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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

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 x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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 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 23, 2012, registrant had 100 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE - None

TABLE OF CONTENTS

2011 FORM 10-K

SOUTHERN STAR CENTRAL CORP.

		Page

Forward-Looking Statements		1

	PART I
Item 1.	Business	2
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	16
Item 4.	Reserved	18

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18
Item 6.	Selected Financial Data	19
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	19
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 8.	Financial Statements and Supplementary Data	28
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	28
Item 9A.	Controls and Procedures	28
Item 9B.	Other Information	29

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	29
Item 11.	Executive Compensation	31
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
Item 13.	Certain Relationships and Related Transactions and Director Independence	38
Item 14.	Principal Accounting Fees and Services	39

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	40

FORWARD-LOOKING STATEMENTS

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

•

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

•

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

•

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

•

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

•

our ability to manage costs;

•

the ability of our customers to pay for services;

•

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

•

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

•

our ability to obtain governmental and regulatory approval of various expansion projects as well as our ability to maintain and comply with such approvals;

•

the cost and effects of legal and administrative proceedings;

•

the effect of accounting interpretations and changes in accounting policies;

•

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

•

changes in general economic, market or business conditions; and

•

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

Other factors and assumptions not identified above, including without limitation, those described under 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. 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 is a wholly-owned subsidiary of EFS-SSCC Holdings, LLC, or Holdings, which is indirectly owned by GE Energy Financial Services, Inc., or GE, and Morgan Stanley Infrastructure Partners and certain other affiliated investment funds managed by Morgan Stanley Infrastructure, Inc., or MSIP. All of our outstanding capital stock is held by Holdings.

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, which are its main market areas. As of December 31, 2011, 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 47 Bcf and an aggregate delivery capacity of approximately 1.3 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, 2011, 95% of Central’s operating revenues were obtained through daily firm reservation charges (“rent” charges under firm contracts) and 5% were obtained through commodity charges (“usage” charges based on volumes actually transported or stored under firm and interruptible contracts).

Central’s principal service is the delivery of natural gas to local natural gas distribution companies in the major metropolitan areas it serves. At December 31, 2011, Central had customer transportation contracts with approximately 142 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 512 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 17 years. At December 31, 2011, the average remaining contract life on a volume-weighted basis was approximately four years.

For the year ended December 31, 2011, approximately 86% 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, and Kansas Gas Service Company, or KGS, a division of ONEOK, Inc., accounted for approximately 57% (approximately 31% and 26% respectively) of operating revenues for the year ended December 31, 2011. MGE sells or resells natural gas to residential, commercial and industrial customers principally in certain major metropolitan areas of Missouri. KGS sells or resells natural gas to residential, commercial and industrial customers principally in certain major metropolitan areas of Kansas. Central has had significant business relationships with both of these customers or their predecessors for more than 20 years. No other customer accounted for more than 10% of our revenues in 2011.

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 the 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 Western Oklahoma area will more than offset the projected declines. We believe that the Western Oklahoma area has substantial potential for future drilling and production. Central’s Rawlins-Hesston line, which extends from Wyoming to Kansas, and its Canadian-Blackwell line, which extends from the Texas panhandle to central Oklahoma, generally operate 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 212,000 certificated horsepower. Thirty-two 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:
	2011	2010	2009
Market area	0.6	0.6	0.6
Production area	0.3	0.3	0.3
Production market interface	0.4	0.4	0.4

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

	TBtu per day
Reserved Capacity:
	2011	2010	2009
Market area	2.0	2.0	2.0
Production area	0.4	0.4	0.4
Production market interface	0.9	0.9	0.9

For the years ended December 31, 2011, 2010 and 2009, Central's firm storage deliverability capacity has been 1.3 TBtu/day, 1.2 TBtu/day and 1.2 TBtu/day, respectively.

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 47 Bcf and an aggregate delivery capacity of approximately 1.3 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 64% of our 2011 operating revenues, and as of December 31, 2011, accounted for approximately 72% of Central’s firm market area capacity, 44% of its firm production area capacity and 85% of its firm storage deliverability.

Transportation. Central offers both firm and interruptible transportation service. Firm transportation service requires Central to reserve pipeline capacity at certain receipt and delivery points on its system. Firm customers generally pay based on the quantity of capacity reserved regardless of use plus a small commodity and fuel retention charge paid on the volume of gas actually transported. Firm transportation revenues tend not to vary over the term of the contract, except to the extent that Central’s rates for firm transportation services change. Under Central’s interruptible transportation service, Central agrees to transport gas for customers on a daily basis but does not reserve pipeline capacity for these services. Interruptible service customers pay only for the transportation of the volume of gas actually transported. Central transports natural gas from a receipt point to a delivery point principally under contracts with local natural gas distribution companies, electrical generators, industrials, marketers and producers. This service accounted for approximately 32% of our 2011 operating revenues, and as of December 31, 2011, comprised approximately 28% of Central’s firm market area capacity and 56% 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 1.3 TBtu/day of firm storage deliverability capacity and 47 TBtu of on-system natural gas storage capacity. Central’s storage service allows shippers to store natural gas close to their customers. Central’s storage facilities are strategically located in close proximity to its key market areas. The majority of the firm storage capacity is contracted as a component of the transportation/storage service (approximately 85% of the firm storage deliverability). The stand-alone firm storage service (approximately 15% of firm storage deliverability) and interruptible storage service accounted for approximately 2% of our operating revenues for the year ended December 31, 2011.

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 bank 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 1% of our operating revenues for the year ended December 31, 2011.

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 new 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:

Ozark Advance Expansion Project – 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. As a result, a firm transportation contract for 5,000 Dths/day was entered into and became effective on January 1, 2011. This contract is expected to generate approximately $0.25 million in annual revenue. No incremental facilities were required for this 5,000 Dths/day contract.

Storage Expansion Project – On April 1, 2011, Central placed into service its Elk City Storage Field Expansion, or the "Storage Expansion Project." This project provides an additional 4 Bcf of storage capacity, which increased our system’s aggregate storage capacity from 43 Bcf to 47 Bcf. The expansion is supported by Firm Storage Service agreements with customers that were effective on April 1, 2011. The cost of the expansion facilities was approximately $21.7 million and is expected to generate approximately $4.7 million in annual revenues.

ONG Norman Expansion Project – On March 1, 2011, Central placed into service a new delivery location to Oklahoma Natural Gas in Norman, Oklahoma. This expansion was supported by a five-year firm transportation contract for 11,000 Dths/day. The expansion cost approximately $0.6 million and is expected to generate annual revenues of $0.6 million.

Black Hills Colwich – Central is installing a new delivery location to Black Hills Utility for 13,000 Dths/day of incremental firm service in Sedgwick County, Kansas with a five-year contract term. The expansion will require the installation of a new delivery meter station. The firm transportation agreement and the in-service date for the facilities will be effective August 1, 2012. The expansion is expected to cost approximately $0.9 million and is expected to ultimately generate annual revenues of $0.9 million.

Canadian Blackwell Expansion Project – Central recently completed non-binding and binding open seasons for the “Canadian Blackwell Expansion Project” to add incremental firm transportation capacity to our system to serve portions of Oklahoma, Kansas and Missouri. The open seasons generated considerable interest from potential shippers. However, the binding commitments were not sufficient for the project to proceed at this time. Central will continue to work with interested shippers and seek anchor shipper commitments for an economically viable expansion project.

Gas Supply Projects and Initiatives

Central actively pursues new gas supply connections to our system to provide customers with additional supply options and flexibility to meet their demands. Our focus is targeted to directly 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:

Superior Pipeline Spring Creek – Central has installed a new receipt point in the Grant County, Oklahoma area capable of receiving up to 5,000 Dths/day. The project facilities were placed in service during the fourth quarter of 2011, and the costs of the interconnect point are reimbursable to Central.

PVR Midstream Antelope Hills – Central is installing an expansion of a receipt point in the Hemphill County, Texas area capable of receiving up to 75,000 Dths/day. The project is underway and facilities are expected to be placed in service during the second quarter of 2012. The costs of the interconnect point are reimbursable to Central.

Superior Pipeline Bellmcn – Central is installing a new receipt point in the Noble County, Oklahoma area capable of receiving up to 9,000 Dths/day. The project is underway and facilities are expected to be placed in service during the second quarter of 2012. The costs of the interconnect point are reimbursable to Central.

TEG Transmission – Central is installing a new receipt point in the Leavenworth County, Kansas area capable of receiving up to 2,000 Dths/day. The project is underway and facilities are expected to be placed in service during the third quarter of 2012. 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 five new supply/receipt projects that would add approximately 150,000 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, Rockies 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.

Demand for natural gas use in electrical power generation could increase significantly with the possible promulgation and implementation of new rules and regulations limiting emissions of carbon and other conventional pollutants such as sulfur dioxide, nitrogen oxides, particulate matter, mercury, coal ash and other hazardous air pollutants.

Seasonality

Substantially all of Central’s operating revenues are generated from fixed daily 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 reservation fees are generally consistent from month to month, Central’s operating revenues do not fluctuate materially from season to season.

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

Regulation

FERC Regulation. The siting of Central’s pipeline system and its transportation and storage of natural gas in interstate commerce for its customers and certain related customer services is subject to regulation by the FERC under the Natural Gas Act of 1938, or NGA, and under the Natural Gas Policy Act of 1978, or NGPA, and as such, its rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and its accounting, among other things, are subject to regulation. Central holds certificates of public convenience and necessity issued by the FERC authorizing the siting, ownership and operation of its pipelines and related facilities, including storage fields, which are considered jurisdictional and for which certificates are required under the NGA. The pipeline’s tariff—a compilation of the pipeline’s rules, and 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 and state utility commissions access to the books and records of any holding company or affiliate that are relevant to the rates of any associated public utility or natural gas company (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. Both of the Company's indirect owners, are holding companies that have filed with the FERC notifications of exemption from PUHCA 2005 under the FERC's PUHCA 2005 regulations except for disclosure and books and records requirements, and regulations regarding exemption. Neither the Company, nor Central, is itself a "public-utility company" or a "holding company" of a “public-utility company” under PUHCA 2005. Each of the Company's ultimate parents, GE and Morgan Stanley, is a “holding company” under PUHCA, but currently is exempt from PUHCA's accounting, cost allocation and related regulations; these exemptions do not provide Central any exemption from FERC regulation under the Natural Gas Act.

Rates. Natural gas pipeline companies subject to FERC jurisdiction may from time to time propose revised rates for their services in formal proceedings conducted by the FERC. Pipeline customers, state regulatory commissions and others are permitted to participate in the FERC rate case proceeding. In FERC rate case proceedings, the pipeline’s total cost of service is determined and is then divided among the various quantities and classes of service offered by the pipeline, resulting in a maximum rate for each type of service that the pipeline offers. For bona fide commercial reasons, a pipeline may offer customers discounts from the maximum rate if such discounts will increase the overall volumes shipped by the pipeline. Central provides no-notice service to local natural gas utilities, pursuant to which the utilities have flexible scheduling rights. In most locations, other than the Kansas City and Wichita metropolitan areas previously discussed under “Competition,” 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. Under the terms of the uncontested settlement, which was approved by the FERC on June 1, 2009, Central is required to file a rate case to be effective 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 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 contained

a list of remedies to address the DA’s findings, which Central has completed. 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. Under this Audit Order, Central filed a “compliance plan” outlining the steps

to be taken to implement the corrective actions, as well as quarterly reports on the status of its compliance plan. In September 2011, Central filed its last quarterly report.

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 2008 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 made 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 imposed 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.

On April 13, 2010, the United States District Court, or Trial Court, for the District of Kansas issued a “Memorandum and Order” in Colorado Interstate Gas Company vs. Thomas E. Wright, et al., Case No. 09-4031-SAC, concluding that the Kansas statutes and regulations pertaining to the regulation of underground storage, or the Kansas Underground Porosity Gas Storage Regulations, are “clearly pre-empted” by both the NGA and the NGPSA, with regard to gas stored in Kansas that is transported in interstate commerce. The KCC, chaired by Mr. Wright, did not file an appeal in the case and now has officially taken the position that the KCC’s jurisdiction extends only to intrastate storage operations in Kansas. Thus, Central is no longer required to obtain fully authorized operating permits from the KCC for its storage fields in Kansas, nor must it comply with the KCC rules regarding integrity testing.

Central identified storage reservoir parameters at seven of its eight storage fields that may require updates to its respective storage field’s existing FERC certificates. Central has filed and the FERC has approved certificate modifications for 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 as amended on August 5, 2008. Certificate modifications for the Alden Storage Field were filed May 13, 2011, with an amendment filed on October 19, 2011; an approved certificate has not been received from the FERC. No certificate modifications were required at one of the storage fields and the information and data for the remaining two storage fields are being reviewed and compiled and may require certificate modifications.

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 the 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 for reciprocating internal combustion engines, stationary turbines, and glycol dehydration equipment in addition to regulations that address regional transport of ozone. On August 20, 2010, the EPA promulgated new emission standards that apply to certain of Central’s existing reciprocating engines. These new standards, with an initial compliance date of October 19, 2013, require the installation of emission control devices on some of Central’s existing units. Based on an analysis of these regulations, management does not expect there to be a material impact to Central’s existing operations. On September 22, 2009, the EPA promulgated a mandatory reporting rule concerning the emission of certain gases, commonly referred to as “greenhouse gases,” that imposes requirements for some of Central’s existing operations; however, management does not expect these requirements to have a material impact on Central’s existing operations. There are also other various proposed rules and potential federal legislation related to greenhouse gas emissions that could impact Central’s existing operations when promulgated. Central continues to monitor the progress of these proposed rules and will determine any impact once the regulations have been promulgated.

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 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 $1.6 million at December 31, 2011 and $2.0 million at December 31, 2010, representing the current estimate of future environmental cleanup costs, most of which is expected to be incurred over the next three to four years.

All of Central’s facilities are located in areas currently designated as being in “attainment” of all National Ambient Air Quality Standards, or NAAQS. The EPA is currently in the process of preparing area designations under revisions to the ozone NAAQS that were promulgated in March 2008. Based on the EPA’s latest projections it appears that all areas housing Central’s operations will continue to be in attainment with the 2008 (current) ozone NAAQS.

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, 2011, we had 430 full time 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 148 field employees. Negotiations on a new agreement are expected to begin during the second quarter of 2012, as the current agreement negotiated during 2008 will expire on 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.

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 operations and financial condition.

Changes in levels of market volatility could negatively affect our ability to grow our business.

The capital and credit markets have experienced extreme volatility and disruption in recent years. 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. Future market disruption and volatility could limit our access to capital and credit markets, 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 30 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 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 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 regulations. Existing environmental 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.

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 predict with certainty whether any areas where our compressor stations are located could become nonattainment areas in the future.

As of December 31, 2011, we were aware of mercury contamination that requires characterization at approximately 50 of our meter sites. Approximately 62 of our meter sites will require remediation. We have an active program to identify and clean up contamination at our facilities. In general, the known contamination is limited to soils within the property boundaries of the sites. We have an accrued liability of $1.6 million as of December 31, 2011, representing the estimate of future cleanup costs, most of which is expected to be incurred over the next three to four years. However, should unanticipated future costs exceed our estimates, such costs could have a material adverse effect on our financial position, since such costs may not be recoverable through our rates.

Additionally, 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 greenhouse gases may be contributing to the 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 imposes 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 2012, 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 the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of 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 to be effective no later than December 1, 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. Liabilities 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, 2011, approximately 98% of our firm contracted market area capacity, 95% of our firm contracted production area capacity and 100% of our firm contracted storage capacity were under long-term contracts (i.e. contracts with terms longer than one year). A decision by customers upon the expiration of long-term agreements to substantially reduce or cease to ship or store volumes of natural gas on our pipeline system could cause a significant decline in our revenues. Our results of operations could also be adversely affected by decreased demand for interruptible services.

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

Our operating results are dependent upon our customers having access to adequate supplies of natural gas. We depend on having access to multiple sources of gas production so that customers can satisfy their total gas requirements and have the opportunity to source gas at the lowest overall delivered cost. Moreover, we do not have the ability to operate our pipeline system at full capacity without access to multiple gas sources. The ability of producers to maintain production is dependent on the prevailing market price of natural gas, the exploration and production budgets of the major and independent gas companies, the depletion rate of existing sources, the success of new sources, environmental concerns, regulatory initiatives and other matters beyond our control. Additionally, some of our customers deliver gas to our pipeline system through other pipelines. Operational failures on those other pipelines, such as reductions in pressure or 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 provide assurance 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 and other pipeline safety regulations may impose significant costs and liabilities on us.

The U.S. Department of Transportation, or DOT, through the Pipeline and Hazardous Materials Safety Administration, has regulations that govern all aspects of the design, construction, operation and maintenance of pipeline facilities. These regulations require, among other things, that pipeline operators engage in a regular program of pipeline integrity testing to assess, evaluate, repair and validate the integrity of their pipelines within areas of high consequence. Determination of such high consequence areas, for natural gas transmission pipelines, is primarily based on population. In response to these regulations, we have developed a pipeline integrity program to conduct pipeline integrity tests on a risk-prioritized basis. Depending on the results of these integrity tests and other integrity program activities, we could incur significant and unexpected capital and operating expenditures, not included in our current budgets, in order to conduct 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 2012 will be approximately $17.3 million and will be charged to capital or expense as appropriate.

Recent pipeline incidents in the U.S. have heightened focus on pipeline safety requirements. As a result, a number of proposed rules and possible federal legislative actions have been introduced which could impose restrictions on Central’s operations or require more stringent testing to ensure pipeline integrity. Adherence to such final regulations could increase our costs of compliance with pipeline integrity and safety regulations, which could have an adverse effect on our business, financial position and results of operations. In addition, on December 8, 2011, new federal legislation was enacted by Congress regarding pipeline safety and integrity issues, including changes that (i) double DOT’s civil penalty authority, and (ii) allow DOT to promulgate regulations requiring additional valves on new and replaced pipeline. Such legislation also requires the DOT Pipeline and Hazardous Materials Safety Administration to conduct various studies, which may ultimately result in additional regulations that could negatively affect our operations.

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 alternative facilities or services could result in a significant reduction in our revenues.

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 86% of operating revenue during the year ended December 31, 2011. Approximately 57% of our operating revenues during the year ended December 31, 2011 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.

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 U.S. 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 U.S. It has been reported that terrorists might be targeting domestic energy facilities, specifically our nation’s pipeline infrastructure. While we are taking steps we believe are appropriate to increase the security of our energy assets, there is no assurance that we can completely secure our assets or completely protect them against a terrorist attack, or obtain adequate insurance coverage for such acts at reasonable rates or at all. These developments have subjected our operations to increased risks and, depending on their ultimate 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.

Strikes or work stoppages may adversely affect our operations as approximately 34% of Central's employees belong to a labor union.

Central is party to a collective bargaining agreement with the International Union of Operating Engineers Local No. 647, or the Union. Disputes with regard to the terms of the collective bargaining agreement or our potential inability to negotiate an acceptable contract with the Union prior to the expiration of the existing agreement on July 15, 2012 could result in, among other things, strikes, work stoppages, or other slowdowns by the affected workers. If the unionized workers were to engage in a strike or work stoppage, or other employees were to become unionized, we could experience a significant disruption of our operations, which could compromise our service reliability, or higher ongoing labor costs, either of which could have a material adverse effect on the results of our business, financial condition and results of operation.

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:

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make investments;

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incur or guarantee additional indebtedness;

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

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create liens;

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incur dividend or other payment restrictions affecting subsidiaries;

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merge or consolidate with other entities; and

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enter into transactions with affiliates.

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Ownership of Property

Central’s pipeline system includes approximately 6,000 miles of mainline and branch transmission and storage pipelines, eight storage fields and 40 compressor stations located in Colorado, Kansas, Missouri, Nebraska, Oklahoma, Texas and Wyoming. The system is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned in fee by others. Most of these easements and rights-of-way are perpetual in nature and any term leases are effective as long as the appropriate payments are made. Central’s compressor stations with appurtenant facilities are located in whole or in part upon lands owned by Central in fee, or held under the same type of term lease as described above, pursuant to permits issued or approved by public authorities, or pursuant to perpetual easements granted by 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; 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 supporting briefs, were filed by the Joint Defendants requesting the Trial Court to dismiss Grynberg’s claims based on lack of subject matter jurisdiction. Those motions were fully briefed and oral arguments occurred on March 17 and 18, 2005. On May 13, 2005, the Special Master appointed to adjudicate procedural issues and help manage the consolidated litigation for the Trial Court Judge, issued his “Report and Recommendations” addressing which Grynberg claims against which defendants should be dismissed. Central was one of the defendants as to which the Special Master recommended that Grynberg's claims be dismissed on jurisdictional grounds. Both Grynberg and a number of the defendants filed objections to the Special Master’s report. On October 20, 2006, the Trial Court Judge entered his “Order on Report and Recommendations of Special Master” dismissing Grynberg's claims against Central and substantially all of the other defendants. Grynberg’s counsel filed 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. On July 27, 2011, the Trial Court entered orders disposing of the defendant’s motions for attorney fees and costs which were the subject of a hearing held on April 24, 2007. The Trial Court Judge awarded attorney fees and costs to the defendants and directed Grynberg to pay a portion of the Special Master’s fees into the Trial Court’s registry. On or about October 7, 2011, Central and many of the other prevailing defendants submitted claims setting forth the amounts and basis for their respective attorney fee and cost awards. It is unknown at this time whether the parties, through counsel, will be able to agree upon the specific amounts, if any, to be paid voluntarily by Grynberg, or whether further post-judgment proceedings before the Trial Court and/or the Appellate Court may be necessary.

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’ 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. By order dated March 31, 2010, the Court denied the Plaintiffs’ October 2, 2009 motion to reconsider the earlier denial of class certification. The Plaintiffs did not file for interlocutory review of the March 31, 2010 order, but through their counsel they have initiated certain discovery to which Central and other defendants have objected. In late June of 2011, certain defendants other than Central filed motions for summary judgment seeking, among other things, a ruling on the legal issue of whether or not Plaintiffs' civil conspiracy claim could be based upon their underlying unjust enrichment claim. In January of 2012, the Court issued an order concluding that under Kansas law a conspiracy claim could be so based. These defendants petitioned for interlocutory review of that ruling, but the Court of Appeals of Kansas denied their request on February 23, 2012. It is unknown whether Plaintiffs will follow through on discovery and/or otherwise proceed with the litigation on a non-class basis.

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 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. By order dated March 31, 2010, the Court denied the Plaintiffs’ October 2, 2009 motion to reconsider the earlier denial of class certification. The Plaintiffs did not file for interlocutory review of the March 31, 2010 order, but through their counsel they have initiated certain discovery to which Central and other defendants have objected. In late June of 2011, certain defendants other than Central filed motions for summary judgment seeking, among other things, a ruling on the legal issue of whether or not Plaintiffs' civil conspiracy claim could be based upon their underlying unjust enrichment claim. In January of 2012, the Court issued an order concluding that under Kansas law a conspiracy claim could be so based. These defendants petitioned for interlocutory review of that ruling, but the Court of Appeals of Kansas denied their request on February 23, 2012. It is unknown whether Plaintiffs will follow through on discovery and/or otherwise proceed with the litigation on a non-class basis.

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 our common stock. As of December 31, 2011, 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 are 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 2011 and 2010 were approximately $32.8 million and $27.2 million, respectively. We expect to continue to pay dividends as permitted under the indenture on a quarterly basis.

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)


	For the Year Ended December 31, 2011			For the Year Ended December 31, 2010			For the Year Ended December 31, 2009			For the Year Ended December 31, 2008			For the Year Ended December 31, 2007

Statement of Operations Data:
Operating Revenues	$	214,093		$	214,142		$	220,801		$	196,788		$	188,081
Operating Costs and Expenses:
Operations and maintenance		51,463			49,253			50,135			49,064			45,085
Administrative and general		37,486			37,770			42,954			39,005			35,562
Depreciation and amortization		33,150			31,057			32,238			29,293			27,470
Taxes, other than income taxes		16,884			16,153			15,293			14,654			14,573
Total Operating Costs and
Expenses		138,983			134,233			140,620			132,016			122,690
Operating Income		75,110			79,909			80,181			64,772			65,391
Interest Expense (Income):
Interest expense		32,367			32,297			32,556			31,210			28,842
Interest income		(96	)		(211	)		(308	)		(877	)		(1,441	)
Miscellaneous other (income)
expense, net		(6,873	)		(768	)		(49	)		(658	)		(516	)
Income Before Income Taxes		49,712			48,591			47,982			35,097			38,506
Provision for Income Taxes		19,495			18,526			19,010			13,838			15,299
Net Income	$	30,217		$	30,065		$	28,972		$	21,259		$	23,207


Balance Sheet Data (end of period):
Cash and Cash Equivalents	$	23,501		$	23,200		$	38,789		$	35,615		$	20,025
Property, Plant & Equipment, net		645,347			637,793			607,794			601,275			563,799
All Other Assets		450,623			428,787			438,671			424,541			473,521
Total Assets	$	1,119,471		$	1,089,780		$	1,085,254		$	1,061,431		$	1,057,345


Capitalization:
Current maturities of long-term
debt	$	250		$	235		$	745		$	720		$	690
Total long-term debt, net of
current portion		481,836			481,453			481,054			481,165			435,312
Common stockholder’s equity		429,934			432,550			429,730			431,341			432,082
Total Capitalization	$	912,020		$	914,238		$	911,529		$	913,226		$	868,084

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 report.

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 Midwestern United States. 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 17 years. Total average remaining contract life on a volume-weighted basis at December 31, 2011 was approximately four 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 no later than December 1, 2013.

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.

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 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.

On April 1, 2011, Central placed into service its Elk City Storage Field Expansion, or the "Storage Expansion Project." This project provides an additional 4 Bcf of storage capacity, which increased our system’s aggregate storage capacity from 43 Bcf to 47 Bcf. The expansion is supported by Firm Storage Service agreements with customers that were effective on April 1, 2011. The cost of the expansion facilities was approximately $21.7 million and is expected to generate approximately $4.7 million in annual revenues.

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. As a result, a firm transportation contract for 5,000 Dths/day was entered into and became effective on January 1, 2011. This contract is expected to generate approximately $0.25 million in annual revenue. No incremental facilities were required for this 5,000 Dths/day contract.

On March 1, 2011, Central placed into service a new delivery location to Oklahoma Natural Gas in Norman, Oklahoma. This expansion was supported by a five-year firm transportation contract for 11,000 Dths/day. The expansion cost approximately $0.6 million and is expected to generate annual revenues of $0.6 million.

Central is installing a new delivery location to Black Hills Utility for 13,000 Dths/day of incremental firm service in Sedgwick County, Kansas with a five-year contract term. The expansion will require the installation of a new delivery meter station. The firm transportation agreement will be effective, and the facilities are expected to be in service, on August 1, 2012. The expansion is expected to cost approximately $0.9 million and is expected to ultimately generate annual revenues of $0.9 million.

Central recently completed non-binding and binding open seasons for the “Canadian Blackwell Expansion Project” to add incremental firm transportation capacity to our system to serve portions of Oklahoma, Kansas and Missouri. The open seasons generated considerable interest from potential shippers. However, the binding commitments were not sufficient for the project to proceed at this time on an economic basis. Central will continue to work with interested shippers and seek anchor shipper commitments for an economically viable expansion project.

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.

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 Accounting Standards Codification, or 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.

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 postretirement 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, we do not recognize changes in the funded status in comprehensive income but recognize them as changes to the related regulatory asset or liability, pending future recovery or refund through its rates. For further discussion of our employee benefit plans, see Note 8 to the accompanying Notes to the Consolidated Financial Statements.

Goodwill

We have recorded $311.8 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 the 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 actual refunds.

Loss Contingencies and Operating Expenses

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

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

Income Taxes

We record deferred taxes under the liability method. Deferred taxes are provided on temporary differences between the book and tax basis of the assets and liabilities pursuant to the Accounting for Income Taxes Topic of the ASC.

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 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 for its federal and state income tax liabilities as though it were filing a separate return. 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 and similar state statutes.

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, 2011, 2010 and 2009:

		For the Year Ended December 31, 2011		For the Year Ended December 31, 2010		For the Year Ended December 31, 2009
		(In thousands)

Operating revenues	$	214,093	$	214,142	$	220,801
Operations and maintenance		51,463		49,253		50,135
Administrative and general		37,486		37,770		42,954
Depreciation and amortization		33,150		31,057		32,238
Taxes, other than income taxes		16,884		16,153		15,293
Operating income		75,110		79,909		80,181

Other (Income) Deductions:
Interest expense		32,367		32,297		32,556
Interest income		(96)		(211)		(308)
Miscellaneous other income, net		(6,873)		(768)		(49)
Total Other Deductions		25,398		31,318		32,199
Income before income taxes		49,712		48,591		47,982
Provision for income taxes		19,495		18,526		19,010
Net Income	$	30,217	$	30,065	$	28,972

Comparison of the Years Ended December 31, 2011 and 2010

Operating revenues were $214.1 million for each of the years ended December 31, 2011 and 2010. Revenues are comparable for the two periods, as a decrease in transportation revenues is being offset by an increase in storage revenues. Lower transportation revenues in 2011 are a result of decreased incremental park and loan service revenues due to lower future price curves and the narrowing of price differentials between producing basins in 2011. The higher storage revenues in 2011 were primarily due to the “Storage Expansion Project” in 2011.

Operations and maintenance expenses were $51.5 million for the year ended December 31, 2011, a $2.2 million, or 4.5%, increase from $49.3 million in 2010. The increase is principally due to higher expenses in 2011 for the pipeline integrity management program, vehicle usage and employee relocations, offset partially by lower expenses in 2011 for labor and leak repairs.

Administrative and general expenses were $37.5 million for the year ended December 31, 2011, a $0.3 million, or 0.8%, decrease from $37.8 million in 2010. The decrease is principally due to lower expenses in 2011 for employee incentives, offset partially by higher expenses for property liability insurance and professional services.

Depreciation and amortization expenses were $33.2 million for the year ended December 31, 2011, a $2.1 million, or 6.7%, increase from $31.1 million in 2010. The increase is primarily due to asset additions to the 2011 depreciable base for transmission mains and storage compressor station equipment.

Taxes other than income taxes were $16.9 million for the year ended December 31, 2011, a $0.7 million, or 4.5%, increase from $16.2 million in 2010. The increase is primarily due to higher ad-valorem tax assessments in 2011.

Interest expense was comparable for each of the years ended December 31, 2011 and 2010.

Interest income was $0.1 million for the year ended December 31, 2011, a $0.1 million decrease from $0.2 million in 2010. The decrease is primarily due to lower interest rates and cash balances in 2011.

Miscellaneous other income, net was $6.9 million for the year ended December 31, 2011, a $6.1 million increase from $0.8 million in 2010. The increase is a result of the sale of excess working gas recently converted from base gas as a result of the “Storage Expansion Project”.

The provision for income taxes was $19.5 million for the year ended December 31, 2011, a $1.0 million, or 5.2%, increase from $18.5 million in 2010, commensurate with higher pre-tax income. Our effective tax rate for 2011 was 39.2% compared to 38.1% for the same period in 2010. The effective tax rate in excess of the 35% federal statutory rate is primarily due to the impact of state income taxes. The effective tax rate increase is primarily attributable to a 2010 cumulative decrease in the composite state tax rate.

Comparison of the Years Ended December 31, 2010 and 2009

Operating revenues were $214.1 million for the year ended December 31, 2010, a $6.7 million, or 3.0%, decrease from $220.8 million in the prior year. The decrease is primarily due to lower transportation and storage revenues in 2010. The lower transportation revenues are a result of decreased park and loan service revenues due to lower future price curves and the narrowing of price differentials between producing basins in 2010, offset partially by higher reservation revenues. The lower storage revenues are a result of decreased inventories in storage that were primarily a result of increased residential natural gas demand in 2010, as compared to the same period in 2009.

Operations and maintenance expenses were $49.3 million for the year ended December 31, 2010, a decrease of $0.9 million, or 1.8%, from 2009. The decrease is principally due to lower expenses in 2010 for labor, materials, supplies and outside services, offset partially by higher expenses in 2010 for leak repair, vehicle usage and right-of-way clearing.

Administrative and general expenses were $37.8 million for the year ended December 31, 2010, a $5.2 million, or 12.1%, decrease from $43.0 million in 2009. The decrease is principally due to lower expenses in 2010 for employee incentives and medical benefits.

Depreciation and amortization expenses were $31.1 million for the year ended December 31, 2010, a $1.2 million, or 3.7%, decrease from 2009. The decrease is primarily due to the retirement of assets that occurred at the end of 2009 along with full amortization of major software in 2010.

Taxes other than income taxes were $16.2 million for the year ended December 31, 2010, a $0.9 million, or 5.6%, increase from $15.3 million in 2009. The increase was mainly the result of increased state assessments and various county tax levies in the state of Kansas for 2010, offset partially by lower payroll taxes.

Interest expense was $32.3 million for the year ended December 31, 2010, a decrease of $0.3 million, or 0.8%, from 2009. The decrease is primarily due higher income from the allowance for borrowed funds used during construction, or AFUDC debt, in 2010 resulting from the timing of construction in-service dates and the timing of capital expenditures.

Interest income was $0.2 million for the year ended December 31, 2010, a $0.1 million, or 31.5%, decrease from $0.3 million in 2009. The decrease is primarily due to lower interest rates and cash balances in 2010 as compared to the same period in 2009.

Other income was $0.8 million for the year ended December 31, 2010, a $0.7 million increase from 2009. The increase is primarily due to higher AFUDC-equity in 2010 resulting from the timing of construction in-service dates, the timing of capital expenditures and a lower loss on disposal of assets in 2010 as compared to 2009.

The provision for income taxes was $18.5 million for the year ended December 31, 2010, a $0.5 million, or 2.6%, decrease from $19.0 million in 2009. Our effective tax rate for 2010 was 38.1% compared to 39.6% for the same period in 2009. The effective tax rate in excess of the federal statutory rate of 35.0% is primarily due to the impact of state income taxes. The effective tax rate reduction relates primarily to a change in the composite state income tax rate recorded in 2010 to reflect a decrease in various state’s income tax rates.

Liquidity and Capital Resources

We expect to fund our capital and other liquidity requirements with cash on hand, cash flows from operating activities, capital contributions from Holdings and by accessing capital markets, if needed and available. We do not maintain a credit facility for working capital needs, but we may establish one in the near future.

Net cash provided by operating activities for the years ended December 31, 2011 and 2010 was $66.8 million and $73.2 million, respectively. Net cash from operating activities was lower in 2011 primarily due to lower 2011 operating income, excluding depreciation, higher 2011 funding to our pension and retiree medical plans and an increase in 2011 receivables. The 2011 decrease was partially offset by lower 2011 employee incentive payments. Funding of our pension plans is 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, 2011 and 2010 was $33.4 million and $60.7 million, respectively. Cash used in investing activities was lower in 2011 primarily due to lower maintenance and expansion capital expenditures and the 2011 receipt of proceeds from the sale of an asset, partially offset by higher capital expenditures for the purchase of storage acreage in 2011.

Net cash used in financing activities for the years ended December 31, 2011 and 2010 was $33.1 million and $28.0 million, respectively. The increase is primarily due to higher 2011common stock dividend payments, partially offset by lower capital lease payments.

Net cash provided by operating activities for the years ended December 31, 2010 and 2009 was $73.2 million and $73.7 million, respectively. Cash from operating activities was higher in 2010 primarily due to payments received for 2009 reimbursable projects, a 2009 construction project prepayment and lower 2010 funding to our pension and retiree medical plans discussed in Note 8 of the accompanying Notes to the Consolidated Financial Statements. The 2010 increase was partially offset by higher employee incentive payments and lower operating income, excluding depreciation.

Net cash used in investing activities for the years ended December 31, 2010 and 2009 was $60.7 million and $39.1 million, respectively. Cash used in investing activities was higher in 2010 primarily due to capital expenditures related to the Storage Expansion Project and higher mandatory capital expenditures.

Net cash used in financing activities for the years ended December 31, 2010 and 2009 was $28.0 million and $31.4 million, respectively. The decrease is primarily due to lower 2010 dividend payments.

6.75% Registered Notes

At December 31, 2011 and 2010, 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 Mellon 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 related issuance costs are being amortized over the life of the 6.75% Registered Notes utilizing the straight line method. 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 payment of dividends or distributions to equity holders, under the 6.75% Registered Notes indenture, are 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. We have the right to redeem all or part of the 6.75% Registered Notes at premiums defined in the indenture.

6.75% Unregistered Notes

At December 31, 2011 and 2010, we had outstanding $50.0 million aggregate principal amount of 6.75% Senior Notes due 2016, or 6.75% Unregistered Notes. The Bank of New York Mellon Trust Company, N.A. serves as trustee under the related indenture. Interest is payable semi-annually on March 1 and September 1 of each year. The related issuance costs are being amortized over the life of the 6.75% Unregistered Notes utilizing the straight line method. 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. We have the right to redeem all or part of the 6.75% Unregistered Notes at premiums defined in the indenture.

Central’s 6.0% Notes

At December 31, 2011 and 2010, 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 Mellon Trust Company, N.A. serves as trustee under the related indenture. Interest is payable semi-annually on June 1 and December 1 of each year. The related issuance costs are being amortized over the life of the 6.0% Notes utilizing the straight line method. 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

Central has a 20-year capital lease with the Owensboro-Daviess County Industrial Development Authority, or the Authority, for use of a headquarters building in Owensboro, Kentucky. Central is the borrower under a $9.0 million loan agreement dated as of January 1, 2004 between Central and the Authority pursuant to which the Authority financed the cost of Central’s office facility in Daviess County, Kentucky. In connection with this financing, the Authority issued Series 2004A and 2004B bonds under an indenture dated as of January 1, 2004 between the Authority and U.S. Bank, N.A. as trustee. Ownership of the facility will transfer to Central for a nominal fee upon expiration of the lease in 2024. The overall effective interest rate on the obligation is 6.29%. Principal and interest are paid semi-annually. Central has the option to prepay all 2004A bonds on or after January 1, 2014 and all 2004B bonds on or after February 1, 2014.

Other

We operate under a Federal and State Income Tax Policy 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 for its federal and state income tax liabilities as though it were filing a separate return. 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 and similar state statutes.

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 no later than December 1, 2013.

We entered into employee retention agreements with certain officers of Central, which expired on December 31, 2010. The agreements required annual payments to those officers for their continued employment. We accrued the expenses associated with these retention payments ratably over the period services were provided to Central. We recorded $1.1 million and $1.7 million in expenses for the years ended 2010 and 2009, respectively, for such annual payments. There were no similar expenses or agreements in 2011.

At December 31, 2011, 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.

Other

Contractual Obligations and Commitments

The table below summarizes our significant contractual obligations and commitments for the years indicated as of December 31, 2011:

Payments Due by Period

(In thousands)

	Long-Term Debt¹		Capital Leases²		Purchase Obligations		Operating Leases		Capital Expenditure Commitments³		Total Contractual Obligations
2012	$	30,675	$	526	$	1,832	$	261	$	6,666	$	39,960
2013		30,675		527		195		261		17,750		49,408
2014		30,675		528		-		257		-		31,460
2015		30,675		538		-		265		-		31,478
2016		495,338		541		-		32		-		495,911
After 2016		-		4,208		-		150		-		4,358
Total	$	618,038	$	6,868	$	2,027	$	1,226	$	24,416	$	652,575

(1)

Includes principal and interest payments of our 6.75% Registered Notes, 6.75% Unregistered Notes and 6.0% Notes, all of which will mature in 2016.

(2)

Includes principal and interest payments.

(3)

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

We have estimated capital expenditures of $75.6 million in 2012 and approximately $16.1 million for projects under our pipeline integrity management program. We expect to fund 2012 capital expenditures from our cash from operations, capital contributions from Holdings and by accessing capital markets, if needed and available.

Central expects to contribute a total of $9.1 million to its Retirement and Post Retirement Medical Benefit Plans in 2012. 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, if needed and available.

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 replaced. Cost-based regulation, along with competition and other market factors, limit 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 fixed daily reservation fees for transportation and 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 daily 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 occur 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. At December 31, 2011, 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 $4.7 million balance of our capital lease obligation matures serially through 2024 and carries a fixed effective interest rate of 6.29%. Our long-term debt at December 31, 2011, had a carrying value of $477.3 million. At December 31, 2011, the fair value of our 6.75% Registered Notes and the 6.75% Unregistered Notes was approximately $203.8 million and $50.9 million, respectively. These fair market values were calculated by discounting the Notes’ cash flows by their respective yield rates as determined by recent market activity. The fair value of the 6.0% Notes was $255.8 million as of December 31, 2011, estimated by discounting the 6.0% Notes’ cash flows by the current yield rate of notes with similar characteristics, as recent transactions of our 6.0% Notes were not available due to recent market inactivity.

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, 2011, 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, 2011.

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

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. 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, 2011.

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, 2011, 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 the Dodd-Frank Wall Street Reform and Consumer Protection Act.

Item 9B. Other Information

None.

PART III.

Item 10. Directors, Executive Officers and Corporate Governance

Management

Directors and Officers of Southern Star Central Corp.

The following is a list of Southern Star’s directors and officers, their ages and their positions as of March 1, 2012.


Name	Age		Position
Mark T. Mellana	47	Director
John V. Veech	53	Director
John B. Watt	55		Director
Tyson R. Yates	43		Director
Jerry L. Morris	56		President and Chief Executive Officer
Susanne W. Harris	53		Vice President, Chief Financial Officer and Treasurer

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

The following is a list of Central’s directors and officers, their ages and their positions as of March 1, 2012.


Name	Age	Position
Mark T. Mellana	47	Director
John V. Veech	53	Director
John B. Watt	55	Director
Tyson R. Yates	43	Director
Jerry L. Morris	56	President and Chief Executive Officer
Robert S. Bahnick	52	Vice President and Chief Operations Officer
Robert W. Carlton	51	Vice President and Chief Compliance Officer
David L. Finley	47	Vice President and Chief Administrative Officer
Susanne W. Harris	53	Vice President, Chief Financial Officer and Treasurer
Philip A. Rullman	53	Vice President and Chief Commercial Services Officer

Mark T. Mellana was appointed to the Board of Directors, or the Board, effective July 27, 2010. Mr. Mellana currently serves as Managing Director of the Midstream and International portfolio group at GE Energy Financial Services, Inc., or GE-EFS, a position he assumed in May 2007. During the past 13 years, Mr. Mellana has held a variety of positions at GE-EFS, including Managing Director of the Power investment group. In his current position, Mr. Mellana serves on a number of Boards which currently include Source Gas Holdings Inc., a local gas distribution company headquartered in Colorado, Energía Mayakan, S. De R.L. DE C.V., a pipeline in Mexico, and WR Carpenter No 1 Pty Ltd, a company involved in developing a power company in Australia. In the past, Mr. Mellana served on the board of Regency Energy Partners, a publicly traded MLP headquartered in Texas with gas transportation, gathering and processing operations. Mr. Mellana holds a Bachelor of Science in Electrical Engineering from Villanova University, and a Master of Business Administration, or M.B.A., in Finance from Boston University.

John V. Veech was appointed to the Board effective March 9, 2010. Mr. Veech has been a Managing Director and head of the Americas region for Morgan Stanley Infrastructure Partners and certain other affiliated investment funds managed by Morgan Stanley Infrastructure, Inc., or 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 Managing Director of 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’s experience involves investing in and managing infrastructure assets, generally in the energy, utilities and transportation sectors, as well as financings and acquisitions of such assets. Mr. Veech earned 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 was appointed to the Board effective March 9, 2010. Mr. Watt currently serves as Head of Asset Management for MSIP, 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, a large, regulated power utility 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 for acquiring and divesting various power assets. From 1985 to 1996, Mr. Watt worked for Amoco Corporation, a large, multinational integrated oil major, 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. Mr. Watt earned 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, and is a registered Professional Engineer in Alberta, Canada.

Tyson R. Yates was appointed to the Board effective April 28, 2010. Mr. Yates is currently Managing Director of the Midstream portfolio group at GE-EFS in Stamford, Connecticut, a position he has held since March 2007. From 2003 to March 2007, Mr. Yates was Vice President, and later Senior Vice President of the GE-EFS Risk Management Group primarily in the midstream sector. Prior to joining GE-EFS, Mr. Yates held the position of Senior Manager in the Special Acquisition Services and Audit practice at Deloitte LLP. Mr. Yates holds a Bachelor of Science Degree in Accounting from the University of Florida and is a CPA.

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 33 years in the interstate natural gas pipeline industry. Mr. Morris earned 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 Vice President and Chief Operations Officer of Central in February 2011. Previously he served as Senior Vice President of Operations and Technical Services for Central since July 2003 and 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 30 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 and Chief Compliance Officer of Central in February 2011. Previously he served as Central's Vice President of Human Resources and Administration since July 2003, 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 29 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’s Executive Council and the Interstate Natural Gas Association of America’s Operations, Safety, and Environmental Committee.

David L. Finley became Vice President and Chief Administrative Officer of Central in February 2011. Previously he served as Central's Vice President of Information Technology since July 2003, 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 24 years in the interstate natural gas pipeline industry. Mr. Finley earned his B.S. in Geology from Murray State University in 1986.

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 31 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.

Philip A. Rullman became Vice President and Chief Commercial Services Officer for Central in February 2011. Previously he served as Central’s Director of Commercial Services since 2008, as Manager of Customer Service and Business Development since 2005, and held various other positions at Central, and/or its predecessors in engineering, operations, storage, gas control, and human resources during his 33 years in the interstate natural gas pipeline industry. Mr. Rullman earned his B.S. in Business Management from Baker University in 1996.

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 is 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 offenses); (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, 2011 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 CEO.

The Board of Directors will engage, from time to time, outside compensation consultants to conduct a survey of compensation for the industry. The most recent such study was commissioned in 2011, and conducted by Towers Watson, an independent compensation consultant. The Board also utilizes compensation data from an annual surveys published by the Southern Gas Association, or SGA, and by the American Gas Association, or AGA in both of which Central participates. The 2011 SGA survey data is a compilation derived from information provided by 17 natural gas distribution, transmission & pipeline companies, including the following peer companies: Centerpoint Energy, CPS Energy, Oneok, Inc., Questar Corporation, Source Gas LLC, and Southern Union Company. For executive compensation, the Board also utilizes compensation data from a confidential annual survey performed by the American Gas Association, or AGA, in which Central participates. The 2011 AGA data is a compilation derived from information provided by its 64 member organizations, including the following peer pipeline companies: Centerpoint Energy, Entergy Corporation, Oneok, Inc., Questar Corporation, Southern Union Company, Nisource, Inc., and Transcanada Corporation. Additionally, management engaged Mercer, an independent compensation consultant, which utilized its own data for energy companies, data from a Towers Watson 2010 Top Management Survey, and data from the SGA and AGA surveys, to conduct its study.

While the Board will review, and take into account, the data provided in such studies, the Board does not view it as appropriate to mechanically “peg” compensation to such a study. Instead, the Board takes into account factors such as management performance relative to stated goals, the size and complexity of Southern Star relative to other companies in the industry, total number of employees in the organization, and prospects for growth and development of the business over time. The Board seeks to determine levels of compensation which are appropriate to attract and retain management level talent, and seeks to have meaningful portions of the total compensation package tied to the achievement by management of specific goals set by the Board.

The Board believes that incentives should be competitive in the market place, and be appropriately balanced between short-term and long-term performance. The Board believes that short-term performance is addressed by the payment of annual discretionary cash bonuses, pursuant to criteria that are established at the beginning of each fiscal year. (The parameters for the 2011 “bonus pool” are set forth under “Compensation Components – Annual Bonus” below, and typically will include both “quantitative” and “qualitative” factors.) The Board is also currently considering the implementation of a long term incentive plan intended for key employees to focus on creating shareholder value over a longer term period.

Compensation Components

Our compensation program for our named executive officers, or officers, consists of three primary elements: (1) base salary; (2) a performance-based annual bonus; and (3) 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.

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. Funding of the Bonus pool establishes the amount available to management for Bonus recognition, but does not ensure that an employee will receive a Bonus award. Individual awards are based on individual performance. Targets are challenging but achievable and are generally designed to reward improvement over prior year results and performance.

For 2011, the Board established the following targets for funding the Bonus pool.

Up to 5% of the Bonus pool was apportioned to provide for the achievement of non-financial goals and objectives on a department or individual level. For 2011, this component was funded at 5%.

Up to 5% of the Bonus pool was attributed to successful progress on achievement of the Company’s Records Information Management goals, including tasks and training assigned to individuals and departments. For 2011, this component was funded at 5%.

Up to 10% of the Bonus pool was attributed to the achievement of company safety goals, including employee training. For 2011, this component was funded at 10%.

Up to 10% of the Bonus pool was attributed to achieving cost savings for certain operating expenses as determined by the Board. For 2011, this component was funded at 10%.

Up to 5% of the Bonus pool was attributed to improving customer service and communications quality as measured by an annual survey. For 2011, this component was funded at 5%.

Up to 10% of the Bonus pool was attributed to identifying and presenting a targeted level of business development growth opportunities. For 2011, this component was funded at 3%.

Up to 40% of the Bonus pool was attributed to the achievement of specified EBITDA targets for Central, as defined by the Board. See table below for further explanation of this target. For 2011, this component was not funded.

Up to 15% of the Bonus pool was attributed to the achievement of specified net income targets for Central, as defined by the Board. See table below for further explanation of this target. For 2011, this component was not funded.

2011 EBITDA Targets for Central

From	To	% of Funding Level
$0.0	$109.500M	—
$109.501M	$114.500M	20%
$114.501M	$117.500M	20%

Note: For purposes of this calculation, Central’s EBITDA was defined as operating income plus depreciation, adjusted for incentive plan costs and other unusual or non-recurring activities as agreed upon by the Board. If the minimum threshold target EBITDA is achieved, the Bonus pool is funded with a pro rata portion of the percentage to be funded for the level of EBITDA achieved.

2011 Net Income Targets for Central

From	To	% of Funding Level
$0.0	$42.500M	—
$42.501M	$45.500M	10%
$45.501M	$47.500M	5%

Note: For purposes of this calculation, net income for Central may be adjusted for unusual or non-recurring activities as agreed upon by the Board. If the minimum threshold target is achieved, the Bonus pool is funded with a pro rata portion of the percentage to be funded for the level of net income achieved.

After the end of each year, the Board determines the level of funding for each component. The Board may, at its discretion, fund the pool at a higher or lower level than indicated by the component calculations, based on overall Company performance or unusual events not included in the targets originally established. The Board exercised this discretion in 2011 and funded an additional 12% to the Bonus pool. The additional funding was made in recognition of market factors beyond the Company’s control which limited the ability to achieve financial goals. In total, the 2011 Bonus pool for all employees was funded at 50% of the maximum potential Bonus pool. In comparison, the 2010 Bonus pool was funded at 53%.

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 75%. The discretionary annual bonus is intended to compensate executive officers for the strategic, operational and financial success of the Company, as a whole, as well as the individual performance of the executive officer. Bonuses are not triggered by achievement of pre-set standards and individual executives may not receive a discretionary bonus even though financial targets are achieved. When determining the annual bonus to be paid to an executive officer, our Board reviews the executive’s achievement of the executive’s stated goals (either individual or team goals), the overall performance of the Company, and the executive’s individual performance. Because the award of a bonus is at the complete discretion of our Board, the Board looks 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 award determinations are subjective and take into consideration achievement of individual goals, including appropriate management of departmental budgets, and individual contributions to team and Company goals, as well as specified performance factors. Performance factors include adaptability, communication skills, innovation, customer service, dependability, initiative, integrity, interpersonal skills, job knowledge, leadership skills, conflict management, diversity management, performance management, people development, planning, focus on results and alignment with the Company’s vision and values. 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 2011 Bonus pool was funded at 50% of the maximum allowed by the Bonus Plan, and as a group, our named executive officers received 13% of the Bonus pool paid to employees. For 2011, each named executive officer received the following percentage of their respective bonus potential: 55% for Mr. Morris, 36% for Mr. Bahnick, 61% for Mr. Carlton, 35% for Mrs. Harris, and 61% for Mr. Rullman.

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. New compensation plans are under consideration by the Board, which may or may not be implemented during 2012.

Roles and responsibilities of, as well as compensation for, our executive officers were reviewed in 2011 as a result of the expiration of the employment agreements. Salaries and 2011 bonus participation levels were adjusted upward or downward in the first quarter of 2011 as a result of this review. For the 2011 named executive officers, salary increases ranged from zero to 31%, and the bonus participation levels for Mr. Morris, Mr. Bahnick, and Ms. Griffith were reduced.

Summary Compensation Table

The following table sets forth certain summary compensation information as to the CEO and CFO during the fiscal year 2011, and for the other top three most highly compensated employees including the most highly compensated executive officers of Central, our operating entity, as of December 31, 2011. The table below indicates, for each of the named executive officers’ salary, bonus and all other compensation of Southern Star and Central for the fiscal years ended December 31, 2011, 2010 and 2009:

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	2011	282,762	117,954	146,546	14,700	561,962
President, CEO	2010	242,528	122,253	105,974	644,700	1,115,455
	2009	247,235	219,032	142,935	644,700	1,253,902

Susanne W. Harris	2011	177,420	31,150	166,738	13,125	388,433
Vice President and CFO	2010	169,226	41,335	84,775	155,325	450,661
	2009	173,586	74,907	82,719	155,325	486,537

Robert W. Carlton	2011	184,606	57,400	177,221	13,649	432,876
Vice President and Chief Compliance	2010	154,712	72,238	73,577	155,325	455,852
Officer of Central	2009	157,929	67,676	79,253	155,325	460,183

Robert S. Bahnick	2011	206,000	37,080	179,423	15,416	437,919
Senior Vice President of Operations	2010	210,532	77,250	82,878	174,075	544,735
and Technical Services of Central	2009	213,923	143,685	95,958	169,724	623,290

Philip A. Rullman	2011	183,618	57,400	157,382	13,162	411,562
Vice President, and Chief Commercial Services	2010	141,998	47,431	76,569	11,109	277,107
Officer of Central	2009	143,455	41,698	53,332	11510	249,995

(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 2011, 2010, and 2009 includes matching contributions by Central under the Southern Star Investment Plan, Central’s broad-based 401(k) plan. For 2011, it contains the amounts of $14,700 for Mr. Morris, $14,700 for Mr. Bahnick, $13,649 for Mr. Carlton, $13,125 for Mrs. Harris, and $13,163 for Mr. Rullman. For 2010, it contains the amounts of $14,700 for Mr. Morris, $14,700 for Mr. Bahnick, $14,700 for Mr. Carlton, $14,700 for Mrs. Harris, and $11,109 for Mr. Rullman. For 2009, it contains the amounts of $14,700 for Mr. Morris, $10,349 for Mr. Bahnick, $14,700 for Mr. Carlton, $14,700 for Mrs. Harris, and $10,787 for Mr. Rullman. These amounts are to be paid out to the named executives only upon retirement, termination, disability or death. All other compensation also includes amounts paid as retention bonuses under the employment agreements of the respective employees as follows for 2010 and 2009, the amounts of $630,000 to Mr. Morris, $159,375 to Mr. Bahnick, $140,625 to Mr. Carlton, and $140,625 to Mrs. Harris. Each of the employment agreements expired on December 31, 2010 and, as such, no retention bonuses were paid for 2011. Mr. Rullman was not party to an employment agreement. In addition, Mr. Bahnick and Mr. Rullman received $716 and $723, respectively, related to a service award.

(3)

Each of these officers is compensated by Central.

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 2011:

SOUTHERN STAR RETIREMENT PLAN

Name	Number of Years of Credited Service	Present Value of Accumulated Benefit*	Payments During Last Fiscal Year
Jerry L. Morris	9.167	$ 548,290	$ —
Robert S. Bahnick	9.167	468,862	—
Robert W. Carlton	9.167	424,723	—
Susanne W. Harris	9.167	459,293	—
Philip A. Rullman	9.167	367,483	—

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, 2011, except the retirement age assumption adheres to the requirements of U.S. SEC REGULATIONS-K Subpart 229.402(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 $245,000 per year. 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.

Participants under the Non-Union Plan, including the named executive officers, are eligible for early retirement at age 55. Mr. Morris is the only named executive officer currently eligible for early retirement under the plan. The formula for determining the normal retirement benefit is 1.275% of average monthly compensation per year of service. Years of service are credited for all service after November 15, 2002. Normal retirement age is the later of age 65 or the 5^th anniversary of plan participation. If an early retirement date is 3 years or less before normal retirement, the early retirement benefit is equal to the normal retirement benefit accrued at early retirement date (i.e., no reduction for early commencement). If the early retirement date is more than 3 years before the normal retirement date, the early retirement benefit is equal to the normal retirement benefit accrued at early retirement date, but is reduced for each month early retirement precedes normal retirement by more than 3 years by 0.4167% per month for the first 24 such months and reduced 0.3333% for each additional such month. However, the benefit is unreduced if the sum of the participant’s age and years of vesting service is at least 85 and the participant retires at age 59 or later. Participants are eligible to convert the pension into a lump sum equivalent benefit, based upon actuarial equivalence determined using PBGC interest discount rates.

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.

Potential Payments Upon Termination or Change in Control

The Company has a Severance Pay Plan for Non-Union employees that applies to all eligible non-union employees. Under such plan, an eligible employee, including each named executive officer, is entitled to receive severance payments if his or her employment is terminated due to a reduction in force or job elimination and the employee signs a release of claims. Eligibility is negated when (i) termination is for cause, (ii) resignation is voluntary, (iii) benefits are accepted under an incentive retirement plan, (iv) a comparable position is offered, (v) the employee dies before the established termination date, or (vi) the employee is receiving long-term disability benefits at the time of notification. The severance benefit is based on continuous “Years of Service”. Upon severance, the named executive would receive two weeks of pay for each full, completed “Year of Service,” with a minimum of six (6) weeks and a maximum of fifty-two (52) weeks of severance pay. Severance pay benefits would be paid in installment payments through the normal pay cycle of the Company. If each named executive officer were terminated at December 31, 2011 and qualified for payments under this plan, each named executive officer would be paid the following total severance payments under the plan: $285,950 for Mr. Morris, $178,000 for Mrs. Harris, $206,000 for Mr. Bahnick, $187,000 for Mr. Rullman, and $187,000 for Mr. Carlton.

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.

Members of the Board:

Mark T. Mellana

John V. Veech

John B. Watt

Tyson R. Yates

Indemnification of Executive Officers and Directors

Section 145 of the Delaware General Corporation Law provides that a company may indemnify any persons who were, or are threatened to be made, parties to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such company), by reason of the fact that such person is or was an officer, director, employee or agent of such company, or is or was serving at the request of such company as a director, officer, employee or agent of another company, partnership, joint venture, trust or other enterprise. The indemnity may include expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such person acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the company’s best interests 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 of our directors and officers.

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

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

The following table sets forth certain information, as of March 15, 2012, 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%
800 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

Central has an Operating Company Services Agreement, or Operating Services Agreement, with EFS Services, LLC, or EFS Services, an affiliate of GE. Pursuant to the Operating Services Agreement, EFS Services 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 in providing such services. For each of the years ended 2011, 2010 and 2009, Central paid approximately $1.0 million for service fees and expenses to EFS Services. The Operating Services Agreement terminates at such time as GE or any of its affiliates ceases to beneficially own any securities of Holdings.

On August 11, 2005, we entered into an Administrative Services Agreement, or EFS Services Agreement, with EFS Services to provide certain administrative services to us and Holdings. On January 23, 2012, we entered into an Administrative Services Agreement, or MSIP Services Agreement, with MSIP Southern Star L.L.C., or MSIP Southern Star, an affiliate of MSIP, to provide certain administrative services to us and Holdings. Pursuant to the terms of these agreements, the parties are not paid a fee for their services; however, they are entitled to be reimbursed for reasonable expenses incurred 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, 2011 and 2010, and in connection with statutory and regulatory filings for such fiscal periods, were approximately $474,000 and $455,000, 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, 2011 and 2010 were approximately $65,000 and $62,000, respectively.

Tax Fees

There were no 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, 2011 and 2010.

All Other Fees

No other services were provided by E&Y for the fiscal years ended December 31, 2011 and 2010.

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 2011 were pre-approved by the Board.

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

Consolidated Balance Sheets at December 31, 2011 and 2010

Consolidated Statements of Operations for the years ended December 31, 2011, 2010, and 2009

Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010, and 2009

Consolidated Statements of Stockholder’s Equity for the years ended December 31, 2011, 2010, and 2009

Notes to the Consolidated Financial Statements

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


3.1¹			Amended and Restated Certificate of Incorporation of Southern Star Central Corp., dated August 11, 2005.

3.2⁵			Third Amended and Restated Bylaws of Southern Star Central Corp., dated February 1, 2011.

3.3²			Restated Certificate of Incorporation of Southern Star Central Gas Pipeline, Inc., as amended.

3.4⁵			Third Amended and Restated Bylaws of Southern Star Central Gas Pipeline, Inc., dated February 1, 2011.

4.4⁴			Indenture, dated April 13, 2006, between Southern Star Central Corp. and The Bank of New York Trust Company, N.A. (the “Trustee”).

4.6⁶			Form of Certificate of 6³/4% 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.

10.7			Administrative Services Agreement, dated as of January 23, 2012, among MSIP Southern Star, LLC, EFS-SSCC Holdings, LLC and Southern Star Central Corp.

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.

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definitions Document
101.LAB	XBRL Taxonomy Label Linkbase Document
101.PRE	XBRL Taxonomy Presentation Linkbase Document

(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 Southern Star Central Corp.’s Report on Form 8-K filed with the SEC on February 4, 2011.

(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.

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 23, 2012	By:	/s/ JERRY L. MORRIS
		Jerry L. Morris President and Chief Executive Officer

March 23, 2012	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/ MARK T. MELLANA Mark T. Mellana	Director	March 23, 2012


By:	/s/ JOHN V. VEECH John V. Veech	Director	March 23, 2012


By:	/s/ JOHN B. WATT John B. Watt	Director	March 23, 2012


By:	/s/ TYSON R. YATES Tyson R. Yates	Director	March 23, 2012

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

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.

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, 2011 and 2010, and the related consolidated statements of operations, stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2011. 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 made 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, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Louisville, Kentucky

March 23, 2012

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		December 31, 2011			December 31, 2010

	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	23,501		$	23,200
Receivables:
Trade		19,136			18,704
Income taxes		1,379			2,088
Transportation, exchange and fuel gas		10,844			2,986
Other		7,859			5,711
Inventories		7,194			6,727
Deferred income taxes		1,241			1,806
Costs recoverable from customers		2,771			11,369
Prepaid expenses		4,822			4,288
Other		390			478
Total current assets		79,137			77,357

Property, Plant and Equipment, at cost:
Natural gas transmission plant		733,833			705,659
Other natural gas plant		26,495			21,884
		760,328			727,543
Less – Accumulated depreciation and amortization		(114,981	)		(89,750	)
Property, plant and equipment, net		645,347			637,793

Other Assets:
Goodwill		311,766			311,766
Costs recoverable from customers		77,029			55,585
Prepaid expenses		2			240
Other deferred and noncurrent assets		6,190			7,039
Total other assets		394,987			374,630
Total Assets	$	1,119,471		$	1,089,780

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, 2011		December 31, 2010

	(In thousands)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Payables:
Trade	$	8,250	$	5,320
Transportation, exchange and fuel gas		12,865		13,604
Income Taxes		247		145
Other		5,599		7,381
Accrued taxes, other than income taxes		6,939		6,827
Accrued interest		6,914		6,920
Accrued payroll and employee benefits		8,319		8,591
Costs refundable to customers		3		94
Capitalized lease obligation due in one year		250		235
Other accrued liabilities		3,263		1,945
Total current liabilities		52,649		51,062

Long-Term Debt:
Capitalized lease obligation		4,495		4,745
Other long-term debt		477,341		476,708
Total long-term debt		481,836		481,453

Other Liabilities and Deferred Credits:
Deferred income taxes		83,069		72,661
Postretirement benefits other than pensions		32,982		20,934
Asset retirement obligations		1,738		1,631
Costs refundable to customers		168		146
Environmental remediation		827		1,225
Accrued pension		36,015		27,946
Other		253		172
Total other liabilities and deferred credits		155,052		124,715

Stockholder’s Equity:
Common stock, $.01 par value, 100 shares authorized and issued,
100 shares outstanding at December 31, 2011 and 2010		—		—
Premium on capital stock and other paid-in capital		423,869		423,869
Retained earnings		6,065		8,681
Total stockholder’s equity		429,934		432,550
Total Liabilities and Stockholder’s Equity	$	1,119,471	$	1,089,780

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, 2011			For the Year Ended December 31, 2010			For the Year Ended December 31, 2009

	(In thousands)
Operating Revenues:
Transportation	$	185,085		$	187,398		$	193,415
Storage		28,290			26,096			26,912
Other revenue		718			648			474
Total operating revenues		214,093			214,142			220,801

Operating Costs and Expenses:
Operations and maintenance		51,463			49,253			50,135
Administrative and general		37,486			37,770			42,954
Depreciation and amortization		33,150			31,057			32,238
Taxes, other than income taxes		16,884			16,153			15,293
Total operating costs and expenses		138,983			134,233			140,620

Operating Income		75,110			79,909			80,181

Other (Income) Deductions:
Interest expense		32,367			32,297			32,556
Interest income		(96	)		(211	)		(308	)
Miscellaneous other income, net		(6,873	)		(768	)		(49	)
Total other deductions		25,398			31,318			32,199

Income Before Income Taxes		49,712			48,591			47,982

Provision for Income Taxes		19,495			18,526			19,010

Net Income	$	30,217		$	30,065		$	28,972

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, 2011			For the Year Ended December 31, 2010			For the Year Ended December 31, 2009

	(In thousands)
OPERATING ACTIVITIES:
Net income	$	30,217		$	30,065		$	28,972
Adjustments to reconcile to net cash provided from operations:
Depreciation and amortization		33,150			31,057			32,238
Deferred income taxes		10,973			10,364			11,033
Gain on sale of assets		(6,089	)		—			—
Amortization of debt discount and expense		1,678			1,681			1,688
Receivables		(1,556	)		(592	)		(4,496	)
Inventories		(467	)		183			46
Other current assets		(447	)		1,102			(493	)
Payables and accrued liabilities		915			(1,592	)		4,063
Other, including changes in noncurrent assets and liabilities		(1,582	)		889			600
Net cash provided by operating activities	66,792			73,157			73,651

INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of allowance for funds
used during construction		(38,710	)		(59,957	)		(40,275	)
Proceeds from sales and salvage values, net of costs of removal		5,331			(752	)		1,156
Net cash used in investing activities	(33,379		)	(60,709		)	(39,119		)

FINANCING ACTIVITIES:
Common dividends		(32,833	)		(27,245	)		(30,583	)
Debt issuance costs		(44	)		(47	)		(55	)
Capital lease payments		(235	)		(745	)		(720	)
Net cash used in financing activities		(33,112	)		(28,037	)		(31,358	)

Increase (decrease) in cash and cash equivalents		301			(15,589	)		3,174

Cash and cash equivalents at beginning of period		23,200			38,789			35,615

Cash and cash equivalents at end of period	$	23,501		$	23,200		$	38,789

Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (net of amounts capitalized)	$	30,697		$	30,636		$	30,878
Income tax, net		7,711			8,725			9,071

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			Total Stockholder’s Equity

	(In Thousands)
Balance, January 1, 2009	$	423,869	$	7,472		$	431,341
Add (deduct):
Net income		—		28,972			28,972
Common dividends		—		(30,583	)		(30,583	)
Balance, December 31, 2009		423,869		5,861			429,730

Add (deduct):
Net income		—		30,065			30,065
Common dividends		—		(27,245	)		(27,245	)
Balance, December 31, 2010		423,869		8,681			432,550—

Add (deduct):
Net income		—		30,217			30,217
Common dividends		—		(32,833	)		(32,833	)
Balance, December 31, 2011	$	423,869	$	6,065		$	429,934

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 Morgan Stanley Infrastructure Partners and certain other affiliated investment funds managed by Morgan Stanley Infrastructure, Inc., or MSIP, through their indirect ownership of EFS-SSCC Holdings, LLC, or Holdings. 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. 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, which are 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 212,000 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, 2011, Central had transportation customer contracts with approximately 142 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 512 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 47 Bcf and aggregate delivery capacity of approximately 1.3 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 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 or available under the NGA.

2. Accounting Policies

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.

Reclassifications

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

Revenue Recognition

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

Regulatory Assets and Liabilities

As a rate regulated enterprise, Central meets the requirements for accounting under the Effects of Certain Types of Regulation Topic of the Accounting Standards Codification, or 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.

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, 2011 and 2010 and classified as current or noncurrent depending on the expected timing of recovery (expressed in thousands):

2011			2010			Current Assets:
						Environmental costs
$	750		$	750		Fuel costs
	2,021			10,619		Total Current Assets
	2,771			11,369
						Noncurrent Assets:
						Environmental costs
	827			1,225		Income taxes on AFUDC equity
	4,967			4,740		Gas imbalance cash cost recoverable
	43			74		Postretirement benefits other than pensions
	32,478			20,599		Pensions
	37,874			27,946		Asset retirement obligations
	827			995		Long-term disability
	13			6		Total Noncurrent Assets
	77,029			55,585
						Total Assets
	79,800			66,954
						Current Liabilities:
						Costs refundable to customers
	(3	)		(94	)	Total Current Liabilities
	(3	)		(94	)
						Noncurrent Liabilities:
						Gas imbalance cash cost refundable
	(168	)		(146	)	Total Noncurrent Liabilities
	(168	)		(146	)
						Total Liabilities
	(171	)		(240	)
						Net Regulatory Assets
$	79,629		$	66,714

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, 2011, 2010 and 2009 was approximately $33.2 million, $31.1 million and $32.2 million, respectively.

Goodwill

The Company has recorded $311.8 million of goodwill. 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 2011, 2010 and 2009, 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 $0.1 million for the year ended December 31, 2011, and approximately $0.3 million for the year ended December 31, 2010, respectively.

Income Taxes

Southern Star and Central record deferred taxes under the liability method. Deferred taxes are provided on temporary differences between the book and tax basis of the assets and liabilities pursuant to the Accounting for Income Taxes Topic of the ASC.

In accordance with the Accounting for Uncertainty in Income Taxes Topic of the ASC, 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. For the years ended December 31, 2011, 2010, and 2009 the Company did not have a liability for penalties or interest related to uncertain tax positions.

The Company 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 for its federal and state income tax liabilities as though it were filing a separate return. 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 and similar state statutes.

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, 2011 were $0.3 million and $0.8 million, respectively; for the year ended December 31, 2010 were $0.4 million and $1.0 million, respectively; and for the year ended December 31, 2009 were $0.2 million and $0.4 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 Asset Retirement and Environmental Obligations Topic of the ASC, concerning Accounting for Conditional Asset Retirement Obligations, Central recorded an asset retirement obligation, or ARO, for the remediation of asbestos existing on its system. The asbestos existing on Central’s system is primarily in building materials and pipe coatings used prior to the Clean Air Act of 1973. The Clean Air Act of 1973 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 Sheets at December 31, 2011 was $0.8 million and $1.7 million, respectively. The amount of the regulatory asset and the related ARO liability on the accompanying Consolidated Balance Sheet at December 31, 2010 was $1.0 million and $1.6 million, respectively. Central began recovering asset retirement obligations in its rates 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. During the years ended December 31, 2011, 2010 and 2009, the company did not identify an impairment of its long-lived assets.

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.

In January 2010, the FASB issued Accounting Standard Update, or ASU, No. 2010-06, “Improving Disclosures about Fair Value Measurements.” This ASU requires both the gross presentation of activity within the Level 3 fair value measurement roll forward and the details of transfers in and out of Level 1 and 2 fair value measurements. It also clarifies certain disclosure requirements on the level of disaggregation of fair value measurements and disclosures on inputs and valuation techniques. This ASU was effective January 1, 2010 (except for Level 3 roll forward which was to be effective January 1, 2011). The adoption of this ASU did not have a significant effect on the disclosures of the Company.

On March 15, 2011, the FASB extended the implementation of Level 3 fair value measurements to interim and annual periods beginning after December 15, 2011. Management is currently evaluating the effect that the provisions of this ASU will have on the Company’s disclosures.

Recent Accounting Standards

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards.” This ASU amended the Fair Value Measurements and Disclosures Topic of the ASC to converge the fair value measurement guidance in GAAP and the International Financial Reporting Standards, or IFRS. Some of the amendments clarify the application of existing fair value measurement requirements, while other amendments change a particular principle in the Fair Value Measurements and Disclosures Topic of the ASC. In addition, this ASU requires additional fair value disclosures. The amendments are to be applied prospectively and are effective for annual periods beginning after December 15, 2011. Management is currently evaluating the effect that the provisions of this ASU will have on the Company's financial statements.

In September 2011, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2011-08, “Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment.” This ASU amended the Goodwill and Other Intangible Assets Topic of the ASC, stating that a company no longer has to calculate the fair value of a reporting unit unless it believes it’s more likely than not that the unit’s fair value is less than the value carried on the balance sheet. The amendment is to be applied prospectively and will be effective for annual periods beginning after December 15, 2011.

In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities.” Under this ASU, new disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under U.S. GAAP and IFRS related to the offsetting of financial instruments. The existing U.S. GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The amendments are to be applied retrospectively for all periods presented and become effective for interim and annual reporting periods beginning on or after January 1, 2013. Management is currently evaluating the effect that the provisions of this ASU will have on the Company.

3. Financing

At December 31, 2011 and 2010, long-term debt consisted of the following (expressed in thousands):

	December 31, 2011			December 31, 2010
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		4,745			4,980
Unamortized debt discount		(2,659	)		(3,292	)
Total debt		482,086			481,688
Less current capitalized lease obligation		250			235
Total long-term debt	$	481,836		$	481,453

6.75% Registered Notes

At December 31, 2011 and 2010, Southern Star 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 Mellon 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 related issuance costs are being amortized over the life of the 6.75% Registered Notes utilizing the straight line method. 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 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. Southern Star has the right to redeem all or part of the 6.75% Registered Notes at premiums defined in the indenture.

6.75% Unregistered Notes

At December 31, 2011 and 2010, Southern Star had outstanding $50.0 million aggregate principal amount of 6.75% Senior Notes due 2016, or 6.75% Unregistered Notes. The Bank of New York Mellon Trust Company, N.A. serves as trustee under the related indenture. Interest is payable semi-annually on March 1 and September 1 of each year. The related issuance costs are being amortized over the life of the 6.75% Unregistered Notes utilizing the straight line method. 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. Southern Star has the right to redeem all or part of the 6.75% Unregistered Notes at premiums defined in the indenture.

Central’s 6.0% Notes

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, N. A. 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. Approximately $2.2 million of amortization relating to the capital lease has been included in Accumulated depreciation and amortization in the accompanying Consolidated Financial Statements. 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, 2011, 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)
2012	$	—	$	250
2013		—		265
2014		—		280
2015		—		305
2016		480,000		325
After 2016		—		3,320
Total	$	480,000	$	4,745

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.

General Rate Issues