO liability on the accompanying Consolidated Balance Sheet at December 31, 2008 was $2.5 million and $2.6 million respectively. Central began recovering asset retirement obligations in its ra tes in 2008.

Long-Lived Assets

Consistent with the Accounting for the Impairment or Disposal of Long-Lived Assets Topic of the ASC, 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 reduce the carrying amount to fair market value to the extent necessary. Application of this standard for the years ended December 31, 2009, 2008 and 2007, did not result in an impairment loss.

 Fair Value Measurements

The Fair Value Measurements Topic of the ASC, which defines fair value, establishes a framework for measuring fair value in accordance with GAAP, and expands disclosures about fair value measurements to include the methods and assumptions used to measure fair value and the effect of fair value measures on earnings. Fair Value Measurements requires the fair value of an asset or liability to be based on market-based measures which reflect the credit risk of the Company. Additionally, in October 2008, FASB issued a Staff Position concerning Determining the Fair Value of a Financial Asset when the Market for That Asset is Not Active.   Determining the Fair Value of a Financial Asset when the Market for That Asset is Not Active clarifies the adoption of Fair Value Measurements in a market that is not active. The Company adopted the provisions of Fair Value Measurements related to financial assets and liab ilities as of January 1, 2008 and for non-financial assets and liabilities as of January 1, 2009. Fair Value Measurements does not require new fair value measurements. The adoption of Fair Value Measurements did not have a material impact on the Company’s financial position or operating results.

In February 2007, the FASB issued The Fair Value Option for Financial Assets and Financial Liabilities Topic of the ASC. The Fair Value Option for Financial Assets and Financial Liabilities is elective for fiscal years that began after November 15, 2007 on a prospective basis. The Fair Value Option for Financial Assets and Financial Liabilities allows companies to measure certain financial assets and financial liabilities at fair market value and to report changes in the fair market value in earnings. The Company did not elect the fair value option for any of its financial assets and financial liabilities.

 Recent Accounting Standards

In December 2007, the FASB issued the Business Combinations Topic of the ASC, which establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquired business. The statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The Company will apply the provisions of Business Combinations to business combinations for which the acquisition date is on or after January 1, 2009.

In March 2008, the FASB issued the Disclosures about Derivative Instruments and Hedging Activities-an amendment of Accounting for Derivative Instruments and Hedging Activities Topic of the ASC.  The new standard is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, results of operations and cash flows. The new standard also improves transparency about how and why a company uses derivative instruments and how derivative instruments and related hedged items are accounted for under Accounting for Derivative Instruments and Hedging Activities. The adoption of Disclosures about Derivative Instruments and Hedging Activities on January 1, 2009 did not have a material impact to the Company’s existing disclosures.

3. Financing

At December 31, 2009 and 2008, long-term debt consisted of the following (expressed in thousands):

	December 31, 2009			December 31, 2008
6.0% Senior Notes due 2016	$	230,000		$	230,000
6.75% Registered Senior Notes due 2016		200,000			200,000
6.75% Unregistered Senior Notes due 2016		50,000			50,000
Capitalized lease obligation		5,725			6,445
Unamortized debt discount		(3,926	)		(4,560	)
Total debt		481,799			481,885
Less current capitalized lease obligation		745			720
Total long-term debt	$	481,054		$	481,165

8.5% Notes

In June 2007, Southern Star issued a notice of full redemption to the holders of its 8.5% Notes due 2010, 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% Registered Notes

At December 31, 2009, we had outstanding $200.0 million of 6.75% Notes registered under the Securities Act of 1933 as amended, or 6.75% Registered Notes. The Bank of New York Trust Company, N.A. serves as trustee pursuant to the related Indenture. Interest is payable semi-annually on March 1 and September 1 of each year. The 6.75% Registered Notes mature on March 1, 2016 and have an overall effective interest rate of 7.06%. The 6.75% Registered 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% Registered 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% Registered 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.

Beginning March 1, 2009, we have the right to redeem all or part of the 6.75% Registered 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.

6.75% Unregistered Notes

On April 16, 2008, Southern Star completed the sale of $50.0 million aggregate principal amount of 6.75% Senior Notes due 2016, or 6.75% Unregistered Notes, in a private placement. In connection with the offering, the Company entered into an indenture dated April 16, 2008 by and between Southern Star and The Bank of New York Trust Company, N.A., as trustee.

Interest is payable semi-annually on March 1 and September 1 of each year, beginning on September 1, 2008.  The 6.75% Unregistered Notes will mature on March 1, 2016 and have an overall effective interest rate of 8.55%. The 6.75% Unregistered Notes are senior unsecured obligations and rank equal in rights of payment to all of Southern Star’s 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. All covenants, restrictions, and other terms and conditions are identical to those for the 6.75% Registered Notes described above.

Central’s 6.0% Notes

At December 31, 2009, Central had outstanding $230.0 million aggregate principal amount of 6.0% Senior Notes due 2016, or 6.0% Notes. The Bank of New York Trust Company, N.A. serves as trustee under the related indenture. The indenture governing the 6.0% Notes 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. Approximately $9.5 million of assets are included in Property, plant and equipment as a capital lease and are being amortized over the same life as similar assets.  Amortizat ion of the assets is included in Depreciation and amortization. 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

As of December 31, 2009, 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)
2010	$	—	$	745
2011		—		235
2012		—		250
2013		—		265
2014		—		280
After 2014		480,000		3,950
Total	$	480,000	$	5,725

4. 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 12 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 conference to discuss the issues raised in the protests. Subsequent to the technical conference, Central settled all issues with all parties by agreeing to absorb a portion of the losses related to the girth weld failure and the storage lateral line failure. The settlement and loss, net of insurance recoveries, resulted in no material adverse impact on its financial position or results of operations.

On November 26, 2008, Central made its annual fuel filing to establish its transmission and storage fuel and loss reimbursement percentages for 2009 based on the actual fuel and loss for the 12 months ended September 30, 2008. One party protested the inclusion of gas losses related to a storage lateral line failure. On December 30, 2008, the FERC issued an Order disallowing the recovery of the losses related to the storage lateral line failure in its annual fuel filing. Central has complied with the Order and in December 2008 charged to expense approximately $0.2 million related to the disallowance.  

General Rate Issues

On April 30, 2008, Central filed a general rate case under FERC Docket No. RP08-350 which became effective November 1, 2008, subject to the condition that Central refund to customers any amounts it collects in excess of the rates ultimately allowed. This general rate proceeding increased Central’s transportation, storage and related rates, and also provided for various changes to a number of the terms and conditions of customer services which are provided for in Central’s tariff. On November 17, 2008, the parties reached a settlement to resolve all issues related to this proceeding. The settlement provided for Central to bill the settlement rates beginning November 1, 2008, on an interim basis and, if approved, no refunds would be due. The settlement was filed with the FERC on December 11, 2008, and all comments filed by various parties were in support of the settlement. On January 13, 2009 , the Administrative Law Judge certified the settlement to the FERC and on June 1, 2009, the FERC issued an Order approving the settlement without modification. The settlement rates were designed to increase Central’s revenues approximately $20.0 million above revenues for the 12 months ended January 31, 2008, the base period covered in its filing. Under the terms of the settlement, Central is required to file a rate case no later than December 1, 2013.

 On October 22, 2008, the FERC issued an “Order Approving Audit Report and Directing Compliance and Other Corrective Actions,” or Audit Order,  in Docket No. PA08-1-000, as a result of a Compliance Audit conducted by the Division of Audits, or DA, within the Office of Enforcement of the FERC, pursuant to Section 8 of the NGA. This audit examined Central’s compliance with certain FERC accounting, reporting and transportation regulations, North American Energy Standards Board standards and provisions of Central’s FERC gas tariff.

The Audit Order found instances where Central did not comply with certain filing and electronic posting requirements of the FERC. The FERC imposed no penalty on Central, and instead imposed remedial requirements only. The Audit Order noted that the findings “implicated substantive non-compliance by [Central]” and that the FERC “seriously considered pursuing the imposition of penalties for the violations.” However, the FERC took into consideration Central’s “willingness to take corrective action” and its “exemplary cooperation during the audit” and the fact that a predecessor owner of Central was “responsible for most of the serious violations.” The FERC specified corrective actions to be taken by Central and issued the Audit Order publicly “to provide guidance to other companies similarly situated.”

The Audit Order contains a list of remedies to address the DA’s findings, some of which Central has either already completed or is in the process of completing. The Audit Order also contained a number of recommendations for ensuring compliance, including the implementation of a comprehensive compliance program, consistent with recent FERC policy statements.

The Audit Order required Central to file a “compliance plan” outlining the steps it will take to implement the corrective actions recommended by November 20, 2008, with quarterly reports to follow. The Audit Order also required certain information with respect to “non-conforming” shipper agreements to be filed within 120 days of the date of the Audit Order, and directed Central to file within 150 days of the Audit Order all unfiled agreements that contain non-conforming terms and conditions. Central has made all of the required filings and continues to file quarterly reports on the status of its compliance plan. As there were no monetary penalties levied and although there will be costs and time spent by Central on implementing the Audit Order’s recommended corrective actions, we do not expect that this action by the FERC will have any material adverse effect on our future financial po sition, results of operations, or cash flows.

Environmental and Safety Matters

Environmental

Central has identified polychlorinated biphenyl 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 an undiscounted liability of approximately $2.2 million at December 31, 2009 and $2.3 million at December 31, 2008 representing the current estimate of future environmental cleanup costs, most of which is expected to be incurred over the next two to three 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. Based on analysis of these regulations, management does not expect there to be a material impact to Central’s existing operations. On March 5, 2009, the EPA proposed new emission standards that could apply to certain of Central’s existing reciprocating engines. These regulations are scheduled to be finalized during 2010, and any compliance obligations would likely have to be completed during 2013.

On September 22, 2009, the EPA promulgated a mandatory greenhouse gas reporting rule that will impose requirements for some of Central’s existing operations; however, these requirements will not have a material impact on Central’s existing operations during 2010. There are also other various proposed rules and possible federal legislation related to greenhouse gas emissions that could impact Central’s existing operations. Central continues to monitor the progress of these proposed rules and will determine any impact once the regulations have been promulgated.

All of Central’s facilities are located in areas currently designated as being in “attainment” of all National Ambient Air Quality Standards, or 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. Final area designations are set to be issued by the EPA in March 2011 and a more thorough assessment can be made at that time. On January 6, 2010, the EPA proposed even more stringent NAAQS for ozone. Central will continue to track these developments and any potential impact on existing operations. The final standards are currently scheduled for promulgation by August 31, 2010. The proposal included a range of values; therefore, the fin al standard and any impacts are not quantifiable at this time.  

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

Legal Issues

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

In 1998, Jack Grynberg, an individual, sued Central and approximately 300 other energy companies, purportedly on behalf of the federal government, or qui tam. Invoking the False Claims Act, Grynberg alleged that the defendants had mismeasured the volume and wrongfully analyzed the heating content of natural gas, causing underpayments of royalties to the United States. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, or civil penalty, attorney fees and costs. The Department of Justice declined to intervene in Grynberg’s qui tam cases, which were consolidated for pretrial purposes before a single judge in the United States District Court, or Trial Court, for the District of Wyoming. Initial discovery was limited to public disclosure/original source jurisdictional issues. On June 4, 2004, motions, with supporti ng 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 co unsel filed notices of appeal with the United States Court of Appeals for the Tenth Circuit, or Appellate Court, where his appeals were docketed as In re Natural Gas Royalties Qui tam Litigation, Case No. 06-8099. Oral argument occurred on September 25, 2008. On March 17, 2009, the Appellate Court affirmed the Trial Court’s dismissal of Grynberg’s complaints on jurisdictional grounds related to the “original source” defense asserted by Central. On March 20, 2009, Grynberg filed a motion for an extension of time to file a petition for rehearing of the Appellate Court’s decision. The Court granted Grynberg’s motion and he subsequently filed his petition for rehearing on April 14, 2009. On May 4, 2009, the Appellate Court denied Grynberg’s petition for rehearing. On August 4, 2009, Grynberg filed a petition (Number 09-170) for certiorari review with the United States Supreme Court. On October 5, 2009, the Supreme Court denied Grynberg’s petition. The parties contin ue to await the Trial Court’s Ruling on the defendants’ motion(s) for attorney’s 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 under measured the volume of, and therefore have underpaid for, the natural gas they have obtained from or measured for Plaintiffs. Plaintiffs seek unspecified actual damages, attorney fees, pre- and post-judgment interest, and reserved the right to plead for punitive damages. On August 22, 2003, an answer to that pleading was filed on behalf of Central. Despite a denial by the Court on April 10, 2003 of their original motion for class certification, the Plaintiffs continue to seek the certification of a class. The Plaintiffs’ motion seeking class certification for a second time was fully briefed and the Court heard oral argument on the motion on April 1, 2005.  On September 18, 2009, the Court denied the Plaintiff’s most recent motion for class certification. The Plaintiffs filed a motion to reconsider that ruling on October 2, 2009. The defendants, including Central, filed a response in opposition to the Plaintiffs’ motion for reconsideration on January 18, 2010.  The Plaintiffs filed a reply, and oral argument, which was presented before a different judge, was heard on February 10, 2010. It is unknown when the Court will rule on the pending motion (which will likely be decided by a different judge), or whether the Plaintiffs will petition for an appeal if their motion for reconsideration is denied.   

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 under measured 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 Plaintiffs’ second class certification motion in Price Litigation I, was fully briefed and the Court heard oral argument on this motion on April&nbs p;1, 2005. On September 18, 2009, the Court denied the Plaintiffs’ motion for class certification. The Plaintiffs filed a motion to reconsider that ruling on October 2, 2009. The defendants, including Central, filed a response in opposition to the Plaintiffs’ motion for reconsideration on January 18, 2010.  The Plaintiffs filed a reply, and oral argument, which was presented before a different judge, was heard on February 10, 2010. It is unknown when the Court will rule on the pending motion (which will likely be decided by a different judge), or whether the Plaintiffs will petition for an appeal if their motion for reconsideration is denied.

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 flows. Costs incurred to date of defending pending cases have not been material.

49

5. Income Taxes

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

	For the Year Ended December 31, 2009		For the Year Ended December 31, 2008			For the Year Ended December 31, 2007
Current provision (benefit):
Federal	$	6,154	$	435		$	364
State		1,823		715			539
		7,977		1,150			903
Deferred provision:
Federal		9,572		10,968			12,285
State		1,461		1,720			2,111
		11,033		12,688			14,396
Income tax provision	$	19,010	$		13,838	$	15,299

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

	For the Year Ended December 31, 2009		For the Year Ended December 31, 2008		For the Year Ended December 31, 2007
U.S. statutory rate		35.0%		35.0%		35.0%
State income taxes, net of federal taxes benefits		4.5%		4.5%		4.5%
Permanent items:
Other, net		0.1%		(0.1)%		0.2%
Income tax provision		39.6%		39.4%		39.7%

Significant components of deferred tax assets and liabilities as of December 31, 2009 and 2008 are as follows (expressed in thousands):

		2009			2008
Deferred tax assets:
Tax benefit carryforwards	$	69		$	4,975
Accrued environmental costs		842			902
Accrued employee benefits		20,292			16,803
Intangibles		2,452			2,765
Other		1,589			1,550
Total deferred tax assets		25,244			26,995
Deferred tax liabilities:
Property, plant and equipment		65,455			58,241
Regulatory assets		19,202			17,174
Other		14,156			14,116
Total deferred tax liabilities		98,813			89,531
Net deferred tax liabilities	$	(73,569	)	$	(62,536	)
Classification:
Net current assets	$	2,559		$	5,351
Net long-term liabilities		(76,128	)		(67,887	)
Net deferred tax liabilities	$	(73,569	)	$	(62,536	)

As of December 31, 2009, tax benefit carryforwards of $69,000 are attributable to state income tax net operating losses with a carryforward period of 20 years. As such, these carryforward benefits will expire in 2029 to the extent not used by that date.

The use of net operating loss carryforwards occurring prior to the 2005 acquisition by Holdings 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.

The Accounting for Uncertainty in Income Taxes Topic of the ASC establishes the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with Income Taxes. Accounting for Uncertainty in Income Taxes 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 Accounting for Uncertainty in Income Taxes resulted in a $14,000 charge to retained earnings. As of December 31, 2009 and 2008, Southern Star had no net unrecognized tax benefits.

Pursuant to the Accounting for Uncertainty in Income Taxes Topic of the ASC, 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. The Company currently does not have a liability for tax penalties or interest related to uncertain tax positions. Comparable amounts for 2008 and 2007 were not significant.

As of December 31, 2009 and 2008, the Company remained subject to examination by Federal and State jurisdictions for the tax years beginning 2003 and November 16, 2002, respectively 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.

6. Dividends and Related Restrictions

Certain of the Company’s debt instruments 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 related debt agreements.

7. Financial Instruments

The Fair Value Measurements and Disclosures Topic of the ASC establishes a three-level hierarchy for fair value measurements. The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date.

•

Level 1 – Valuation is based upon unadjusted quoted prices for identical assets or liabilities in active markets.

•

Level 2 – Valuation is based upon quoted prices for similar assets and liabilities in active markets, or other inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instruments.

•

Level 3 – Valuation is based upon other unobservable inputs that are significant to the fair value measurements.

The classification of fair value measurements within the hierarchy is based upon the lowest level of input that is significant to the measurement. The Company had no financial assets or liabilities required to be measured at fair value on a recurring basis as of December 31, 2009 and 2008. The carrying value of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the relative short maturity of these instruments. The fair value of the Company’s debt is based on market prices for these instruments and was $475.2 million, consisting of approximately $195.9 million for the 6.75% Registered Notes, $44.6 million for the 6.75% Unregistered Notes and $234.7 million for the 6.0% Notes at December 31, 2009, respectively.

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 these parties is limited to the face value of their respective receivables. As a general policy, collateral is not required for receivables, but customers’ financial position and creditworthiness are evaluated regularly.

8. Employee Benefit Plans

The Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans Topic of the ASC 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 the Company to apply the accounting prescribed by the Accounting for the Effects of Certain Types of Regulations Topic of the ASC, the Company does not recognize changes in the funded status in comprehensive income but recognizes them as changes to the related regulatory asset or liability, pending future recovery or refund through its rates.

Pursuant to the Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans Topic of the ASC, no portion of the related liabilities are classified as current because plan assets exceed the value of benefit obligations expected to be paid within the 12 months ending December 31, 2010. In addition, no plan assets are expected to be returned to the Company during the 12 months ending December 31, 2010.

The terms of the RP08-350 rate settlement allow Central to recover, in its rates, $9.5 million annually for pension benefits and postretirement benefits other than pensions. In comparison, Central’s previous rate settlement had allowed recoveries of $7.5 million annually. Central must fund the amounts recovered into irrevocable trusts established solely for the provision of the aforementioned benefits in a manner that permits Central to maximize the tax deductibility of the deposits and adhere to minimum and maximum funding requirements. Central’s $9.5 million annual funding requirement may only be reduced by amounts funded in excess of recoveries in prior years. Central, as of December 31, 2009, had funded a total of $0.8 million in excess of its recoveries. Central’s funding of $10.0 million in 2009 was $0.5 million higher than its 2009 recoveries. Central’s funding of $8.1 million in 200 8 was $0.3 million higher than its 2008 recoveries, which consisted of $6.2 million recovered pursuant to the previous rate settlement and $1.6 million recovered pursuant to the RP08-350 rate settlement.

Union Retirement Plan

Central maintains a separate non-contributory defined benefits pension plan, which covers union employees, or Union Plan. The Union Plan covers 35% of the 480 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, 2009 and 2008 (expressed in thousands):

		2009			2008
Change in benefit obligation:
Benefit obligation at beginning of year	$	26,259		$	33,932
Service cost		1,010			1,231
Interest cost		1,457			1,804
Actuarial loss/(gain)		5,522			(3,122	)
Benefits paid		(548	)		(567	)
Settlements		(3,128	)		(6,622	)
Transfers to non-union plan		(704	)		(397	)
Benefit obligation at end of year		29,868			26,259
Change in plan assets:
Fair value of plan assets at beginning of year		11,336			15,025
Actual return/(loss) on plan assets		2,548			(4,448	)
Employer contributions		5,672			8,100
Benefits paid		(548	)		(567	)
Settlements		(3,128	)		(6,622	)
Transfers to non-union plan		(337	)		(152	)
Fair value of plan assets at end of year		15,543			11,336
Funded status/Accrued benefit cost	$	(14,325	)	$	(14,923	)

Pursuant to the Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans Topic of the ASC, the accrued benefit cost in 2009 and 2008 includes $6.1 million and $2.7 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 $26.0 million and $22.4 million at December 31, 2009 and 2008, respectively.

Lump sum distributions of $3.1 million and $6.6 million were paid to plan participants in 2009 and 2008, respectively.  The Union Plan’s distributions in 2009 and 2008 exceeded each year’s respective service and interest cost, triggering settlement accounting under Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits Topic of the ASC. The effects of the 2009 settlements were calculated as of January 31, 2009 and as of December 31, 2009 and the effects of the 2008 settlements were calculated as of March 31, 2008 and as of December 31, 2008.  

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

	For the Year Ended December 31, 2009			For the Year Ended December 31, 2008			For the Year Ended December 31, 2007
Components of net periodic pension expense:
Service cost	$	1,010		$	1,231		$	1,269
Interest cost		1,457			1,804			1,838
Expected return on plan assets		(1,068	)		(1,088	)		(1,211	)
Recognized actuarial loss		49			—			—
Employee transfers		(328	)		(232	)		(263	)
Settlement recognition		528			544			53
Regulatory recovery of costs		3,672			5,574			3,571
Net periodic pension expense	$	5,320		$	7,833		$	5,257

Approximately $0.1 million of amortization of net losses is expected to be reflected in expense in 2010.

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

	For the Year Ended December 31, 2009	For the Year Ended December 31, 2008	For the Year Ended December 31, 2007
Discount rate	5.48%	6.03%	6.17%
Rate of compensation increase	2.50%	3.75%	4.35%

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

	For the Period February 1  through December 31, 2009 *	For the Period January 1 through    January 31,    2009	For the Period April 1  through December 31, 2008 *	For the Period January 1 through    March 31,    2008	For the Period May 1  through December 31, 2007 *	For the Period January 1 through    April 30,    2007
Discount rate	6.31%	6.03%	6.34%	6.17%	5.75%	5.69%
Expected return on plan assets	8.50%	8.50%	8.50%	8.50%	8.50%	8.50%
Rate of compensation increase	4.35%	3.75%	4.35%	4.35%	3.85%	3.75%

*

Changes in 2009, 2008 and 2007 weighted-average assumptions related to settlement accounting under the Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits Topic of the ASC.

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 following are the fair values of the Union Plan’s assets for the period indicated (in thousands):

	As of December 31, 2009
Asset Category	Total Fair Value	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Observable Inputs (Level 2)
Cash & Cash Equivalents	$ 558	$ -	$ 558
Equity and Exchange Traded Funds:
Emerging Markets	625	625	-
International Large Cap Core	730	730	-
International Large Cap Growth	395	395	-
International Large Cap Value	619	619	-
Large Cap Growth	2,916	2,916	-
Large Cap Value	2,169	2,169	-
Mid Cap Growth	963	963	-
Mid Cap Value	896	896	-
Small Cap Core	461	461	-
Small Cap Growth	509	509	-
Fixed Income:
Government Agency Obligations	1,183	-	1,183
Government Treasury Obligations	479	479	-
Municipal Obligations	196	-	196
Corporate Obligations	2,801	-	2,801
Other:
Accrued Income	43	1	42
Total	$ 15,543	$ 10,763	$ 4,780

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	35.0%	45.0%	65.0%
Non-U.S. equities	5.0%	10.0%	15.0%
Total equities	40.0%	55.0%	70.0%
Fixed income and cash	30.0%	45.0%	60.0%
Special situations	0.0%	0.0%	5.0%

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 is responsible for rebalancing the assets and ensuring that the Trustee and the Investment Managers, as applicable, minimize deviations from their target asset allocation mixes.

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

In 2010, the Company expects to contribute to the Union Plan a minimum of $2.0 million up to an amount that, when combined with the funding to the Non-Union Pension is, at a minimum, equivalent to the $8.7 million required by the Company’s RP08-350 rate settlement.

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):

2010	$      2,746
2011	2,470
2012	2,895
2013	4,273
2014	3,915
Years 2015 through 2019	16,353

50

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, 2009 and 2008 (expressed in thousands):

	2009			2008
Change in benefit obligation:
Benefit obligation at beginning of year	$	14,935		$	14,030
Service cost		2,293			2,516
Interest cost		933			913
Actuarial loss/(gain)		4,907			(2,432	)
Benefits paid		(649	)		(489	)
Transfers from union plan		704			397
Benefit obligation at end of year		23,123			14,935
Change in plan assets:
Fair value of plan assets at beginning of year		6,130			9,498
Actual return/(loss) on plan assets		1,761			(3,031	)
Employer contributions		4,374			—
Benefits paid		(649	)		(489	)
Transfers from union plan		337			152
Fair value of plan assets at end of year		11,953			6,130
Funded status/Accrued benefit cost	$	(11,170	)	$	(8,805	)

Pursuant to the Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans Topic of the ASC, the accrued benefit cost in 2009 and 2008 includes $5.6 million and $1.6 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 $18.5 million and $12.0 million at December 31, 2009 and 2008, respectively.

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

	For the Year Ended December 31, 2009			For the Year Ended December 31, 2008			For  the Year Ended December 31, 2007
Components of net periodic pension expense:
Service cost	$	2,293		$	2,516		$	2,453
Interest cost		932			913			652
Expected return on plan assets		(807	)		(807	)		(665	)
Employee transfers		328			232			263
Regulatory recovery/(accrual) of costs		1,434			(2,854	)		(460	)
Net periodic pension expense	$	4,180		$	—		$	2,243

Approximately $0.2 million of amortization of net losses is expected to be reflected in expense in 2010.

51

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

	For the Year Ended December 31, 2009		For the Year Ended December 31, 2008		For the Year Ended December 31, 2007
Discount Rate		5.79%		6.07%		6.38%
Rate of compensation increase		3.75%		3.75%		4.35%

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

	For the Year Ended December 31, 2009		For the Year Ended December 31, 2008		For the Year Ended December 31, 2007
Discount Rate		6.07%		6.38%		5.83%
Expected return on plan assets		8.50%		8.50%		8.50%
Rate of compensation increase		3.75%		4.35%		3.75%

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 following are the fair values of the Non-Union Plan’s assets for the period indicated (expressed in thousands):

	As of December 31, 2009
Asset Category	Total Fair Value	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Observable Inputs (Level 2)
Cash & Cash Equivalents	$ 287	$ -	$ 287
Equity and Exchange Traded Funds:
Emerging Markets	481	481	-
International Large Cap Core	549	549	-
International Large Cap Growth	299	299	-
International Large Cap Value	475	475	-
Large Cap Growth	2,244	2,244	-
Large Cap Value	1,670	1,670	-
Mid Cap Growth	741	741	-
Mid Cap Value	690	690	-
Small Cap Core	355	355	-
Small Cap Growth	391	391	-
Bond Funds:
Global Income	605	605	-
Intermediate Investment Grade Debt	469	469	-
Short – Intermediate Investment Grade Debt	474	474	-
Short Investment Grade Debt	1,376	1,376	-
Total Return	847	847	-
Total	$ 11,953	$ 11,666	$ 287

52

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.

Percent of Total Assets at Market Value

Asset Class	Minimum	Target	Maximum
U.S. equities	35.0%	45.0%	65.0%
Non-U.S. equities	5.0%	10.0%	15.0%
Total equities	40.0%	55.0%	70.0%
Fixed income and cash	30.0%	45.0%	60.0%
Special situations	0.0%	0.0%	5.0%

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 is responsible for rebalancing the assets and ensuring that the Trustee and the Investment Managers, as applicable, minimize deviations from their target asset allocation mixes.

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

In 2010, the Company expects to contribute to the Non-Union Plan a minimum of $2.7 million up to an amount that, when combined with the funding to the Union Pension is, at a minimum, equivalent to the $8.7 million required by the Company’s RP08-350 rate settlement.

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):

2010	$      1,262
2011	1,375
2012	2,103
2013	2,232
2014	2,880
Years 2015 through 2019	18,319

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, 2009 and 2008 (expressed in thousands):

	2009			2008
Change in benefit obligation:
Benefit obligation at beginning of year	$	37,582		$	34,109
Service cost		484			348
Interest cost		2,136			2,152
Actuarial loss		2,433			2,644
Medicare Part D subsidy recognition		4			232
Benefits paid		(2,436	)		(1,903	)
Benefit obligation at end of year		40,203			37,582
Change in plan assets:
Fair value of plan assets at beginning of year		23,280			34,909
Actual return/(loss) on plan assets		5,545			(9,726	)
Benefits paid		(2,436	)		(1,903	)
Fair value of plan assets at end of year		26,389			23,280
Funded status/Net accrued benefit cost	$	(13,814	)	$	(14,302	)

Pursuant to the Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans Topic of the ASC, the net accrued benefit costs in 2009 and 2008 include $9.6 million and $12.0 million, respectively, of previously unrecognized net losses. 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 accrued 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, for the periods indicated (expressed in thousands):

	For the Year Ended December 31, 2009			For the Year Ended December 31, 2008			For the Year Ended December 31, 2007
Components of net periodic benefit expense:
Service cost	$	484		$	348		$	417
Interest cost		2,136			2,152			1,981
Expected return on plan assets		(1,878	)		(2,867	)		(2,808	)
Recognized actuarial loss/(gain)		1,239			(58	)		—
Regulatory (accrual)/recovery of costs		(1,981	)		425			410
Net periodic benefit expense	$	—		$	—		$	—

Approximately $0.8 million of amortization of net losses is expected to be reflected in expense in 2010.

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

	For the Year Ended December 31, 2009		For the Year Ended December 31, 2008	For the Year Ended December 31, 2007
Discount rate		5.83%	6.03%	6.39%
Healthcare cost trend rate assumed for next year		7.75%	8.75%	9.75%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		4.85%	4.85%	5.15%
Year that the rate reaches the ultimate trend		2015	2012	2012

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

	For the Year Ended December 31, 2009	For the Year Ended December 31, 2008	For the Year Ended December 31, 2007
Discount rate	6.03%	6.39%	5.84%
Expected return on plan assets (non-union/union)	6.67%/8.50%	6.67%/8.50%	6.67%/8.50%

Assumed health care cost trend rates for the periods indicated:

	December 31, 2009		December 31, 2008		December 31, 2007
Healthcare cost trend rate assumed for next year		7.75%		8.75%		11.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		4.85%		5.15%		4.85%
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	$	330	$	(271)
Effect on accumulated postretirement benefit obligation	$	5,375	$	(4,142)

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 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 following are the fair values of the Welfare Plan’s assets for the period indicated (expressed in thousands):

	As of December 31, 2009
Asset Category	Total Fair Value	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Observable Inputs (Level 2)
Cash & Cash Equivalents	$ 809	$ 809	$ -
Equity and Exchange Traded Funds:
Emerging Markets	1,048	1,048	-
International Large Cap Core	1,237	1,237	-
International Large Cap Growth	657	657	-
International Large Cap Value	1,031	1,031	-
Large Cap Growth	4,967	4,967	-
Large Cap Value	3,693	3,693	-
Mid Cap Growth	1,654	1,654	-
Mid Cap Value	1,535	1,535	-
Small Cap Core	792	792	-
Small Cap Growth	875	875	-
Fixed Income:
Government Agency Obligations	1,656	-	1,656
Government Treasury Obligations	465	465	-
Municipal Obligations	43	-	43
Corporate Obligations	5,995	-	5,995
Bond Funds:
Global Income	43	43	-
Intermediate Investment Grade Debt	33	33	-
Short – Intermediate Investment Grade Debt	34	34	-
Short Investment Grade Debt	98	98	-
Total Return	60	60	-
Other:
Accrued Income	63	3	60
Benefits Receivable	96	-	96
Benefits Payable	(495)	-	(495)
Total	$ 26,389	$ 19,034	$ 7,355

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	35.0%	45.0%	65.0%
Non-U.S. equities	5.0%	10.0%	15.0%
Total equities	40.0%	55.0%	70.0%
Fixed income and cash	30.0%	45.0%	60.0%
Special situations	0.0%	0.0%	5.0%

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 is 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 2010.

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
2010	$           420	$        1,764	$       2,184
2011	505	1,824	2,329
2012	601	1,854	2,455
2013	710	1,944	2,654
2014	839	1,990	2,829
Years 2015 through 2019	5,812	10,784	16,596

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
2010	$                 6	$          200	$         206
2011	11	222	233
2012	20	249	269
2013	29	269	298
2014	38	292	330
Years 2015 through 2019	436	1,719	2,155

 Other

Central maintains a defined contribution plan covering substantially all employees. Central’s costs related to this plan for the years ended December 31, 2009, 2008, and 2007 were $2.2 million, $2.0 million and $1.8 million, respectively.

9. 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, Inc. Revenues received from MGE were $66.7 million, $59.4 million, and $58.3 million for the years ended December 31, 2009, 2008 and 2007, respectively. Revenues received from KGS were $56.6 million, $51.3 million, and $50.5 million for the years ended December 31, 2009, 2008 and 2007, respectively.

MGE had receivable balances of $5.4 million and $5.4 million for each of the years ended December 31, 2009 and 2008. KGS had receivable balances of $4.9 million and $5.0 million for the years ended December 31, 2009 and 2008, respectively.

10. 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):

2010	$	282
2011		268
2012		268
2013		269
2014		236
After 2014		235
Total	$	1,558

Total rental expense relating to operating leases was approximately $1.3 million, $1.3 million, and $1.0 million for the years ended December 31, 2009, 2008 and 2007, respectively.

11. Related Party Transactions

Central and Western Frontier have 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 2009, 2008 and 2007 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, Southern Star has 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.

12.  Employee Retention Agreements

In 2005, the Company entered into employee retention agreements with the officers of Central. These agreements 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 $1.7 million, $2.0 million and $1.9 million in expenses for each of the years ended 2009, 2008 and 2007, respectively, for such annual payments.

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13. Quarterly Data (Unaudited)

The following summarizes selected quarterly financial data for 2009 and 2008 (expressed in thousands):

	2009
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Operating revenues	$	55,355 33,355		$	54,744		$	55,526		$	55,176
Operating costs and expenses		33,355			35,573			34,354			37,338
Operating income		22,000			19,171			21,172			17,838
Interest expense		8,169			8,155			8,122			8,110
Interest income		(78	)		(71	)		(75	)		(84	)
Miscellaneous other (income) expenses, net		65			(67	)		(134	)		87
Total other expense, net		8,156			8,017			7,913			8,113
Income before income taxes		13,844			11,154			13,259			9,725
Provision for income taxes		5,479			4,425			5,240			3,866
Net Income	$	8,365		$	6,729		$	8,019		$	5,859

	2008
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Operating revenues	$	47,805		$	46,868		$	46,715		$	55,400
Operating costs and expenses		30,336			33,540			33,100			35,040
Operating income		17,469			13,328			13,615			20,360
Interest expense		7,081			7,876			8,084			8,169
Interest income		(164	)		(293	)		(271	)		(149	)
Miscellaneous other (income) expenses, net		(300	)		(150	)		(189	)		(19	)
Total other expense, net		6,617			7,433			7,624			8,001
Income before income taxes		10,852			5,895			5,991			12,359
Provision for income taxes		4,303			2,234			2,413			4,888
Net Income	$	6,549		$	3,661		$	3,578		$	7,471

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Exhibit 12.1

Ratio of Earnings to Fixed Charges

(In thousands)

	Post-acquisition															Pre-acquisition
	Year Ended December 31, 2009			Year Ended December 31, 2008			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
Fixed Charges:
Interest expense	$	32,556		$	31,210		$	28,842		$	29,964		$	11,337			$	25,169
Capitalized interest		152			317			309			222			50				31
Fixed Charges	$	32,708		$	31,527		$	29,151		$	30,186		$	11,387			$	25,200
Earnings:
Add:
Income before income taxes	$	47,982		$	35,097		$	38,506		$	43,929		$	16,150			$	12,477
Fixed charges (calculated above)		32,708			31,527			29,151			30,186			11,387				25,200
Deduct:
Capitalized interest		(152	)		(317	)		(309	)		(222	)		(50	)			(31	)
Earnings	$	80,538		$	66,307		$	67,348		$	73,893		$	27,487			$	37,646
Ratio of Earnings to Fixed Charges1		2.46			2.10			2.31			2.45			2.41				1.49

 (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) OR 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(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a - 15(e) and 15d - 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(s) 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 the 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 15, 2010
	Jerry L. Morris

79

Exhibit 31.2

CERTIFICATION PURSUANT TO RULES 13a – 14(a) OR 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(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a - 15(e) and 15d - 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(s) 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 the 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 15, 2010
	Susanne W. Harris

80

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, 2009 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 15, 2010
	Jerry L. Morris
By:	/s/ Susanne W. Harris	Chief Financial Officer	March 15, 2010
	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.

81