13 Q4 GS 10K Q4

10-K 1 a13q4gs10kq4.htm 10-K 13 Q4 GS 10K Q4

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2013

o 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: 01-32665
GULF SOUTH PIPELINE COMPANY, LP
(Exact name of registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of incorporation or organization)
20-3265614
(I.R.S. Employer Identification No.)
9 Greenway Plaza, Suite 2800 Houston, Texas 77046 (866) 913-2122
(Address and Telephone Number of Registrant’s Principal Executive Office)
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 o No ý

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 o No ý

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

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 ý No o

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. ý

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. (Check one)

Large accelerated filer o Accelerated filer o Non-accelerated filer ý Smaller reporting company o

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

Documents incorporated by reference. None.

Gulf South Pipeline Company, LP meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

TABLE OF CONTENTS

2013 FORM 10-K

GULF SOUTH PIPELINE COMPANY, LP



PART I	3
Item 1. Business	3
Item 1A. Risk Factors	8
Item 1B. Unresolved Staff Comments	15
Item 2. Properties	15
Item 3. Legal Proceedings	15
Item 4. Mine Safety Disclosures	15
PART II	16
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6. Selected Financial Data	16
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	23
Item 8. Financial Statements and Supplementary Data	24
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	50
Item 9A. Controls and Procedures	50
PART III	51
Item 10. Directors, Executive Officers and Corporate Governance	51
Item 11. Executive Compensation	51
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	51
Item 13. Certain Relationships and Related Transactions, and Director Independence	51
Item 14. Principal Accounting Fees and Services	51
PART IV	52
Item 15. Exhibits and Financial Statement Schedule	52

PART I

Item 1. Business

Unless the context otherwise requires, all references in this Report to “Gulf South,” “we,” “us” and “our” refer to Gulf South Pipeline Company, LP, a Delaware limited partnership.

Introduction

We are a wholly-owned subsidiary of Boardwalk Pipelines, LP (Boardwalk Pipelines), which is a wholly-owned subsidiary of Boardwalk Pipeline Partners, LP (Boardwalk Pipeline Partners or the master limited partnership). Boardwalk Pipeline Partners is a publicly-traded Delaware limited partnership formed in 2005. Loews Corporation (Loews) owns the general partner and the majority of the limited partnership units of Boardwalk Pipeline Partners.

Our Business

We are an interstate natural gas transmission company which owns and operates an integrated natural gas pipeline and storage system located along the Gulf Coast in the states of Texas, Louisiana, Mississippi, Alabama and Florida. As of December 31, 2013, our pipeline transmission system had a peak day delivery capacity of approximately 6.9 billion cubic feet (Bcf) per day and consisted of approximately 7,200 miles of pipeline and two natural gas storage facilities. Our gas storage facility located in Bistineau, Louisiana, has approximately 78.0 Bcf of working gas storage capacity with which we offer firm and interruptible storage service, including no-notice service. Our Jackson, Mississippi, gas storage facility has approximately 5.0 Bcf of working gas storage capacity, which is used for operational purposes and is not offered for sale to the market.

The on-system markets directly served by our system are generally located in eastern Texas, Louisiana, southern Mississippi, southern Alabama, and the Florida Panhandle. These markets include local distribution companies (LDCs) and municipalities located across the system, including New Orleans, Louisiana, Jackson, Mississippi, Mobile, Alabama, and Pensacola, Florida, and other end-users located across the system, including the Baton Rouge to New Orleans industrial corridor and Lake Charles, Louisiana. We also have indirect access to off-system markets through numerous interconnections with affiliated and unaffiliated interstate and intrastate pipelines. These pipeline interconnections provide access to markets in the midwestern, northeastern and southeastern United States (U.S.).

We serve a broad mix of customers, including producers of natural gas, marketers, interstate and intrastate pipelines, LDCs, electric power generators and industrial users. We provide a significant portion of our natural gas pipeline transportation and storage services through firm contracts under which our customers pay monthly capacity reservation fees which are fees owed regardless of actual pipeline or storage capacity utilization. Other fees are based on actual utilization of the capacity under firm contracts and contracts for interruptible services. For the year ended December 31, 2013, approximately 78% of our revenues were derived from capacity reservation fees under firm contracts, approximately 15% of our revenues were derived from fees based on utilization under firm contracts and approximately 7% of our revenues were derived from interruptible transportation, interruptible storage, parking and lending (PAL) and other services.

The majority of our natural gas transportation and storage rates and general terms and conditions of service are established by, and subject to review and revision by, the Federal Energy Regulatory Commission (FERC). These rates are based upon certain assumptions to allow us the opportunity to recover the cost of providing these services and earn a reasonable return on equity. However, it is possible that we may not recover all of our costs or earn a return. We are authorized to charge market-based rates for our natural gas storage capacity pursuant to authority granted by FERC.

The principal sources of supply for our natural gas pipeline system are regional supply hubs and market centers located in the Gulf Coast region, including offshore Louisiana, the Perryville, Louisiana area, the Henry Hub in Louisiana, which serves as the designated delivery point for natural gas futures contracts traded on the New York Mercantile Exchange, and the Carthage, Texas area, which provide access to natural gas supplies from the Bossier Sands, Barnett Shale, Haynesville Shale and other natural gas producing regions in eastern Texas and northern Louisiana. We receive supply from the Woodford Shale through an interconnect with an affiliated pipeline.

Current Growth Projects

Southeast Market Expansion: Our Southeast Market Expansion project consists of constructing an interconnection between us and Petal Gas Storage, LLC (Petal), adding additional compression facilities to our system and constructing approximately 70 miles of 24-inch and 30-inch pipeline in southeastern Mississippi. The project will add approximately 0.5 Bcf per day of peak-day transmission capacity to our system from multiple locations in Texas and Louisiana to Mississippi, Alabama and Florida and is fully contracted with a weighted-average contract life of approximately 10 years. The project, which was approved by the FERC, is expected to cost approximately $300.0 million and to be placed in service in the fourth quarter 2014.

Nature of Contracts

We contract with our customers to provide transportation and storage services on a firm and interruptible basis. We also provide bundled firm transportation and storage services, which we provide to our natural gas customers as no-notice services, and we provide interruptible PAL services for our natural gas customers.

Transportation Services. We offer natural gas transportation services on both a firm and interruptible basis. Our natural gas customers choose, based upon their particular needs, the applicable mix of services depending upon availability of pipeline capacity, the price of services and the volume and timing of the customer’s requirements. Our natural gas firm transportation customers reserve a specific amount of pipeline capacity at specified receipt and delivery points on our system. Firm natural gas customers generally pay fees based on the quantity of capacity reserved regardless of use, plus a commodity and a fuel charge paid on the volume of natural gas actually transported. Capacity reservation revenues derived from a firm service contract are generally consistent during the contract term, but can be higher in winter periods than the rest of the year, especially for no-notice service agreements. Firm transportation contracts generally range in term from one to ten years, although we may enter into shorter or longer term contracts. In providing interruptible natural gas transportation service, we agree to transport natural gas for a customer when capacity is available. Interruptible natural gas transportation service customers pay a commodity charge only for the volume of gas actually transported, plus a fuel charge. Interruptible transportation agreements have terms ranging from day-to-day to multiple years, with rates that change on a daily, monthly or seasonal basis.

Storage Services. We offer customers natural gas storage services on both a firm and interruptible basis. Firm storage customers reserve a specific amount of storage capacity, including injection and withdrawal rights, while interruptible customers receive storage capacity and injection and withdrawal rights when it is available. Similar to firm transportation customers, firm storage customers generally pay fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically range in term from one to ten years. Interruptible storage customers pay for the volume of gas actually stored plus injection and withdrawal fees. Generally, interruptible storage agreements are for monthly terms. We are able to charge market-based rates for our natural gas storage capacity pursuant to authority granted by FERC.

No-Notice Services. No-notice services consist of a combination of firm natural gas transportation and storage services that allow customers to withdraw natural gas from storage with little or no notice. Customers pay a reservation charge based upon the capacity reserved plus a commodity and a fuel charge based on the volume of gas actually transported.

Parking and Lending Service. PAL is an interruptible service offered to customers providing them the ability to park (inject) or borrow (withdraw) natural gas into or out of our pipeline system at a specific location for a specific period of time. Customers pay for PAL service in advance or on a monthly basis depending on the terms of the agreement.

Customers and Markets Served

We contract directly with producers of natural gas, and with end-use customers including LDCs, marketers, electric power generators, industrial users and interstate and intrastate pipelines who, in turn, provide transportation and storage services to end-users. Based on 2013 revenues, our customer mix was as follows: natural gas producers (46%), marketers (18%), interstate and intrastate pipelines (18%), LDCs (14%), power generators (3%) and industrial end users and others (1%). Based upon 2013 revenues, our deliveries were as follows: pipeline interconnects (70%), LDCs (14%), storage activities (9%), industrial end-users (4%), power generators (2%) and other (1%). One non-affiliated customer, EOG Resources, Inc., accounted for approximately 11% of our 2013 operating revenues.

Natural Gas Producers. Producers of natural gas use our services to transport gas supplies from producing areas, primarily from the Gulf Coast region, including shale natural gas production areas in Texas, Louisiana and Oklahoma, to supply pools and to other customers on and off of our system. Producers contract with us for storage services to store excess production and to optimize the ultimate sales prices for their gas.

Marketers. Natural gas marketing companies utilize our services to provide services to our other customer groups as well as to customer groups in off-system markets. The services may include combined gas transportation and storage services to support the needs of the other customer groups. Some of the marketers are sponsored by LDCs or producers.

Pipelines (off-system). Our natural gas pipelines serve as feeder pipelines for long-haul interstate pipelines serving markets throughout the midwestern, northeastern and southeastern portions of the U.S. We have numerous interconnects with third-party interstate and intrastate pipelines.

LDCs. Most of our LDC customers use firm natural gas transportation services, including no-notice service. We serve approximately 90 LDCs at more than 200 delivery locations across our pipeline system. The demand of these customers peaks during the winter heating season.

Power Generators. Our natural gas pipelines are directly connected to 16 natural-gas-fired power generation facilities in five states. The demand of the power generating customers peaks during the summer cooling season which is counter to the winter season peak demands of the LDCs. Most of our power-generating customers use a combination of no-notice, firm and interruptible transportation services.

Industrial End Users. We provide approximately 160 industrial facilities with a combination of firm and interruptible natural gas transportation and storage services. Our pipeline system is directly connected to industrial facilities in the Baton Rouge to New Orleans industrial corridor; Lake Charles, Louisiana; Mobile, Alabama and Pensacola, Florida. We can also access the Houston Ship Channel through third-party natural gas pipelines.

Competition

We compete with numerous other pipelines that provide transportation storage and other services at many locations along our pipeline system. We also compete with pipelines that are attached to new natural gas supply sources that are being developed closer to some of our traditional natural gas market areas. In addition, regulators’ continuing efforts to increase competition in the natural gas industry have increased the natural gas transportation options of our traditional customers. As a result of regulators’ policies, capacity segmentation and capacity release have created an active secondary market which increasingly competes with our own natural gas pipeline services. Further, natural gas competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative fuel sources.

The principal elements of competition among pipelines are available capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. In many cases, the elements of competition, in particular flexibility, terms of service and reliability, are key differentiating factors between competitors. This is especially the case with capacity being sold on a longer-term basis. We are focused on finding opportunities to enhance our competitive profile in these areas by increasing the flexibility of our pipeline system to meet the demands of customers such as power generators and industrial users, and are continually reviewing our services and terms of service to offer customers enhanced service options.

Government Regulation

Federal Energy Regulatory Commission. FERC regulates us under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. FERC regulates, among other things, the rates and charges for the transportation and storage of natural gas in interstate commerce and the extension, enlargement or abandonment of facilities under its jurisdiction. Where required, we hold certificates of public convenience and necessity issued by FERC covering certain of our facilities, activities and services. FERC also prescribes accounting treatment for us, which is separately reported pursuant to forms filed with FERC. Our regulatory books and records and other activities may be periodically audited by FERC.

The maximum rates that may be charged by us for all aspects of the natural gas transportation services that we provide are established through FERC’s cost-of-service rate-making process. Key determinants in FERC’s cost-of-service rate-making process are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. FERC has authorized us to charge market-based rates for firm and interruptible storage services. We do not have an obligation to file a new rate case.

U.S. Department of Transportation (DOT). We are regulated by DOT, through the Pipeline and Hazardous Materials Safety Administration (PHMSA), under the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979 (NGPSA). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas pipeline facilities. We have received authority from PHMSA to operate certain natural gas pipeline assets under special permits that will allow us to operate those pipeline assets at higher than normal operating pressures of up to 0.80 of

the pipe’s Specified Minimum Yield Strength (SMYS). Operating at higher than normal operating pressures will allow us to transport all of the volumes we have contracted for with our customers. PHMSA retains discretion whether to grant or maintain authority for us to operate our natural gas pipeline assets at higher pressures. PHMSA has also developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain high risk areas along our pipeline and take additional measures to protect pipeline segments located in highly populated areas. The NGPSA was most recently amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act) in 2012, with the 2011 Act requiring increased maximum civil penalties for certain violations to $200,000 per violation per day, and an increased total cap of $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in more stringent safety controls or additional natural gas and hazardous liquids pipeline safety rulemaking. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.

Other. Our operations are also subject to extensive federal, state, and local laws and regulations relating to protection of the environment. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases, discharges and emissions of various substances into the environment. Environmental regulations also require that our facilities, sites and other properties be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. The laws our operations are subject to include, for example:


•	the Clean Air Act (CAA) and analogous state laws which impose obligations related to air emissions, including, in the case of the CAA, greenhouse gas emissions and regulations affecting reciprocating engines subject to Maximum Achievable Control Technology (MACT) standards;


•	the Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws which regulate discharge of wastewater from our facilities into state and federal waters;


•	the Comprehensive Environmental Response, Compensation and Liability Act, commonly referred to as CERCLA, or the Superfund law, and analogous state laws which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;


•	the Resource Conservation and Recovery Act, and analogous state laws which impose requirements for the handling and discharge of solid and hazardous waste from our facilities; and


•	the Occupational Safety and Health Act (OSHA) and analogous state laws, which establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of orders enjoining performance of some or all of our operations. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that the current regulatory standards will not become more onerous in the future, resulting in more significant costs to maintain compliance or increased exposure to significant liabilities.

Effects of Compliance with Environmental Regulations

Note 3 in Item 8 of this Report contains information regarding environmental compliance.

Employee Relations

At December 31, 2013, we had approximately 585 employees. A satisfactory relationship exists between management and labor. We maintain various benefit plans covering substantially all of our employees.

Available Information

Our website is located at www.gulfsouthpl.com. We make available free of charge through our website our annual reports on Form 10-K, which include our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as we electronically file such material with the Securities and Exchange Commission (SEC). These documents are also available at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549 or at the SEC's website at www.sec.gov. You can obtain additional information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Additionally, copies of these documents, excluding exhibits, may be requested at no cost by contacting Investor Relations, Boardwalk Pipeline Partners, LP, 9 Greenway Plaza, Suite 2800, Houston, TX 77046.

Item 1A. Risk Factors

Our business faces many risks. We have described below the material risks which we face. Each of the risks and uncertainties described below could lead to events or circumstances that may have a material adverse effect on our business, financial condition, results of operations or cash flows.

All of the information included in this Report and any subsequent reports we may file with the SEC or make available to the public should be carefully considered and evaluated before investing in any securities issued by us.

Business Risks

We may not be able to replace expiring gas transportation and storage contracts at attractive rates or on a long-term basis and may not be able to sell short-term services at attractive rates or at all due to narrower basis differentials which adversely affect the value of our transportation services and narrowing of price spreads between time periods and reduced volatility which adversely affect our storage services.

New sources of natural gas continue to be identified and developed in the U.S., including the Marcellus and Utica shale plays which are closer to the traditional high value markets we serve than the supply basins connected to our facilities. As a result, pipeline infrastructure has been, and continues to be, developed to move natural gas from these supply basins to market areas, resulting in changes in pricing dynamics between supply basins, pooling points and market areas. Additionally, these new supplies of natural gas have reduced production or slowed production growth from supply areas connected to our pipelines and have caused some of the gas production that is supplied to our system to be diverted to other market areas. These factors have adversely affected, and are expected to continue to adversely affect, the value of our transportation and storage services and have lowered the volumes we have transported on our pipelines, as further discussed below.

Transportation Services:

A key market driver that influences the rates and terms of our transportation contracts is the current and anticipated basis differentials - generally meaning the difference in the price of natural gas at receipt and delivery points on our natural gas pipelines - which influence how much customers are willing to pay to transport gas between those points. Basis differentials can be affected by, among other things, the availability and supply of natural gas, the proximity of supply areas to end use markets, competition from other pipelines, including pipelines under development, available transportation and storage capacity, storage inventories, regulatory developments, weather and general market demand in markets served by our pipeline systems. As a result of the new sources of supply and related pipeline infrastructure discussed above, basis differentials on our pipeline systems have narrowed significantly in recent years, reducing the transportation rates and other contract terms we can negotiate with our customers for available transportation capacity and for contracts due for renewal for our firm transportation services. The narrowing of basis differentials has also adversely affected the rates we are able to charge for our interruptible and short-term firm transportation services.

Each year, a portion of our firm natural gas transportation contracts expire and need to be renewed or replaced. For the reasons discussed above and elsewhere in this Report, in recent periods we have renewed many expiring contracts at lower rates and for shorter terms than in the past, which has materially adversely impacted our transportation revenues. We expect this trend to continue and therefore may not be able to sell our available capacity, extend expiring contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts, which would continue to adversely affect our business.

In 2008 and 2009, we placed into service a number of large new pipelines and expansions of our system, including our East Texas Pipeline and Southeast Expansion. These projects were supported by firm transportation agreements with anchor shippers, typically having a term of ten years and pricing and other terms negotiated based on then current market conditions, which included wider basis spreads and, correspondingly, higher transportation rates than those prevailing in the current market. As a result, in 2018, we will have significantly more contract expirations than other years. We cannot predict what market conditions will prevail at the time such contracts expire and what pricing and other terms may be available in the marketplace for renewal or replacement of such contracts. If we are unable to renew or replace these and other expiring contracts when they expire, or if the terms of any such renewal or replacement contracts are not as favorable as the expiring agreements, our revenues and cash flows could be materially adversely affected.

Storage and PAL Services:

We own and operate substantial natural gas storage facilities. The market for the storage and PAL services that we offer is also impacted by the factors discussed above, as well as natural gas price differentials between time periods, such as winter to summer (time period price spreads), and the volatility in time period price spreads. Recently, the market conditions described above have caused time period price spreads to narrow considerably and price volatility of natural gas to decline significantly, reducing the rates we can charge for our storage and PAL services and adversely impacting the value of these services. These market conditions, together with regulatory changes in the financial services industry, have also caused a number of gas marketers, which have traditionally been large consumers of our storage and PAL services, to exit the market, further impacting the market for those services.

We expect the conditions described above to continue in 2014 and cannot give assurances they will not continue beyond 2014. These market factors and conditions adversely impact our revenues and earnings before interest, taxes, depreciation and amortization (EBITDA) and could impact us on a long-term basis.

Changes in the prices of natural gas impacts supply of and demand for those commodities, which impact our business.

The prices of natural gas fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors, including:


•	worldwide economic conditions;


•	weather conditions, seasonal trends and hurricane disruptions;


•	the relationship between the available supplies and the demand for natural gas;


•	new supply sources;


•	the availability of adequate transportation capacity;


•	storage inventory levels;


•	the price and availability of oil and other forms of energy;


•	the effect of energy conservation measures;


•	the nature and extent of, and changes in, governmental regulation, new regulations adopted by the Environmental Protection Agency (EPA), for example, greenhouse gas legislation and taxation; and


•	the anticipated future prices of natural gas, oil and other commodities.

It is difficult to predict future changes in natural gas prices. However, the economic environment that has existed over the last several years generally indicates a bias toward continued downward pressure on natural gas prices. Sustained low natural gas prices could negatively impact producers, including those directly connected to our pipelines that have contracted for capacity with us which could adversely impact our revenues and EBITDA.

Conversely, future increases in the price of natural gas could make alternative energy sources more competitive and reduce demand for natural gas. A reduced level of demand for natural gas could reduce the utilization of capacity on our systems, reduce the demand for our services and could result in the non-renewal of contracted capacity as contracts expire and affect our business.

Our revolving credit facility contains operating and financial covenants that restrict our business and financing activities.

Boardwalk Pipelines maintains a revolving credit facility under which we may borrow funds, subject to sublimits. The revolving credit facility contains operating and financial covenants that may restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our credit agreement limits our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate or engage in asset sales, or grant liens or make negative pledges. The agreement also requires us to maintain a ratio of consolidated debt to consolidated EBITDA (as defined in the agreement) of no more than five to one, which limits the amount of additional indebtedness we can incur, including to grow our business, and could require us to prepay indebtedness if our EBITDA decreases to a level that would cause us to breach this covenant. Future financing agreements we may enter into may contain similar or more restrictive covenants or may not be as favorable as those under our existing indebtedness.

Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions or

our financial performance deteriorate further, our ability to comply with these covenants may be impaired. If we are not able to incur additional indebtedness we may need to seek other sources of funding that may be on terms that materially adversely affect our financial condition. If we default under our credit agreement or another financing agreement, significant additional restrictions may become applicable. In addition, a default could result in a significant portion of our indebtedness becoming immediately due and payable, and our lenders could terminate their commitment to make further loans to us. In such event, we would not have, and may not be able to obtain, sufficient funds to make these accelerated payments.

A significant portion of our debt will mature over the next five years and will need to be paid or refinanced.

A significant portion of our debt is set to mature in the next five years, including our revolving credit facility. We may not be able to refinance our maturing debt upon commercially reasonable terms, or at all, depending on numerous factors, including our financial condition and prospects at the time and the then current state of the bank and capital markets in the U.S. Further, our liquidity may be adversely affected if we are unable to replace our revolving credit facility upon acceptable terms when it matures.

In addition, most of our debt is rated by independent credit rating agencies. Our borrowing costs can be affected by ratings assigned by the rating agencies. In February 2014, two of the major rating agencies that rate our indebtedness lowered our credit ratings, citing the challenges to our business discussed above. These ratings decreases, and any further decrease in our credit ratings, could increase our cost of borrowing and make it more difficult to refinance our debt.

Limited access to the debt markets could adversely affect our business.

Changes in the debt markets, including market disruptions, limited liquidity, and interest rate volatility, may increase the cost of financing as well as the risks of refinancing maturing debt. Instability in the financial markets may increase our cost of capital while reducing the availability of funds. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations or growth projects. Reduced access to the debt markets could limit our ability to grow our business through growth projects. If the debt markets were not available, it is not certain if other adequate financing options would be available to us on terms and conditions that are acceptable.

We have historically relied on our cash flow from operations, borrowings under our revolving credit facility and proceeds from debt offerings to execute our growth projects and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. Any disruption could require us to take additional measures to conserve cash until the markets stabilize or until we can arrange alternative credit arrangements or other funding for our business needs. Such measures could include reducing or delaying business activities, reducing our operations to lower expenses, and reducing other discretionary uses of cash.

Changes in the pipeline safety laws and regulations requiring substantial changes to existing integrity management programs or safety technologies could subject us to increased capital and operating costs and require us to use more comprehensive and stringent safety controls.

We are subject to regulation by PHMSA of the DOT under the NGPSA as amended. The NGPSA governs the design, installation, testing, construction, operation, replacement and management of natural gas pipeline facilities. These amendments have resulted in the adoption of rules through PHMSA, that require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas, such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. These regulations have resulted in an overall increase in our maintenance costs. Due to recent highly publicized incidents on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. We could incur significant additional costs if new or more stringent pipeline safety requirements are implemented.

The 2011 Act was enacted and signed into law in early 2012. Under the 2011 Act, maximum civil penalties for certain violations have been increased to $200,000 per violation per day, and from a total cap of $1.0 million to $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas and hazardous liquids pipeline safety rulemaking in 2014 or soon thereafter. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.

Further, we have entered into firm transportation contracts with shippers which utilize the design capacity of certain of our pipeline assets, assuming that we operate those pipeline assets at higher than normal operating pressures (up to 0.80 of the pipeline's SMYS). We have authority from PHMSA to operate those pipeline assets at such higher pressures, however PHMSA retains discretion to withdraw or modify this authority. If PHMSA were to withdraw or materially modify such authority, we may

not be able to transport all of our contracted quantities of natural gas on our pipeline assets and could incur significant additional costs to re-obtain such authority or to develop alternate ways to meet our contractual obligations.

Our natural gas transportation and storage operations are subject to extensive regulation by FERC, including rules and regulations related to the rates we can charge for our services and our ability to construct or abandon facilities. FERC's rate-making policies could limit our ability to recover the full cost of operating our pipelines, including earning a reasonable return.

We are subject to extensive regulation by FERC, including the types and terms of services we may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities, recordkeeping and relationships with affiliated companies. FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to FERC's regulations. FERC can also deny us the right to remove certain facilities from service.

FERC also regulates the rates we can charge for our natural gas transportation and storage operations. For our cost-based services, FERC establishes both the maximum and minimum rates we can charge. The basic elements that FERC considers are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. We may not be able to recover all of our costs, including certain costs associated with pipeline integrity, through existing or future rates.

FERC can challenge the existing rates on our pipeline. Such a challenge against us could adversely affect our ability to charge rates that would cover future increases in our costs or even to continue to collect rates to maintain our current revenue levels that are designed to permit a reasonable opportunity to recover current costs and depreciation and earn a reasonable return.

If we were to file a rate case, or if we have to defend our rates in a proceeding commenced by FERC, we would be required, among other things, to establish that the inclusion of an income tax allowance in our cost of service is just and reasonable. Under current FERC policy, since Boardwalk Pipeline Partners is a limited partnership and does not pay U.S. federal income taxes, this would require Boardwalk Pipeline Partners to show that its unitholders (or their ultimate owners) are subject to federal income taxation. To support such a showing, Boardwalk Pipeline Partners' general partner may elect to require owners of its units to re-certify their status as being subject to U.S. federal income taxation on the income generated by us or we may attempt to provide other evidence. We can provide no assurance that the evidence we might provide to FERC will be sufficient to establish that Boardwalk Pipeline Partners' unitholders (or their ultimate owners) are subject to U.S. federal income tax liability on the income generated by us. If we are unable to make such a showing, FERC could disallow a substantial portion of the income tax allowance included in the determination of the maximum rates that may be charged by us, which could result in a reduction of such maximum rates from current levels.

If affiliated and third-party pipelines and other facilities interconnected to us become unavailable to transport natural gas, our revenues could be adversely affected.

We depend upon affiliated and third-party pipelines and other facilities that provide delivery options to and from our pipelines. If any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas to end markets could be restricted, thereby reducing our revenues.

Our business requires the retention and recruitment of a skilled workforce and the loss of such workforce could result in the failure to implement our business plans.

Our operations and management require the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. We compete with other companies for this skilled workforce. In addition, many of our current employees are approaching retirement age and have significant institutional knowledge that must be transferred to other employees. If we are unable to (a) retain our current employees, (b) successfully complete the knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

A failure in our computer systems or a cyber security attack on any of our facilities, or those of third parties, may affect adversely our ability to operate our business.

We have become more reliant on technology to help increase efficiency in our businesses. Our businesses are dependent upon our operational and financial computer systems to process the data necessary to conduct almost all aspects of our business, including the operation of our pipeline and storage facilities and the recording and reporting of commercial and financial transactions. Any failure of our computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our business.

It has been reported that unknown entities or groups have mounted so-called “cyber attacks” on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. Any cyber attacks that affect our facilities, or those of our customers, suppliers or others with whom we do business could have a material adverse effect on our business, cause us a financial loss and/or damage our reputation.

We are exposed to credit risk relating to nonperformance by our customers.

Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Our exposure generally relates to receivables for services provided, future performance under firm agreements and volumes of gas or other products owed by customers for imbalances or product loaned by us to them under certain of our services. Our tariffs allow us to require limited credit support in the event that our transportation customers are unable to pay for our services. If any of our significant customers have credit or financial problems which result in a delay or failure to pay for services provided by us or contracted for with us, or to repay the product they owe us, it could have a material adverse effect on our business. In addition, as contracts expire, the credit or financial failure of any of our customers could also result in the non-renewal of contracted capacity, which could have a material adverse effect on our business. Item 7A of this Report contains more information on credit risk arising from products loaned to customers.

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues.

We rely on a limited number of customers for a significant portion of revenues. Our largest non-affiliated customer in terms of revenues, EOG Resources, Inc. represented over 11% of our 2013 revenues. Including revenues earned from affiliates, our top ten customers comprised approximately 57% of our revenues in 2013. We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms which could materially reduce our contracted transportation volumes and the rates we can charge for our services.

Failure to comply with existing or new environmental laws or regulations or an accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.

Our operations are subject to extensive federal, regional, state and local laws and regulations relating to protection of the environment. These laws include, for example, the CAA, the Clean Water Act, CERCLA, the Resource Conservation and Recovery Act, OSHA and analogous state laws. These laws and regulations may restrict or impact our business activities in many ways, including requiring the acquisition of permits or other approvals to conduct regulated activities, restricting the manner in which we dispose of wastes, requiring remedial action to remove or mitigate contamination resulting from a spill or other release, requiring capital expenditures to comply with pollution control requirements, and imposing substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating and capital costs and reduced demand for our pipeline and storage services.

The U.S. Congress and the EPA as well as some states and regional groupings of states have in recent years considered legislation or regulations to reduce emissions of greenhouse gases (GHG). These efforts have included cap-and-trade programs, carbon taxes and GHG reporting and tracking programs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. In addition, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets and operations.

We compete with other pipelines.

The principal elements of competition among pipeline systems are availability of capacity, rates, terms of service, access to supplies, flexibility and reliability of service. Additionally, FERC's policies promote competition in natural gas markets by increasing the number of natural gas transportation options available to our customer base. Increased competition could reduce the volumes of product we transport or store or, in instances where we do not have long-term contracts with fixed rates, could cause us to decrease the transportation or storage rates we can charge our customers. Competition could intensify the negative impact of factors that adversely affect the demand for our services, such as adverse economic conditions, weather, higher fuel costs and taxes or other regulatory actions that increase the cost, or limit the use, of products we transport and store.

Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are a variety of operating risks inherent in our transportation and storage operations such as leaks and other forms of releases, explosions, fires and mechanical problems. Additionally, the nature and location of our business may make us susceptible to catastrophic losses from hurricanes or other named storms, particularly with regard to our assets in the Gulf Coast region, windstorms, earthquakes, hail, and severe winter weather. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from some of these risks.

We currently possess property, business interruption and general liability insurance, but proceeds from such insurance coverage may not be adequate for all liabilities or expenses incurred or revenues lost. Moreover, such insurance may not be available in the future at commercially reasonable costs and terms. The insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or all potential losses.

Possible terrorist activities or military actions could adversely affect our business.

The continued threat of terrorism and the impact of retaliatory military and other action by 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 markets for our natural gas transportation and storage services. While we are taking steps that we believe are appropriate to increase the security of our assets, we may not be able to completely secure our assets or completely protect them against a terrorist attack.

Tax Risks

Our tax treatment depends on Boardwalk Pipeline Partners’ status as a partnership for federal income tax purposes, as well as our and Boardwalk Pipeline Partners not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us or Boardwalk Pipeline Partners as a corporation for federal income tax purposes, or if we or Boardwalk Pipeline Partners were to become subject to additional amounts of entity-level taxation for state tax purposes, the amount of cash available for payment of principal and interest on Gulf South’s notes would be substantially reduced.

Despite the fact that we and Boardwalk Pipeline Partners are limited partnerships under Delaware law, Boardwalk Pipeline Partners would be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement.

Based upon Boardwalk Pipeline Partners’ current operations, it believes it satisfies the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause Boardwalk Pipeline Partners to be treated as a corporation for federal income tax purposes or otherwise subject Boardwalk Pipeline Partners to taxation as an entity.

If Boardwalk Pipeline Partners were treated as a corporation for United States federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state income tax at varying rates. Thus, treatment of us or Boardwalk Pipeline Partners as a corporation would result in a material reduction in our anticipated cash flow, which could materially and adversely affect our ability to service our debt.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of such a tax on us or Boardwalk Pipeline Partners by any state would reduce the cash flow available to service our debt.

The tax treatment of publicly traded partnerships could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including Boardwalk Pipeline Partners, may be modified by legislative, judicial or administrative changes and differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which Boardwalk Pipeline Partners relies for its treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the cash flow available to service our debt.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

We are headquartered in approximately 108,000 square feet of leased office space located in Houston, Texas. We own our respective pipeline system in fee. However, substantial portions of our system are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Item 1 of this Report contains additional information regarding our material property, including our pipelines and storage facilities.

Item 3. Legal Proceedings

Refer to Note 3 in Item 8 of this Report for a discussion of our legal proceedings.

Item 4. Mine Safety Disclosures

None.

PART II

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

None. We are a wholly-owned subsidiary of Boardwalk Pipelines, which is wholly-owned by Boardwalk Pipeline Partners. As such, there is no public trading market for our common equity.

Item 6. Selected Financial Data

Omitted in accordance with General Instruction I to Form 10-K.

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

Overview

As of December 31, 2013, our pipeline system consisted of approximately 7,200 miles of interconnected pipelines with a peak day delivery capacity of approximately 6.9 Bcf per day. The on-system markets directly served by our system are generally located in eastern Texas, Louisiana, southern Mississippi, southern Alabama, and the Florida Panhandle. These markets include LDCs and municipalities located across the system, including New Orleans, Louisiana, Jackson, Mississippi, Mobile, Alabama and Pensacola, Florida, and other end-users located across the system, including the Baton Rouge to New Orleans industrial corridor and Lake Charles, Louisiana. We also have indirect access to off-system markets through numerous interconnections with affiliated and unaffiliated interstate and intrastate pipelines and storage facilities. We have two natural gas storage facilities located in two states with aggregate working gas capacity of approximately 83.0 Bcf.

Our transportation services consist of firm natural gas transportation, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible natural gas transportation, whereby the customer pays to transport gas only when capacity is available and used. We offer firm natural gas storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and parking and lending (PAL) services where the customer receives and pays for capacity only when it is available and used. We are not in the business of buying and selling natural gas other than for system management purposes, but changes in the level of natural gas prices may impact the volumes of gas transported and stored on our pipeline system. Our operating costs and expenses typically do not vary significantly based upon the amount of products transported, with the exception of fuel consumed at our compressor stations, which is included in Fuel and gas transportation expenses on our Statements of Income.

Market Conditions and Contract Renewals

We provide natural gas transportation services to customers that are directly connected to our pipeline system and, through interconnects with third-party pipelines, to customers that are not directly connected to our system. Transportation rates that we can charge customers we serve through interconnects with third-party pipelines are heavily influenced by current and anticipated basis differentials. Basis differentials, generally the difference in the price of natural gas at receipt and delivery points across our natural gas pipeline system, influence how much customers are willing to pay to transport gas between those points. Basis differentials can be affected by, among other things, the availability and supply of natural gas, the proximity of supply areas to end use markets, competition from other pipelines, including pipelines under development, available transportation and storage capacity, storage inventories, regulatory developments, weather and general market demand in markets served by our pipeline system. New sources of natural gas continue to be identified and developed in the U.S., including the Marcellus and the Utica shale plays which are closer to the traditional high value markets we serve, than the supply basins connected to our facilities. As a result, pipeline infrastructure has been and continues to be developed to move natural gas from these supply basins to market areas, resulting in changes in pricing dynamics between supply basins, pooling points and market areas. Additionally, these new supplies of natural gas have reduced production or slowed production growth from supply areas connected to our pipeline and have caused some of the gas production that is supplied to our system to be diverted to other market areas. As a result of the new sources of supply and related pipeline infrastructure discussed above, basis differentials on our pipeline system have narrowed significantly in recent years, reducing the transportation rates and other contract terms we can negotiate with our customers for available transportation capacity and for contracts due for renewal for our interruptible and firm transportation services.

A substantial portion of our transportation capacity is contracted for under firm transportation agreements. Each year a portion of our firm transportation agreements expire and need to be renewed or replaced. Due to the factors noted above, in recent periods we have renewed many expiring contracts at lower rates and for shorter terms than in the past, which has materially adversely impacted our firm and interruptible transportation revenues. In light of the market conditions discussed above, natural gas transportation contracts we have renewed or entered into in 2013 and in recent years have been at lower rates, and any remaining available capacity generally has been marketed and sold at lower rates under short-term firm or interruptible contracts, or in some cases not sold at all. As a result, capacity reservation charges under firm transportation agreements for the year ended December 31, 2013, were lower by $32.4 million than they were for the comparable 2012 period. We expect this trend to continue and therefore may not be able to sell our available capacity, extend expiring contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts, all of which would continue to adversely impact our transportation revenues and EBITDA and could impact us on a long-term basis.

More recently, we have seen the value of our storage and PAL services adversely impacted by the factors discussed above, which have contributed to a narrowing of natural gas price differentials between time periods, such as winter to summer (time period price spreads), and the price volatility of natural gas to decline significantly, reducing the rates we can charge for our storage and PAL services. Based on the current forward pricing curve, which is backwardated, time period price spreads for 2013 have significantly deteriorated from the 2012 levels and we expect such conditions to persist. In recent months, we have seen the deterioration of storage spreads accelerate and that trend is expected to continue into 2014. These market conditions, together with regulatory changes in the financial services industry, have also caused a number of gas marketers, which have traditionally been large consumers of our storage and PAL services, to exit the market, further negatively impacting the market for those services. A reduced need for storage as supply increases, narrowing time period price spreads and fewer market participants has caused, and could continue to cause demand for our storage and PAL services to decline on a long-term basis.

Pipeline System Maintenance

We incur substantial costs for ongoing maintenance of our pipeline system and related facilities, including those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. These costs are not dependent on the amount of revenues earned from our natural gas transportation services. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. These regulations have resulted in an overall increase in our ongoing maintenance costs, including maintenance capital and maintenance expense. Due to recent widely-known incidents that have occurred on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. We could incur significant additional costs if new or more stringently interpreted pipeline safety requirements are implemented.

Results of Operations

2013 Compared with 2012

Our net income for the year ended December 31, 2013, decreased $21.9 million, or 20%, to $88.2 million compared to $110.1 million for the year ended December 31, 2012 as a result of the factors discussed below.

Operating revenues for the year ended December 31, 2013, decreased $48.5 million, or 9%, to $468.7 million, compared to $517.2 million for the year ended December 31, 2012. The decrease in revenues was primarily a result of the market conditions discussed above, resulting in lower transportation revenues, excluding fuel, of $41.2 million and $11.5 million of reduced storage and PAL revenues. These decreases were partially offset by increased revenues from fuel of $3.8 million, resulting mainly from higher natural gas prices.

Operating costs and expenses for the year ended December 31, 2013, decreased $21.6 million, or 6%, to $340.1 million, compared to $361.7 million for the year ended December 31, 2012, primarily driven by $17.0 million from the sale of storage base gas, which was sold in 2013 as a result of a strategy to monetize base gas and provide capacity for additional parks of customer gas under PAL services, lower maintenance expense projects and lower administrative and general expenses.

Total other deductions for the year ended December 31, 2013, decreased by $5.0 million, or 11%, to $40.4 million compared to $45.4 million for the year ended December 31, 2012, driven by driven by a reduction in interest expense due to lower weighted-average borrowing rates and increased capitalized interest from increased capital project spending.

Liquidity and Capital Resources

Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility, debt issuances and advances from affiliates. We use funds from our operations to fund our operating activities and maintenance capital requirements, service our indebtedness and make advances or distributions to Boardwalk Pipelines. We participate in a cash management program with our affiliates to the extent we are permitted under FERC regulations. Under the cash management program, depending on whether we have short-term cash surpluses or cash requirements, Boardwalk Pipelines either provides cash to us or we provide cash to Boardwalk Pipelines. We also periodically make cash advances to Boardwalk Pipelines, which are represented as demand notes. Advances are stated at historical carrying amounts. Interest income and expense are recognized on an accrual basis when collection is reasonably assured. The interest rate on intercompany demand notes is the London Interbank Offered Rate (or LIBOR) plus one percent and is adjusted every three months. We have no guarantees of debt or other similar commitments to unaffiliated parties. We anticipate that our existing capital resources, ability to obtain financing and cash flow generated from future operations will enable us to maintain our current level of operations and planned operations, including capital expenditures.

Capital Expenditures

Our growth and maintenance capital expenditures for the years ended December 31, 2013, 2012 and 2011 were as follows (in millions):



	Year Ended December 31,
	2013		2012		2011
Growth capital	$	73.6	$	4.7	$	64.4
Maintenance capital	39.2		49.6		55.6
Total	$	112.8	$	54.3	$	120.0

We financed our growth capital expenditures through issuances of debt by us and through available operating cash flows in excess of our operating needs.

We expect our total capital expenditures to be approximately $305.0 million in 2014, including approximately $55.0 million for maintenance capital. Our primary growth project for 2014 is the Southeast Market Expansion. We expect to spend approximately $300.0 million on this project to construct an interconnection between us and Petal, add additional compression facilities to our system and construct approximately 70 miles of 24-inch and 30-inch pipeline in southeastern Mississippi. Through December 31, 2013, we have spent $53.8 million on this project and expect to spend an additional $248.9 million in 2014. Refer to Item 1 for further discussion.

Revolving Credit Facility

Boardwalk Pipelines maintains a revolving credit facility under which we may borrow funds, subject to a sublimit of $200.0 million. As of December 31, 2013, we had no borrowings outstanding under our revolving credit facility, no letters of credit issued thereunder and had $200.0 million of available borrowing capacity under our revolving credit facility.

The credit facility, which matures in April 2017, contains various restrictive covenants and other usual and customary terms and conditions, including the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the credit facility requires Boardwalk Pipelines and its subsidiaries, including us, to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the Amended Credit Agreement) measured for the previous twelve months of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following an acquisition. We were in compliance with all covenant requirements under the credit facility as of December 31, 2013. Note 7 in Item 8 of this Report contains more information regarding our revolving credit facility.

Contractual Obligations

The following table summarizes significant contractual cash payment obligations under firm commitments as of December 31, 2013, by period (in millions):



	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 years
Principal payments on long-term debt ⁽¹⁾	$	850.0	$	—	$	275.0	$	275.0	$	300.0
Interest on long-term debt	192.3		43.2		65.7		41.4		42.0
Capital commitments ⁽²⁾	51.2		51.2		—		—		—
Pipeline capacity agreements ⁽³⁾	26.7		6.2		12.4		8.1		—
Operating lease commitments	12.0		3.5		6.7		1.8		—
Total	$	1,132.2	$	104.1	$	359.8	$	326.3	$	342.0


(1)	Includes our senior unsecured notes, having maturity dates from 2015 to 2022. We currently do not have any borrowings outstanding under our revolving credit facility, which has a maturity date of April 27, 2017.

(2) Capital commitments represent binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at December 31, 2013.

(3) The amounts shown are associated with pipeline capacity agreements on third-party pipelines that allow us to transport gas to off-system markets on behalf of our customers.

Changes in cash flow from operating activities

Net cash provided by operating activities decreased $54.5 million to $178.7 million for the year ended December 31, 2013 compared to $233.2 million for the comparable 2012 period, primarily due to a reduction in our earnings as discussed under Results of Operations.

Changes in cash flow from investing activities

Net cash used in investing activities increased $101.6 million to $177.7 million for the year ended December 31, 2013 compared to $76.1 million for the comparable 2012 period. The increase was primarily driven by an increase in cash loaned to Boardwalk Pipelines under the cash management program and an increase in capital expenditures, partially offset by proceeds received from the sale of storage gas.

Changes in cash flow from financing activities

Net cash used in financing activities decreased $157.0 million, or 100%, compared to the 2012 period, due to net debt repayments made in the 2012 period.

Impact of Inflation

The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant and equipment is subject to rate-making treatment, and under current FERC practices, recovery is limited to historical costs. Amounts in excess of historical cost are not recoverable unless a rate case is filed. However, cost-based regulation, along with competition and other market factors, may limit our ability to price jurisdictional services to ensure recovery of inflation’s effect on costs.

Off-Balance Sheet Arrangements

At December 31, 2013, we had no guarantees of off-balance sheet debt to third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings, and no other off-balance sheet arrangements.

Critical Accounting Estimates and Policies

Our significant accounting policies are described in Note 2 to the Financial Statements included in Item 8 of this Report. The preparation of these financial statements in accordance with accounting principles generally accepted in the U.S. (GAAP) requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. The result of this process forms the basis for making judgments about the carrying amount of assets and liabilities that are not readily apparent from other sources. We review our estimates and judgments on a regular, ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the periods in which the facts that give rise to the revisions become known.

The following accounting policies and estimates are considered critical due to the potentially material impact that the estimates, judgments and uncertainties affecting the application of these policies might have on our reported financial information.

Regulation

We are regulated by FERC. When certain criteria are met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates (regulatory accounting). Regulatory accounting is not applicable to us because competition in our market areas has resulted in discounts from the maximum allowable cost-based rates being granted to customers and certain services provided by us are priced using market-based rates.

In the course of providing transportation and storage services to customers, we may receive different quantities of gas from shippers and operators than the quantities delivered by the pipelines on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are primarily settled in cash or the receipt or delivery of gas in the future. Settlement of natural gas imbalances requires agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. The receivables and payables are valued at market price.

Fair Value Measurements

Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances. We use fair value measurements to record our derivatives, asset retirement obligations and impairments. We also use fair value measurements to report fair values for certain items in the Notes to the Financial Statements in Item 8 of this Report. Note 4 contains more information regarding our fair value measurements.

Environmental Liabilities

Our environmental liabilities are based on management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of our operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these environmental matters. At December 31, 2013, we had accrued approximately $5.3 million for environmental matters. Our environmental accrued liabilities could change substantially in the future due to factors such as the nature and extent of any contamination, changes in remedial requirements, technological changes, discovery of new information, and the involvement of and direction taken by the EPA, FERC and other governmental authorities on these matters. We continue to conduct environmental assessments and are implementing a variety of remedial measures that may result in increases or decreases in the estimated environmental costs. Note 3 in Item 8 of this Report contains more information regarding our environmental liabilities.

Impairment of Long-Lived Assets

We evaluate whether the carrying amounts of our long-lived assets have been impaired when circumstances indicate the carrying amounts of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount is not recoverable, an impairment loss is measured as the excess of the asset’s carrying amount over its fair value. Notes 4 and 5 in Item 8 of this Report contain more information regarding impairments we have recognized.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this Report, as well as some statements in periodic press releases and some oral statements made by our officials and our affiliates during presentations about us, are “forward-looking.” Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will likely result,” and similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by us or our affiliates, are also forward-looking statements.

Forward-looking statements are based on current expectations and projections about future events and their potential impact on us. While management believes that these forward-looking statements are reasonable as and when made, there is no assurance that future events affecting us will be those that we anticipate. All forward-looking statements are inherently subject to a variety of risks and uncertainties, many of which are beyond our control that could cause actual results to differ materially from those anticipated or projected. These risks and uncertainties include, among others:


•	our ability to maintain or replace expiring gas transportation and storage contracts and to sell short-term capacity on our pipeline;


•	the costs of maintaining and ensuring the integrity and reliability of our pipeline system;


•	the impact of new pipelines or new gas supply sources on competition and basis spreads on our pipeline system;


•	volatility or disruptions in the capital or financial markets;


•	the impact of FERC’s rate-making policies and actions on the services we offer and the rates we charge and our ability to recover the full cost of operating our pipelines, including earning a reasonable return;


•	the consummation and completion of contemplated transactions, projects and agreements, including obtaining all necessary regulatory approvals, or the timing, cost, scope and financial performance of our recent, current and future growth projects;


•	the impact of changes to laws and regulations, such as the proposed greenhouse gas legislation and other changes in environmental legislations, the pipeline safety bill, and regulatory changes that result from that legislation applicable to interstate pipelines, on our business, including our costs, liabilities and revenues;


•	our ability to access the debt markets on acceptable terms to refinance our outstanding indebtedness and to fund our capital needs;


•	operational hazards, litigation and unforeseen interruptions for which we may not have adequate or appropriate insurance coverage;


•	the future cost of insuring our assets;


•	our ability to access new sources of natural gas and the impact on us of any future decreases in supplies of natural gas in our supply areas;


•	the impact on our system throughput and revenues from changes in the supply of and demand for natural gas, including as a result of commodity price changes; and


•	the additional risks and uncertainties described in Part I, Item 1A, Risk Factors of this Report.

Developments in any of these areas could cause our results to differ materially from results that have been or may be anticipated or projected. Forward-looking statements speak only as of the date of this Report and we expressly disclaim any obligation or undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest rate risk:

With the exception of the revolving credit facility, for which the interest rates are 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. The following table presents market risk associated with our fixed-rate long-term debt at December 31 (in millions, except interest rates):



	2013			2012
Carrying amount of fixed-rate debt	$	846.3		$	845.5
Fair value of fixed-rate debt	$	889.7		$	930.4
100 basis point increase in interest rates and resulting debt decrease	$	32.9		$	42.3
100 basis point decrease in interest rates and resulting debt increase	$	35.1		$	45.3
Weighted-average interest rate	5.33		%	5.33		%

At December 31, 2013, and at the time of this filing, we had no borrowings outstanding under the revolving credit facility. A significant amount of our debt, including the revolving credit facility, will mature over the next five years. We expect to refinance the debt either prior to or at maturity. Our ability to refinance the debt at interest rates that are currently available is subject to risk at the magnitude illustrated in the table above. We expect to refinance the remainder of our debt that will mature based on our assessment of the term rates of interest available in the market.

Commodity risk:

We do not take title to the natural gas which we transport and store, therefore we do not assume the related commodity price risk associated with the products. However, certain volumes of our gas stored underground are available for sale and subject to commodity price risk. We manage our exposure to commodity price risk through the use of futures, swaps and option contracts. Note 4 of Item 8 contains additional information regarding our derivative contracts.

Credit risk:

Our credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them, generally under PAL and no-notice services. Natural gas price volatility can materially increase credit risk related to gas loaned to customers. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the gas they owe to us, this could have a material adverse effect on our business, financial condition, results of operations or cash flows.

As of December 31, 2013, the amount of gas loaned out by us or owed to us due to gas imbalances was approximately 2.9 trillion British thermal units (TBtu). Assuming an average market price during December 2013 of $4.17 per million British thermal units (MMBtu), the market value of that gas was approximately $12.1 million. As of December 31, 2012, the amount of gas loaned out by us or owed to us due to gas imbalances was approximately 1.8 TBtu. Assuming an average market price during December 2012 of $3.32 per MMBtu, the market value of this gas at December 31, 2012, would have been approximately $6.0 million.

Although nearly all of our customers pay for our services on a timely basis, we actively monitor the credit exposure to our customers. We include in our ongoing assessments amounts due pursuant to services we render plus the value of any gas we have lent to a customer through no-notice or PAL services and the value of gas due to us under a transportation imbalance. Our natural gas pipeline tariffs contain language that allow us to require a customer that does not meet certain credit criteria to provide cash collateral, post a letter of credit or provide a guarantee from a credit-worthy entity in an amount equaling up to three months of capacity reservation charges. For certain agreements, we have included contractual provisions that require additional credit support should the credit ratings of those customers fall below investment grade.

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Boardwalk GP, LLC

We have audited the accompanying balance sheets of Gulf South Pipeline Company, LP (the “Partnership”) as of December 31, 2013 and 2012, and the related statements of income, comprehensive income, cash flows, and changes in partner's capital for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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. The Company is not required to have, nor were we engaged to perform, an audit of its 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 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulf South Pipeline Company, LP as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Houston, Texas

March 10, 2014

GULF SOUTH PIPELINE COMPANY, LP

BALANCE SHEETS

(Millions)



	December 31,
ASSETS	2013		2012
Current Assets:
Cash	$	1.1	$	0.1
Receivables:
Trade, net		29.5		38.0
Affiliates		8.9		5.9
Other		7.0		2.8
Gas receivables:
Transportation		4.2		6.5
Transportation - affiliates		2.0		0.7
Advances to affiliates		192.6		—
Gas stored underground		0.3		0.3
Prepayments		4.6		6.1
Other current assets		2.0		1.3
Total current assets		252.2		61.7

Property, Plant and Equipment:
Natural gas transmission and other plant		3,342.5		3,266.6
Construction work in progress		109.6		72.4
Property, plant and equipment, gross		3,452.1		3,339.0
Less-accumulated depreciation and amortization		707.1		602.1
Property, plant and equipment, net		2,745.0		2,736.9

Other Assets:
Gas stored underground		2.3		9.1
Advances to affiliates		—		101.0
Other		5.5		9.9
Total other assets		7.8		120.0

Total Assets	$	3,005.0	$	2,918.6

The accompanying notes are an integral part of these financial statements.

GULF SOUTH PIPELINE COMPANY, LP

BALANCE SHEETS

(Millions)



	December 31,
LIABILITIES AND PARTNER'S CAPITAL	2013			2012
Current Liabilities:
Payables:
Trade	$	26.4		$	31.3
Affiliates		2.5			1.1
Other		1.3			2.7
Gas Payables:
Transportation		5.5			7.2
Transportation – affiliates		6.8			2.7
Storage		—			3.4
Accrued taxes, other		19.3			17.0
Accrued interest		12.8			12.8
Accrued payroll and employee benefits		14.5			11.1
Deferred income		7.6			16.5
Other current liabilities		14.0			12.9
Total current liabilities		110.7			118.7

Long-term debt		846.3			845.5

Other Liabilities and Deferred Credits:
Asset retirement obligation		17.8			13.8
Other		13.0			12.5
Total other liabilities and deferred credits		30.8			26.3

Commitments and Contingencies

Partner's Capital:
Partner's capital		2,022.7			1,934.5
Accumulated other comprehensive loss		(5.5	)		(6.4	)
Total partner's capital		2,017.2			1,928.1
Total Liabilities and Partner's Capital	$	3,005.0		$	2,918.6

The accompanying notes are an integral part of these financial statements.

GULF SOUTH PIPELINE COMPANY, LP

STATEMENTS OF INCOME

(Millions)



	For the Year Ended December 31,
	2013			2012			2011
Operating Revenues:
Transportation	$	348.6		$	387.1		$	421.2
Transportation - affiliates		75.9			75.0			81.2
Parking and lending		19.9			24.6			9.5
Parking and lending - affiliates		0.1			—			0.8
Gas storage		17.6			24.5			27.0
Other		6.6			6.0			9.4
Total operating revenues		468.7			517.2			549.1

Operating Costs and Expenses:
Fuel and transportation		55.8			55.8			74.3
Fuel and transportation - affiliates		12.6			14.8			17.4
Operation and maintenance		83.6			86.3			99.6
Administrative and general		50.0			51.1			62.1
Depreciation and amortization		109.4			106.4			105.7
Asset impairment		3.6			6.3			9.2
Net gain on sale of operating assets		(16.6	)		(0.6	)		—
Taxes other than income taxes		41.7			41.6			41.7
Total operating costs and expenses		340.1			361.7			410.0

Operating income		128.6			155.5			139.1

Other Deductions (Income):
Interest expense		42.8			47.6			44.4
Interest (income) expense - affiliates		(1.9	)		(1.5	)		—
Interest income		(0.5	)		(0.7	)		(0.4	)
Miscellaneous other income, net		—			—			(0.2	)
Total other deductions		40.4			45.4			43.8

Net Income	$	88.2		$	110.1		$	95.3

The accompanying notes are an integral part of these financial statements.

GULF SOUTH PIPELINE COMPANY, LP

STATEMENTS OF COMPREHENSIVE INCOME

(Millions)



	For the Year Ended December 31,
	2013			2012			2011
Net income	$	88.2		$	110.1		$	95.3
Other comprehensive income (loss):
(Loss) gain on cash flow hedges	(0.1		)	(6.6		)	1.9
Reclassification adjustment transferred to Net Income from cash flow hedges	1.0			0.2			(1.5		)
Total Comprehensive Income	$	89.1		$	103.7		$	95.7

The accompanying notes are an integral part of these financial statements.

GULF SOUTH PIPELINE COMPANY, LP

STATEMENTS OF CASH FLOWS

(Millions)



	For the Year Ended December 31,
	2013			2012			2011
OPERATING ACTIVITIES:
Net income	$	88.2		$	110.1		$	95.3
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	109.4			106.4			105.7
Amortization of deferred costs	0.9			1.1			1.0
Asset impairment	3.6			6.3			9.2
Storage gas loss	—			—			3.7
Net gain on sale of operating assets	(16.6		)	(0.6		)	—
Changes in operating assets and liabilities:
Trade and other receivables	1.1			1.1			(7.7		)
Gas receivables and storage assets	9.2			(1.9		)	21.0
Other assets	(1.6		)	(3.2		)	2.1
Affiliates, net	1.0			0.7			(1.7		)
Trade and other payables	(7.4		)	(1.9		)	(0.4		)
Gas payables	(3.7		)	11.2			(14.0		)
Accrued liabilities	4.4			(2.9		)	0.9
Other liabilities	(9.8		)	6.8			1.1
Net cash provided by operating activities	178.7			233.2			216.2
INVESTING ACTIVITIES:
Capital expenditures	(112.8		)	(54.3		)	(120.0		)
Proceeds from sale of operating assets	25.3			1.9			4.9
Proceeds from insurance and other recoveries	1.4			6.1			5.3
Advances to affiliates	(91.6		)	(29.8		)	(71.2		)
Net cash used in investing activities	(177.7		)	(76.1		)	(181.0		)
FINANCING ACTIVITIES:
Proceeds from long-term debt, net of issuance costs	—			296.5			—
Repayment of borrowings from long-term debt	—			(225.0		)	—
Proceeds from borrowings on revolving credit agreement	—			265.0			—
Repayment of borrowings on revolving credit agreement	—			(493.5		)	—
Advances from affiliates	—			—			(37.2		)
Net cash used in financing activities	—			(157.0		)	(37.2		)
Increase (decrease) in cash	1.0			0.1			(2.0		)
Cash at beginning of period	0.1			—			2.0
Cash at end of period	$	1.1		$	0.1		$	—

The accompanying notes are an integral part of these financial statements.

GULF SOUTH PIPELINE COMPANY, LP

STATEMENTS OF CHANGES IN PARTNER’S CAPITAL

(Millions)



	Partner's Capital			Accumulated Other Comprehensive Income (Loss)			Total Partner's Capital
Balance January 1, 2011	$	1,774.4		(0.4		)	1,774.0
Add (deduct):
Net income	95.3			—			95.3
Distribution of assets	(14.7		)	—			(14.7		)
Other comprehensive gain	—			0.4			0.4
Balance December 31, 2011	1,855.0			—			1,855.0
Add (deduct):
Net income	110.1			—			110.1
Distribution of assets	(30.6		)	—			(30.6		)
Other comprehensive loss	—			(6.4		)	(6.4		)
Balance December 31, 2012	1,934.5			(6.4		)	1,928.1
Add (deduct):
Net income	88.2			—			88.2
Other comprehensive gain	—			0.9			0.9
Balance December 31, 2013	$	2,022.7		$	(5.5	)	$	2,017.2

The accompanying notes are an integral part of these financial statements.

GULF SOUTH PIPELINE COMPANY, LP

NOTES TO FINANCIAL STATEMENTS

Note 1: Corporate Structure

Gulf South Pipeline Company, LP (Gulf South) is a wholly-owned subsidiary of Boardwalk Pipelines, LP (Boardwalk Pipelines), which is a wholly-owned subsidiary of Boardwalk Pipeline Partners, LP (Boardwalk Pipeline Partners). Boardwalk Pipeline Partners is a publicly-traded Delaware limited partnership formed in 2005. Loews Corporation (Loews) owns the general partner and the majority of the limited partnership units of Boardwalk Pipeline Partners.

Basis of Presentation

The accompanying financial statements of Gulf South were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

Certain amounts reported within Total operating costs and expenses in the Statements of Income for the 2012 and 2011 periods have been reclassified to conform to the current presentation. The effect of the reclassification increased Operation and maintenance expenses and decreased Net gain on sale of operating assets by $1.0 million and $6.2 million for the years ended December 31, 2012 and 2011, with no impact on Total operating costs and expenses, Operating income or Net Income. Additionally, interest expense had been reported net of interest income in the 2012 and 2011 reporting periods. In order to conform to the current presentation, $0.7 million and $0.4 million of interest income for the years ended December 31, 2012 and 2011, have been reclassified from interest expense to interest income.

Note 2: Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities and the fair values of certain items. Gulf South bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.

Regulatory Accounting

Gulf South is regulated by the Federal Energy Regulatory Commission (FERC). When certain criteria are met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates (regulatory accounting). Regulatory accounting is not applicable to Gulf South because competition in its market area has resulted in discounts from the maximum allowable cost based rates being granted to customers and certain services provided by Gulf South are priced using market-based rates.

Fair Value Measurements

Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances. Gulf South uses fair value measurements to record derivatives, asset retirement obligations and impairments. Fair value measurements are also used to report fair values for certain items contained in this Report. Gulf South considers any transfers between levels within the fair value hierarchy to have occurred at the beginning of a quarterly reporting

period. Gulf South did not recognize any transfers between Level 1 and Level 2 of the fair value hierarchy and did not change its valuation techniques or inputs during the years ended December 31, 2013 and 2012.

Notes 4 and 8 contain more information regarding fair value measurements.

Cash

Cash includes demand deposits with banks or other financial institutions. Gulf South had no restricted cash at December 31, 2013 and 2012.

Cash Management

Gulf South participates in a cash management program to the extent it is permitted under FERC regulations. Under the cash management program, depending on whether Gulf South has short-term cash surpluses or cash requirements, Boardwalk Pipelines either provides cash to it or Gulf South provides cash to Boardwalk Pipelines. The transactions are represented by demand notes and are stated at historical carrying amounts. Interest income and expense is recognized on an accrual basis when collection is reasonably assured. Amounts expected to be collected or repaid within one year of the Balance Sheet date are classified as current, otherwise the amounts are classified as long-term. The interest rate on intercompany demand notes is London Interbank Offered Rate (LIBOR) plus one percent and is adjusted every three months.

Trade and Other Receivables

Trade and other receivables are stated at their historical carrying amount, net of allowances for doubtful accounts. Gulf South establishes an allowance for doubtful accounts on a case-by-case basis when it believes the required payment of specific amounts owed is unlikely to occur. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise unrealizable.

Gas Stored Underground and Gas Receivables and Payables

Gulf South has underground gas in storage which is utilized for system management and operational balancing, as well as for services including firm and interruptible storage associated with certain no-notice and parking and lending (PAL) services. Gas stored underground includes the historical cost of natural gas volumes owned by Gulf South, at times reduced by certain operational encroachments upon that gas. Current gas stored underground represents net retained fuel remaining after providing transportation and storage services which is available for resale and is valued at the lower of weighted-average cost or market.

Gulf South provides storage services whereby it stores gas on behalf of customers and also periodically holds customer gas under PAL services. Since the customers retain title to the gas held by Gulf South in providing these services, Gulf South does not record the related gas on its balance sheet. Gulf South also periodically lends gas to customers under PAL services. Note 9 contains more information related to Gulf South’s gas loaned to customers.

In the course of providing transportation and storage services to customers, Gulf South may receive different quantities of gas from shippers and operators than the quantities delivered on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are settled in cash or the receipt or delivery of gas in the future. Settlement of imbalances requires agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. The gas receivables and payables are valued at market price.

Materials and Supplies

Materials and supplies are carried at average cost and are included in Other Assets on the Balance Sheets. Gulf South expects its materials and supplies to be used for capital projects related to its property, plant and equipment and for future growth projects.

Property, Plant and Equipment (PPE) and Repair and Maintenance Costs

PPE is recorded at its original cost of construction or fair value of assets purchased. Construction costs and expenditures for major renewals and improvements which extend the lives of the respective assets are capitalized. Construction work in progress is included in the financial statements as a component of PPE. All repair and maintenance costs are expensed as incurred.

Gulf South depreciates assets using the straight-line method of depreciation over the estimated useful lives of the assets, which range from 3 to 35 years. The ordinary sale or retirement of PPE for these assets could result in a gain or loss. Note 5 contains more information regarding Gulf South’s PPE.

Impairment of Long-lived Assets

Gulf South evaluates its long-lived assets for impairment when, in management’s judgment, events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the remaining economic useful life of the asset is compared to the carrying amount of the asset to determine whether an impairment has occurred. If an impairment of the carrying amount has occurred, the amount of impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss to the extent that the carrying amount exceeds the estimated fair value.

Capitalized Interest

Capitalized interest represents the cost of borrowed funds used to finance construction activities. Capitalized interest is recognized as a reduction to Interest expense. Capitalized interest for the years ended December 31, 2013, 2012 and 2011 was $2.3 million, $1.0 million and $1.9 million.

Income Taxes

Gulf South is not a taxable entity for federal income tax purposes. As such, it does not directly pay federal income tax. Gulf South’s taxable income or loss, which may vary substantially from the net income or loss reported in the Statements of Income, is includable in the federal income tax returns of each partner of Boardwalk Pipeline Partners. The aggregate difference in the basis of Gulf South’s net assets for financial and income tax purposes cannot be readily determined as Gulf South does not have access to the information about each partner’s tax attributes related to Boardwalk Pipeline Partners. There was no provision for income taxes or deferred tax assets and liabilities for the years ended December 31, 2013, 2012 and 2011. Gulf South’s tax years 2010 through 2013 remain subject to examination by the Internal Revenue Service and the states in which it operates.

Revenue Recognition

The maximum rates that may be charged by Gulf South for its services are established through FERC’s cost-based rate-making process; however, rates charged by Gulf South may be less than those allowed by FERC. Revenues from transportation and storage of gas are recognized in the period the service is provided based on contractual terms and the related volumes transported or stored. In connection with some PAL and interruptible storage service agreements, cash is received at inception of the service period resulting in the recording of deferred revenues which are recognized in revenues over the period the services are provided. At December 31, 2013 and 2012, Gulf South had deferred revenues of $7.6 million and $16.5 million related to PAL and interruptible storage services. The deferred revenues related to PAL and interruptible storage services at December 31, 2013, will be recognized in 2014 and 2015.

Retained fuel is recognized in revenues at market prices in the month of retention. The related fuel consumed in providing transportation services is recorded in Fuel and transportation expenses on the Statements of Income at market prices in the month consumed. In some cases, customers may elect to pay cash for the cost of fuel used in providing transportation services instead of having fuel retained in-kind. Retained fuel included in Transportation revenues on the Statements of Income for the years ended December 31, 2013, 2012 and 2011 was $48.1 million, $46.2 million and $70.0 million.

Under FERC regulations, certain revenues that Gulf South collects may be subject to possible refunds to their customers. Accordingly, during a rate case, estimates of rate refund liabilities are recorded considering regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. At December 31, 2013 and 2012, there were no liabilities for any open rate case recorded on the Balance Sheets.

Asset Retirement Obligations

The accounting requirements for existing legal obligations associated with the future retirement of long-lived assets require entities to record the fair value of a liability for an asset retirement obligation in the period during which the liability is incurred. The liability is initially recognized at fair value and is increased with the passage of time as accretion expense is recorded, until the liability is ultimately settled. The accretion expense is included within Operation and maintenance costs within the Statements of Income. An amount corresponding to the amount of the initial liability is capitalized as part of the carrying amount of the related long-lived asset and depreciated over the useful life of that asset. Note 6 contains more information regarding Gulf South’s asset retirement obligations.

Environmental Liabilities

Gulf South records environmental liabilities based on management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these environmental matters.

Note 3 contains more information regarding Gulf South’s environmental liabilities.

Derivative Financial Instruments

Gulf South use futures, swaps, and option contracts (collectively, derivatives) to hedge exposure to various risks, including natural gas commodity and interest rate risk. The effective portion of the related unrealized gains and losses resulting from changes in fair values of the derivatives contracts designated as cash flow hedges are deferred as a component of accumulated other comprehensive income (AOCI). The deferred gains and losses are recognized in earnings when the hedged anticipated transactions affect earnings. Changes in fair value of derivatives that are not designated as cash flow hedges are recognized in earnings in the periods that those changes in fair value occur.

The changes in fair values of the derivatives designated as cash flow hedges are expected to, and do, have a high correlation to changes in value of the anticipated transactions. Each reporting period Gulf South measures the effectiveness of the cash flow hedge contracts. To the extent the changes in the fair values of the hedge contracts do not effectively offset the changes in the estimated cash flows of the anticipated transactions, the ineffective portion of the hedge contracts is currently recognized in earnings. If it becomes probable that the anticipated transactions will not occur, hedge accounting would be terminated and changes in the fair values of the associated derivative financial instruments would be recognized currently in earnings. Gulf South did not discontinue any cash flow hedges during the years ended December 31, 2013 and 2012.

The effective component of gains and losses resulting from changes in fair values of the derivatives designated as cash flow hedges are deferred as a component of AOCI. The deferred gains and losses associated with the anticipated operational sale of gas reported as current Gas stored underground are recognized in operating revenues when the anticipated transactions affect earnings. In situations where continued reporting of a loss in AOCI would result in recognition of a future loss on the combination of the derivative and the hedged transaction, the loss is required to be immediately recognized in earnings for the amount that is not expected to be recovered. No such losses were recognized in the years ended December 31, 2013, 2012, and 2011.

Note 4 contains more information regarding Gulf South’s derivative financial instruments.

Note 3: Commitments and Contingencies

Legal Proceedings and Settlements

Gulf South is party to various legal actions arising in the normal course of business. Management believes the disposition of these outstanding legal actions will not have a material impact on Gulf South's financial condition, results of operations or cash flows.

Whistler Junction Matter

Gulf South and several other defendants, including Mobile Gas Service Corporation (MGSC), have been named as defendants in nine lawsuits, including one purported class action suit, commenced by multiple plaintiffs in the Circuit Court of Mobile County, Alabama. The plaintiffs seek unspecified damages for personal injury and property damage related to an alleged release of mercaptan at the Whistler Junction facilities in Eight Mile, Alabama. Gulf South delivers natural gas to MGSC, the local distribution company for that region, at Whistler Junction where MGSC odorizes the gas prior to delivery to end user customers by injecting mercaptan into the gas stream, as required by law. The cases are: Parker, et al. v. MGSC, et al. (Case No. CV-12-900711), Crum, et al. v. MGSC, et al. (Case No. CV-12-901057), Austin, et al. v. MGSC, et al. (Case No. CV-12-901133), Moore, et al. v. MGSC, et al. (Case No. CV-12-901471), Davis, et al. v. MGSC, et al. (Case No. CV-12-901490), Joel G. Reed, et al. v. MGSC, et al. (Case No. CV-2013-922265), The Housing Authority of the City of Prichard, Alabama v. MGSC, et al. (Case No. CV-2013-901002), Robert Evans, et al. v. MGSC, et al. (Case No. CV-2013-902627), and Devin Nobles, et al. v. MGSC, et al. (Case No. CV-2013-902786). Gulf South has denied liability. Gulf South has demanded that MGSC indemnify Gulf South against all liability related to these matters pursuant to a right-of-way agreement between Gulf South and MGSC, and has filed cross-claims against MGSC for any such liability. MGSC has also filed cross-claims against Gulf South seeking indemnity and other relief from Gulf South.

Southeast Louisiana Flood Protection Litigation

Gulf South and Boardwalk Pipeline Partners, along with approximately 100 other energy companies operating in Southern Louisiana, have been named as defendants in a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) by the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (Flood Protection Authority). The case was filed in state court, but was removed to the United States District Court for the Eastern District of New Orleans. The plaintiff has moved for remand back to state court, which motion is being briefed, and thus pending. The lawsuit claims include negligence, strict liability, public nuisance, private nuisance, breach of contract, and breach of the natural servitude of drain against the defendants, alleging that the defendants’ drilling, dredging, pipeline and industrial operations since the 1930s have caused increased storm surge risk, increased flood protection costs and unspecified damages to the Flood Protection Authority. In addition to attorney fees and unspecified monetary damages, the lawsuit seeks abatement and restoration of the coastal lands, including backfilling and revegetating of canals dredged and used by the defendants, and abatement and restoration activities such as wetlands creation, reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, bank stabilization, and ridge restoration.

The outcome of these cases cannot be predicted at this time; however, based on the facts and circumstances presently known, in the opinion of management, these cases will not be material to Gulf South's financial condition, results of operations or cash flows.

Environmental and Safety Matters

Gulf South is subject to federal, state, and local environmental laws and regulations in connection with the operation and remediation of various operating sites. As of December 31, 2013, and 2012, Gulf South had an accrued liability of approximately $5.3 million and $6.1 million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury, groundwater protection measures and other costs. The liability represents management’s estimate of the undiscounted future obligations based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these matters. The related expenditures are expected to occur over the next eight years. As of December 31, 2013, and 2012, approximately $1.2 million and $1.4 million were recorded in Other current liabilities and approximately $4.1 million and $4.7 million were recorded in Other Liabilities and Deferred Credits.

Clean Air Act

Gulf South’s pipelines are subject to the Clean Air Act, as amended, (CAA) and the CAA Amendments of 1990, as amended, (Amendments) which added significant provisions to the CAA. The Amendments require the Environmental Protection Agency (EPA) to promulgate new regulations pertaining to mobile sources, air toxics, areas of ozone non-attainment, greenhouse gases and regulations affecting reciprocating engines subject to Maximum Achievable Control Technology (MACT). Gulf South does not operate any facilities in areas affected by non-attainment requirements for the current ozone standard (8-hour ozone standard). If the EPA designates additional new non-attainment areas or promulgates new air regulations where Gulf South operates, the cost of additions to PPE is expected to increase. Gulf South has assessed the impact of the CAA on its facilities and does not believe compliance with these regulations will have a material impact on its financial condition, results of operations or cash flows.

In 2008, the EPA adopted regulations lowering the 8-hour ozone standard relevant to non-attainment areas. Under the regulations, new non-attainment areas were identified in April 2012, which did not include any of Gulf South’s facilities. The 8-

hour ozone standard is due for review by the EPA with final rulemaking expected to be completed in 2014. Revisions to the regulation could lower the 8-hour ozone standard set in 2008 and include a compliance deadline between 2017 and 2031. Gulf South continues to monitor this regulation relative to potentially impacted facilities.

Gulf South is required to file annual reports with the EPA regarding greenhouse gas emissions from its compressor stations, pursuant to final rules issued by the EPA regarding the reporting of greenhouse gas emissions from sources in the U.S. that annually emit 25,000 or more metric tons of greenhouse gases, including carbon dioxide, methane and others. Additionally, Gulf South is required to conduct periodic and various facility surveys across its entire system to comply with the EPA's greenhouse gas emission calculations and reporting regulations. Some states have also adopted laws regulating greenhouse gas emissions, although none of the states in which Gulf South operates have adopted such laws. The federal rules and determinations regarding greenhouse gas emissions have not had, and are not expected to have, a material effect on Gulf South's financial condition, results of operations or cash flows.

Lease Commitments

Gulf South has various operating lease commitments extending through the year 2018 generally covering office space and equipment rentals. Total lease expense for the years ended December 31, 2013, 2012 and 2011 were approximately $2.5 million, $3.8 million and $3.7 million. The following table summarizes minimum future commitments related to these items at December 31, 2013 (in millions):



2014	$	3.5
2015	3.4
2016	3.3
2017	1.4
2018	0.4
Thereafter	—
Total	$	12.0

Commitments for Construction

Gulf South’s future capital commitments are comprised of binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements. The commitments as of December 31, 2013, were approximately $51.2 million, all of which are expected to be settled in 2014.

Pipeline Capacity Agreements

Gulf South has entered into pipeline capacity agreements with third-party pipelines that allow it to transport gas to off-system markets on behalf of customers. Gulf South incurred expenses of $6.3 million, $6.5 million and $7.4 million related to pipeline capacity agreements for the years ended December 31, 2013, 2012 and 2011. The future commitments related to pipeline capacity agreements as of December 31, 2013, were (in millions):



2014	$	6.2
2015	6.2
2016	6.2
2017	6.1
2018	2.0
Thereafter	—
Total	$	26.7

Note 4: Fair Value Measurements, Derivatives and Other Comprehensive Income (OCI)

The table below identifies Gulf South's assets and liabilities that were recorded at fair value at December 31, 2013 (in millions):



			Fair Value Measurements at December 31, 2013
	December 31, 2013		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total Gains (losses) for the year ended December 31, 2013
Recurring fair value measurements - Assets
Derivatives
Commodity contracts	$	0.5	$	—	$	0.5	$	—	$	—

Recurring fair value measurements - Liabilities
Derivatives
Commodity contracts	$	0.3	$	—	$	0.3	$	—	$	—

The table below identifies Gulf South's assets that were recorded at fair value at December 31, 2012. There were no liabilities recorded at fair value at December 31, 2012 (in millions):



			Fair Value Measurements at December 31, 2012
	December 31, 2012		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total Gains (losses) for the year ended December 31, 2012
Nonrecurring fair value measurements - Assets
Assets to be abandoned ⁽¹⁾	$	—	$	—	$	—	$	—	$	(3.5	)

(1)

In 2012, Gulf South determined that it would retire a number of small-diameter pipeline assets and recorded an asset impairment charge of $5.2 million comprised of the carrying amount of the assets of $2.4 million and amounts related to asset retirement obligations for the assets. Additionally, in 2012, Gulf South recorded an asset impairment charge when it determined that it would retire a turbine associated with one of its compressor stations which had a carrying amount of $1.1 million.

Derivatives

Gulf South uses futures, swaps and option contracts (collectively, derivatives) to hedge exposure to natural gas commodity price risk related to the future operational sales of natural gas and cash for fuel reimbursement where customers pay cash for the cost of fuel used in providing transportation services as opposed to having fuel retained in kind. At December 31, 2012, this price risk exposure includes approximately $0.3 million of gas stored underground which Gulf South owned and carried on its balance sheet as current Gas stored underground. At December 31, 2013, approximately 0.9 billion cubic feet (Bcf) of anticipated future sales of natural gas and cash for fuel reimbursement were hedged with derivatives having settlement dates in 2014. The derivatives qualify for cash flow hedge accounting and are designated as such. Gulf South's natural gas derivatives are reported at fair value based on New York Mercantile Exchange (NYMEX) quotes for natural gas futures and options. The NYMEX quotes are deemed to be observable inputs in an active market for similar assets and liabilities and are considered Level 2 inputs for purposes of fair value disclosures.

In 2012, Gulf South entered into a Treasury rate lock for notional amounts of $300.0 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates. The Treasury rate lock was designated as a cash flow hedge. Gulf South settled the rate lock concurrently with the issuance of the 10-year notes described in Note 7 and paid the counterparties approximately $6.8 million. The losses were deferred as a component of Accumulated other comprehensive loss (AOCI) and will be amortized to interest expense over the 10-year terms of the notes.

Gulf South had no outstanding cash flow hedges at December 31, 2012. The fair values of derivatives existing as of December 31, 2013 were included in the following captions in the Balance Sheets (in millions):

Derivative Assets

Derivative Liabilities

December 31,

2013

December 31,

2012

December 31,

2013

December 31,

2012

Balance sheet

location

Balance

sheet location

Balance sheet

location

Balance sheet

location

Derivatives designated as hedging instruments

Commodity contracts

Other current assets

0.5

Other current assets

—

Other current liabilities

0.3

Other current liabilities

—

Gulf South's AOCI as of December 31, 2013 and 2012 was $5.5 million and $6.4 million, all of which related to losses on cash flow hedges. Gulf South estimates that approximately $0.5 million of net losses reported in AOCI as of December 31, 2013 are expected to be reclassified into earnings within the next twelve months. The amount of gains and losses from cash flow hedges recognized in AOCI and reclassified into earnings in the Statements of Income for the year ended December 31, 2013, were (in millions):



	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)			Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in cash flow hedging relationship
Commodity contracts	$	(0.1	)	Operating revenues ⁽²⁾	$	(0.3	)	N/A	$	—
Interest rate contracts ⁽¹⁾	—			Interest expense	(0.7		)	N/A	—
	$	(0.1	)		$	(1.0	)		$	—


(1)	Related to amounts deferred in AOCI from Treasury rate locks used to hedge interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.


(2)	A $0.1 million loss was recorded as a reduction to Transportation revenues and a $0.2 million loss was recorded as a reduction to Other revenues for the year ended December 31,2013.

The amount of gains and losses from cash flow hedges recognized in AOCI and reclassified into earnings in the Statements of Income for the year ended December 31, 2012, were (in millions):



	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)			Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)			Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in cash flow hedging relationship
Commodity contracts	$	0.1		Operating revenues ⁽²⁾	$	0.2		N/A	$	—
Interest rate contracts ⁽¹⁾	(6.7		)	Interest expense	(0.4		)	N/A	—
	$	(6.6	)		$	(0.2	)		$	—


(1)	Related to amounts deferred in AOCI from Treasury rate locks used to hedge interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.


(2)	$0.2 million was recorded as a gain in Other revenues for the year ended December 31,2012.

The amount of gains and losses from cash flow hedges recognized in AOCI and reclassified into earnings in the Statements of Income for the year ended December 31, 2011, were (in millions):



	Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)		Location of gain/(loss) reclassified from AOCI into income (effective portion)	Amount of gain/(loss) reclassified from AOCI into income (effective portion)		Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)	Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in cash flow hedging relationship
Commodity contracts	$	1.9	Operating revenues ⁽¹⁾	$	1.5	N/A	$	—


(1)	A $1.1 million gain was recorded in Transportation revenues and a $0.4 million gain was recorded in Other revenues.

Gulf South has entered into master netting agreements to manage counterparty credit risk associated with its derivatives; however, it does not offset on its balance sheets fair value amounts recorded for derivative instruments under these agreements. At December 31, 2013, Gulf South's outstanding derivatives were with two counterparties, one of which was affiliated. The net receivable position with Gulf South's counterparties was $0.2 million as of December 31, 2013.

In accordance with the contracts governing Gulf South's derivatives, the counterparty or Gulf South may be required to post cash collateral when credit risk exceeds certain thresholds. The threshold for posting collateral with the counterparty varies based on the credit ratings of Gulf South or the counterparty. Based on credit ratings at December 31, 2013, Gulf South would be required to post cash collateral to the extent the fair value amount payable to the other party exceeds $10.0 million and the counterparty would be required to post cash collateral to the extent the fair value amount payable to Gulf South exceeds $25.0 million. Additionally, the outstanding derivative contracts contain ratings triggers which would require Gulf South to immediately post collateral in the form of cash or a letter of credit for the full value of any of the derivatives that are in a liability position if the subsidiary's credit rating were reduced below investment grade. At December 31, 2013 and 2012, Gulf South was not required to post any collateral nor did it hold any collateral associated with its outstanding derivatives.

Nonfinancial Assets and Liabilities

Gulf South evaluates long-lived assets for impairment when, in management's judgment, events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Refer to the fair value measurements table above for more information.

Financial Assets and Liabilities

The following methods and assumptions were used in estimating the fair value disclosure amounts for financial assets and liabilities:

Cash: For cash, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.

Advances to Affiliates: Advances to affiliates, which are represented by demand notes, earn a variable rate of interest, which is adjusted regularly to reflect current market conditions. Therefore, the carrying amount is a reasonable estimate of fair value. The interest rate on intercompany demand notes is LIBOR plus one percent and is adjusted every three months.

Long-Term Debt: The estimated fair value of Gulf South's publicly traded debt is based on quoted market prices at December 31, 2013. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at December 31, 2013 and 2012.

The carrying amount and estimated fair values of Gulf South's financial assets and liabilities which are not recorded at fair value on the Balance Sheets as of December 31, 2013 and 2012, were as follows (in millions):



As of December 31, 2013			Estimated Fair Value
Financial Assets	Carrying Amount		Level 1		Level 2		Level 3		Total
Cash	$	1.1	$	1.1	$	—	$	—	$	1.1
Advances to affiliates - current	192.6		—		192.6		—		192.6

Financial Liabilities
Long-term debt	$	846.3	$	—	$	889.7	$	—	$	889.7



As of December 31, 2012			Estimated Fair Value
Financial Assets	Carrying Amount		Level 1		Level 2		Level 3		Total
Cash	$	0.1	$	0.1	$	—	$	—	$	0.1
Advances to affiliates - noncurrent	101.0		—		101.0		—		101.0

Financial Liabilities
Long-term debt	$	845.5	$	—	$	930.4	$	—	$	930.4

Note 5: Property, Plant and Equipment (PPE)

The following table presents Gulf South’s PPE as of December 31, 2013 and 2012 (in millions):



Category	2013 Class Amount		Weighted-Average Useful Lives (Years)	2012 Class Amount		Weighted-Average Useful Lives (Years)
Depreciable plant:
Transmission	$	3,025.1	34	$	2,948.3	34
Storage	119.2		34	118.5		34
Gathering	64.2		20	65.6		20
General	89.5		8	87.1		8
Rights of way and other	18.7		35	18.7		35
Total utility depreciable plant	3,316.7		34	3,238.2		34

Non-depreciable:
Construction work in progress	109.6			72.4
Storage	16.7			19.3
Land	9.1			9.1
Total other	135.4			100.8

Total PPE	3,452.1			3,339.0
Less: accumulated depreciation	707.1			602.1

Total PPE, net	$	2,745.0		$	2,736.9

The non-depreciable assets were not included in the calculation of the weighted-average useful lives.

Gulf South holds undivided interests in certain assets, including the Bistineau storage facility of which Gulf South owns 92%, the Mobile Bay Pipeline of which Gulf South owns 64% and offshore and other assets, comprised of pipeline and gathering assets in which Gulf South holds various ownership interests. The proportionate share of investment associated with these interests has been recorded as PPE on the balance sheets. Gulf South records its portion of direct operating expenses associated with the assets in Operation and maintenance expense. The following table presents the gross PPE investment and related accumulated depreciation for Gulf South’s undivided interests as of December 31, 2013 and 2012 (in millions):



	2013				2012
	Gross PPE Investment		Accumulated Depreciation		Gross PPE Investment		Accumulated Depreciation
Bistineau storage	$	55.8	$	15.1	$	55.7	$	13.4
Mobile Bay Pipeline	11.1		3.1		11.1		2.8
Offshore and other assets	9.0		3.4		9.0		3.0
Total	$	75.9	$	21.6	$	75.8	$	19.2

Asset Dispositions and Impairment Charges

Gulf South recognized $3.6 million, $6.3 million and $9.2 million of asset impairment charges for the years ended December 31, 2013, 2012 and 2011. Refer to Note 4 or to Materials and Supplies below for more information.

In 2012, Gulf South transferred gathering and transmission pipeline with a carrying amount of $30.6 million to an affiliate. This transaction was accounted for as a non-cash distribution.

Gas Sales

For the year ended December 31, 2013, Gulf South recognized a gain of $17.0 million from the sale of approximately 5.0 Bcf of natural gas stored underground with a carrying amount of $2.6 million. The gas was sold as a result of a strategy to monetize storage base gas and provide capacity for additional parks of customer gas under PAL services.

Carthage Compressor Station Incident

In 2011, a fire occurred at one of Gulf South’s compressor stations near Carthage, Texas, which caused significant damage to the compressor building, the compressor units and related equipment housed in the building. In 2011, Gulf South recognized expenses of $5.0 million for the amounts of costs incurred which were subject to an insurance deductible and recorded a receivable of $8.8 million related to probable recoveries from insurance for expenses incurred that exceeded the deductible amount. Gulf South received a total of $11.7 million in insurance proceeds, of which $1.7 million and $1.2 million were recorded as a reduction in Operation and maintenance expense for the years ended December 31, 2013 and 2012.

Materials and Supplies

Gulf South holds materials and supplies comprised of pipe, valves, fittings and other materials to support its ongoing operations and for potential future growth projects. In 2011, Gulf South determined that a portion of the materials and supplies would not be used given the types of projects Gulf South would likely pursue under its growth strategy and the costs to carry and maintain the materials and recognized an impairment charge of $7.5 million to adjust the carrying amount of those materials and supplies to an estimated fair value of $1.8 million. The fair value of the materials was determined by obtaining information from brokers, resellers and distributors of these types of materials which are considered Level 3 inputs under the fair value hierarchy. The materials were subsequently sold, resulting in small net realized gains for the years ended December 31, 2013, 2012 and 2011. At December 31, 2013 and 2012, Gulf South held approximately $1.0 million and $5.7 million of materials and supplies which was reflected in Other Assets on the Balance Sheets.

Bistineau Storage Gas Loss

In 2011, Gulf South completed a series of tests to verify the quantity of gas stored at its Bistineau storage facility. These tests indicated that a gas loss of approximately 6.7 Bcf occurred at the facility. As a result, Gulf South recorded a charge to Fuel and transportation expense of $3.7 million to recognize the loss in base gas which had a carrying amount of $0.53 per MMBtu.

Note 6: Asset Retirement Obligations (ARO)

Gulf South has identified and recorded legal obligations associated with the abandonment of certain pipeline assets and offshore facilities as well as abatement of asbestos consisting of removal, transportation and disposal when removed from certain compressor stations and meter station buildings. Legal obligations exist for the main pipeline and certain other of Gulf South's assets; however, the fair value of the obligations cannot be determined because the lives of the assets are indefinite and therefore cash flows associated with retirement of the assets cannot be estimated with the degree of accuracy necessary to establish a liability for the obligations.

The following table summarizes the aggregate carrying amount of Gulf South’s ARO (in millions):



	2013			2012
Balance at beginning of year	$	17.7		$	14.9
Liabilities recorded	3.5			2.6
Liabilities settled	(0.7		)	(0.6		)
Accretion expense	0.9			0.8
Balance at end of year	21.4			17.7
Less: Current portion of asset retirement obligations	(3.6		)	(3.9		)
Long-term asset retirement obligations	$	17.8		$	13.8

Note 7: Financing

Long-Term Debt

The following table presents all long-term debt issues outstanding as of December 31, 2013 and 2012 (in millions):



	2013			2012
Notes :
5.05% Notes due 2015	$	275.0		$	275.0
6.30% Notes due 2017	275.0			275.0
4.00% Notes due 2022	300.0			300.0
Total notes	850.0			850.0
Revolving Credit Facility	—			—
	850.0			850.0
Less: unamortized debt discount	(3.7		)	(4.5		)
Total Long-Term Debt	$	846.3		$	845.5

Maturities of Gulf South’s long-term debt for the next five years and in total thereafter are as follows (in millions):



2014	$	—
2015	275.0
2016	—
2017	275.0
2018	—
Thereafter	300.0
Total long-term debt	$	850.0

Notes

As of December 31, 2013 and 2012, the weighted-average interest rate of Gulf South's notes was 5.33%. For the years ended December 31, 2013, 2012 and 2011, Gulf South completed the following debt issuance (in millions, except interest rates):

Date of

Issuance

Issuing Subsidiary

Amount of Issuance

Purchaser Discounts and Expenses

Net Proceeds

₍₁₎

Interest

Rate

Maturity Date

Interest Payable

June 2012

Gulf South

$300.0

3.5

$296.5

4.00

June 15, 2022

June 15 and December 15


(1)	The net proceeds of this offering were used to reduce borrowings under Gulf South’s revolving credit facility.

Gulf South’s notes are redeemable, in whole or in part, at Gulf South’s option at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes to be redeemed or a “make whole” redemption price based on the remaining scheduled payments of principal and interest discounted to the date of redemption at a rate equal to the Treasury rate plus 20 to 50 basis points depending upon the particular issue of notes, plus accrued and unpaid interest, if any. Other customary covenants apply, including those concerning events of default.

The indentures governing the notes have restrictive covenants which provide that, with certain exceptions, neither Gulf South nor any of its subsidiaries may create, assume or suffer to exist any lien upon any property to secure any indebtedness unless the debentures and notes shall be equally and ratably secured. All of Gulf South's debt obligations are unsecured. At December 31, 2013, Gulf South was in compliance with its debt covenants.

Redemption/Retirement of Notes

In August 2012, $225.0 million aggregate principal amount of 5.75% notes due 2012 at Gulf South matured and were retired in full. The retirement of this debt was financed through borrowings under the revolving credit facility.

Revolving Credit Facility

Boardwalk Pipelines has a revolving credit facility which has aggregate lending commitments of $1.0 billion, and for which Gulf South is a borrower under the revolving credit facility with a borrowing sub-limit of $200.0 million. Gulf South had no outstanding borrowings under the credit facility as of December 31, 2013 and 2012, and had an available borrowing capacity of $200.0 million.

Interest is determined, at Gulf South's election, by reference to (a) the base rate which is the highest of (1) the prime rate, (2) the federal funds rate plus 0.50%, and (3) the one month Eurodollar Rate plus 1.0%, plus an applicable margin, or (b) the London InterBank Offered Rate (LIBOR) plus an applicable margin. The applicable margin ranges from 0.00% to 0.875% for loans bearing interest tied to the base rate and ranges from 1.00% to 1.875% for loans bearing interest based on the LIBOR rate, in each case determined based on the individual borrower's credit rating from time to time. The Amended Credit Agreement also provides for a quarterly commitment fee charged on the average daily unused amount of the revolving credit facility ranging from 0.125% to 0.30% and determined based on the individual borrower's credit rating from time to time.

The credit facility contains various restrictive covenants and other usual and customary terms and conditions, including restrictions regarding the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the credit facility require Boardwalk Pipelines and its subsidiaries, including Gulf South, to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the credit agreement) measured for the previous twelve months of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following an acquisition. Boardwalk Pipelines and its subsidiaries, including Gulf South, were in compliance with all covenant requirements under the credit facility as of December 31, 2013.

Note 8: Employee Benefits

Defined Contribution Plans

Gulf South employees are provided retirement benefits under a defined contribution money purchase plan and a 401(k) plan. Costs related to the defined contribution plans were $4.8 million, $4.7 million and $4.5 million for the years ended December 31, 2013, 2012 and 2011.

Long-Term Incentive Compensation Plans

Boardwalk Pipeline Partners and its subsidiaries grant to selected employees long-term compensation awards under the Long-Term Incentive Plan (LTIP) and the Boardwalk Pipeline Partners Unit Appreciation Rights and Cash Bonus Plan (UAR and Cash Bonus Plan), and previously made grants under the Strategic Long-Term Incentive Plan (SLTIP). The following disclosures provide information regarding these plans, under which Gulf South received an allocation of expenses of $1.9 million, $2.1 million and $1.8 million during 2013, 2012 and 2011 related to these plans.

LTIP

Boardwalk Pipeline Partners reserved 3,525,000 units for grants of units, restricted units, unit options and unit appreciation rights to officers and directors of its general partner and for selected employees under the LTIP. Boardwalk Pipeline Partners has outstanding phantom common units (Phantom Common Units) which were granted under the plan. Each such grant: includes a tandem grant of Distribution Equivalent Rights (DERs); vests on the third anniversary of the grant date; and will be payable to the grantee in cash, but may be settled in common units at the discretion of Boardwalk Pipeline Partners’ Board of Directors, upon vesting in an amount equal to the sum of the fair market value of the units (as defined in the plan) that vest on the vesting date, less applicable taxes. The vested amount then credited to the grantee’s DER account is payable only in cash, less applicable taxes. The economic value of the Phantom Common Units is directly tied to the value of Boardwalk Pipeline Partners’ common units, but these awards do not confer any rights of ownership to the grantee. The fair value of the awards will be recognized ratably over the vesting period and remeasured each quarter until settlement based on the market price of Boardwalk Pipeline Partners’ common units and amounts credited under the DERs. Boardwalk Pipeline Partners and its subsidiaries have not made any grants of units, restricted units, unit options or unit appreciation rights under the plan.

A summary of the Phantom Common Units granted under the LTIP as of December 31, 2013 and 2012, and changes during the years ended December 31, 2013 and 2012, is presented below:



	Phantom Common Units		Total Fair Value (in millions)	Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2012 ⁽¹⁾	218,089	⁽²⁾	$5.3	2.9
Granted	22,814		0.6	2.4
Paid	(24,270)		(0.8)	—
Forfeited	(24,038)		—	—
Outstanding at December 31, 2012⁽¹⁾	192,595		4.7	2.0
Granted	220,808		5.7	2.8
Forfeited	(33,355)		—	—
Outstanding at December 31, 2013 ⁽¹⁾	380,048		$10.9	1.5


(1)	Represents fair value and remaining weighted-average vesting period of outstanding awards at the end of the period.


(2)	Includes 24,270 of Phantom Common Units with a total value of $0.8 million which vested on December 16, 2011 and were paid in cash on January 20, 2012.

The fair value of the awards at the date of grant was based on the closing market price of Boardwalk Pipeline Partners’ common units on or directly preceding the date of grant. The fair value of the awards at December 31, 2013 and 2012 was based on the closing market price of the common unit on those dates of $25.52 and $24.90 plus the accumulated value of the DERs. The fair value of the awards will be recognized ratably over the vesting period and remeasured each quarter until settlement in accordance with the treatment of awards classified as liabilities. Boardwalk Pipeline Partners recorded $3.2 million, $1.5 million and $0.3 million in Administrative and general expenses during 2013, 2012 and 2011 for the ratable recognition of the fair value of the Phantom Common Unit awards. The total estimated remaining unrecognized compensation expense related to the Phantom Common Units outstanding at December 31, 2013 and 2012, was $6.1 million and 3.1 million.

In 2013 and 2012, the general partner of Boardwalk Pipeline Partners purchased 7,484 and 2,000 of Boardwalk Pipeline Partners’ common units in the open market at a price of $26.72 and $27.24 per unit. These units were granted under the LTIP to the independent directors as part of their director compensation. At December 31, 2013, 3,506,224 units were available for grants under the LTIP.

UAR and Cash Bonus Plan

The UAR and Cash Bonus Plan provides for grants of unit appreciation rights (UARs) and cash bonuses (Long-Term Cash Bonuses) to selected employees of Boardwalk Pipeline Partners. As of December 31, 2013, there were no Long-Term Cash bonuses outstanding. Boardwalk Pipeline Partners recorded compensation expense of $0.5 million, $0.6 million and $0.5 million for the years ended December 31, 2013, 2012 and 20ll related to the Long-Term Cash bonuses.

The economic value of the UARs is tied to the value of Boardwalk Pipeline Partners’ common units, but these awards do not confer any rights of ownership to the grantee. Under the terms of the UAR and Cash Bonus Plan, after the expiration of a restricted period (vesting period) each awarded UAR would become vested and payable in cash to the extent the fair market value (as defined in the plan) of a common unit on such date exceeds the exercise price. Each UAR includes a feature whereby the exercise price is reduced by the amount of any cash distributions made by Boardwalk Pipeline Partners with respect to a common unit during the restricted period (DER Adjustment). Except in limited circumstances, upon termination of employment during the restricted period, any outstanding and unvested awards of UARs would be cancelled unpaid. The fair value of the UARs will be recognized ratably over the vesting period, and will be remeasured each quarter until settlement in accordance with the treatment of awards classified as liabilities.

A summary of the outstanding UARs granted under Boardwalk Pipeline Partners’ UAR and Cash Bonus Plan as of December 31, 2013 and 2012, and changes during 2013 and 2012 is presented below:



	UARs		Weighted Average Exercise Price		Total Fair Value (in millions)		Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2012 ⁽¹⁾	656,517		$	29.28	$	3.0	2.3
Forfeited	(83,638	)
Granted ⁽²⁾	6,786		26.46		—		2.7
Granted ⁽³⁾	26,082		27.90		0.1		2.2
Outstanding at December 31, 2012 ⁽¹⁾	605,747		29.18		1.7		1.4
Paid	(359,148	)
Forfeited	(61,400	)
Granted ⁽⁴⁾	293,809		27.57		1.8		2.8
Outstanding at December 31, 2013 ⁽¹⁾	479,008		$	27.47	$	1.9	1.5


(1)	Represents weighted-average exercise price, remaining weighted-average vesting period and total fair value of outstanding awards at the end of the period.


(2)	Represents the weighted-average exercise price and weighted-average vesting period of awards at grant date. The exercise price for each UAR granted was set at $26.46, the closing price of Boardwalk Pipeline Partners’ common units on the New York Stock Exchange on the grant date on March 31, 2012.


(3)	Represents the weighted-average exercise price and weighted-average vesting period of awards at grant date. The exercise price for each UAR granted was set at $27.90, the closing price of Boardwalk Pipeline Partners’ common units on the New York Stock Exchange on the grant date on September 30, 2012.


(4)	Represents the weighted-average exercise price and weighted-average vesting period of awards at grant date. The exercise price for each UAR granted was set at $27.57, the closing price of Boardwalk Pipeline Partners’ common units on the New York Stock Exchange on the grant date on February 7, 2013.

The fair value of the UARs were based on the computed value of a call on Boardwalk Pipeline Partners’ common units at the exercise price. The following assumptions were used as inputs to the Black-Scholes valuation model for grants made during 2013 and 2012:



	Grant Date Assumptions for Grants Made in 2013	Grant Date Assumptions for Grants Made in 2012
Expected life (years)	2.8	2.2-2.7
Risk free interest rate ⁽¹⁾	0.35%	0.29%-0.47%
Expected volatility ⁽²⁾	32%	31%-34%


(1)	Based on the U.S. Treasury yield curve corresponding to the remaining life of the UAR.


(2)	Based on the historical volatility of Boardwalk Pipeline Partners’ common units.

Boardwalk Pipeline Partners recorded compensation expense of $0.9 million, $0.3 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011, related to the UARs. As of December 31, 2013 and 2012, there was $0.9 million and $0.8 million of total unrecognized compensation cost related to the non-vested portion of the UARs.

SLTIP

The SLTIP provided for the issuance of up to 500 phantom general partner units (Phantom GP Units) to selected employees of Boardwalk Pipeline Partners and its subsidiaries. Boardwalk Pipeline Partners recorded $0.2 million, $2.3 million and $2.5 million in Administrative and general expenses during 2013, 2012 and 2011 for the ratable recognition of the fair value of the GP Phantom Unit awards. There are no GP Phantom Units outstanding at December 31, 2013, and no additional grants of Phantom GP Units are expected to be made under the SLTIP.

A summary of the status of Boardwalk Pipeline Partners’ SLTIP as of December 31, 2013 and 2012, and changes during the years ended December 31, 2013 and 2012, is presented below:



	Phantom GP Units	Total Fair Value (in millions)			Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2012 ⁽¹⁾	262.5	$	12.4		0.8
Paid	(116.5)	(5.0		)	—
Forfeited	(1.0)	—			—
Outstanding at December 31, 2012 ⁽¹⁾	145.0	6.9			0.2
Paid	(145.0)	(7.2		)	—
Outstanding at December 31, 2013 ⁽¹⁾	—	$	—		—


(1)	Represents fair value and remaining weighted-average vesting period of outstanding awards at the end of the period.

Note 9: Credit Risk

Major Customers

Operating revenues received from Gulf South’s major non-affiliated customer (in millions) and the percentage of total operating revenues earned from that customer was:



	For the Year Ended December 31,
	2013			2012			2011
	Revenue		%	Revenue		%	Revenue		%
EOG Resources, Inc.	$	50.9	11%	$	51.3	10%	$	52.3	10%

Gas Loaned to Customers

Natural gas price volatility can cause changes in credit risk related to gas loaned to customers. As of December 31, 2013, the amount of gas owed to Gulf South due to gas imbalances and gas loaned under PAL agreements was approximately 2.9 TBtu. Assuming an average market price during December 2013 of $4.17 per MMBtu, the market value of that gas was approximately $12.1 million. As of December 31, 2012, the amount of gas owed to Gulf South due to gas imbalances and gas loaned under PAL agreements was approximately 1.8 TBtu. Assuming an average market price during December 2012 of $3.32 per MMBtu, the market value of this gas at December 31, 2012, would have been approximately $6.0 million. If any significant customer should have credit or financial problems resulting in a delay or failure to repay the gas owed to Gulf South, it could have a material adverse effect on Gulf South’s financial condition, results of operations or cash flows.

Note 10: Related Party Transactions

Gulf South makes advances to or receives advances from Boardwalk Pipelines under the cash management program described in Note 2. At December 31, 2013 and 2012, advances due to Gulf South from Boardwalk Pipelines totaled $192.6 million which was reflected as a current asset and $101.0 million which was reflected as non-current. The advances are represented by demand notes. The interest rate on intercompany demand notes is compounded monthly based on LIBOR plus one percent and is adjusted quarterly.

Boardwalk Pipelines provides certain management and other services to Gulf South. For the years ended December 31, 2013, 2012 and 2011, Boardwalk Pipelines charged Gulf South $7.3 million, $7.2 million, and $12.6 million for these services. These costs were based on actual costs incurred and allocated to Gulf South based on the modified Massachusetts formula, which utilizes three components as the basis for allocation: 1) the gross book value of property, plant and equipment; 2) operating revenues; and 3) labor costs. This allocation method has been consistently applied for all periods presented. Management believes the assumptions and allocations were made on a reasonable basis. Due to the nature of the shared costs, it is not practicable to estimate what the costs would have been had Gulf South operated on a stand-alone basis.

In 2012 and 2011, Gulf South transferred PPE with a carrying amount of $30.6 million and $14.7 million, which transfers occurred by a non-cash distribution to Boardwalk Pipelines.

Amounts applicable to transportation and storage services with affiliates, including fuel costs, shown on Gulf South's Statements of Income are as follows (in millions):



	For the Year Ended December 31,
Affiliate:	2013		2012		2011
Gulf Crossing:
Transportation revenue - affiliates	$	73.1	$	71.9	$	73.2
Texas Gas:
Transportation revenue - affiliates	$	2.8	$	3.1	$	2.9
Parking and lending revenue - affiliates	$	—	$	—	$	0.8
Fuel and transportation expense - affiliates	$	12.4	$	13.5	$	17.4
Field Services:
Transportation revenue - affiliates	$	—	$	—	$	5.1
Petal Gas Storage, LLC:
Parking and lending revenue - affiliates	$	0.1	$	—	$	—
Fuel and transportation expense - affiliates	$	0.2	$	1.3	$	—

Note 11: Supplemental Disclosure of Cash Flow Information (in millions):



	For the Year Ended December 31,
	2013		2012		2011
Cash paid during the period for:
Interest (net of amount capitalized) ⁽¹⁾	$	40.9	$	57.0	$	43.3
Income taxes, net	$	0.1	$	0.1	$	0.1
Non-cash adjustments:
Accounts payable and PPE	$	16.1	$	14.3	$	13.6
Distribution of assets	$	—	$	30.6	$	14.7


(1)	The 2012 period includes payments of $6.8 million related to the settlements of interest rate derivatives.

Note 12: Selected Quarterly Financial Data (Unaudited)



	2013
	For the Quarter Ended:
	December 31		September 30		June 30		March 31
Operating revenues	$	115.6	$	110.5	$	113.9	$	128.7
Operating expenses	91.0		86.2		72.6		90.3
Operating income	24.6		24.3		41.3		38.4
Interest expense, net	9.6		10.0		10.2		10.6
Net income	$	15.0	$	14.3	$	31.1	$	27.8



	2012
	For the Quarter Ended:
	December 31		September 30		June 30		March 31
Operating revenues	$	134.5	$	122.8	$	124.8	$	135.1
Operating expenses	95.0		87.1		87.8		91.8
Operating income	39.5		35.7		37.0		43.3
Interest expense, net	10.4		12.1		11.9		11.0
Net income	$	29.1	$	23.6	$	25.1	$	32.3

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

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2013, at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2013, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.

There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (1992). Based on this assessment, our management believes that, as of December 31, 2013, our internal control over financial reporting was effective.

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Omitted in accordance with General Instruction I to Form 10-K.

Item 11. Executive Compensation

Omitted in accordance with General Instruction I to Form 10-K.

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

Omitted in accordance with General Instruction I to Form 10-K.

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

Omitted in accordance with General Instruction I to Form 10-K.

Item 14. Principal Accounting Fees and Services

Audit Fees and Services

The audit fees billed by Deloitte & Touche LLP (Deloitte) related to our annual financial statement audit are included as part of the total audit fees billed to Boardwalk Pipeline Partners, which total fees for 2013 and 2012 were $2.5 million and $2.4 million. In 2012, Deloitte billed us approximately $0.3 million of audit related fees, which includes the aggregate fees and expenses for services that were reasonably related to the performance of the financial statement audit or review, mainly including due diligence, consents and comfort letters. There were no such fees charged to Gulf South in 2013.

Auditor Engagement Pre-Approval Policy

As a wholly-owned subsidiary of Boardwalk Pipeline Partners, we do not have a separate audit committee. The policies and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board of Directors of Boardwalk Pipeline Partner's general partner have been set forth in Boardwalk Pipeline Partner's 2013 Annual Report on Form 10-K, which is available on the SEC's website at http://www.sec.gov and on Boardwalk Pipeline Partner's website at http://bwpmlp.com.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) 1. Financial Statements

Included in Item 8 of this Report:

Report of Independent Registered Public Accounting Firm

Balance Sheets at December 31, 2013 and 2012

Statements of Income for the years ended December 31, 2013, 2012 and 2011

Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011

Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011

Statements of Changes in Partners’ Capital for the years ended December 31, 2013, 2012 and 2011

Notes to Financial Statements

(a) 2. Financial Statement Schedules

Valuation and Qualifying Accounts

The following table presents those accounts that have a reserve as of December 31, 2013, 2012 and 2011 and are not included in specific schedules herein. These amounts have been deducted from the respective assets on the Balance Sheets (in millions):



			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Other Additions		Deductions			Balance at End of Period
Allowance for doubtful accounts:
2013	$	0.1	$	(0.1	)	$	—	$	—		$	—
2012	0.1		—			—		—			0.1
2011	0.4		0.3			—		(0.6		)	0.1

(a) 3. Exhibits

The following documents are filed as exhibits to this Report:



Exhibit Number		Description
3.1		Certificate of Limited Partnership of Gulf South Pipeline Company, LP (Incorporated herein by reference to Exhibit 3.1 to the Registrant’s Registration Statement of Form S-4, File No. 333-184428, filed on October 15, 2012).
3.2		Agreement of Limited Partnership of Gulf South Pipeline Company, LP(Incorporated herein by reference to Exhibit 3.2 to the Registrant’s Registration Statement of Form S-4, File No. 333-184428, filed on October 15, 2012).
4.1		Indenture dated as of January 18, 2005, between Gulf South Pipeline Company, LP and The Bank of New York, as Trustee (incorporated herein by reference to Exhibit 10.2 to Boardwalk Pipelines, LLC’s (now known as Boardwalk Pipelines, LP) Current Report on Form 8-K (File No. 333-108693-01) filed on January 24, 2005).
4.2		Indenture dated August 17, 2007, between Gulf South Pipeline Company, LP and the Bank of New York Trust Company, N.A. therein (incorporated herein by reference to Exhibit 4.1 to Boardwalk Pipeline Partner’s Current Report on Form 8-K (File No. 001-32665) filed on August 17, 2007).
4.3		Registration Rights Agreement, dated as of June 12, 2012, by and among Gulf South Pipeline Company, LP and the Initial Purchasers (incorporated herein by reference to Exhibit 4.2 to Boardwalk Pipeline Partner’s Current Report on Form 8-K (File No. 001-32665) filed on June 13, 2012).
4.4		Indenture, dated June 12, 2012, between Gulf South Pipeline Company, LP and the Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.1 to Boardwalk Pipeline Partner’s Current Report on Form 8-K (File No. 001-32665) filed on June 13, 2012).
10.1		Second Amended and Restated Revolving Credit Agreement, dated as of April 27, 2012, among Boardwalk Pipelines, LP, Texas Gas Transmission, LLC, Gulf South Pipeline Company, LP, Gulf Crossing Pipeline Company LLC, Boardwalk HP Storage Company, LLC and Boardwalk Midstream, LP, as Borrowers, Boardwalk Pipeline Partners, LP, and the several lenders and issuers from time to time party hereto, Wells Fargo Bank, N.A., as administrative agent, Citibank, N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents, and Bank of China, New York Branch, Royal Bank of Canada, and Union Bank, N.A., as co-documentation agents, and Wells Fargo Securities, LLC, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, Bank of China, New York Branch, RBC Capital Markets and Union Bank, N.A., as joint lead arrangers and joint book managers (incorporated herein by reference to Exhibit 10.1 to Boardwalk Pipeline Partner’s Quarterly Report on Form 10-Q (File No. 001-32665) filed on May 3, 2012).
*12.1		Statement of Computation of Ratio of Earnings to Fixed Charges.
*31.1		Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
*31.2		Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a).
**32.1		Certification of Stanley C. Horton, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2		Certification of Jamie L. Buskill, Chief Financial Officer, 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

* Filed herewith

** Furnished herewith

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.



		Gulf South Pipeline Company, LP
		By: GS Pipeline Company, LLC
		its general partner
Dated:	March 10, 2014	By:	/s/ Jamie L. Buskill
			Jamie L. Buskill
			Senior Vice President, Chief Financial and Administrative Officer and 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 date indicated.



Dated:	March 10, 2014	/s/ Stanley C. Horton
		Stanley C. Horton President, Chief Executive Officer and Director (principal executive officer)
Dated:	March 10, 2014	/s/ Jamie L. Buskill
		Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer and Treasurer (principal financial officer)
Dated:	March 10, 2014	/s/ Steven A. Barkauskas
		Steven A. Barkauskas Senior Vice President, Controller and Chief Accounting Officer (principal accounting officer)
Dated:	March 10, 2014	/s/ Michael E. McMahon
		Michael E. McMahon Director
Dated:	March 10, 2014	/s/ Andrew H. Tisch
		Andrew H. Tisch Director