UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________

FORM 10-K

_________________________

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

For the fiscal year ended December 31, 2013

or

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

For the transition period from to

Commission file number 333-110979

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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.    Yesx    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	(Do not check if a smaller reporting company)	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 28, 2014, registrant had 100 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE - None

TABLE OF CONTENTS

2013 FORM 10-K

SOUTHERN STAR CENTRAL CORP.

		Page
Forward-Looking Statements		1
	PART I
Item 1.	Business	2
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	15
Item 2.	Properties	15
Item 3.	Legal Proceedings	15
Item 4.	Mine Safety Disclosures	16
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6.	Selected Financial Data	17
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
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	37
Item 13.	Certain Relationships and Related Transactions, and Director Independence	37
Item 14.	Principal Accounting Fees and Services	37
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	38

FORWARD-LOOKING STATEMENTS

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

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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 Central Corp., or Southern Star, was a wholly-owned subsidiary of EFS-SSCC Holdings, LLC, or EFS, as of and during the year ended December 31, 2011 and through September 23, 2012. 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, indirectly held all of the outstanding capital stock of EFS during these periods.

On August 23, 2012, GE entered into an agreement to sell to MSIP its 60% economic stake and 50% voting stake in Southern Star through the sale of its interests in EFS, or the Sale. The Sale was consummated on September 24, 2012, constituting a change in control and resulting in a new basis of accounting for Southern Star. In connection with the Sale, EFS changed its name to MSIP-SSCC Holdings, LLC, or Holdings. See Note 3 in the Notes to Consolidated Financial Statements section of this annual report on Form 10-K for further information regarding the Sale.

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 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, 2013, 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 was 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, 2013, 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, 2013, Central had customer transportation contracts with approximately 127 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 528 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 15 years. At December 31, 2013, the average remaining contract life on a volume-weighted basis was approximately five years.

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For the year ended December 31, 2013, approximately 88% 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, Laclede Gas Company, Missouri Gas Energy Division, or MGE, and Kansas Gas Service Company, or KGS, a division of ONE Gas, Inc., accounted for approximately 58% (approximately 31% and 27% respectively) of operating revenues for the year ended December 31, 2013. 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. Central also receives revenues from other subsidiaries of Laclede Gas Company and ONE Gas, Inc., but these amounts were immaterial to Central’s aggregate 2013 revenues. No other customer accounted for more than 10% of our revenues in 2013.

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 Mississippi Lime (Anadarko) area has substantial potential for incremental production. 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; ten are receipt points; and five 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.

Central currently has 41 compressor stations with approximately 206,000 certificated horsepower. Thirty-three 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.

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

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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 2013, 2012 and 2011 operating revenues and approximately 72% of Central’s firm market area capacity as of December 31, 2013, 2012 and 2011. Of its firm production area capacity, this service represents approximately 45% as of December 31, 2013 and 44% as of December 31, 2012 and 2011, and approximately 85% of its firm storage deliverability as of December 31, 2013, 2012 and 2011, respectively.

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 31% of our 2013 and 2012 operating revenues and approximately 32% of our 2011 operating revenues, approximately 28% of Central’s firm market area capacity as of December 31, 2013, 2012 and 2011, and of its firm production area capacity, approximately 55% as of December 31, 2013 and 56% as of December 31, 2012 and 2011, respectively.

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 Bcf/day of firm storage deliverability capacity and 47 Bcf of on-system natural gas storage capacity. Central’s storage service allows shippers to store natural gas close to their customers. Central’s storage facilities are strategically located in close proximity to its key market areas. The majority of the firm storage capacity is contracted as a component of 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 4% of our operating revenues for the year ended December 31, 2013.

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, 2013.

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.

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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:

ONG Ottawa - In March of 2013, Central placed into service a new delivery facility for Oklahoma Natural Gas near Ottawa, Oklahoma. This facility was constructed to meet both existing and new incremental load at that location. It was supported by an incremental five-year contract expected to generate approximately $0.4 million in revenue over the contract term.

Linn Energy Sublette - In April of 2013, Central installed a new delivery point for service to Linn Energy's Sublette Station. This production area expansion is supported by a five-year firm transportation contract for 5,000 Dekatherms, or Dths/day, and is expected to generate approximately $0.4 million in annual revenue.

Black Hills Cheyenne Prairie - Black Hills subsidiary Cheyenne Light Fuel & Power is moving forward with its Cheyenne Prairie power generation project in Cheyenne, Wyoming. The project consists of a five-mile lateral line and delivery meter station in Laramie County, Wyoming and is expected to be completed in the second quarter of 2014. This production area expansion is supported by a seven-year, seven-month firm transportation contract for 10,000 Dths/day. The contract will become effective in October of 2014 and is expected to generate approximately $0.7 million in annual revenue.

Straight Blackwell Expansion Project - Central completed a binding open season for the “Straight Blackwell Expansion Project” to add incremental firm transportation capacity to our system to serve portions of Oklahoma, Kansas and Missouri. The open season generated interest from shippers for an additional 225,000 Dths/day of capacity and is slated to be in service during the fourth quarter of 2014. Portions of the project were constructed during 2013 and the remainder will be completed during 2014. New and incremental receipts from two gas processing plants in Woods County, Oklahoma will be able to transport gas to the Production/Market Interface, or PMI, and to a new delivery point to Natural Gas Pipeline Company of America, or NGPL, in Beaver County, Oklahoma. The facilities required for two receipt points and the deliveries to NGPL will be placed in service during the first quarter of 2014. The facilities required for deliveries to the PMI will be completed during the third quarter of 2014. The project is supported by contracts with terms up to ten years and is expected to generate approximately $6.8 million in annual revenue.

Sedalia Expansion Project- Central conducted an open season in March 2013 for incremental service on its Sedalia system in Missouri. The open season generated interest in an incremental 10,600 Dths/day in the market area. The project was placed in service November 1, 2013. The project is supported by firm transportation agreements with a 20-year term and is expected to generate approximately $0.5 million in annual revenue.

Blackwell to Shidler Expansion - Central conducted an open season during May 2013 for interest in expanding its Blackwell to Shidler segment in Oklahoma. Central received binding bids for 6,217 Dths/day of capacity. Central anticipates facilities to be in service January 1, 2015. The project will be supported by contracts with a ten-year term and is expected to generate $0.3 million in annual revenue.

Sunflower Rubart Expansion - Central constructed a new delivery point to serve Mid-Kansas Electric's Rubart Generating Station in Grant County, Kansas. The point will be capable of delivering 50,000 Dths/day to the plant. The project is expected to be placed in service during the first quarter of 2014. The costs of the project are reimbursable to Central.

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 on directly connected supply opportunities, which provide 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 Bellmon - During 2013, Central upgraded a receipt point in the Noble County, Oklahoma area capable of receiving up to 50,000 Dths/day. Central is currently upgrading the facility to receive up to 90,000 Dths/day. The upgrade is expected to be in service during the second quarter of 2014. 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 expected to be placed in service during the second quarter of 2014. The costs of the interconnect point are reimbursable to Central.

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Devon Grant County -Central installed a new receipt point for Devon Energy in Grant County, Oklahoma during 2013. The facility is capable of receiving 30,000 Dths/day into the Central system. The project was placed in service in July 2013. The costs of the interconnect have been reimbursed to Central.

PVR Midstream Logan County - Central installed a new receipt point in Logan County, Oklahoma capable of receiving 42,000 Dths/day. The project was placed in service December 26, 2013. The costs of the interconnect have been reimbursed to Central.

TIGT Yuma County - Central initiated construction of a new receipt point in Yuma County, Colorado capable of receiving up to 25,000 Dths/day. The project is expected to be in service during the first quarter of 2014. The costs of the interconnect point are reimbursable to Central.

Superior Pipeline Perkins - Central is upgrading an existing receipt point in Lincoln County, Oklahoma capable of receiving up to 15,000 Dths/day. The project is expected to be placed in service during the first quarter of 2014. The costs of the upgrade are reimbursable to Central.

Various Other Projects and Initiatives - In addition, we are in the preliminary stages of evaluating three new supply/receipt projects that would add approximately 70,000 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. Central’s primary competitors in these markets are Kansas Pipeline Company, Tallgrass Interstate Gas Transmission, 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 typically 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 are 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

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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. Neither the Company, Central nor the Company's parent, is itself a "public-utility company" or a "holding company" of a public-utility company under PUHCA 2005.

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 May 31, 2013, Central filed a general rate case under FERC Docket No. RP13-941, to be effective December 1, 2013. The FERC issued a suspension order dated July 5, 2013 accepting and suspending the proposed tariff records to be effective December 1, 2013, subject to refund and conditions, and the outcome of a hearing. On November 26, 2013, Central submitted a filing that reflected suspended rates, which Central requested be moved into effect on December 1, 2013, subject to refund of revenues collected in excess of settlement rates, consistent with the FERC's orders in this proceeding. The motion rates reflect adjustments required by the FERC's orders and regulations. Pursuant to the principles of settlement reached with active parties in the case, Central filed, and the FERC approved, an interim rate reduction to be effective February 1, 2014. Such interim rates were the settlement rates. Central filed a Stipulation and Agreement on March 7, 2014. The settlement, if approved, will increase Central’s revenues approximately $28.0 million above revenues for the 12 months ended February 28, 2013, the base period covered in its filing, and will require Central to make refunds to its customers for revenues collected in excess of settlement rates for the months of December 2013 and January 2014.

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

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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, or HCAs, that must be completed within ten years of the enactment of the PSIA. Central completed the initial 10-year assessment in December 2012. In January 2011, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, or the Act, was enacted, setting forth certain requirements of the Pipeline and Hazardous Materials Safety Administration, or PHMSA, to produce certain studies and follow-up rulemakings for the natural gas pipeline industry. PHMSA has yet to issue a Notice of Proposed Rulemaking or a follow-up final set of rules. The Act contemplates, among other things, a broadened definition of HCA, the installation of automated or remote control valves, as well as the validation of Maximum Allowable Operating Pressures of all pipelines included in the newly defined HCAs. Based on current information, we do not expect these costs to have a material adverse effect on our financial position or results of operations.

Environmental Matters

Central is subject to federal, state and local statutes, rules and regulations relating to environmental protection, including the National Environmental Policy Act, the Clean Water Act, the Clean Air Act and the Resource Conservation and Recovery Act. These laws and regulations can result in capital, operating and other costs. These laws and regulations generally subject Central to inspections and require it to obtain and comply with a wide variety of environmental licenses, permits and other approvals. Under the Clean Air Act, the U.S. Environmental Protection Agency, or EPA, has promulgated regulations addressing emissions from equipment present at typical natural gas compressor stations. The Clean Air Act of 1973 established the National Emission Standards for Hazardous Air Pollutants, or NESHAPs, for reciprocating internal combustion engines, stationary turbines, and glycol dehydration equipment in addition to regulations that address regional transport 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 operations. 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. There are also other potential state or federal regulations or legislation related to greenhouse gas emissions that could impact Central’s existing operations if promulgated. Central continues to monitor the progress of any proposed rules or legislation and will determine any impact once the regulations have been promulgated.

Central has identified polychlorinated biphenyl, or PCB, contamination in air compressor systems, soils, and related properties at certain compressor station sites and has been involved in negotiations with the EPA and state agencies to develop screening, sampling, and cleanup programs. In addition, negotiations with certain environmental agencies concerning investigative and remedial actions relative to potential mercury contamination at certain natural gas metering sites have commenced. Central had accrued an undiscounted liability of approximately $1.0 million at December 31, 2013 and $1.2 million at December 31, 2012, representing the current estimate of future environmental testing and cleanup costs, most of which is expected to be incurred over the next three to four years. However, timing is highly dependent upon State and Federal negotiations.

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 most, if not 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

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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, 2013, we had 498 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. 351, or the Union, previously the International Union of Operating Engineers Local No. 647, covering 155 field employees. The collective bargaining agreement expires on April 1, 2017.

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 on 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 may be experiencing, or may experience in the future, financial problems that 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 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

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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 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, 2013, we were aware of mercury contamination that requires characterization at approximately nine of our meter sites, covering three states with remediation anticipated at all nine sites.

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 $1.0 million as of December 31, 2013, representing the estimate of future cleanup costs, most of which is expected to be incurred over the next three to four years. However, timing is highly dependent upon State and Federal negotiations.

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 2014, 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 compliance with the terms of the settlement in our 2008 rate case (Docket No. RP08-350), we filed a new 2013 general rate case (Docket No. RP13-941) to be effective December 1, 2013. Pursuant to the principles of settlement reached with active parties in the 2013 rate case, Central filed a Stipulation and Agreement on March 7, 2014. The settlement, if

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approved, will require Central to submit another rate case filing no later than November 1, 2021. 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, tornadoes, 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, 2013, approximately 96% of our firm contracted market area capacity, 96% 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.

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

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

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.

An impairment of goodwill and intangible assets could reduce our earnings.

As of December 31, 2013, our Consolidated Balance Sheets reflected approximately $471.0 million of goodwill. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on stockholder's equity and balance sheet leverage as measured by debt to total capitalization.

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. Failure to comply with these regulations could result in the assessment of fines or penalties against the Company. 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.

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

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(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.

Cybersecurity breaches, failures of our information technology systems and other disruptions or security breaches could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personal identification information of our employees, in our data centers and on our networks. We are also highly dependent on financial, accounting and other data processing systems and other communications and information systems. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Also, if a key system was to fail or experience unscheduled downtime for any reason, our operations and financial results could be affected adversely. Any such breach or malfunction could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of our operations, damage to our reputation, and cause a loss of confidence in our services, which could adversely affect our business.

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, Tallgrass Interstate Gas Transmission 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.

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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 88% of operating revenue during the year ended December 31, 2013. Approximately 58% of our operating revenues during the year ended December 31, 2013 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 were extended for an additional five years and are now set to expire in 2018. 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. 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.

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Strikes or work stoppages may adversely affect our operations as approximately 31% 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. 351, or the Union, previously the International Union of Operating Engineers Local No. 647. 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 April 1, 2017 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:

• make investments;

• incur or guarantee additional indebtedness;

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

• create liens;

• incur dividend or other payment restrictions affecting subsidiaries;

• merge or consolidate with other entities; and

• enter into transactions with affiliates.

Our ability to comply with these covenants may be affected by many events beyond our control. Failure to comply with these covenants could result in an event of default, which could cause our outstanding senior notes and amounts under our revolving credit agreement (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 41 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.

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

Item 3. Legal Proceedings

None.

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Item 4. Mine Safety Disclosures

None.

PART II.

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

There is no established public trading market for our common stock. As of December 31, 2013, 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 or returns of capital declared during the years 2013 and 2012 were approximately $37.7 million and $28.2 million, respectively. We expect to continue to pay dividends as permitted under the indenture on a quarterly basis.

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Item 6. Selected Financial Data

The following table presents our selected consolidated financial data which should be read 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)

	Successor (a)						Predecessor (a)
	For the Year Ended December 31, 2013			For the Period September 24 through December 31, 2012			For the Period January 1 through September 23, 2012			For the Year Ended December 31, 2011			For the Year Ended December 31, 2010			For the Year Ended December 31, 2009
Statement of Net Income Data:
Operating Revenues	$	216,179		$	60,838		$	157,736		$	214,093		$	214,142		$	220,801
Operating Costs and Expenses:
Operations and maintenance	54,402			13,624			36,372			51,463			49,253			50,135
Administrative and general	42,358			10,589			28,624			37,486			37,770			42,954
Depreciation and amortization	36,007			9,404			25,114			33,150			31,057			32,238
Taxes, other than income taxes	18,377			4,597			12,708			16,884			16,153			15,293
Total Operating Costs and Expenses	151,144			38,214			102,818			138,983			134,233			140,620
Operating Income	65,035			22,624			54,918			75,110			79,909			80,181
Interest Expense (Income):
Interest expense	30,873			8,074			23,735			32,367			32,367			32,556
Interest income	(38		)	(12		)	(37		)	(96		)	(96		)	(308		)
Miscellaneous other income	(888		)	(200		)	(637		)	(6,873		)	(768		)	(49		)
Income Before Income Taxes	35,088			14,762			31,857			49,712			48,591			47,982
Provision for Income Taxes	13,130			5,820			12,511			19,495			18,526			19,010
Net Income	$	21,958		$	8,942		$	19,346		$	30,217		$	30,065		$	28,972
Balance Sheet Data (end of period):
Cash and Cash Equivalents	$	18,388		$	37,467		$	31,251		$	23,501		$	23,200		$	38,789
Property, Plant & Equipment, net	766,242			681,975			657,060			645,347			637,793			607,794
All Other Assets	592,953			615,420			438,557			450,623			428,787			438,671
Total Assets	$	1,377,583		$	1,334,862		$	1,126,868		$	1,119,471		$	1,089,780		$	1,085,254
Capitalization:
Current maturities of long-term debt	$	280		$	265		$	265		$	250		$	235		$	745
Total long-term debt, net of current portion	486,902			488,408			482,034			481,836			481,453			481,054
Common stockholder’s equity	567,446			583,227			430,473			429,934			432,550			429,730
Total Capitalization	$	1,054,628		$	1,071,900		$	912,772		$	912,020		$	914,238		$	911,529

(a) The term "Predecessor" refers to the Company's operations prior to GE's sale of its 60% economic stake and 50% voting stake in Southern Star to MSIP, or the Sale. The term "Successor" refers to the Company's operations subsequent to the Sale. See Notes 2 and 3 in the Consolidated Financial Statements section of this annual report on Form 10-K for further information regarding the Sale.

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

17

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 15 years. Total average remaining contract life on a volume-weighted basis at December 31, 2013 was approximately five years.

On May 31, 2013, Central filed a general rate case under FERC Docket No. RP13-941, to be effective December 1, 2013. The FERC issued a suspension order dated July 5, 2013 accepting and suspending the proposed tariff records to be effective December 1, 2013, subject to refund and conditions, and the outcome of a hearing. On November 26, 2013, Central submitted a filing that reflected suspended rates, which Central requested be moved into effect on December 1, 2013, subject to refund of revenues collected in excess of settlement rates, consistent with the FERC's orders in this proceeding. The motion rates reflect adjustments required by the FERC's orders and regulations. Pursuant to the principles of settlement reached with active parties in the case, Central filed, and the FERC approved, an interim rate reduction to be effective February 1, 2014. Such interim rates were the settlement rates. Central filed a Stipulation and Agreement on March 7, 2014. The settlement, if approved, will require Central to make refunds to its customers for revenues collected in excess of settlement rates for the months of December 2013 and January 2014.

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. Furthermore, 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 remains on schedule to meet all compliance regulations and expects that operating costs associated with such regulations will continue to be recovered in the rates it charges for its services.

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

In addition, we proactively seek growth opportunities that will further strengthen our financial position and results of operations. The costs we incur for many of our growth opportunities are reimbursed by the operator of the gas supply or delivery point.

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On April 4, 2013, Central completed the installation of a new delivery point for service to Linn Energy's Sublette Station. This expansion was supported by a five-year firm transportation contract for 5,000 Dths/day that was effective September 1, 2012. The expansion is expected to generate revenues of $0.4 million annually.

On February 1, 2013, Central was selected by Black Hills subsidiary, Cheyenne Light Fuel & Power, as the gas transportation provider for the Cheyenne Prairie power generation project in Cheyenne, WY. The project consists of a five-mile lateral line and delivery meter station in Laramie County, WY. This expansion is supported by a seven-year, seven-month firm transportation contract for 10,000 Dths/day and is expected to be effective October 1, 2014. The expansion is expected to generate revenues of $0.7 million annually.

On May 14, 2013, Central concluded an open season for the "Blackwell to Shidler Expansion Project" to reserve capacity for the Oklahoma Municipal Power Authority, or OMPA. The project is supported by a 10-year transportation agreement for approximately 6,000 Dths/day and is expected to be effective January 1, 2015. The expansion is expected to generate revenues of $0.3 million annually.

Central finalized agreements with two shippers on May 21, 2013 for the "Straight Blackwell Expansion Project" to expand capacity on its Straight-Blackwell system. The expansion will require the installation of new meter stations, pressure regulators and a pipeline pressure uprate. The project is supported by five-year and ten-year firm transportation agreements for approximately 225,000 Dths/day and is expected to be effective October 1, 2014. The project is expected to generate revenues of $6.8 million annually.

Central concluded an Open Season on April 1, 2013 for the "Sedalia Expansion Project" to reserve capacity on its Sedalia Line. The project is supported by a 20-year firm transportation agreement for approximately 11,000 Dths/day of capacity that was effective November 1, 2013. The project is expected to generate revenues of $0.5 million annually.

Acquisition

On August 23, 2012, GE entered into an agreement to sell to MSIP its 60% economic stake and 50% voting stake in the Company through the sale of its interests in EFS. The Sale was consummated on September 24, 2012. The Company is now indirectly wholly owned by MSIP.

Basis of Presentation

The Sale resulted in a change in control and a new basis of accounting for Southern Star, as required by the Business Combinations Topic 805 of the Accounting Standards Codifications, or the ASC. The total consideration, including the estimated fair value of MSIP's original 40% economic interest, has been "pushed down" and allocated to our assets and liabilities. Our financial statements, related to periods prior to the Sale, reflect the previous accounting basis in the Company's assets and liabilities and are labeled Predecessor, while the periods subsequent to the Sale are labeled Successor and reflect the allocation of purchase price to all assets acquired and liabilities assumed in the Sale. Therefore, our Consolidated Statements of Net Income and Cash Flows for the period January 1, 2012 through September 23, 2012 and the year ended December 31, 2011 each reflect the operations of the Predecessor. Our Consolidated Statements of Net Income and Cash Flows for the year ended December 31, 2013, the period September 24, 2012 through December 31, 2012, and the Consolidated Balance Sheets as of December 31, 2013 and 2012 each reflect the operations and financial position of the Successor.

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 Regulated Operations Topic 980 of the ASC, or ASC 980, 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

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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 ASC 980 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 ASC 980 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 ASC 980, 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 Central's rates. For further discussion of our employee benefit plans, see Note 10 to the accompanying Notes to the Consolidated Financial Statements.

Goodwill

As a result of the Sale, we recorded $471.0 million of goodwill. Goodwill is not amortized and is subject to an annual impairment test as of October 1 and whenever events or circumstances make it more likely than not that impairment may have occurred in accordance with Goodwill and Other Intangible Assets Topic 350 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. Please see Note 2 of the accompanying Notes to the Consolidated Financial Statements.

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. At December 31, 2013, Central had estimated reserves for revenues subject to refund pending settlement of its RP13-941 rate proceeding of $4.4 million, excluding interest, which will be refunded to customers within 60 days of final approval by the FERC. The reserve is included in Other accrued liabilities on the Consolidated Balance Sheet. 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

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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. Holdings and Central generally make payments to Southern Star for their federal and state income tax liabilities as though they were filing separate returns. Southern Star has an obligation to indemnify Holdings and Central for any liability that they incur for taxes of the affiliated group of which Southern Star, Holdings 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.

Results of Operations

Results of operations for all periods presented include the operations of Central, our only operating subsidiary. All periods include the application of purchase accounting. The periods subsequent to September 23, 2012 reflect the impact of the Sale. For discussion purposes, we have combined the results of operations for the Successor and Predecessor periods of 2012 because we believe it facilitates the comparison of 2013 and 2011 operating and financial performance to 2012 and because the operations of Southern Star have not changed as a result of the Sale. Pro forma results of operations are not presented, as the only continuing impacts of the Sale on the results of operations are those discussed in Note 3 of the accompanying Notes to the Consolidated Financial Statements.

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, 2013, 2012 and 2011:

	Successor			Successor/Predecessor			Predecessor
	For the Year Ended December 31, 2013			(Unaudited) Combined Year Ended December 31, 2012			For the Year Ended December 31, 2011
	(In thousands)
Operating revenues	$	216,179		$	218,574		$	214,093
Operations and maintenance	54,402			49,996			51,463
Administrative and general	42,358			39,213			37,486
Depreciation and amortization	36,007			34,518			33,150
Taxes, other than income taxes	18,377			17,305			16,884
Operating income	65,035			77,542			75,110
Other (Income) Deductions:
Interest expense	30,873			31,809			32,367
Interest income	(38		)	(49		)	(96		)
Miscellaneous other income, net	(888		)	(837		)	(6,873		)
Total Other Deductions	29,947			30,923			25,398
Income before income taxes	35,088			46,619			49,712
Provision for income taxes	13,130			18,331			19,495
Net Income	$	21,958		$	28,288		$	30,217

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Comparison of the Years Ended December 31, 2013 and 2012

Operating revenues were $216.2 million for the year ended December 31, 2013, a $2.4 million, or 1.1% decrease from $218.6 million in 2012. The decrease in 2013 is principally due to lower storage capacity revenues resulting from a normal winter season compared to the milder winter season in 2012 and lower revenue from the incremental park and loan services, partially offset by higher transportation reservation revenue.

Operations and maintenance expenses were $54.4 million for the year ended December 31, 2013, a $4.4 million, or 8.8%, increase from $50.0 million in 2012. The increase is principally due to higher expenses in 2013 for pipeline integrity management, labor, engine overhauls and maintenance, geographic information systems, outside contracting, lube oil, and well testing, offset partially by lower expenses for environmental remediation and outside engineering support for encroachments.

Administrative and general expenses were $42.4 million for the year ended December 31, 2013, a $3.2 million, or 8.0%, increase from $39.2 million in 2012. The increase is principally due to higher expenses in 2013 for labor, employee benefits, computer software maintenance and fees associated with the Company's line of credit, offset partially by lower expenses for professional services and higher expenses transferred to capital.

Depreciation and amortization expenses were $36.0 million for the year ended December 31, 2013, a $1.5 million, or 4.3%, increase from $34.5 million in 2012. The increase is primarily due to asset additions to the 2013 depreciable base for transmission mains.

Taxes other than income taxes were $18.4 million for the year ended December 31, 2013, a $1.1 million, or 6.2%, increase from $17.3 million in 2012. The increase is primarily due to higher ad-valorem tax assessments in 2013.

Interest expense was $30.9 million for the year ended December 31, 2013, a $0.9 million, or 2.9% decrease from $31.8 million in 2012. The decrease is a result of the change in the amortization of debt discounts/premiums as a result of the Sale in the third quarter 2012, as further discussed in Note 3 of the accompanying Notes to the Consolidated Financial Statements. The decrease was partially offset by higher interest expense associated with the Company's line of credit.

Interest income was comparable for each of the years ended December 31, 2013 and 2012.

The provision for income taxes was $13.1 million for the year ended December 31, 2013, a $5.2 million, or 28.4%, decrease from $18.3 million in 2012, commensurate with lower pre-tax income. Our effective tax rate for 2013 was 37.4% compared to 39.3% for the same period in 2012. The comparability of our reported income taxes for the reported periods were affected by a Kansas property expense deduction enacted in 2012. Kansas Senate Bill 196 created an expense deduction against Kansas taxable income for businesses that invest in property located in Kansas. This deduction reduced our 2012 Kansas state taxes by $0.7 million and was recorded as an adjustment in 2013. If the expensing deduction exceeds Kansas net income, such excess is treated as a Kansas net operating loss that may be carried forward. Such is the case for 2013 where the estimated savings of $0.6 million will be carried forward to 2014.

Comparison of the Years Ended December 31, 2012 and 2011

Operating revenues were $218.6 million for the year ended December 31, 2012, a $4.5 million, or 2.1% increase from $214.1 million in 2011. The increase in 2012 is principally due to a full year of revenues from the Elk City Storage Field expansion, or "Storage Expansion Project," placed into service on April 1, 2011 and higher storage capacity revenues in 2012 as a result of the mild winter season. Also contributing to the increase were higher park and loan and transportation reservation revenues.

Operations and maintenance expenses were $50.0 million for the year ended December 31, 2012, a $1.5 million, or 2.9%, decrease from $51.5 million in 2011. The decrease is principally due to lower expenses in 2012 for pipeline integrity management program and labor, offset partially by higher expenses in 2012 for compressor engine overhauls and maintenance.

Administrative and general expenses were $39.2 million for the year ended December 31, 2012, a $1.7 million, or 4.6%, increase from $37.5 million in 2011. The increase is principally due to higher expenses in 2012 for employee incentives, hardware and software maintenance, property and liability insurance and outside legal services, offset partially by lower expenses for group insurance, supplies and other professional services as well as higher expenses transferred to capital.

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Depreciation and amortization expenses were $34.5 million for the year ended December 31, 2012, a $1.4 million, or 4.1%, increase from 2011. The increase is primarily due to asset additions to the 2012 depreciable base for transmission mains.

Taxes other than income taxes were $17.3 million for the year ended December 31, 2012, a $0.4 million, or 2.5%, increase from $16.9 million in 2011. The increase is primarily due to higher ad-valorem tax assessments in 2012.

Interest expense was $31.8 million for the year ended December 31, 2012, a $0.6 million, or 1.7% decrease from $32.4 million in 2011. The decrease is a result of the decrease in the amortization of debt discounts/premiums as a result of the Sale, as further discussed in Note 3 of the accompanying Notes to the Consolidated Financial Statements.

Interest income was comparable for each of the years ended December 31, 2012 and 2011.

Miscellaneous other income, net was $0.8 million for the year ended December 31, 2012, a $6.0 million decrease from 2011. The decrease is a result of the sale of excess working gas converted from base gas as a result of the "Storage Expansion Project" in 2011.

The provision for income taxes was $18.3 million for the year ended December 31, 2012, a $1.2 million, or 6.0%, decrease from $19.5 million in 2011, commensurate with lower pre-tax income. Our effective tax rate for 2012 was 39.3% compared to 39.2% for the same period in 2011.

Liquidity and Capital Resources

We expect to fund our capital and other liquidity requirements with cash on hand, cash flows from operating activities and by drawing on a credit facility that was established in 2012, as discussed below. The following table sets forth our selected cash flow data for the years ended December 31, 2013, 2012 and 2011:

	Successor			Successor/Predecessor			Predecessor
	For the Year Ended December 31, 2013			(Unaudited) Combined Year Ended December 31, 2012			For the Year Ended December 31, 2011
Net income	$	21,958		$	28,288		$	30,217
Adjustments to reconcile net cash provided from operations	55,631			45,485			37,358
Net cash provided by operating activities	77,589			73,773			67,575
Net cash used in investing activities	(118,007		)	(70,083		)	(34,162		)
Net cash provided by (used in) financing activities	21,339			10,276			(33,112		)
Net change in cash and cash equivalents	(19,079		)	13,966			301
Cash and cash equivalents at beginning of period	37,467			54,752			23,200
Cash and cash equivalents at end of period	$	18,388		$	68,718		$	23,501

Net cash provided by operating activities for the years ended December 31, 2013 and 2012 was $77.6 million and $73.8 million, respectively. Net cash from operating activities was higher in 2013 primarily due to higher 2013 cash receipts for reimbursable projects, an insurance settlement, a decrease in purchases of materials and supplies inventory and lower pension funding. The increase was partially offset by lower 2013 operating income, excluding depreciation, higher incentive payments and higher property and liability insurance premiums. Funding to our pension plans is further discussed in Note 10 of the accompanying Notes to the Consolidated Financial Statements.

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Net cash used in investing activities for the years ended December 31, 2013 and 2012 was $118.0 million and $70.1 million, respectively. Cash used in investing activities was higher in 2013 primarily due to higher capital expenditures for maintenance and expansion projects.

Net cash provided in financing activities for the years ended December 31, 2013 and 2012 was $21.3 million and $10.3 million, respectively. The change is primarily due to draws on the credit facility being $20.0 million higher in 2013 than in 2012, partially offset by higher 2013 common stock dividend payments.

Net cash provided by operating activities for the years ended December 31, 2012 and 2011 was $73.8 million and $67.6 million, respectively. Net cash from operating activities was higher in 2012 primarily due to higher cash receipts for reimbursable projects, higher 2012 storage revenues and lower 2012 pension funding. The increase was partially offset by increased materials and supplies inventory and higher cash payments for income taxes in 2012. Funding to our pension plans is further discussed in Note 10 of the accompanying Notes to the Consolidated Financial Statements.

Net cash used in investing activities for the years ended December 31, 2012 and 2011 was $70.1 million and $34.2 million, respectively. Cash used in investing activities was higher in 2012 primarily due to higher maintenance capital expenditures and a receipt of proceeds, in 2011, from the sale of an asset, partially offset by lower capital expenditures for expansion in 2012 and the purchase of storage acreage in 2011.

Net cash provided from financing activities was $10.3 million for the year ended December 31, 2012, as compared to net cash used of $33.1 million for the same period in 2011. The change is primarily due to a $40.0 million draw on the credit facility established in 2012 and lower 2012 common stock dividend payments, partially offset by the issuance costs associated with the establishment of the credit facility, further discussed in Note 5 of the accompanying Notes to the Consolidated Financial Statements.

6.75% Registered Notes

At December 31, 2013 and 2012, 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. Prior to the Sale, the related issuance costs were being amortized over the life of the 6.75% Registered Notes utilizing the straight line method which approximated the effective interest method. As of September 24, 2012, there were no issuance costs related to the 6.75% Registered Notes included in our Consolidated Balance Sheets as such costs were not recognized as part of the purchase price allocation. However, the premium established as a result of recognizing the debt acquired at fair value in conjunction with the Sale will be amortized over the remaining period of the 6.75% Registered Notes utilizing the effective interest method. The 6.75% Registered Notes mature on March 1, 2016. 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, 2013 and 2012, 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. Prior to the Sale, the related issuance costs were being amortized over the life of the 6.75% Unregistered Notes utilizing the straight line method which approximated the effective interest method. As of September 24, 2012, there were no issuance costs related to the 6.75% Unregistered Notes included in our Consolidated Balance Sheets as such costs were not recognized as part of the purchase price allocation. However, the premium established as a result of recognizing the debt acquired at fair value in conjunction with the Sale will be amortized over the remaining period of the 6.75% Unregistered Notes utilizing the effective interest method. The 6.75%

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Unregistered Notes will mature on March 1, 2016. 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.

Credit Agreement

On July 3, 2012, the Company entered into a $65.0 million four-year revolving credit agreement, or Credit Agreement, among several banks and other financial institutions or entities from time to time party to the Credit Agreement, or the Lenders, and Royal Bank of Canada, as Administrative Agent, pursuant to which the Lenders agreed to make revolving credit loans to the Company. Effective March 22, 2013, the Credit Agreement was amended and the total aggregate commitment was extended to $125.0 million. Under the Credit Agreement, letters of credit may be issued by the Administrative Agent or by one or more of the other Lenders in an aggregate amount not to exceed $10.0 million.

Borrowings under the Credit Agreement bear interest at a rate per annum equal to, at the Company’s option, either (a) an alternate base rate or (b) a rate based on the rates applicable for deposits in the interbank market for U.S. Dollars or the applicable currency in which the loans are made plus an applicable margin. The applicable margin for each revolving loan will be adjusted in relation to the Company’s then current unsecured debt ratings. Additionally, the Company pays a commitment fee for the average daily unused amount of the facility, payable quarterly in arrears, and certain fees with respect to letters of credit issued under the Credit Agreement. At December 31, 2013 and 2012, we had $100.0 million and $40.0 million outstanding under our revolving credit facility with stated interest rates of 2.17% and 2.2%, respectively. There were no outstanding letters of credit issued under the Credit Agreement as of December 31, 2013 and 2012.

In connection with the Credit Agreement, and pursuant to a pledge agreement dated as of July 3, 2012, among the Company, Central and the Administrative Agent, the Company pledged as collateral its equity interests in Central and certain future acquired subsidiaries.

The Credit Agreement contains negative covenants that, subject to significant exceptions, limit the ability of the Company and its Restricted Subsidiaries to, among other things, (i) incur debt, (ii) engage in new lines of business, (iii) incur liens, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) dispose of substantially all of the assets of the Company and its subsidiaries, (vi) make investments, loans, advances, guarantees and acquisitions, (vii) make certain restricted payments and (viii) enter into transactions with affiliates. The covenants require the Company to comply on a quarterly basis with capitalization ratios with respect to the Company and Central and a minimum fixed charge coverage ratio. The Credit Agreement contains events of default that are customary for a facility of this nature. If an event of default occurs, the commitments of the Lenders to lend under the facility may be terminated and the maturity of the amounts outstanding may be accelerated.

Central’s 6.0% Notes

At December 31, 2013 and 2012, 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. 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

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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 had 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 May 31, 2013, Central filed a general rate case under FERC Docket No. RP13-941, to be effective December 1, 2013. The FERC issued a suspension order dated July 5, 2013 accepting and suspending the proposed tariff records to be effective December 1, 2013, subject to refund and conditions, and the outcome of a hearing. On November 26, 2013, Central submitted a filing that reflected suspended rates, which Central requested be moved into effect on December 1, 2013, subject to refund of revenues collected in excess of settlement rates, consistent with the FERC's orders in this proceeding. The motion rates reflect adjustments required by the FERC's orders and regulations. Pursuant to the principles of settlement reached with active parties in the case, Central filed, and the FERC approved, an interim rate reduction to be effective February 1, 2014. Such interim rates were the settlement rates. Central filed a Stipulation and Agreement on March 7, 2014. The settlement, if approved, will increase Central’s revenues approximately $28.0 million above revenues for the 12 months ended February 28, 2013, the base period covered in its filing, and will require Central to make refunds to its customers for revenues collected in excess of settlement rates for the months of December 2013 and January 2014.

At December 31, 2013, we were in compliance with the covenants of all outstanding debt instruments. See Note 5 of the accompanying Notes to the Consolidated Financial Statements for further discussion of our debt instruments.

Other

Contractual Obligations and Commitments

The table below summarizes our significant contractual obligations and commitments for the years indicated as of December 31, 2013:

Payments Due by Period
(In thousands)
	Total		Less than  1 Year		1-3 Years		3-5 Years		More than 5 Years
Long-term debt obligations (1)	$	556,688	$	30,675	$	526,013	$	—	$	—
Short-term borrowing and other (2)	100,134		100,134		—		—		—
Capital lease obligations (3)	5,816		528		1,079		1,100		3,109
Operating lease commitments	1,033		264		321		91		357
Purchase obligations	3,975		3,975		—		—		—
Capital expenditure commitments (4)	38,403		27,446		10,957		—		—
Total	$	706,049	$	163,022	$	538,370	$	1,191	$	3,466

_________________________

(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) Short-term borrowings consist of amounts outstanding and the associated contractual interest payments under the Credit Agreement.

(3) Includes principal and interest payments.

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

We have estimated capital expenditures of $65.3 million in 2014. We expect to fund 2014 capital expenditures with cash on hand, cash flows from operating activities and by drawing on a credit facility that was established on July 3, 2012.

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Central expects to contribute approximately $7.8 million to its Retirement and Post Retirement Medical Benefit Plans in 2014. See Note 10 of the accompanying Notes to the Consolidated Financial Statements for further discussion of our employee benefit plans.

Contractual obligations and commitments are expected to be funded with cash flows from operating activities, borrowings under the Credit Agreement or by accessing capital markets, if needed and available.

Contingencies

See Note 6 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 over the last three 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.

Dodd-Frank Act

Certain interpretive guidance has been issued by the Commodity Futures Trading Commission, or CFTC, regarding its final rule further defining the term “swap” in accordance with Section 712(b)(1) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act. This guidance has raised concerns for the interstate pipeline industry as to the application of the CFTC’s rules regarding facility usage agreements that employ “two-part” rate structures consisting of a “demand” or “reservation” charge and other usage fees and those rules’ application to natural gas transportation and storage agreements and other transactions that utilize two-part rates, but that are currently regulated exclusively by the FERC. This regulation took effect October 12, 2012, although the CFTC accepted comments up to that date for further revisions and clarifications to the interpretive guidance previously issued.

Absent further guidance by the CFTC, the current rule arguably subjects all of Central’s two-part rate transportation and storage service agreements, as well as all of its capacity release transactions, to CFTC jurisdiction, creating additional recordkeeping and reporting burdens.

The Interstate Natural Gas Association of America, or INGAA, has filed on behalf of its members, including Central, two pleadings with the CFTC requesting that the interpretive guidance at issue be amended or clarified to exempt two-part fee service transactions already regulated by the FERC from further CFTC regulation under the Dodd-Frank Act. On October 9, 2012, INGAA filed a “Request for Clarification and No-Action Relief Regarding Commission Interpretive Guidance on Transportation and Storage Agreements with Two-Part Fee Structure Set Forth in the Commission’s Swap Definition Final Rule”. Besides requesting clarification that two-part rate interstate service agreements do not meet the definition of “swap” under the CFTC’s new regulations, this filing also requests the CFTC issue a no-action letter stating it will not take or recommend any enforcement action if INGAA’s member companies, including Central, do not treat such agreements as subject to the swap definition, at least for as long as and until the CFTC issues a final clarification, revision or response to the comments concerning such rule.

On October 12, 2012, INGAA submitted its “Comments on Joint Final Rule and Interpretations on Further Definition of ‘Swap’, ‘Security-Based Swap’, and ‘Security-Based Swap Agreement’; Mixed Swap; Security-Based Swap Agreement Recordkeeping (RIN No. 3038-AD46),” to the CFTC on behalf of its members, including Central. These comments contain supporting arguments and facts, which if accepted by the CFTC (and modification of the rules or interpretive guidance was implemented by the CFTC), would effectively exempt the transactions of concern to Central and all other INGAA members from CFTC jurisdiction and avoid any additional regulatory requirements.

In addition on October 12, 2012, the FERC submitted similar comments to the CFTC consistent with INGAA and its members’ position. On November 14, 2012, the CFTC's Office of General Counsel issued a Response to Frequently Asked Questions, or FAQ, clarifying that "Two-Part" rate structures are not "options" within the meaning of the CFTC rules,

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supporting the position taken by INGAA and its members. While Central cannot state with complete certainty that INGAA will be successful in its efforts to modify the CFTC interpretive guidance on this issue, it believes INGAA’s filings have addressed Central’s concerns and provided sufficient protection from any risk of non-compliance with the CFTC rules, at least for the short-term.

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 typically 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

With the exception of our Credit Agreement, for which the interest rate is periodically reset, our debt has been issued at fixed rates. For fixed rate debt, changes in interest rates affect the fair value of the debt instruments but do not directly affect earnings or cash flows. At December 31, 2013, the weighted-average interest rate of our long-term debt was 6.15%. 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 $4.0 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, 2013 had a carrying value of $483.0 million. At December 31, 2013, the fair value of our 6.75% Registered Notes, the 6.75% Unregistered Notes, and the 6.0% Notes was approximately $201.2 million, $50.3 million, and $255.1 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. At December 31, 2013, we had $100.0 million outstanding under our Credit Agreement at a weighted-average interest rate of 2.17%, for which the rate is reset periodically. A 1% increase in interest rates would increase our cash payments for interest on the credit facility by approximately $1.0 million on an annualized basis.

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, 2013, 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, 2013.

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, 2013. In making this assessment, management used the criteria established in Internal Control-Integrated Framework (1992 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Based on

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management’s assessment and the criteria established by COSO, management believes that we maintained effective internal control over financial reporting as of December 31, 2013.

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, 2013, 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, 2014.

Name	Age	Position
Thomas M. Gray	41	Director
John V. Veech	55	Director
John B. Watt	57	Director
Jerry L. Morris	58	President and Chief Executive Officer
Susanne W. Harris	55	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, 2014.

Name	Age	Position
Thomas M. Gray	41	Director
John V. Veech	55	Director
John B. Watt	57	Director
Jerry L. Morris	58	President and Chief Executive Officer
Robert S. Bahnick	54	Vice President and Chief Operations Officer
Robert W. Carlton	53	Vice President and Chief Compliance Officer
David L. Finley	49	Vice President and Chief Administrative Officer
Susanne W. Harris	55	Vice President, Chief Financial Officer and Treasurer
Philip A. Rullman	55	Vice President and Chief Commercial Services Officer

Thomas M. Gray was elected to the Board on September 26, 2012. Mr. Gray has worked for the Management Group of Morgan Stanley Infrastructure Partners and certain other affiliated investment funds managed by Morgan Stanley Infrastructure, Inc., or MSIP, since February 2009 and is currently an Executive Director and Senior manager with that group. Before joining MSIP, Mr. Gray worked for Lehman Brothers Global Infrastructure Partners where he held positions as Senior Vice President and Principal. He also held positions in the Power and Utility Industry Group in the Investment Banking Division of Lehman Brothers where he specialized in regulated utilities, wholesale power generation and project financing. Mr. Gray serves on the board of several MSIP portfolio companies, including Chicago Parking Meters, LLC, Madrilena Red

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de Gas and Montreal Gateway Terminals, LP Corp. Mr. Gray holds a M.B.A. in Finance and Management and a B.S. in Finance and International Business from the Stern School of Business at New York 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 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.

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 36 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 industryorganizations.

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 32 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 30 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

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affiliates since 1998, holding a variety of positions in Information Technology during his 27 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 34 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 34 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 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.

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, 2013 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.

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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 utilizes compensation data from annual surveys conducted on behalf of the Natural Gas Transmission Industry, or NGTI, and by the American Gas Association, or AGA, in both of which Central participates. The 2013 NGTI survey data is a confidential compilation derived from information provided by 19 natural gas transmission pipeline company participants, including peer pipeline companies. For executive compensation, the Board also utilizes compensation data from a confidential annual survey performed by the AGA. The 2013 AGA data is a compilation derived from information provided by 62 AGA member organizations, including the following peer pipeline companies: Centerpoint Energy, Entergy Corporation, Oneok, Inc., Questar Corporation, Nisource, Inc., and Transcanada Corporation. Additionally, management engaged Mercer, an independent compensation consultant, which utilized its own data for energy companies as well as data from the NGTI and AGA surveys, to conduct its study. The Board of Directors may also engage, from time to time, outside compensation consultants to conduct a survey of compensation for the industry.

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 2013 “bonus pool” are set forth under “Compensation Components – Annual Bonus” below, and typically will include both “quantitative” and “qualitative” factors.) The Board is also 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 contributions 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 pools of dollars that may be funded for Bonus Plan awards to employees each year, or the Bonus pools, based on each individual employee’s performance and achievement of goals set within each employee’s annual performance plans. Targets are the same for all employees, but different targets are given different weightings, depending on the employee's classification. Funding of the Bonus pool for officers of the Company, including the named executive officers, establishes the amount available for such officer's Bonus recognition, but does not ensure that an individual officer 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.

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For 2013, the Board established the following targets for funding the Bonus pool for its officers.

• Up to 5% of the Bonus pool was attributed to improving customer satisfaction as measured by annual surveys. For 2013, this component was funded at 5%.

• Up to 10% of the Bonus pool was apportioned to provide for the achievement of non-financial goals and objectives on a department or individual level. For 2013, this component was funded at 10%.

• Up to 15% of the Bonus pool was attributed to the achievement of company safety and compliance goals, including employee training. For 2013, this component was funded at 14%.

• Up to 21% of the Bonus pool was attributed to identifying and presenting business development growth opportunities and executing capital project plans. For 2013, this component was funded at 21%.

• Up to 49% 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 2013, this component was funded at 42%.

2013 EBITDA Targets for Central

From	To	% of Funding Level
$0.0	$100.000M	—
$100.001M	$101.700M	30%
$101.701M	$105.700M	19%

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.

After the end of each year, the Board determines the level of funding for each component. The Board may, at its discretion, fund each 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 2013 for the officer's Bonus pool and funded an additional 13% to the pool. The additional funding was made in recognition of progress made on strategic company initiatives not included in the bonus plan measures. In total, the 2013 Bonus pool in which the named executive officers participate was funded at 105% of the maximum potential Bonus pool. In comparison, the 2012 Bonus pool was funded at 101%.

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.

33

The 2013 Bonus pool in which the named executive officers participate was funded at 105% of the maximum allowed by the Bonus Plan, and as a group, our named executive officers received 17% of the Bonus pool paid to all employees. For 2013, each named executive officer received the following percentage of their respective bonus potential: 115% for Mr. Morris, 105% for Mr. Bahnick, 110% for Mr. Carlton, 85% for Mrs. Harris, and 110% 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 2014.

Summary Compensation Table

The following table sets forth certain summary compensation information as to the CEO and CFO during the fiscal year 2013, 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, 2013. 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, 2013, 2012 and 2011:

Name and Principal Position(4)	Year	Salary $	Bonus $		Change in Pension Value(1) $		All Other Compensation(2) $	Total $
Jerry L. Morris	2013	292,654	271,687		8,872		15,300	588,513
President, CEO	2012	285,950	214,463		158,846		17,213	676,471
	2011	282,762	117,954		146,546		14,700	561,962
Susanne W. Harris	2013	183,077	85,000		(20,740	)	15,300	262,637
Vice President and CFO	2012	178,000	89,000		140,280		12,549	419,829
	2011	177,420	31,150		166,738		13,125	388,433
Robert W. Carlton	2013	195,769	123,750		(23,464	)	16,170	312,225
Vice President and Chief Compliance	2012	187,000	95,000		134,985		15,302	432,287
Officer of Central	2011	184,606	57,400		177,221		13,649	432,876
Robert S. Bahnick	2013	208,654	114,187		(18,840	)	15,300	319,301
Vice President and Chief Operations	2012	206,000	103,000		147,366		14,585	470,951
Officer of Central	2011	206,000	37,080		179,423		15,416	437,919
Philip A. Rullman	2013	195,769	163,750	(3)	42,337		15,300	417,156
Vice President and Chief Commercial	2012	187,000	100,000		168,028		14,664	469,692
Services Officer of Central	2011	183,618	57,400		157,382		13,162	411,562

(1) See Note 10 of the accompanying Notes to the Consolidated Financial Statements for discussion of assumptions used in determining these present values at December 31, 2013 and December 31, 2012, except for the pre-retirement decrement assumptions and the retirement age assumption. No pre-retirement decrements are used and 100% retirement is assumed at the earliest unreduced retirement age in accordance with the requirements of US SEC REGULATION S-K Subpart 229.402(h)(2) and the US SEC Compliance and Disclosure Interpretation Q/A No. 124.02 and Q/A No. 124.04.

(2)  All Other Compensation for 2013, 2012, and 2011 includes matching contributions by Central under the Southern Star Investment Plan, Central's broad-based 401(k) plan. These amounts are to be paid out to the named executives only upon retirement, termination, disability or death. Mr. Carlton received $870 related to a service award in addition to the $15,300 matching contribution received from Central under the Southern Star Investment Plan.

(3) Mr. Rullman received a $40,000 bonus in 2013 in addition to the Annual Bonus.

(4) Each of these officers is compensated by Central.

34

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 2013:

SOUTHERN STAR RETIREMENT PLAN
Name	Number of Years of Credited Service(1)	Present Value of Accumulated Benefit(2)		Payments During Last Fiscal Year
Jerry L. Morris	11.167	$	716,008	$	—
Robert S. Bahnick	11.167	597,388		—
Robert W. Carlton	11.167	536,244		—
Susanne W. Harris	11.167	578,833		—
Philip A. Rullman	11.167	577,848		—

_________________________

(1) Southern Star Retirement Plan (Non-Union) only credits benefit service for service after November 15, 2002. The vesting service for these executives reflects their entire period of service with the employer. As of December 31, 2013, vesting service is as follows: Mr. Morris 37 years, Ms. Harris 35 years, Mr. Bahnick 33 years, Mr. Carlton 31 years, and Mr. Rullman 34 years.

(2) See Note 10 of the accompanying Notes to the Consolidated Financial Statements for discussion of assumptions used in determining these present values at December 31, 2013, except for the pre-retirement decrement assumptions and the retirement age assumption. No pre-retirement decrements are used and 100% retirement is assumed at the earliest unreduced retirement age in accordance with the requirements of US SEC REGULATION S-K Subpart 229.402(h)(2) and the US SEC Compliance and Disclosure Interpretation Q/A No. 124.02 and Q/A No. 124.04.

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 $255,000 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, Ms. Harris, and Mr. Rullman are the named executive officers 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

35

the 5th 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 the Pension Benefit Guaranty Corporation's 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 due to a reduction in force or job elimination at December 31, 2013 and qualified for payments under this plan (as described above), each named executive officer would be paid the following total severance payments under the plan: $315,000 for Mr. Morris, $200,000 for Mrs. Harris, $217,500 for Mr. Bahnick, $225,000 for Mr. Rullman, and $225,000 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:

Thomas M. Gray

John V. Veech

John B. Watt

36

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

The following table sets forth certain information, as of March 28, 2014, 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
MSIP-SSCC Holdings, LLC(1)	100 shares	100	%
1585 Broadway
New York, NY 10036
All named executive officers and directors as a group (nine total)	0 shares	0	%

_________________________

(1) MSIP-SSCC Holdings, LLC is indirectly owned 100% by MSIP.

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

Central had 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 provided 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. The Operating Services Agreement terminated on September 24, 2012 as a result of the Sale. Central paid approximately $0.7 million for service fees and expenses to EFS Services for the period January 1, 2012 through September 23, 2012 and $1.0 million for the year ended December 31, 2011, respectively.

Southern Star had an Administrative Services Agreement with EFS Services to provide certain administrative services to Southern Star and Holdings. Pursuant to the Administrative Services Agreement, EFS Services was not paid a fee for its services; however, it was entitled to be reimbursed for reasonable expenses incurred in providing such services. The Administrative Services Agreement terminated on September 24, 2012 as a result of the Sale. No significant expenses were incurred during 2012.

On January 23, 2012, Southern Star entered into an Administrative Services Agreement with MSIP Southern Star L.L.C., an affiliate of MSIP, to provide certain administrative services to Southern Star and Holdings. Pursuant to the terms of this agreement, 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. Invoices and supporting documentation for these reimbursements are approved by the Chief Financial Officer or Chief Executive Officer of Southern Star. No significant expenses were incurred during 2013 or 2012.

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, 2013 and 2012, and in connection with statutory and regulatory filings for such fiscal periods, were approximately $491,000 and $561,000, 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, 2013 and 2012 were approximately $58,000 and $60,000, respectively.

37

Tax Fees

The aggregate fees paid or accrued for services rendered by E&Y in connection with tax compliance, tax advice or tax planning services for the fiscal years ended December 31, 2013 and 2012 were approximately $0 and $25,000, respectively.

All Other Fees

No other services were provided by E&Y for the fiscal years ended December 31, 2013 and 2012.

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 2013 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 16, listed in the Index on page 42 of this report:
Report of Independent Registered Public Accounting Firm	43
Consolidated Balance Sheets at December 31, 2013 and 2012	44
Consolidated Statements of Net Income for the years ended December 31, 2013, 2012, and 2011	46
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012, and 2011	47
Consolidated Statements of Stockholder’s Equity for the years ended December 31, 2013, 2012, and 2011	48
Notes to the Consolidated Financial Statements	49

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.
4.14	Indenture, dated April 13, 2006, between Southern Star Central Corp. and The Bank of New York Trust Company, N.A. (the “Trustee”).
4.26	Form of Certificate of 6 3/4% Senior Notes due 2016.
4.33	Reimbursement and Credit Agreement, dated January 1, 2004, between Southern Star Central Gas Pipeline, Inc. and U.S. Bank, N.A.
4.43	Trust Indenture, dated January 1, 2004, between Industrial Development Authority and U.S. Bank.

38

Exhibit Number	Description of Document
4.53	Loan Agreement, dated January 1, 2004, between Industrial Development Authority and Southern Star Central Gas Pipeline, Inc.
4.64	Indenture, dated April 13, 2006, between Central and The Bank of New York Trust Company, N.A.
4.74	Supplemental Indenture, dated April 10, 2006, by and between Southern Star Central Corp. and Deutsche Bank Trust Company Americas, as Trustee.
4.88	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.
10.89	Revolving Credit Agreement, dated as of July 3, 2012, among Southern Star Central Corp., the lenders listed therein and Royal Bank of Canada, as Administrative Agent.
10.99	Pledge Agreement, dated as of July 3, 2012, among Southern Star Central Corp., Southern Star Central Gas Pipeline, Inc. and Royal Bank of Canada, as Administrative Agent.
10.10	Amendment to Revolving Credit Agreement, dated as of March 22, 2013, among Southern Star Central Corp., the lenders listed therein and Royal Bank of Canada, as Administrative Agent.
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

39

_________________________

(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.

(9) Incorporated by reference from Southern Star Central Corp.'s Report on Form 8-K filed with the SEC on July 6, 2012.

40

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 28, 2014	By:	/s/     JERRY L. MORRIS
		Jerry L. Morris President and Chief Executive Officer
March 28, 2014	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/    THOMAS M. GRAY	Director	March 28, 2014
	Thomas M. Gray
By:	/s/    JOHN V. VEECH	Director	March 28, 2014
	John V. Veech
By:	/s/    JOHN B. WATT	Director	March 28, 2014
	John B. Watt

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

41

Item 16. Consolidated Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	43
Consolidated Financial Statements:
Consolidated Balance Sheets	44
Consolidated Statements of Net Income	46
Consolidated Statements of Cash Flows	47
Consolidated Statements of Stockholder’s Equity	48
Notes to the Consolidated Financial Statements	49

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.

42

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Southern Star Central Corp. and Subsidiaries

We have audited the accompanying consolidated balance sheets of Southern Star Central Corp. and Subsidiaries as of December 31, 2013 and 2012 (Successor), and the related consolidated statements of net income, stockholder’s equity, and cash flows for the year ended December 31, 2013 (Successor), the period from September 24, 2012 through December 31, 2012 (Successor), the period January 1, 2012 through September 23, 2012 (Predecessor), and the year ended December 31, 2011 (Predecessor). 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, 2013 and 2012 (Successor), and the consolidated results of their operations and their cash flows for the year ended December 31, 2013 (Successor), the period from September 24, 2012 through December 31, 2012 (Successor), the period from January 1, 2012 through September 23, 2012 (Predecessor) and the year ended December 31, 2011 (Predecessor), in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

March 28, 2014

Louisville, Kentucky

43

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31, 2013			December 31, 2012
	(In thousands)			(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	18,388		$	37,467
Receivables:
Trade	27,049			19,651
Income taxes	7,394			1,068
Transportation, exchange and fuel gas	5,947			8,075
Other	2,659			5,165
Inventories	10,679			10,350
Deferred income taxes	1,847			1,536
Costs recoverable from customers	750			3,990
Prepaid expenses	5,274			4,874
Other	608			489
Total current assets	80,595			92,665
Property, Plant and Equipment, at cost:
Natural gas transmission plant	764,838			652,780
Other natural gas plant	35,239			36,403
	800,077			689,183
Less – Accumulated depreciation and amortization	(33,835		)	(7,208		)
Property, plant and equipment, net	766,242			681,975
Other Assets:
Goodwill	470,962			470,962
Costs recoverable from customers	54,048			85,267
Postretirement benefits other than pensions	2,921			—
Other deferred and noncurrent assets	2,815			3,993
Total other assets	530,746			560,222
Total Assets	$	1,377,583		$	1,334,862

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

44

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31, 2013		December 31, 2012
	(In thousands)		(In thousands)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Payables:
Trade	$	13,564	$	8,712
Transportation, exchange and fuel gas	5,862		11,315
Income taxes	4,385		380
Revolving credit agreement	100,000		40,000
Other	6,124		6,481
Accrued taxes, other than income taxes	7,561		7,090
Accrued interest	7,035		6,908
Accrued payroll and employee benefits	10,650		9,842
Costs refundable to customers	88		3
Capitalized lease obligation due in one year	280		265
Other accrued liabilities	11,082		3,907
Total current liabilities	166,631		94,903
Long-Term Debt:
Capitalized lease obligation	3,950		4,230
Other long-term debt	482,952		484,178
Total long-term debt	486,902		488,408
Other Liabilities and Deferred Credits:
Deferred income taxes	101,356		86,905
Postretirement benefits other than pensions	24,019		38,932
Asset retirement obligations	1,731		1,798
Costs refundable to customers	3,793		177
Environmental remediation	222		450
Accrued pension	24,444		39,760
Other	1,039		302
Total other liabilities and deferred credits	156,604		168,324
Stockholder’s Equity:
Common stock, $.01 par value, 100 shares authorized and issued,
100 shares outstanding at December 31, 2013 and December 31, 2012	—		—
Premium on capital stock and other paid-in capital	559,921		574,571
Retained earnings	7,525		8,656
Total stockholder’s equity	567,446		583,227
Total Liabilities and Stockholder’s Equity	$	1,377,583	$	1,334,862

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

45

SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF NET INCOME

	Successor						Predecessor
	For the Year Ended December 31, 2013			For the Period September 24 through December 31, 2012			For the Period January 1 through September 23, 2012			For the Year Ended December 31, 2011
	(In thousands)						(In thousands)
Operating Revenues:
Transportation	$	186,808		$	50,975		$	134,867		$	185,085
Storage	28,705			9,674			22,357			28,290
Other revenue	666			189			512			718
Total operating revenues	216,179			60,838			157,736			214,093
Operating Costs and Expenses:
Operations and maintenance	54,402			13,624			36,372			51,463
Administrative and general	42,358			10,589			28,624			37,486
Depreciation and amortization	36,007			9,404			25,114			33,150
Taxes, other than income taxes	18,377			4,597			12,708			16,884
Total operating costs and expenses	151,144			38,214			102,818			138,983
Operating Income	65,035			22,624			54,918			75,110
Other (Income) Deductions:
Interest expense	30,873			8,074			23,735			32,367
Interest income	(38		)	(12		)	(37		)	(96		)
Miscellaneous other income	(888		)	(200		)	(637		)	(6,873		)
Total other deductions	29,947			7,862			23,061			25,398
Income Before Income Taxes	35,088			14,762			31,857			49,712
Provision for Income Taxes	13,130			5,820			12,511			19,495
Net Income (a)	$	21,958		$	8,942		$	19,346		$	30,217

(a) Net income equals comprehensive income.

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

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SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Successor						Predecessor
	For the Year Ended December 31, 2013			For the Period September 24 through December 31, 2012			For the Period January 1 through September 23, 2012			For the Year Ended December 31, 2011
	(In thousands)						(In thousands)
OPERATING ACTIVITIES:
Net income	$	21,958		$	8,942		$	19,346		$	30,217
Adjustments to reconcile to net cash provided by operating activities:
Depreciation and amortization	36,007			9,404			25,114			33,150
Deferred income taxes	14,140			(3,154		)	10,359			10,973
Provision for rate and regulatory matters	4,446			—			—			—
Gain on sale of assets	—			—			—			(6,089		)
Amortization of debt (premium) discount and expense	(542		)	(174		)	1,304			1,678
Receivables	(11,219		)	(6,811		)	9,307			(1,556		)
Inventories	(329		)	(942		)	(2,214		)	(467		)
Other current assets	(488		)	(3,351		)	3,200			(447		)
Payables and accrued liabilities	10,703			5,888			(3,334		)	1,698
Other, including changes in noncurrent assets and liabilities	2,913			1,495			(606		)	(1,582		)
Net cash provided by operating activities	77,589			11,297			62,476			67,575
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of allowance for funds used during construction	(114,592		)	(30,167		)	(39,655		)	(38,815		)
Proceeds from sales and salvage values, net of costs of removal	(3,415		)	(369		)	108			4,653
Net cash used in investing activities	(118,007		)	(30,536		)	(39,547		)	(34,162		)
FINANCING ACTIVITIES:
Common dividends/return of capital	(37,739		)	(14,530		)	(13,712		)	(32,833		)
Issuance of debt - Revolving credit agreement	80,000			40,000			—			—
Payment of debt - Revolving credit agreement	(20,000		)	—			—			—
Debt issuance costs	(657		)	(15		)	(1,217		)	(44		)
Capital lease payments	(265		)	—			(250		)	(235		)
Net cash provided by (used in) financing activities	21,339			25,455			(15,179		)	(33,112		)
Net change in cash and cash equivalents	(19,079		)	6,216			7,750			301
Cash and cash equivalents at beginning of period	37,467			31,251			23,501			23,200
Cash and cash equivalents at end of period	$	18,388		$	37,467		$	31,251		$	23,501
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (net of amounts capitalized)	$	31,286		$	6,816		$	23,870		$	30,697
Income tax, net	1,311			7,007			3,675			7,711
Noncash Investing Transaction:
Additions to capital expenditures included in Payables: Other	5,720			3,729			—			2,481

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

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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)
Predecessor:
Balance, January 1, 2011	$	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
Add (deduct):
Net income	—			19,346			19,346
Common dividends	—			(18,807		)	(18,807		)
Balance, September 23, 2012	423,869			6,604			430,473
Successor:
Opening equity	583,720			—			583,720
Add (deduct):
Net income	—			8,942			8,942
Common dividends/return of capital	(9,149		)	(286		)	(9,435		)
Balance, December 31, 2012	574,571			8,656			583,227
Add (deduct):
Net income	—			21,958			21,958
Common dividends/return of capital	(14,650		)	(23,089		)	(37,739		)
Balance, December 31, 2013	$	559,921		$	7,525		$	567,446

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

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SOUTHERN STAR CENTRAL CORP. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business

Southern Star

Southern Star Central Corp., or Southern Star, was a wholly-owned subsidiary of EFS-SSCC Holdings, LLC, or EFS, as of and during the year ended December 31, 2011 and through September 23, 2012. 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, indirectly held all of the outstanding capital stock of EFS during these periods.

On August 23, 2012, GE entered into an agreement to sell to MSIP its 60% economic stake and 50% voting stake in Southern Star through the sale of its interests in EFS, or the Sale. The Sale was consummated on September 24, 2012, constituting a change in control and resulting in a new basis of accounting for Southern Star. In connection with the Sale, EFS changed its name to MSIP-SSCC Holdings, LLC, or Holdings. See Note 3 for further information regarding the Sale.

Southern Star was incorporated in Delaware in September 2002 and operates as a holding company for its regulated natural gas pipeline operations and development opportunities. Southern Star Central Gas Pipeline, Inc., or Central, is Southern Star’s only operating subsidiary and the sole source of its operating revenues and cash flows.

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 41 compressor stations with approximately 206,000 certificated horsepower.

Central’s principal service is the delivery of natural gas to local natural gas distribution companies in the major metropolitan areas it serves. At December 31, 2013, Central had transportation customer contracts with approximately 127 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 528 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. Basis of Presentation

The Sale resulted in a change in control and a new basis of accounting for Southern Star, as required by the Business Combinations Topic 805 of the Accounting Standards Codification, or the ASC. The total consideration, including the estimated fair value of MSIP's original 40% economic interest, has been “pushed down” and allocated to the assets and liabilities of the Company. The Company's financial statements related to periods prior to the Sale reflect the historical

49

accounting basis in the Company's assets and liabilities and are labeled Predecessor, while the periods subsequent to the Sale are labeled Successor and reflect the allocation of purchase price to all assets acquired and liabilities assumed in the Sale. Therefore, the Company's Consolidated Statements of Net Income and Cash Flows for the period January 1, 2012 through September 23, 2012 and the year ended December 31, 2011 each reflect the operations of the Predecessor. The Company's Consolidated Statements of Net Income and Cash Flows for the year ended December 31, 2013, the period September 24, 2012 through December 31, 2012, and the Consolidated Balance Sheets as of December 31, 2013 and 2012 each reflect the operations and financial position of the Successor.

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States, or GAAP, and SEC regulations.

3. Acquisition

On August 23, 2012, GE entered into an agreement to sell to MSIP its 60% economic stake and 50% voting stake in the Company through the sale of its interests in EFS. The Sale, which constituted a change in control, was consummated on September 24, 2012. The push-down basis of accounting was used to record the fair value adjustments for assets and liabilities of Southern Star at the acquisition date. The total consideration included the estimated fair value of MSIP's original 40% economic interest and the fair value of cash and equity consideration exchanged in the Sale.

As Central’s rates are regulated by the FERC, and the FERC does not allow recovery in rates of amounts in excess of original cost, many of Central’s historical assets and liabilities approximate their respective estimated fair values at the date of the change in control. The following summarizes the allocation of the total consideration to the assets acquired and the liabilities assumed of the Company at the date of the change in control (expressed in thousands):

Cash and cash equivalents	$	31,251
Receivables	25,782
Inventories	9,408
Other current assets	4,505
Regulatory assets - current	750
Property, plant and equipment	657,060
Regulatory assets - noncurrent	78,990
Other assets	4,432
Regulatory liabilities - current	(2,311		)
Capitalized lease obligation due in one year	(265		)
Current liabilities - other	(43,213		)
Long-term debt	(484,494		)
Capitalized lease obligation	(4,230		)
Regulatory liabilities - noncurrent	(145		)
Deferred tax liability	(91,016		)
Other long-term liabilities	(73,746		)
Goodwill	470,962
Fair values of assets and liabilities	$	583,720

Based on the allocation of the total consideration, the Company recorded approximately $471.0 million of Goodwill in the Successor Consolidated Balance Sheet. At September 24, 2012, the fair value of Southern Star’s 6.75% Notes was approximately $254.8 million. Central's debt was not adjusted as a result of the Sale since Central is a rate regulated entity as discussed above. The fair value of each of the Notes was calculated by utilizing an income approach whereby the future cash flows were discounted at estimated current cost of funding rates. The fair value measurement of these Notes is classified as Level 2.

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4. 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. At December 31, 2013, Central had estimated reserves for revenues subject to refund pending settlement of its RP13-941 rate proceeding of $4.4 million, excluding interest, which will be refunded to customers within 60 days of final approval by the FERC. The reserve is included in Other accrued liabilities on the Consolidated Balance Sheet. If the actual refunds differ from the estimated refund liability, revenues would be impacted by the difference between estimated and actual refunds.

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.

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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, 2013 and 2012 and classified as current or noncurrent depending on the expected timing of recovery (expressed in thousands):

	2013		2012
Current Assets:
Environmental costs	$	750	$	750
Fuel costs	—		3,240
Total Current Assets	750		3,990
Noncurrent Assets:
Environmental costs	222		450
Income taxes on AFUDC equity	5,764		5,166
Gas imbalance cash cost recoverable	64		69
Postretirement benefits other than pensions	23,984		38,282
Pensions	23,652		40,680
Asset retirement obligations	362		620
Total Noncurrent Assets	54,048		85,267
Total Assets	54,798		89,257

Current Liabilities:
Costs refundable to customers	88		3
Total Current Liabilities	88		3
Noncurrent Liabilities:
Gas imbalance cash cost refundable	92		177
Postretirement benefits other than pensions	3,701		—
Total Noncurrent Liabilities	3,793		177
Total Liabilities	3,881		180
Net Regulatory Assets	$	50,917	$	89,077

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, composite and group methods 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 Sale. 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 was $36.0 million, $9.4 million, $25.1 million and $33.2 million for the year ended December 31, 2013, the period September 24 through December 31, 2012, the period January 1 through September 23, 2012, and the year ended December 31, 2011, respectively.

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Goodwill

In connection with the Sale, Southern Star recorded goodwill representing the excess of the total purchase consideration over the estimated fair value of the assets acquired and liabilities assumed. Goodwill is tested annually for impairment on October 1, or more frequently if management determines that a triggering event may have occurred that would more likely than not reduce the estimated fair value of the Company below its carrying value. Goodwill impairment charges are not subject to rate recovery.

Goodwill is attributable to the Company's regulated utilities, Central, as it is the Company's only operating subsidiary and constitutes substantially all of the Company's assets. As a result of the Sale, the carrying value of the Company's goodwill as of September 23, 2012 was eliminated and new goodwill was recorded on September 24, 2012. The following table sets forth the carrying amount of goodwill as of and for the years ended December 31, 2013 and 2012 (expressed in thousands):

	Cost			Accumulated Impairment		Net
Balance at September 23, 2012, Predecessor	$	311,766		$	—	$	311,766
Dispositions (a)	(311,766		)	—		(311,766		)
Purchase accounting adjustments (b)(c)	470,962			—		470,962
Balance at December 31, 2012 and 2013, Successor	$	470,962		$	—	$	470,962

(a) Predecessor goodwill as of September 23, 2012 was eliminated in purchase accounting at September 24, 2012.

(b) Recognized as a result of the Sale. Represents the purchase accounting allocation process established as of September 24, 2012 in conjunction with the Sale. See Note 3 for further information regarding the Sale.

(c) No portion of the recorded adjustment amount is tax deductible. Accordingly, no deferred income taxes have been provided.

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 as of December 31, 2013 and 2012.

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 Income Taxes Topic 740 of the ASC, or ASC 740.

In accordance with ASC 740, the Company records interest related to uncertain tax positions as a part of Interest expense on the accompanying Statements of Net Income. Any penalties are recognized as part of Miscellaneous expense on the accompanying Statements of Net Income. As of December 31, 2013 and 2012, the Company did not have a liability for tax 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. Holdings and Central generally make payments to Southern Star for their federal and state income tax liabilities as though they were filing separate returns. Southern Star has an obligation to indemnify Holdings and Central for any liability that they incur for taxes of the affiliated group of which Southern Star, Holdings 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 the prior quarter's Retained Earnings balances are deemed to be returns of capital.

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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, 2013 were $0.4 million and $1.3 million, respectively; for the period September 24 through December 31, 2012 were $0.1 million and $0.2 million, respectively; for the period January 1 through September 23, 2012 were $0.2 million and $0.5 million, respectively; and for the year ended December 31, 2011 were $0.3 million and $0.8 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 historical cost. Upon removal from inventory for use, the average cost method is used.

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 accordance with the Asset Retirement and Environmental Obligations Topic 410 of the ASC, 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, 2013 was $0.4 million and $1.7 million, respectively. The amount of the regulatory asset and the related ARO liability on the accompanying Consolidated Balance Sheets at December 31, 2012 was $0.6 million and $1.8 million, respectively.

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

54

year ended December 31, 2013, the period September 24 through December 31, 2012, the period January 1 through September 23, 2012, and the year ended 2011, the Company did not identify an impairment of its long-lived assets.

Fair Value Measurements

The Fair Value Measurements and Disclosures Topic 820 of the ASC, or ASC 820, 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. ASC 820 requires the fair value of an asset or liability to be based on market-based measures which reflect the credit risk of the Company.

The carrying values of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values because of the relative short maturity of those instruments. At December 31, 2013, the fair value of the Company’s 6.75% Notes and Central’s 6.0% Notes was approximately $251.5 million and $255.1 million, respectively. The estimated fair value of each of the notes was calculated by discounting the notes' cash flows by their respective yield rates as determined by recent market activity. The fair value measurement of these notes is classified as Level 2.

5. Financing

At December 31, 2013 and 2012, long-term debt consisted of the following (expressed in thousands):

	December 31, 2013			December 31, 2012
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
Long-term portion of capitalized lease obligation	3,950			4,230
Unamortized debt premium	3,137			4,439
Unamortized debt discount	(185		)	(261		)
Total long-term debt	$	486,902		$	488,408

6.75% Registered Notes

At December 31, 2013 and 2012, 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. Prior to the Sale, the related issuance costs were being amortized over the life of the 6.75% Registered Notes utilizing the straight line method which approximated the effective interest method. As of September 24, 2012, there were no issuance costs related to the 6.75% Registered Notes included in the Consolidated Balance Sheets as such costs were not recognized as part of the purchase price allocation. However, the premium established as a result of recognizing the debt acquired at fair value in conjunction with the Sale will be amortized over the remaining period of the 6.75% Registered Notes utilizing the effective interest method. The 6.75% Registered Notes mature on March 1, 2016. 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. Southern Star has the right to redeem all or part of the 6.75% Registered Notes at premiums defined in the indenture.

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6.75% Unregistered Notes

At December 31, 2013 and 2012, 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. Prior to the Sale, the related issuance costs were being amortized over the life of the 6.75% Unregistered Notes utilizing the straight line method which approximated the effective interest method. As of September 24, 2012, there were no issuance costs related to the 6.75% Unregistered Notes included in the Consolidated Balance Sheets as such costs were not recognized as part of the purchase price allocation. However, the premium established as a result of recognizing the debt acquired at fair value in conjunction with the Sale will be amortized over the remaining period of the 6.75% Unregistered Notes utilizing the effective interest method. The 6.75% Unregistered Notes will mature on March 1, 2016. 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.

Credit Agreement

On July 3, 2012, the Company entered into a $65.0 million four-year revolving credit agreement, or Credit Agreement, among several banks and other financial institutions or entities from time to time party to the Credit Agreement, or the Lenders, and Royal Bank of Canada, as Administrative Agent, pursuant to which the Lenders agreed to make revolving credit loans to the Company. Effective March 22, 2013, the Credit Agreement was amended and the total aggregate commitment was extended to $125.0 million. Under the Credit Agreement, letters of credit may be issued by the Administrative Agent or by one or more of the other Lenders in an aggregate amount not to exceed $10.0 million.

Borrowings under the Credit Agreement bear interest at a rate per annum equal to, at the Company’s option, either (a) an alternate base rate or (b) a rate based on the rates applicable for deposits in the interbank market for U.S. Dollars or the applicable currency in which the loans are made plus an applicable margin. The applicable margin for each revolving loan will be adjusted in relation to the Company’s then current unsecured debt ratings. Additionally, the Company will pay a commitment fee for the average daily unused amount of the facility, payable quarterly in arrears, and certain fees with respect to letters of credit issued under the Credit Agreement. At December 31, 2013 and 2012, the Company had $100.0 million and $40.0 million outstanding under the revolving credit facility with stated interest rates of 2.17% and 2.2%, respectively. There were no outstanding letters of credit issued under the Credit Agreement as of December 31, 2013 and 2012.

In connection with the Credit Agreement, and pursuant to a pledge agreement dated as of July 3, 2012, among the Company, Central and the Administrative Agent, the Company pledged as collateral its equity interests in Central and certain future acquired subsidiaries.

The Credit Agreement contains negative covenants that, subject to significant exceptions, limit the ability of the Company and its Restricted Subsidiaries to, among other things, (i) incur debt, (ii) engage in new lines of business, (iii) incur liens, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) dispose of substantially all of the assets of the Company and its subsidiaries, (vi) make investments, loans, advances, guarantees and acquisitions, (vii) make certain restricted payments and (viii) enter into transactions with affiliates. The covenants require the Company to comply on a quarterly basis with capitalization ratios with respect to the Company and Central and a minimum fixed charge coverage ratio. The Credit Agreement contains events of defaults that are customary for a facility of this nature. If an event of default occurs, the commitments of the Lenders to lend under the facility may be terminated and the maturity of the amounts outstanding may be accelerated.

Central’s 6.0% Notes

At December 31, 2013 and 2012, 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. 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

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extent of the value of the assets securing such indebtedness, if any. The 6.0% Notes are structurally senior to the 6.75% Notes.

The 6.0% Notes are subject to certain covenants that restrict, among other things, Central’s ability to create liens, enter into sale and leaseback transactions or merge or consolidate with other entities. Central has the option to call the 6.0% Notes at any time at a make-whole premium as defined in the indenture.

Capital Lease

In 2004, Central entered into a 20-year capital lease with the Owensboro-Daviess County Industrial Development Authority, or the Authority, for use of a headquarters building in Owensboro, Kentucky. Central is the borrower under a $9.0 million loan agreement dated as of January 1, 2004 between Central and the Authority pursuant to which the Authority financed the cost of Central’s office facility in Daviess County, Kentucky. In connection with this financing, the Authority issued Series 2004A and 2004B bonds under an indenture dated as of January 1, 2004 between the Authority and U.S. Bank, N. A. as trustee. Ownership of the facility will transfer to Central for a nominal fee upon expiration of the lease in 2024. Approximately $7.1 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 $0.3 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 had the option to prepay all 2004A bonds on or after January 1, 2014 and all 2004B bonds on or after February 1, 2014.

The following table summarizes the Company's future capital lease obligations due by period (expressed in thousands):

Year ending December 31:
2014	$	528
2015	538
2016	541
2017	548
2018	552
Thereafter	3,109
Total minimum lease payments	5,816
Less amount representing interest	1,586
Present value of minimum lease payments	4,230
Current portion of capital lease obligations	280
Capital lease obligations	$	3,950

Other

As of December 31, 2013, the Company was in compliance with the covenants of all outstanding debt instruments. The Company's 6.75% Registered Notes, 6.75% Unregistered Notes and 6.0% Notes mature within the next five fiscal years, with their aggregate principal amounts of $480.0 million due in 2016.

6. 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.

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General Rate Issues

On May 31, 2013, Central filed a general rate case under FERC Docket No. RP13-941, to be effective December 1, 2013. The FERC issued a suspension order dated July 5, 2013 accepting and suspending the proposed tariff records to be effective December 1, 2013, subject to refund and conditions, and the outcome of a hearing. On November 26, 2013, Central submitted a filing that reflected suspended rates, which Central requested be moved into effect on December 1, 2013, subject to refund of revenues collected in excess of settlement rates, consistent with the FERC's orders in this proceeding. The motion rates reflect adjustments required by the FERC's orders and regulations. Pursuant to the principles of settlement reached with active parties in the case, Central filed, and the FERC approved, an interim rate reduction to be effective February 1, 2014. Such interim rates were the settlement rates. Central filed a Stipulation and Agreement on March 7, 2014. The settlement, if approved, will increase Central’s revenues approximately $28.0 million above revenues for the 12 months ended February 28, 2013, the base period covered in its filing, and will require Central to make refunds to its customers for revenues collected in excess of settlement rates for the months of December 2013 and January 2014. At December 31, 2013, the Company had estimated reserves for revenues collected in excess of expected settlement rates of approximately $4.4 million, excluding interest, which will be refunded to customers within 60 days of final approval by the FERC. The reserve is included in Other accrued liabilities on the Consolidated Balance Sheets.

Environmental and Safety Matters

Environmental

Central has identified polychlorinated biphenyl, or PCB, contamination in air compressor systems, soils, and related properties at certain compressor station sites and has been involved in negotiations with the U.S. Environmental Protection Agency, or EPA, and state agencies to develop screening, sampling, and cleanup programs. In addition, negotiations with certain environmental agencies concerning investigative and remedial actions relative to potential mercury contamination at certain natural gas metering sites have commenced. Central had accrued an undiscounted liability of approximately $1.0 million at December 31, 2013 and $1.2 million at December 31, 2012, representing the current estimate of future environmental testing and cleanup costs, most of which is expected to be incurred over the next three to four years. However, timing is highly dependent upon State and Federal negotiations.

Central is subject to federal, state and local statutes, rules and regulations relating to environmental protection, including the National Environmental Policy Act, the Clean Water Act, the Clean Air Act and the Resource Conservation and Recovery Act. These laws and regulations can result in capital, operating and other costs. These laws and regulations generally subject Central to inspections and require it to obtain and comply with a wide variety of environmental licenses, permits and other approvals. Under the Clean Air Act, the EPA has promulgated regulations addressing emissions from equipment present at typical natural gas compressor stations. These regulations include NESHAPs for reciprocating internal combustion engines, stationary turbines, and glycol dehydration equipment in addition to regulations that address regional transport of ozone. 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 operations. 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. There are also other potential state or federal regulations or legislation related to greenhouse gas emissions that could impact Central’s existing operations if promulgated. Central continues to monitor the progress of any proposed rules or legislation and will determine any impact once the regulations have been promulgated.

All of Central’s facilities are located in areas currently designated as being in “attainment” of all National Ambient Air Quality Standards, or NAAQS. 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.

Summary of Commitments and Contingencies

The Company is subject to claims and legal actions in the normal course of business in addition to those disclosed above. While no assurances can be given, management believes, based on advice of counsel and after consideration of

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amounts accrued, insurance coverage, potential recovery from customers and other indemnification arrangements, that the ultimate resolution of these matters will not have a material adverse effect upon the Company’s future financial position, results of operations, or cash flows. Costs incurred to date of defending pending cases have not been material.

7. Income Taxes

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

	Successor						Predecessor
	For the Year Ended December 31, 2013			For the Period September 24 through December 31, 2012			For the Period January 1 through September 23, 2012		For the Year Ended December 31, 2011
Current provision:
Federal	$	(398	)	$	7,585		$	1,657	$	7,024
State	(612		)	1,389			495		1,498
	(1,010		)	8,974			2,152		8,522
Deferred provision:
Federal	12,391			(2,710		)	8,779		9,266
State	1,749			(444		)	1,580		1,707
	14,140			(3,154		)	10,359		10,973
Income tax provision	$	13,130		$	5,820		$	12,511	$	19,495

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

	Successor				Predecessor
	For the Year Ended December 31, 2013		For the Period September 24 through December 31, 2012		For the Period January 1 through September 23, 2012		For the Year Ended December 31, 2011
U.S. statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
State income taxes, net of federal tax benefits	3.6	%	4.2	%	4.2	%	4.2	%
Permanent items:
Kansas property deduction	(1.3	)%	—	%	—	%	—	%
Other, net	0.1	%	0.2	%	0.1	%	—	%
Income tax provision	37.4	%	39.4	%	39.3	%	39.2	%

The 2013 reduction in state income taxes, net of federal tax benefits relates primarily to a Kansas property expense deduction enacted in 2012, which was reflected as a 2013 tax adjustment in the fourth quarter of 2013.

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Significant components of deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows (expressed in thousands):

	2013			2012
Deferred tax assets:
Accrued employee benefits	$	24,396		$	33,936
Tax benefit carryforwards	19,150			—
Intangibles	1,194			1,504
Accrued environmental costs	389			468
Debt Costs	2,487			3,550
Other	860			932
Total deferred tax assets	48,476			40,390
Deferred tax liabilities:
Property, plant and equipment	124,901			91,604
Regulatory assets	21,035			32,300
Other	2,049			1,855
Total deferred tax liabilities	147,985			125,759
Net deferred tax liabilities	$	(99,509	)	$	(85,369	)
Classification:
Net current assets	$	1,847		$	1,536
Net long-term liabilities	(101,356		)	(86,905		)
Net deferred tax liabilities	$	(99,509	)	$	(85,369	)

The Company generated a net operating loss in 2013 primarily due to the election of bonus depreciation. As of December 31, 2013, tax benefit carryforwards approximating $19.2 million consist of the tax benefit of net operating losses for federal purposes of $16.4 million with the remainder applicable for state income tax purposes. Federal net operating losses have a carryforward period of 20 years and vary from 5 to 20 years in the principal filing states. As such, these carryforward benefits will begin expiring in 2018 to the extent not used by that date.

The Accounting for Uncertainty in Income Taxes Topic of the ASC establishes the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with Income Taxes. Accounting for Uncertainty in Income Taxes prescribes a recognition threshold and measurement attribute for financial statement disclosure of tax positions taken or expected to be taken on a tax return. The Company also records interest related to uncertain tax positions as a part of Interest expense on the accompanying Statement of Net Income. Any penalties are recognized as part of miscellaneous expense on the accompanying Statement of Net Income. As of December 31, 2013 and 2012, the Company did not have a liability for tax penalties or interest related to uncertain tax positions.

As of December 31, 2013, the Company remained subject to examination by Federal and State jurisdictions for the tax years beginning in 2004 and forward, in some cases due to net operating losses carried forward.

No portion of the Goodwill recorded as a result of the Sale is tax deductible.

8. Dividends and Related Restrictions

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

`

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9. Financial Instruments

ASC 820 establishes a three-level hierarchy for fair value measurements. The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date.

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

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

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

The carrying amounts of the Company's long-term debt on the Balance Sheets and their estimated fair values are set forth below. These estimated fair market values of the Company’s 6.75% Registered Notes, the 6.75% Unregistered Notes, and the 6.0% Notes were calculated by discounting the Notes’ cash flows by their respective yield rates as determined by recent market activity. These instruments are classified as Level 2.

	December 31, 2013				December 31, 2012
	(In Thousands)				(In Thousands)
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
6.0% Senior Notes due 2016	$	229,815	$	255,113	$	229,739	$	264,145
6.75% Registered Senior Notes due 2016	202,510		201,169		203,551		203,856
6.75% Unregistered Senior Notes due 2016	50,628		50,292		50,888		50,964

Concentrations of Credit Risk

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

10. Employee Benefit Plans

Central maintains two pension plans, the Union Pension Plan and the Non-Union Pension Plan, and a postretirement benefit other than pension plan, or PBOP.

The Union Pension Plan is a noncontributory defined benefit plan open to all employees of the Company who: (1) are covered by the collective bargaining agreement between the Company and the International Union of Operating Engineers Local No. 351, previously the International Union of Operating Engineers Local No. 647, AFL-CIO and any successors thereto, (2) have attained age 21, and (3) have completed one year of employment containing 1,000 hours or more of service in a 12-month period. The Union Pension Plan covered 31% of the 498 total employees at December 31, 2013.

The Non-Union Pension Plan is a noncontributory defined benefit plan. The plan is open to all employees of the Company who are not represented by any collective bargaining agreement, have attained age 21, and completed one year of employment containing 1,000 hours or more of service in a 12-month period.

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

The terms of the RP08-350 rate settlement allowed Central to recover, in its rates, $9.5 million annually for pension benefits and postretirement benefits other than pensions. Central must fund the amounts recovered into irrevocable trusts established solely for the provision of the aforementioned benefits in a manner that permits Central to maximize the tax deductibility of the deposits and adhere to minimum and maximum funding requirements. Central’s $9.5 million annual

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funding requirement may only be reduced by amounts funded in excess of recoveries in prior years. As of December 31, 2013, Central’s funding was equivalent to its RP08-350 recoveries.

The terms of the RP13-941 rate settlement, which is subject to final approval by the FERC, will allow Central to recover, in its rates, approximately $7.8 million annually for pension benefits and postretirement benefits other than pensions. Central must fund the amounts recovered into irrevocable trusts established solely for the provision of the aforementioned benefits in a manner that permits Central to maximize the tax deductibility of the deposits and adhere to minimum and maximum funding requirements. Central’s $7.8 million annual funding requirement may only be reduced by amounts funded in excess of recoveries in prior years.

The Compensation - Retirement Benefits Topic 715 of the ASC, or ASC 715, requires companies to recognize the funded status of their defined benefit pension and other postretirement benefit plans as a net liability or asset in their balance sheets and to recognize changes in that funded status in the year in which changes occur through comprehensive income. As it is appropriate for the Company to apply the accounting prescribed by the Regulated Operations Topic 980 of the ASC, the Company does not recognize changes in the funded status in comprehensive income but recognizes them as changes to the related regulatory asset or liability, pending future recovery or refund through its rates.

Pursuant to ASC 715, no portion of the related liabilities are classified as current because plan assets exceed the value of benefit obligations expected to be paid within the 12 months ending December 31, 2014. In addition, no plan assets are expected to be returned to the Company during the 12 months ending December 31, 2014.

The following table depicts the annual changes in benefit obligation and plan assets for the pension and PBOP plans for the periods indicated. The table also presents a reconciliation of the funded status of these benefits to the amounts recognized on the accompanying Consolidated Balance Sheets at December 31, 2013 and 2012 (expressed in thousands):

	Pension Plans									PBOP Plan
	Successor						Predecessor			Successor						Predecessor
	2013			2012			2012			2013			2012			2012
Change in benefit obligation:
Benefit obligation at beginning of year	$	76,598		$	75,960		$	70,230		$	67,106		$	66,205		$	60,021
Service cost	6,743			1,818			4,342			594			176			424
Interest cost	2,514			667			1,814			2,298			639			1,817
Actuarial (gain)/loss	(12,245		)	179			7,941			(12,901		)	1,463			4,859
Medicare Part D subsidy recognition	—			—			—			165			—			146
Benefits and expenses paid	(5,726		)	(787		)	(1,423		)	(2,212		)	(1,377		)	(1,062		)
Settlements	(7,968		)	(1,239		)	(6,944		)	—			—			—
Benefit obligation at end of year	59,916			76,598			75,960			55,050			67,106			66,205
Change in plan assets:
Fair value of plan assets at beginning of year	36,838			36,985			34,214			28,174			29,205			27,039
Actual return on plan assets	6,390			478			3,977			6,139			346			3,228
Employer contributions	5,938			1,401			7,161			1,850			—			—
Benefits and expenses paid	(5,726		)	(787		)	(1,423		)	(2,212		)	(1,377		)	(1,062		)
Settlements	(7,968		)	(1,239		)	(6,944		)	—			—			—
Fair value of plan assets at end of year	35,472			36,838			36,985			33,951			28,174			29,205
Funded status/Accrued benefit cost	$	(24,444	)	$	(39,760	)	$	(38,975	)	$	(21,099	)	$	(38,932	)	$	(37,000	)

The FERC allows Central to recognize allowances for these prudently incurred costs through recovery in its rates. As such, the related assets and liabilities recognized were offset with a corresponding regulatory asset or regulatory liability. The accrued benefit costs reported above for the pension plans are reflected in Accrued pension on the accompanying Consolidated Balance Sheets. The net accrued benefit costs reported above for the PBOP plan are reflected in Postretirement benefits other than pensions on the accompanying Consolidated Balance Sheets. The accumulated benefit obligation for the pension plans was $48.5 million and $62.4 million at December 31, 2013 and 2012, respectively.

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Lump sum distributions of $8.0 million, $1.2 million and $7.0 million were paid to Union Pension Plan participants for the year ended December 31, 2013, the period September 24 through December 31, 2012 and the period January 1 through September 23, 2012, respectively. The Union Pension Plan’s distributions in 2013 and 2012 exceeded each year’s respective service and interest cost, triggering settlement accounting under Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits Topic of the ASC. The effects of the 2013 settlements were calculated as of April 30, 2013 and as of December 31, 2013. The effects of the 2012 settlements were calculated as of March 31, 2012, September 23, 2012 and as of December 31, 2012.

Central’s net periodic benefit expense attributable to the pension and PBOP plans consists of the following (expressed in thousands):

	Pension Plans												PBOP Plan
	Successor						Predecessor						Successor						Predecessor
	For the Year Ended December 31, 2013			For the Period September 24 through December 31, 2012			For the Period January 1 through September 23, 2012			For the Year Ended December 31, 2011			For the Year Ended December 31, 2013			For the Period September 24 through December 31, 2012			For the Period January 1 through September 23, 2012			For the Year Ended December 31, 2011
Components of net periodic benefit expense:
Service cost	$	6,743		$	1,818		$	4,342		$	5,131		$	594		$	176		$	424		$	555
Interest cost	2,514			667			1,814			2,692			2,298			639			1,817			2,613
Expected return on plan assets	(2,651		)	(882		)	(2,271		)	(3,062		)	(2,287		)	(631		)	(1,596		)	(2,330		)
Recognized actuarial loss	—			—			1,177			714			—			—			2,468			1,758
Settlement recognition	(560		)	(1		)	2,467			778			—			—			—			—
Regulatory recovery/(accrual) of costs	1,604			958			(589		)	3,247			1,245			(184		)	(3,113		)	(2,596		)
Net periodic benefit expense	$	7,650		$	2,560		$	6,940		$	9,500		$	1,850		$	—		$	—		$	—

Approximately $0.7 million of net gains are expected to be recognized for the pension plans in 2014. Approximately $1.7 million of net gains are expected to be recognized for the PBOP plan in 2014.

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

	Pension Plans
	Successor				Predecessor
	For the Year Ended December 31, 2013		For the Period September 24 through December 31, 2012		For the Period January 1 through September 23, 2012		For the Year Ended December 31, 2011
Discount rate:
Union	4.43	%	3.33	%	3.22	%	3.73	%
Non-Union	4.39	%	3.50	%	3.42	%	3.99	%
Rate of compensation increase:
Union	3.60	%	3.60	%	3.60	%	3.60	%
Non-Union	3.60	%	3.80	%	3.60	%	3.60	%

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	PBOP Plan
	Successor				Predecessor
	For the Year Ended December 31, 2013		For the Period September 24 through December 31, 2012		For the Period January 1 through September 23, 2012		For the Year Ended December 31, 2011
Discount rate	4.66	%	3.78	%	3.69	%	4.23	%
Healthcare cost trend rate assumed for next year	8.00	%	8.50	%	7.95	%	8.50	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.90	%	4.95	%	4.75	%	4.75	%
Year that the rate reaches the ultimate trend	2021		2020		2020		2018

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

	Union Pension Plan
	Successor						Predecessor
	For the Period May 1 through December 31, 2013 *		For the Period January 1 through April 30, 2013 *		For the Period September 24 through December 31, 2012 *		For the Period April 1 through September 23, 2012 *		For the Period January 1 through March 31, 2012 *		For the Period May 1 through December 31, 2011 *		For the Period January 1 through April 30, 2011 *
Discount rate	3.46	%	3.33	%	3.22	%	3.88	%	3.73	%	4.61	%	5.16	%
Expected return on plan assets	8.50	%	8.50	%	8.50	%	8.50	%	8.50	%	8.50	%	8.50	%
Rate of compensation increase	3.60	%	3.60	%	3.60	%	3.60	%	3.60	%	3.75	%	3.60	%

* Changes in 2013, 2012 and 2011 weighted-average assumptions related to settlement accounting under the Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits Topic of the ASC.

	Non-Union Pension Plan
	Successor				Predecessor
	For the Year Ended December 31, 2013		For the Period September 24 through December 31, 2012		For the Period January 1 through September 23, 2012		For the Year Ended December 31, 2011
Discount rate	3.50	%	3.42	%	3.99	%	5.26	%
Expected return on plan assets	8.50	%	8.50	%	8.50	%	8.50	%
Rate of compensation increase	3.80	%	3.60	%	3.60	%	3.60	%

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The following are the various assumptions used to determine net periodic benefit cost for the PBOP plan for the periods indicated:

	PBOP Plan
	Successor		Predecessor
	For the Year Ended December 31, 2013	For the Period September 24 through December 31, 2012	For the Period January 1 through September 23, 2012	For the Year Ended December 31, 2011
Discount rate	3.78%	3.69%	4.23%	5.34%
Expected return on plan assets (non-union)	6.67%	6.67%	6.67%	6.67%
Expected return on plan assets (union)	8.50%	8.50%	8.50%	8.50%

Assumed health care cost trend rates for the PBOP plan for the periods indicated:

	PBOP Plan
	Successor				Predecessor
	For the Year Ended December 31, 2013		For the Period September 24 through December 31, 2012		For the Period January 1 through September 23, 2012		For the Year Ended December 31, 2011
Healthcare cost trend rate assumed for next year	8.00	%	7.95	%	7.95	%	8.50	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.95	%	4.75	%	4.75	%	4.75	%
Year that the rate reaches the ultimate trend	2020		2020		2018		2017

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

	PBOP Plan
	One Percentage Point
	Increase		Decrease
Effect on total of service and interest cost components	$	403	$	(330	)
Effect on accumulated postretirement benefit obligation	$	7,599	$	(6,264	)

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

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The following are the fair values of the pension and PBOP plans' assets for the period indicated (in thousands):

	Pension Plans
	As of December 31, 2013						As of December 31, 2012
Asset Category	Total Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)(2)		Significant Observable Inputs (Level 2)(1)(2)		Total Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)(2)		Significant Observable Inputs (Level 2)(1)(2)
Cash & Cash Equivalents	$	2,652	$	—	$	2,652	$	2,190	$	—	$	2,190
Equity and Exchange Traded Funds:
Emerging Markets	1,093		1,093		—		707		707		—
International Large Cap Core	—		—		—		830		830		—
International Large Cap Growth	935		935		—		574		574		—
International Large Cap Value	2,318		2,318		—		—		—		—
Large Cap Core	2,558		2,558		—		3,234		3,234		—
Large Cap Growth	4,047		4,047		—		4,365		4,365		—
Large Cap Value	5,928		5,928		—		7,595		7,595		—
Mid Cap Growth	2,531		2,531		—		2,590		2,590		—
Mid Cap Value	2,269		2,269		—		2,366		2,366		—
Small Cap Core	—		—		—		551		551		—
Small Cap Growth	1,445		1,445		—		1,322		1,322		—
Small Cap Value	519		519		—		—		—		—
Fixed Income:
Government Agency Obligations	4,192		—		4,192		444		—		444
Government Treasury Obligations	2,634		2,634		—		919		919		—
Municipal Obligations	492		—		492		228		—		228
Corporate Obligations	1,825		—		1,825		2,104		—		2,104
Bond Funds:
Global Income	—		—		—		1,244		1,244		—
Intermediate Investment Grade Debt	—		—		—		1,380		1,380		—
Short - Intermediate Investment Grade Debt	—		—		—		704		704		—
Short Investment Grade Debt	—		—		—		1,734		1,734		—
Total Return	—		—		—		1,735		1,735		—
Other	34		6		28		22		4		18
Total	$	35,472	$	26,283	$	9,189	$	36,838	$	31,854	$	4,984

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	PBOP Plan
	As of December 31, 2013								As of December 31, 2012
Asset Category	Total Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)(2)		Significant Observable Inputs (Level 2)(1)(2)			Total Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)(2)		Significant Observable Inputs (Level 2)(1)(2)
Cash & Cash Equivalents	$	1,884		$	—	$	1,884		$	1,663		$	—	$	1,663
Equity and Exchange Traded Funds:
Emerging Markets	1,037			1,037		—			539			539		—
International Large Cap Core	—			—		—			617			617		—
International Large Cap Growth	890			890		—			432			432		—
International Large Cap Value	2,202			2,202		—			—			—		—
Large Cap Core	2,467			2,467		—			2,509			2,509		—
Large Cap Growth	3,907			3,907		—			3,375			3,375		—
Large Cap Value	5,692			5,692		—			5,821			5,821		—
Mid Cap Growth	2,445			2,445		—			2,006			2,006		—
Mid Cap Value	2,193			2,193		—			1,834			1,834		—
Small Cap Core	—			—		—			426			426		—
Small Cap Growth	1,396			1,396		—			1,035			1,035		—
Small Cap Value	502			502		—			—			—		—
Fixed Income:
Government Agency Obligations	3,518			250		3,268			1,536			—		1,536
Government Treasury Obligations	2,284			2,284		—			2,703			2,703		—
Municipal Obligations	167			—		167			47			—		47
Corporate Obligations	2,906			—		2,906			3,598			—		3,598
Bond Funds:
Global Income	97			97		—			37			37		—
Intermediate Investment Grade Debt	172			172		—			41			41		—
Short - Intermediate Investment Grade Debt	118			118		—			21			21		—
Short Investment Grade Debt	205			205		—			53			53		—
Total Return	75			75		—			53			53		—
Other	(206		)	21		(227		)	(172		)	16		(188		)
Total	$	33,951		$	25,953	$	7,998		$	28,174		$	21,518	$	6,656

(1) Cash and Cash Equivalents represent Money Market funds that are valued at amortized cost, which approximates market value. Fixed income securities are valued at prices of actual trades or bid/ask quotes made by broker-dealers gathered by a pricing service.

(2) There were no significant transfers between Level 1 and Level 2 during the year.

The investment objectives of the pension and PBOP plans are as follows:

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

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

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

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

A formal semi-annual review of these investment objectives is performed by the Investment Committee. These objectives will remain in effect unless they are deemed inappropriate by the Investment Committee. The Investment Committee will also re-examine the applicability of these objectives in the event of significant changes in Company structure,

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actuarial assumptions, contribution levels, economic conditions or any event which may significantly alter the pension and PBOP plans' characteristics.

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

Percent of Total Assets at Market Value

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

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

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

In 2014, the Company expects to contribute to the pension and PBOP plans an amount that is equivalent to the $7.8 million pending approval in the Company's RP13-941 rate proceeding.

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

	Pension Plans		PBOP Plan
2014	$	4,614	$	2,828
2015	4,907		3,038
2016	4,946		3,217
2017	5,869		3,397
2018	6,430		3,532
Years 2019 through 2023	30,102		18,829

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

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

	PBOP Plan
2014	$	240
2015	269
2016	303
2017	338
2018	375
Years 2019 through 2023	2,431

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Other

Central maintains a defined contribution plan covering all employees. Central’s costs related to this plan were $2.2 million, $0.5 million, $1.5 million and $1.9 million for the year ended December 31, 2013, the period September 24, 2012 through December 31, 2012, the period January 1, 2012 through September 23, 2012, and the year ended December 31, 2011, respectively.

11. Major Customers

Central’s two largest customers are Laclede Gas Company, Missouri Gas Energy Division, or MGE, and Kansas Gas Service Company, or KGS, a division of ONE Gas, Inc. Revenues received from MGE were $67.0 million, $18.9 million, $48.7 million, and $66.3 million for the year ended December 31, 2013, the period September 24, 2012 through December 31, 2012, the period January 1, 2012 through September 23, 2012 and the year ended December 31, 2011, respectively. Revenues received from KGS were $57.5 million, $16.0 million, $41.1 million, and $56.3 million for the year ended December 31, 2013, the period September 24, 2012 through December 31, 2012, the period January 1, 2012 through September 23, 2012 and the year ended December 31, 2011, respectively.

MGE had receivable balances of $7.7 million and $5.4 million as of December 31, 2013 and 2012, respectively. KGS had receivable balances of $7.1 million and $5.1 million as of December 31, 2013 and 2012, respectively.

Central also receives revenues from other subsidiaries of Laclede Gas Company and ONE Gas, Inc., but these amounts were immaterial to Central’s aggregate 2013 revenues.

12. Operating Leases

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

2014	$	264
2015	271
2016	50
2017	45
2018	46
After 2018	357
Total	$	1,033

Total rental expense relating to operating leases was approximately $1.3 million, $0.3 million, $0.9 million and $1.4 million for the year ended December 31, 2013, the period September 24, 2012 through December 31, 2012, the period January 1, 2012 through September 23, 2012, and the year ended December 31, 2011, respectively.

13. Related Party Transactions

Central had 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 provided 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. The Operating Services Agreement terminated on September 24, 2012 as a result of the Sale. Central paid approximately $0.7 million for service fees and expenses to EFS Services for the period January 1, 2012 through September 23, 2012 and $1.0 million for the year ended December 31, 2011, respectively.

Southern Star had an Administrative Services Agreement with EFS Services to provide certain administrative services to Southern Star and Holdings. Pursuant to the Administrative Services Agreement, EFS Services was not paid a fee for its services; however, it was entitled to be reimbursed for reasonable expenses incurred in providing such services. The Administrative Services Agreement terminated on September 24, 2012 as a result of the Sale. No significant expenses were incurred during 2012.

On January 23, 2012, Southern Star entered into an Administrative Services Agreement with MSIP Southern Star L.L.C., an affiliate of MSIP, to provide certain administrative services to Southern Star and Holdings. Pursuant to the terms of

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this agreement, 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. No significant expenses were incurred during 2013 or 2012.

14. Quarterly Data (Unaudited)

The following summarizes selected quarterly financial data for 2013 and 2012 (expressed in thousands):

	Successor
	2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Operating revenues	$	53,117		$	50,845		$	53,344		$	58,873
Operating costs and expenses	35,598			38,100			37,338			40,108
Operating income	17,519			12,745			16,006			18,765
Interest expense	7,686			7,693			7,712			7,782
Interest income	(11		)	(9		)	(8		)	(10		)
Miscellaneous other income, net	(93		)	(190		)	(333		)	(272		)
Total other expense, net	7,582			7,494			7,371			7,500
Income before income taxes	9,937			5,251			8,635			11,265
Provision for income taxes	3,918			2,045			3,427			3,740
Net Income	$	6,019		$	3,206		$	5,208		$	7,525

	2012
	Predecessor									Successor
	For the Three Months Ended March 31, 2012			For the Three Months Ended June 30, 2012			For the Period July 1 Through September 23, 2012			For the Period September 24 Through September 30, 2012			For the Three Months Ended December 31, 2012
Operating revenues	$	54,538		$	52,510		$	50,688		$	4,188		$	56,650
Operating costs and expenses	34,212			36,203			32,403			3,154			35,060
Operating income	20,326			16,307			18,285			1,034			21,590
Interest expense	8,085			8,108			7,542			579			7,495
Interest income	(16		)	(11		)	(10		)	(1		)	(11		)
Miscellaneous other income, net	(352		)	(135		)	(150		)	(16		)	(184		)
Total other expense, net	7,717			7,962			7,382			562			7,300
Income before income taxes	12,609			8,345			10,903			472			14,290
Provision for income taxes	4,961			3,250			4,300			184			5,636
Net Income	$	7,648		$	5,095		$	6,603		$	288		$	8,654

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