Gulf South Pipeline Company, LP - FORM 10-K

Attached files

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EX-31.1 - EXHIBIT 31.1 - Gulf South Pipeline Company, LP	gsexhibit311.htm
EX-12.1 - EXHIBIT 12.1 - Gulf South Pipeline Company, LP	gsexhibit121.htm
EX-32.1 - EXHIBIT 32.1 - Gulf South Pipeline Company, LP	gsexhibit321.htm
EX-31.2 - EXHIBIT 31.2 - Gulf South Pipeline Company, LP	gsexhibit312.htm
EX-32.2 - EXHIBIT 32.2 - Gulf South Pipeline Company, LP	gsexhibit322.htm

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, 2012

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 o 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

2012 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	14
Item 2. Properties	14
Item 3. Legal Proceedings	14
Item 4. Mine Safety Disclosures	14
PART II	15
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	15
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	25
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	51
Item 9A. Controls and Procedures	52
PART III	52
Item 10. Directors, Executive Officers and Corporate Governance	52
Item 11. Executive Compensation	52
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	52
Item 13. Certain Relationships and Related Transactions, and Director Independence	52
Item 14. Principal Accounting Fees and Services	52
PART IV	54
Item 15. Exhibits and Financial Statement Schedule	54

PART I

Item 1. Business

All references to “Gulf South,” “we,” “us” and “our” refer to Gulf South Pipeline Company, LP, a Delaware limited partnership, unless otherwise indicated or the context otherwise requires.

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, 2012, our pipeline transmission system had a peak day delivery capacity of approximately 6.8 billion cubic feet (Bcf) per day and consisted of approximately 7,240 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 and storage facilities. 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, 2012, approximately 78% of our revenues were derived from capacity reservation fees under firm contracts, approximately 14% of our revenues were derived from fees based on utilization under firm contracts and approximately 8% of our revenues were derived from interruptible transportation, interruptible storage, parking and lending (PAL) and other services. For the twelve months ended December 31, 2012, EOG Resources, Inc. represented approximately 10% of our revenues, with no other non-affiliated customer representing 10% or more of our revenues. As of December 31, 2012, the weighted average life of our transportation contracts was approximately 5.5 years.

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 our costs or earn a return. We are able 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 Projects

Southeast Market Expansion: Our Southeast Market Expansion project consists of constructing an interconnection between us and Petal Gas Storage, LLC (Petal), an affiliate, 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 is subject to FERC approval, is expected to cost approximately $300.0 million and to be placed in service in the second half 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, marketers, interstate and intrastate pipelines, and with end-use customers, including LDCs, electric power generators and industrial users who, in turn, provide transportation and storage services to end-users. Based on 2012 revenues, our customer mix was as follows: natural gas producers (47%), marketers (22%), interstate and intrastate pipelines (16%), LDCs (12%), power generators (2%) and industrial end users and others (1%). Based upon 2012 revenues, our deliveries were as follows: pipeline interconnects (70%), LDCs (13%), storage activities (11%), industrial end-users (4%), power generators (1%) and other (1%). One non-affiliated customer, EOG Resources, Inc., accounted for approximately 10% of our 2012 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 205 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 our regulators’ policies, capacity release has 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.

Seasonality

Our revenues can be affected by weather, natural gas price levels and natural gas price volatility. Weather impacts natural gas demand for heating needs and power generation, which in turn influences the short-term value of transportation and storage across our pipeline system. Colder than normal winters can result in an increase in the demand for natural gas for heating needs and warmer than normal summers can impact cooling needs, both of which typically result in increased pipeline transportation revenues and throughput. While traditionally peak demand for natural gas occurs during the winter months driven by heating needs, the increased use of natural gas for cooling needs during the summer months has partially reduced the seasonality of our revenues. During 2012, approximately 52% of our revenues and 53% of our operating income were recognized in the first and fourth quarters of the year, excluding asset impairments and gains and losses on the disposal of operating assets.

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 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 the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency of DOT, 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 interstate pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in highly populated areas. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act) was enacted in 2012 and increased maximum civil penalties for certain violations 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 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 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 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. These laws include, for example:


•	the Clean Air Act and analogous state laws which impose obligations related to air emissions, including, in the case of the Clean Air Act, 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; and


•	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.

Effects of Compliance with Environmental Regulations

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

Employee Relations

At December 31, 2012, we had approximately 570 employees, none of whom are included in collective bargaining units. 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. The Securities and Exchange Commission (SEC) maintains an Internet site at www.sec.gov that contains 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. 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 maintain or replace expiring gas transportation and storage contracts at attractive rates or on a long-term basis.

Each year, a portion of our natural gas transportation contracts expire and need to be renewed or replaced. We may not be able to extend contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts. A key driver that influences the rates and terms of our transportation contracts is the current and anticipated basis spreads - generally meaning the difference in the price of natural gas at receipt and delivery points on our natural gas pipeline system - 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, 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. As new sources of natural gas have been identified and developed, changes in pricing dynamics between supply basins, pooling points and market areas have occurred. As a result of the increase in overall pipeline capacity and the new sources of supply, basis spreads on our pipeline system have narrowed over the past several years, reducing the transportation rates we can negotiate with our customers on 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. As a result, the rates we are able to obtain on renewals of expiring contracts are generally lower than those under the expiring contracts, which adversely impacts our revenues and earnings before interest, taxes, depreciation and amortization (EBITDA).

The development of large new gas supply basins in the U.S. and the overall increase in the supply of natural gas created by such development can significantly affect our business.

Growing supplies of natural gas are being produced in new production areas that are not connected to our system and are closer to large end-user market areas than the supply basins connected to our system that traditionally served these markets. For example, gas produced in the Marcellus Shale in Pennsylvania, New York, West Virginia and Ohio is being shipped to nearby northeast markets such as New York and Philadelphia which have traditionally been served by gas produced in Gulf Coast areas, which are connected to us. This has caused and may continue to cause gas produced in supply areas connected to our system to be diverted to other market areas which may adversely affect capacity utilization and transportation rates on our system. In addition, as discussed above, growing supplies of natural gas from developing supply basins, especially shale plays, connected to our system have caused and may continue to cause basis spreads to narrow. All of these dynamics continue to impair our ability to renew or replace existing contracts or to sell interruptible and short-term firm transportation services at attractive rates, which adversely impacts our revenues and EBITDA.

Changes in the price of natural gas impacts supply of and demand for natural gas, which impacts our business.

Natural gas prices in the U.S. are currently lower than historical averages driven by the abundant and growing gas supply discussed above. The price of natural gas fluctuates 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 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 us, that have contracted for capacity with us.

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 system, reduce the demand for our services and could result in the non-renewal of contracted capacity as contracts expire and affect our business.

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 tariff only allows 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 10% of our 2012 revenues. Including revenues earned from affiliates, our top ten customers comprised approximately 56% of our revenues in 2012. 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.

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 business. Our business is 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 compete with other pipelines.

The principal elements of competition among pipelines 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.

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 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, the 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 earnings before interest, taxes, depreciation and amortization (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. Future financing agreements we may enter into may contain similar or more restrictive covenants.

Our ability to comply with the covenants and restrictions contained in the 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, our ability to comply with these covenants may be impaired. 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.

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.

Regulatory Risks

Regulation by FERC

We are subject to extensive regulation by FERC, including rules and regulations related to the rates we can charge for our services.

Our business operations 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.

Our natural gas transportation and storage operations are subject to FERC's rate-making policies which could limit our ability to recover the full cost of operating our pipelines, including earning a reasonable return.

We are subject to extensive regulations relating to 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.

If we were to file a rate case, or if we have to defend our rates in a proceeding commenced by a customer or 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.

Customers or FERC can challenge the existing rates on our pipelines. 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.

Pipeline safety laws and regulations

Pipeline safety laws and regulations requiring the performance of integrity management programs or the use of certain 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 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 by the DOT, 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 stringently interpreted pipeline safety requirements are implemented.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (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 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.

We need to maintain authority from PHMSA to operate portions of our pipeline system at higher than normal operating pressures.

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.

Environmental Risks

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 Clean Air Act (CAA), the Clean Water Act, CERCLA, the Resource Conservation and Recovery Act, OPA, 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, 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 as well as some states and regional groupings of states have in recent years considered legislation and regulations to reduce emissions of greenhouse gases (GHG). These efforts have included cap-and-trade programs, carbon taxes, 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.

Tax Risks

If the Internal Revenue Service (IRS) treats us or Boardwalk Pipeline Partners as a corporation for United

States federal income tax purposes or if we or Boardwalk Pipeline Partners become subject to a material amount

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.

Our tax treatment and that of Boardwalk Pipeline Partners depend on Boardwalk Pipeline Partners’ classification as a partnership for United States federal income tax purposes, as well as neither us nor Boardwalk Pipeline Partners being subject to a material amount of entity-level taxation by individual states. If we or Boardwalk Pipeline Partners were treated as a corporation for United States federal income tax purposes, our income would be subject to United States federal income tax at the corporate tax rate, which is currently a maximum of 35%, and would likely be subject to additional state income tax at varying rates. Treatment of us or Boardwalk Pipeline Partners as a corporation could result in a material reduction in our anticipated cash flow, which could materially and adversely affect our ability to service our debt.

Current tax law may change so as to cause us or Boardwalk Pipeline Partners to be treated as a corporation for

United States federal income tax purposes or otherwise subject us or Boardwalk Pipeline Partners to additional amounts of entity-level taxation for state tax purposes. 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. In addition, several states are 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.

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

Not applicable.

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

Overview

As of December 31, 2012, our pipeline system consisted of approximately 7,240 miles of interconnected pipelines with a peak day delivery capacity of approximately 6.8 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 system, 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 PAL services where the customer receives and pays for capacity only when it is available and used. Some PAL agreements are paid for at inception of the service and revenues for these agreements are recognized as service is provided over the term of the agreement. 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.

The majority of our transportation revenues are derived from capacity reservation charges under firm agreements, which typically have multi-year terms. Our customers’ obligations to pay contractual reservation charges are not impacted by the volume of natural gas they actually transport. The majority of our storage revenues are derived from capacity reservation charges under firm storage agreements. Unlike our transportation contracts, firm storage agreements tend to be of a shorter term, primarily due to market alternatives and the needs of our customers.

Market Conditions and Contract Renewals

The amount of natural gas being produced from unconventional natural gas production areas has greatly increased in recent years. This dynamic drove the pipeline industry, including us, to construct substantial new pipeline infrastructure to support this development. However, the oversupply of gas from these and other production areas has resulted in gas prices that are substantially lower than in recent years, which has caused producers to scale back production to levels below those that were expected when the new infrastructure was built. In addition, certain of these new supply basins, such as the Marcellus and Utica Shale plays, are closer to the traditional high value markets served by interstate pipelines like us, a development that has further affected how natural gas moves across the interstate pipeline grid. These factors have led to increased competition in certain pipeline markets, as well as substantially narrower price differentials than previous years between producing/supply areas, and market areas (basis spreads), which has put significant downward pressure on pricing for both firm and interruptible transportation capacity that we are currently marketing. We do not expect basis spreads on our system to improve in the current year.

As of December 31, 2012, a substantial portion of our transportation capacity was contracted for under firm transportation agreements having a weighted-average remaining life of approximately 5.5 years. However, each year a portion of our firm transportation agreements expire and must be renewed or replaced. We renewed or replaced contracts for most of the firm transportation capacity that expired in 2012, though on average at lower rates. The amount of contracted transportation capacity which will expire in 2013 is greater than in recent years. In light of the market conditions discussed above, we expect that transportation contracts we renew or enter into in 2013 will be at lower rates than our expiring contracts. Remaining available capacity will be marketed and sold on a short-term firm or interruptible basis, which will also be at lower rates, based on current market conditions. We expect that these circumstances will negatively affect our transportation revenues and EBITDA in 2013.

The market for storage and PAL services is also impacted by the factors discussed above, as well as by natural gas price differentials between time periods, such as winter to summer (time period price spreads). Time period price spreads declined from 2010 to 2011 and improved in the first half of 2012; however, we believe that current forward pricing curves indicate that the

spreads for 2013 may not be as favorable. Forward pricing curves change frequently as a result of a variety of market factors (including weather, levels of storage gas, and available capacity, among others) and as such may not be a reliable predictor of actual future events. Accordingly, we cannot predict our future revenues from interruptible storage and PAL services due to the uncertainty and volatility in market conditions discussed above.

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. 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. Due to recent highly publicized 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.

Transfer of Assets

In March 2013, we filed applications with the FERC requesting authority to transfer approximately 2,000 miles of small-diameter, lower-pressure pipeline assets representing an immaterial amount of our throughput to affiliated intrastate entities. We do not expect the transfer of the assets to have a material impact on our business, results of operations or cash flows.

Results of Operations

2012 Compared with 2011

Our net income for the year ended December 31, 2012, increased $14.8 million, or 16%, to $110.1 million compared to $95.3 million for the year ended December 31, 2011. The increase in net income was primarily the result of items which negatively impacted the 2011 period and other items noted below.

Operating revenues for the year ended December 31, 2012, decreased $31.9 million, or 6%, to $517.2 million, compared to $549.1 million for the year ended December 31, 2011. The primary drivers for the decrease in revenues were a decrease in fuel retained of $26.4 million, which resulted from lower natural gas prices, and a decrease in transportation revenues, excluding fuel, of $14.5 million resulting from lower firm and interruptible revenues due to market conditions discussed above. These decreases were partially offset by an increase in PAL revenues of $14.3 million due to improved market conditions.

Operating costs and expenses for the year ended December 31, 2012, decreased $48.3 million, or 12%, to $361.7 million, compared to $410.0 million for the year ended December 31, 2011. The primary drivers of the decrease were lower fuel costs of $17.4 million primarily due to lower natural gas prices, lower administrative and general expenses of $11.0 million as a result of cost management activities, particularly with regard to outside services, corporate fees and labor and $9.2 million lower operation and maintenance expenses primarily from lower maintenance project costs and outside services. The decreases were partially offset by $6.3 million of asset impairment charges in 2012, which related to the expected retirement of certain small-diameter pipeline assets. The 2011 period was unfavorably impacted by an impairment charge of $9.2 million primarily related to materials and supplies which were subsequently sold, a $5.0 million charge related to a fire at our Carthage compressor station and a $3.7 million natural gas storage loss at our Bistineau facility.

Total other deductions for the year ended December 31, 2012, increased by $1.6 million, or 4%, to $45.4 million compared to $43.8 million for the year ended December 31, 2011 driven by higher interest expense of $2.9 million resulting from increased debt levels in 2012, partially offset by an increase in affiliated interest income of $1.5 million.

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, 2012, 2011 and 2010 were as follows (in millions):



	Year Ended December 31,
	2012		2011		2010
Growth capital	$	4.7	$	64.4	$	79.3
Maintenance capital	49.6		55.6		38.6
Total	$	54.3	$	120.0	$	117.9

We financed our growth capital expenditures through Boardwalk Pipeline Partners’ issuances of equity securities, issuances of debt borrowings under the revolving credit facility by us and by Boardwalk Pipelines and its other subsidiaries, and through available operating cash flows in excess of our operating needs.

We expect our total capital expenditures to be approximately $127.5 million in 2013, including approximately $69.0 million for maintenance capital. Our more significant growth project for 2013 consists of:

Southeast Market Expansion: We expect to spend approximately $300.0 million 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, of which we expect to spend approximately $32.8 million in 2013.

Refer to Item 1 for further discussion.

Issuance and Retirement of Debt

In June 2012, we received net proceeds of approximately $296.5 million after deducting initial purchaser discounts and offering expenses of $3.5 million from the sale of $300.0 million of our 4.00% senior unsecured notes due June 15, 2022 (2022 Notes). We used the proceeds to repay borrowings under our revolving credit facility and used $225.0 million to redeem our 5.75% notes due August 2012.

Revolving Credit Facility

As of December 31, 2012, 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 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 are in compliance with all covenant requirements under the credit facility as of December 31, 2012. 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, 2012, 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	235.5		43.2		79.5		58.7		54.1
Capital commitments ⁽²⁾	15.8		15.8		—		—		—
Pipeline capacity agreements ⁽³⁾	32.9		6.2		12.4		12.3		2.0
Operating lease commitments	13.8		3.5		6.2		4.1		—
Total	$	1,148.0	$	68.7	$	373.1	$	350.1	$	356.1


(1)	Includes our senior unsecured notes, having maturity dates from 2015 to 2022. We have no borrowings outstanding under our revolving credit facility at December 31, 2012, 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, 2012.

(3) The amounts shown are associated with pipeline capacity agreements on third-party and affiliated 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 increased $17.0 million to $233.2 million for the year ended December 31, 2012, compared to $216.2 million for the comparable 2011 period, primarily due to a $14.8 million increase in net income and timing of cash flows associated with receivables and payables.

Changes in cash flow from investing activities

Net cash used in investing activities decreased $104.9 million to $76.1 million for the year ended December 31, 2012, compared to $181.0 million for the comparable 2011 period. The decrease was primarily driven by a $65.7 million decrease in capital expenditures and a $41.4 million decrease in cash loaned to Boardwalk Pipelines under the cash management program.

Changes in cash flow from financing activities

Net cash used in financing activities increased $119.8 million to $157.0 million for the year months ended December 31, 2012, compared to a $37.2 million cash used in financing activities for the year ended December 31, 2011. The increase was due to an increase in net debt repayments of $157.0 million. In the 2011 period, we repaid $37.2 million repayment of amounts owed under the cash management program.

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, 2012, 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 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, 2012, we had accrued approximately $6.1 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. This evaluation is based on undiscounted cash flow projections expected over the remaining useful life of the asset. 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 contains 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;


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


•	the timing, cost, scope and financial performance of our recent, current and future growth projects;


•	the expansion into new geographic areas;


•	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;


•	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 consummation of contemplated transactions and agreements; and


•	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.

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):



	2012			2011
Carrying amount of fixed-rate debt	$	845.5		$	772.6
Fair value of fixed-rate debt	$	930.4		$	845.4
100 basis point increase in interest rates and resulting debt decrease	$	42.3		$	25.0
100 basis point decrease in interest rates and resulting debt increase	$	45.3		$	25.4
Weighted-average interest rate	5.33		%	5.86		%

At December 31, 2012, and at the time of this filing, we had no borrowings outstanding under the revolving credit facility. Approximately half 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. At December 31, 2012 and 2011, approximately $0.3 million of gas stored underground, which we own and carry as current Gas stored underground, was available for sale and exposed 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.

Market risk:

Our primary exposure to market risk occurs at the time our existing transportation and storage contracts expire and are subject to renewal or marketing. We actively monitor future expiration dates associated with our contract portfolio. The revenue we will be able to earn from renewals of expiring contracts will be influenced by the price differential between physical locations on our pipeline system (basis spreads) and other factors discussed below.

We compete with numerous interstate and intrastate pipelines. Our ability to market available natural gas transportation capacity is impacted by supply and demand for natural gas, competition from other pipelines, natural gas price volatility, basis spreads, economic conditions and other factors. Over the past several years, new sources of natural gas have been identified throughout the U.S. and new pipeline infrastructure has been developed which has led to changes in pricing dynamics between supply basins, pooling points and market areas and an overall weakening of basis spreads across our pipeline system. We do not expect basis spreads to improve in the near future.

As of December 31, 2012, a substantial portion of our transportation capacity was contracted for under firm transportation agreements having a weighted-average remaining life of approximately 5.5 years. However, each year a portion of our firm transportation agreements expire and must be renewed or replaced. We renewed or replaced contracts for most of the firm transportation capacity that expired in 2012, though, on average, at lower rates. The amount of contracted transportation capacity which will expire in 2013 is greater than in recent years. In light of the market conditions discussed above, we expect that transportation contracts we renew or enter into in 2013 will be at lower rates than our expiring contracts. Remaining available capacity will be marketed and sold on a short-term firm or interruptible basis, which will also be at lower rates, based on current market conditions. We expect that these circumstances will negatively affect our transportation revenues and EBITDA in 2013.

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.

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, 2012, the amount of gas loaned out by us or owed to us due to gas imbalances was approximately 1.8 trillion British thermal units (TBtu). Assuming an average market price during December 2012 of $3.32 per million British thermal units (MMBtu), the market value of that gas was approximately $6.0 million. As of December 31, 2011, the amount of gas loaned out by us or owed to us due to gas imbalances was approximately 1.4 TBtu. Assuming an average market price during December 2011 of $3.14 per MMBtu, the market value of this gas at December 31, 2011, would have been approximately $4.4 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, 2012 and 2011, and the related statements of income, comprehensive income, changes in partner's capital, and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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 28, 2013

GULF SOUTH PIPELINE COMPANY, LP

BALANCE SHEETS

(Millions)



	December 31,
ASSETS	2012		2011
Current Assets:
Cash and cash equivalents	$	0.1	$	—
Receivables:
Trade, net	38.0		36.9
Affiliates	5.9		6.9
Other	2.8		12.6
Gas receivables:
Transportation	6.5		4.6
Transportation - affiliates	0.7		—
Gas stored underground	0.3		0.3
Prepayments	6.1		5.5
Other current assets	1.3		0.7
Total current assets	61.7		67.5

Property, Plant and Equipment:
Natural gas transmission and other plant	3,266.6		3,246.5
Construction work in progress	72.4		82.1
Property, plant and equipment, gross	3,339.0		3,328.6
Less-accumulated depreciation and amortization	602.1		505.9
Property, plant and equipment, net	2,736.9		2,822.7

Other Assets:
Gas stored underground	9.1		9.3
Advances to affiliates	101.0		71.2
Other	9.9		10.2
Total other assets	120.0		90.7

Total Assets	$	2,918.6	$	2,980.9

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	2012			2011
Current Liabilities:
Payables:
Trade	$	31.3		$	23.7
Affiliates	1.1			1.6
Other	2.7			5.1
Gas Payables:
Transportation	7.2			2.7
Transportation – affiliates	2.7			1.8
Storage	3.4			0.1
Accrued taxes, other	17.0			17.7
Accrued interest	12.8			17.2
Accrued payroll and employee benefits	11.1			8.9
Construction retainage	—			2.9
Deferred income	16.5			8.4
Other current liabilities	12.9			7.9
Total current liabilities	118.7			98.0

Long-term debt	845.5			1,001.1

Other Liabilities and Deferred Credits:
Asset retirement obligation	13.8			14.1
Other	12.5			12.7
Total other liabilities and deferred credits	26.3			26.8

Partner's Capital:
Partner's capital	1,934.5			1,855.0
Accumulated other comprehensive loss	(6.4		)	—
Total partner's capital	1,928.1			1,855.0
Total Liabilities and Partner's Capital	$	2,918.6		$	2,980.9

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,
	2012			2011			2010
Operating Revenues:
Gas transportation	$	387.1		$	421.2		$	405.4
Gas transportation - affiliates	75.0			81.2			77.1
Parking and lending	24.6			9.5			23.7
Parking and lending - affiliates	—			0.8			3.4
Gas storage	24.5			27.0			32.8
Other	6.0			9.4			17.2
Total operating revenues	517.2			549.1			559.6

Operating Costs and Expenses:
Fuel and gas transportation	55.8			74.3			71.9
Fuel and gas transportation - affiliates	14.8			17.4			29.0
Operation and maintenance	85.3			93.4			78.7
Administrative and general	51.1			62.1			56.3
Depreciation and amortization	106.4			105.7			101.7
Asset impairment	6.3			9.2			5.7
Loss on disposal of operating assets	0.4			6.2			0.5
Taxes other than income taxes	41.6			41.7			39.7
Total operating costs and expenses	361.7			410.0			383.5

Operating income	155.5			139.1			176.1

Other Deductions (Income):
Interest expense, net	46.9			44.0			43.5
Interest (income) expense - affiliates	(1.5		)	—			1.1
Miscellaneous other income, net	—			(0.2		)	—
Total other deductions	45.4			43.8			44.6

Net Income	$	110.1		$	95.3		$	131.5

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,
	2012			2011			2010
Net income	$	110.1		$	95.3		$	131.5
Other comprehensive income (loss):
(Loss) gain on cash flow hedges	(6.6		)	1.9			3.1
Reclassification adjustment transferred to Net Income from cash flow hedges	0.2			(1.5		)	(9.8		)
Total Comprehensive Income	$	103.7		$	95.7		$	124.8

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,
OPERATING ACTIVITIES:	2012			2011			2010
Net income	$	110.1		$	95.3		$	131.5
Adjustments to reconcile to cash provided by operations:
Depreciation and amortization	106.4			105.7			101.7
Amortization of deferred costs	1.1			1.0			1.0
Asset impairment	6.3			9.2			5.7
Storage gas loss	—			3.7			—
Loss on disposal of operating assets	0.4			6.2			0.5
Changes in operating assets and liabilities:
Trade and other receivables	1.1			(7.7		)	47.6
Gas receivables and storage assets	(1.9		)	21.0			(8.1		)
Other assets	(4.2		)	(4.1		)	(0.6		)
Affiliates, net	0.7			(1.7		)	19.2
Trade and other payables	(1.9		)	(0.4		)	(19.0		)
Gas payables	11.2			(14.0		)	4.9
Accrued liabilities	(2.9		)	0.9			1.9
Other liabilities	6.8			1.1			(84.9		)
Net cash provided by operating activities	233.2			216.2			201.4
INVESTING ACTIVITIES:
Capital expenditures	(54.3		)	(120.0		)	(121.7		)
Proceeds from sale of operating assets	1.9			4.9			1.2
Proceeds from insurance and other recoveries	6.1			5.3			—
Advances to affiliates	(29.8		)	(71.2		)	0.4
Net cash used in investing activities	(76.1		)	(181.0		)	(120.1		)
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		)	(79.3		)
Net cash used in financing activities	(157.0		)	(37.2		)	(79.3		)
Increase (decrease) in cash and cash equivalents	0.1			(2.0		)	2.0
Cash and cash equivalents at beginning of period	—			2.0			—
Cash and cash equivalents at end of period	$	0.1		$	—		$	2.0

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, 2010	$	1,642.9		$	6.3		$	1,649.2
Add (deduct):
Net income	131.5			—			131.5
Other comprehensive loss	—			(6.7		)	(6.7)
Balance December 31, 2010	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 loss	-			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

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).

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.

Cash and Cash Equivalents

Cash equivalents are highly liquid investments with an original maturity of three months or less and are stated at cost plus accrued interest, which approximates fair value. Gulf South had no restricted cash at December 31, 2012 and 2011.

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 the 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 and excess working gas 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 held for storage or under PAL agreements approximately 73.7 trillion British thermal units (TBtu) of gas owned by third parties as of December 31, 2012. Assuming an average market price during December 2012, of $3.32 per million British thermal units (MMBtu), the market value of gas held on behalf of others was approximately $244.7 million. As of December 31, 2011, Gulf South held for storage or under PAL agreements approximately 68.3 TBtu of gas owned by third parties. Gulf South also periodically lends gas to customers under PAL services. Note 10 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, 2012, 2011 and 2010 was $1.0 million, $1.9 million and $2.6 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, 2012, 2011 and 2010. Gulf South’s tax years 2009 through 2012 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, 2012 and 2011, Gulf South had deferred revenues of $16.5 million and $8.4 million related to PAL and interruptible storage services. The deferred revenues related to PAL and interruptible storage services will be recognized in 2013 and 2014.

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 gas transportation expenses 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 Gas transportation on the Statements of Income for the years ended December 31, 2012, 2011 and 2010 was $46.2 million, $70.0 million and $77.3 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, 2012 and 2011, 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.

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, 2012 and 2011.

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, 2012, 2011, and 2010. At December 31, 2012 and 2011, Gulf South did not have any derivatives outstanding.

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 six 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. Mobile Gas Service Corp, et al. (Case No. CV-12-900711), Crum, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-12-901057), Austin, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-12-901133), Moore, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-12-901471), Davis, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-12-901490) and Joel G. Reed, et al. v. Mobile Gas Service Corp, et al. (Case No. CV-2013-922265). 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 from Gulf South.

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, 2012, and 2011, Gulf South had an accrued liability of approximately $6.1 million and $6.4 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 nine years. As of December 31, 2012, and 2011, approximately $1.4 million and $1.0 million were recorded in Other current liabilities and approximately $4.7 million and $5.4 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 in 2013 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.

In 2010, the EPA adopted regulations requiring further emission controls for air toxics, specifically formaldehyde, from certain compression engines utilizing MACT. Gulf South estimates that certain of its compression engines will require the installation of certain emission controls by late 2013. Gulf South does not believe the regulation will have a material effect on its financial condition, results of operations or cash flows.

Lease Commitments

Gulf South has various operating lease commitments extending through the year 2017 generally covering office space and equipment rentals. Total lease expense for the years ended December 31, 2012, 2011 and 2010 were approximately $3.8 million, $3.7 million and $3.3 million. The following table summarizes minimum future commitments related to these items at December 31, 2012 (in millions):



2013	$	3.5
2014	3.1
2015	3.1
2016	3.0
2017	1.1
Thereafter	—
Total	$	13.8

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, 2012, were approximately $15.8 million, all of which are expected to be settled in 2013.

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 $6.5 million, $7.4 million and $7.0 million related to pipeline capacity agreements for the years ended December 31, 2012, 2011 and 2010. The future commitments related to pipeline capacity agreements as of December 31, 2012, were (in millions):



2013	$	6.2
2014	6.2
2015	6.2
2016	6.2
2017	6.1
Thereafter	2.0
Total	$	32.9

Note 4: Fair Value Measurements and Derivatives

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 between market participants at the measurement date. A fair value hierarchy has been established that prioritizes the information used to develop fair value measurements 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 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 year ended December 31, 2012.

The table below identifies Gulf South's assets and liabilities that were 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 losses for the year ended December 31, 2012
Nonrecurring fair value measurements - Assets
Assets to be abandoned ⁽¹⁾	$	—	$	—	$	—	$	—	$	(3.5	)

Nonrecurring fair value measurements - Liabilities
Asset retirement obligation ⁽¹⁾	$	2.8	$	—	$	—	$	2.8	$	(2.8	)

(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 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. This price risk exposure includes approximately $0.3 million of gas stored underground at December 31, 2012, and 2011, which Gulf South owns and carries on its balance sheet as current Gas stored underground. At December 31, 2012, approximately 0.5 billion cubic feet (Bcf) of anticipated future sales of natural gas and cash for fuel reimbursement were hedged with derivatives having settlement dates in 2013 and 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 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 and 2011.

The amount of gains and losses from derivatives recognized 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 a Treasury rate lock used in hedging interest payments associated with a debt offering that was settled in the current period and is being amortized to earnings over the term of the related interest payments, generally the term of the related debt.


(2)	$0.2 million was recorded in Other revenues.

The amount of gains and losses from derivatives recognized 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)	$1.1 million was recorded in Gas transportation revenues and $0.4 million was recorded in Other revenues.

The amount of gains and losses from derivatives recognized in the Statements of Income for the year ended December 31, 2010, 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	$	3.1	Operating revenues ⁽¹⁾	$	9.9	Other revenues	$	(0.1	)


(1)	$4.9 million was recorded in Gas transportation revenues and $5.0 million 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.

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 instruments:

Cash and Cash Equivalents: For cash and short-term financial assets, 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, 2012. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at December 31, 2012, and 2011.

The carrying amount and estimated fair values of Gulf South's financial instruments assets and liabilities which are not recorded at fair value on the Balance Sheets as of December 31, 2012, and 2011, were as follows (in millions):



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

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



As of December 31, 2011			Estimated Fair Value
Financial Assets	Carrying Amount		Level 1		Level 2		Level 3		Total
Advances to affiliates	$	71.2	$	—	$	71.2	$	—	$	71.2

Financial Liabilities
Long-term debt	$	1,001.1	$	—	$	1,073.9	$	—	$	1,073.9

Note 5: Property, Plant and Equipment (PPE)

The following table presents Gulf South’s PPE as of December 31, 2012 and 2011 (in millions):



Category	2012 Class Amount		Weighted-Average Useful Lives (Years)	2011 Class Amount	Weighted-Average Useful Lives (Years)
Depreciable plant:
Transmission	$	2,948.3	34	2,942.1	34
Storage	118.5		34	113.4	34
Gathering	65.6		20	65.9	19
General	87.1		8	77.7	8
Rights of way and other	18.7		35	19.1	34
Total utility depreciable plant	3,238.2		34	3,218.2	34

Non-depreciable:
Construction work in progress	72.4			82.1
Storage	19.3			19.5
Land	9.1			8.8
Total other	100.8			110.4

Total PPE	3,339.0			3,328.6
Less: accumulated depreciation	602.1			505.9

Total PPE, net	2,736.9			2,822.7

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, 2012 and 2011 (in millions):



	2012				2011
	Gross PPE Investment		Accumulated Depreciation		Gross PPE Investment		Accumulated Depreciation
Bistineau storage	$	55.7	$	13.4	$	57.5	$	11.9
Mobile Bay Pipeline	11.1		2.8		11.8		2.5
Offshore and other assets	9.0		3.0		9.0		2.6
Total	$	75.8	$	19.2	$	78.3	$	17.0

Asset Dispositions and Impairment Charges

Gulf South recognized $6.3 million of asset impairment charges for the year ended December 31, 2012. Note 4 contains more information regarding the fair value measurements related to the impairment charges for 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 net realized losses of $0.1 million for the years ended December 31, 2012 and 2011. In 2010, Gulf South agreed to sell pipe materials with a book value of $11.1 million for estimated consideration of approximately $7.9 million and recorded an impairment charge of $3.2 million. The fair value of the pipe materials was based on Level 3 inputs under the fair value hierarchy. At December 31, 2012 and 2011, Gulf South held approximately $5.7 million and $7.6 million of materials and supplies which was reflected in Other Assets on the Balance Sheets.

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 amount 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. Through December 31, 2012, Gulf South received $10.0 million in insurance proceeds as partial payment for the insurance claim and in 2012, recognized a $1.2 million gain which was reflected in Net gain on disposal of assets.

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 gas transportation expense of $3.7 million to recognize the loss in base gas which had a carrying amount of $0.53 per MMBtu.

Overton Lateral

In 2010, Gulf South completed the sale of certain of its gathering assets in the Overton Field area in northeastern Texas for a nominal amount. Prior to the sale, Gulf South recognized an impairment loss of approximately $2.2 million, representing the net carrying amount of the assets.

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 Partnership 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):



	2012			2011
Balance at beginning of year	$	14.9		$	16.6
Liabilities recorded	2.6			1.4
Liabilities settled	(0.6		)	(3.5		)
Other	—			(0.2		)
Accretion expense	0.8			0.6
Balance at end of year	17.7			14.9
Less: Current portion of asset retirement obligations	(3.9		)	(0.8		)
Long-term asset retirement obligations	$	13.8		$	14.1

Note 7: Financing

Long-Term Debt

The following table presents all long-term debt issues outstanding as of December 31, 2012 and 2011 (in millions):



	2012			2011
Notes :
5.75% Notes due 2012	$	—		$	225.0
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			—

Revolving Credit Facility	—			228.5
	850.0			1,003.5
Less: unamortized debt discount	(4.5		)	(2.4		)
Total Long-Term Debt	$	845.5		$	1,001.1

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



2013	$	—
2014	—
2015	275.0
2016	—
2017	275.0
Thereafter	300.0
Total long-term debt	$	850.0

Notes and Debentures

As of December 31, 2012 and 2011, the weighted-average interest rate of Gulf South's notes and debentures was 5.33% and 5.86%. For the years ended December 31, 2012, 2011 and 2010, Gulf South completed the following debt issuances (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 and to redeem $225.0 million of Gulf South's 5.75% notes due August 2012 (2012 Notes) discussed below.

Concurrent with the issuance of the 4.00% Gulf South notes due 2022 (2022 Notes), Gulf South entered into a registration rights agreement with the holders of those notes. The agreement obligated Gulf South to file and maintain the effectiveness of an exchange offer registration statement within 360 days of the initial notes issuance to allow for the exchange of the 2022 Notes for notes with materially identical terms that have been registered under the Securities Act of 1933 and are freely tradable (Exchange Notes). On October 15, 2012, Gulf South filed the registration statement on Form S-4, which became effective on December 17, 2012. Gulf South commenced the exchange offer on December 17, 2012, and closed the exchange offer on January 29, 2013.

Gulf South’s notes and debentures 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 and debentures 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, 2012, Gulf South was in compliance with its debt covenants.

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 did not have any outstanding borrowings under the credit facility as of December 31, 2012, and had an available borrowing capacity of $200.0 million. At December 31, 2011, Gulf South had outstanding borrowings of $228.5 million with a weighted-average borrowing rate of 0.50%.

In April 2012, Boardwalk Pipelines and its subsidiaries entered into a Second Amended and Restated Revolving Credit Agreement (Amended Credit Agreement) with Wells Fargo Bank, N.A., as Administrative Agent, having aggregate lending commitments of $1.0 billion, a maturity date of April 27, 2017, and including Gulf Crossing Pipeline Company, LLC (Gulf Crossing), Gulf South, Boardwalk HP Storage Company, LLC, Texas Gas Transmission, LLC (Texas Gas), Boardwalk Pipelines and Boardwalk Midstream, LLC as borrowers. 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, 2012.

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 $4.7 million, $4.5 million and $4.2 million for the years ended December 31, 2012, 2011 and 2010.

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 $2.1 million, $1.8 million and $2.8 million during 2012, 2011 and 2010 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, 2012 and 2011, and changes during the years ended December 31, 2012 and 2011, is presented below:



	Phantom Common Units	Total Fair Value (in millions)	Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2011 (1)	69,583	2.4	1.0
Granted	193,819	5.3	3.0
Paid	(44,069)	(1.5)	—
Forfeited	(1,244)	—	—
Outstanding at December 31, 2011(1)	218,089 ⁽²⁾	5.3 ⁽³⁾	2.9 ⁽³⁾
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


(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.


(3)	Excludes the Phantom Common Units that vested on December 16, 2011.

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, 2012 and 2011 was based on the closing market price of the common unit on those dates of $24.90 and $27.67 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 $1.5 million, $0.3 million and $1.1 million in Administrative and general expenses during 2012, 2011 and 2010 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, 2012 and 2011 was $3.1 million and $5.3 million.

In 2012 and 2011, the general partner purchased 2,000 of Boardwalk Pipeline Partners’ common units each year in the open market at a price of $27.24 and $32.82 per unit. These units were granted under the LTIP to the independent directors as part of their director compensation. At December 31, 2012, 3,513,708 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.

UARs. The economic value of the UARs 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. 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 to the extent the fair market value (as defined in the plan) of a common unit on such date exceeds the exercise price; which resulting amount may be limited to the applicable dollar cap amount per UAR (UAR Cap) depending on the terms of the award agreement. Each UAR may include 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, 2012 and 2011, and changes during 2012 and 2011 is presented below:



	UARs		Weighted Average Exercise Price		Total Fair Value (in millions)		Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2011 ⁽¹⁾	368,956		$	30.36	$	—	3.0
Forfeited	(29,609	)
Granted ⁽²⁾	27,551		32.58		0.1		2.8
Granted ⁽³⁾	71,277		28.93		0.2		2.5
Granted ⁽⁴⁾	218,342		27.30		1.5		3.0
Outstanding at December 31, 2011 ⁽¹⁾	656,517		29.28		3.0		2.3
Forfeited	(83,638	)
Granted ⁽⁵⁾	6,786		26.46		—		2.7
Granted ⁽⁶⁾	26,082		27.90		0.1		2.2
Outstanding at December 31, 2012 ⁽¹⁾	605,747		$	29.18	$	1.7	1.4


(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 $32.58, the closing price of Boardwalk Pipeline Partners’ common units on the New York Stock Exchange on the day immediately preceding the grant date, and a UAR Cap of $14.29 was established for each UAR granted on March 31, 2011.


(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 $28.93, the closing price of Boardwalk Pipeline Partners’ common units on the

New York Stock Exchange on the day immediately preceding the grant date, and a UAR Cap of $12.67 was established for each UAR granted on June 30, 2011.


(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 $27.30, the closing price of Boardwalk Pipeline Partners’ common units on the New York Stock Exchange on the grant date on December 14, 2011. No UAR Cap is applicable to these awards.


(5)	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. No UAR Cap is applicable to these awards.


(6)	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. No UAR Cap is applicable to these awards.

The fair value of the UARs granted in 2012 and December 2011 were based on the computed value of a call on Boardwalk Pipeline Partners’ common units at the exercise price. The fair value of the UARs granted prior to December 2011 was determined by calculating the difference between the computed value of a call on Boardwalk Pipeline Partners’ common units at the exercise price and a similar call at an exercise price that has been increased to accommodate the UAR Cap. The following assumptions were used as inputs to the Black-Scholes valuation model for grants made during 2012 and 2011:



	Grant Date Assumptions for Grants Made in 2012	Grant Date Assumptions for Grants Made in 2011
Expected life (years)	2.2 - 2.7	2.0 - 3.0
Risk free interest rate ⁽¹⁾	0.29% - 0.47%	0.25% - 1.17%
Expected volatility ⁽²⁾	31% - 34%	34% - 38%


(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 $0.3 million and $0.4 million for the years ended December 31, 2012 and 2011, related to the UARs. As of December 31, 2012 and 2011, there was $0.8 million and $2.5 million of total unrecognized compensation cost related to the non-vested portion of the UARs.

Long-Term Cash Bonuses. There were no Long-Term Cash Bonuses granted in 2012. In 2011, Boardwalk Pipeline Partners granted to certain employees $0.4 million of Long-Term Cash Bonuses under the UAR and Cash Bonus Plan. Each Long-Term Cash Bonus granted prior to 2011 will become vested and payable to the holder in cash equal to the amount of the grant after the expiration of a three-year restricted period. Except in limited circumstances, upon termination of employment during the restricted period, any outstanding and unvested awards of Long-Term Cash Bonuses would be cancelled unpaid. Boardwalk Pipeline Partners recorded compensation expense of $0.6 million and $0.5 million for the years ended December 31, 2012 and 2011, related to the Long-Term Cash Bonuses. As of December 31, 2012 and 2011, there was $0.4 million and $1.3 million of total unrecognized compensation cost related to the Long-Term Cash Bonuses.

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. Each Phantom GP Unit entitles the holder thereof, upon vesting, to a lump sum cash payment in an amount determined by a formula based on cash distributions made by Boardwalk Pipeline Partners to its general partner during the four quarters preceding the vesting date and the implied yield on Boardwalk Pipeline Partners’ common units, up to a maximum of $50,000 per unit.

A summary of the status of Boardwalk Pipeline Partners’ SLTIP as of December 31, 2012 and 2011, and changes during the years ended December 31, 2012 and 2011, is presented below:



	Phantom GP Units		Total Fair Value (in millions)	Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2011 ⁽¹⁾	367.0		17.6	1.5
Paid	(83.0	)	(3.6)	—
Forfeited	(21.5	)	—	—
Outstanding at December 31, 2011 ⁽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


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

The fair value of the awards at the date of grant was based on the formula contained in the SLTIP and assumptions made regarding potential future cash distributions made to the general partner during the four quarters preceding the vesting date and the future implied yield on Boardwalk Pipeline Partners' common units. The fair value of the awards was 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 $2.3 million, $2.5 million and $4.9 million in Administrative and general expenses during 2012, 2011 and 2010 for the ratable recognition of the fair value of the GP Phantom Unit awards. The total estimated remaining unrecognized compensation expense related to the GP Phantom Units outstanding at December 31, 2012, was less than $0.1 million. No additional grants of Phantom GP Units are expected to be made under the SLTIP. The outstanding SLTIP awards at December 31, 2012 became fully vested in February 2013.

Note 9: Accumulated Other Comprehensive Loss

The following table shows the components of Accumulated other comprehensive loss which is included in Partners’ Capital on the Balance Sheets (in millions):



	As of December 31,
	2012			2011
Loss on cash flow hedges	$	(6.4	)	$	—

Gulf South did not have any cash flow hedges outstanding as of December 31, 2012 or 2011. The loss on cash flow hedges in the table above as of December 31, 2012, is related to losses deferred in AOCI from a treasury rate lock that was settled and is being amortized over the term of the related interest payments. Gulf South estimates that approximately $0.7 million of net losses reported in AOCI as of December 31, 2012, are expected to be reclassified into earnings within the next twelve months.

Note 10: 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,
	2012			2011			2010
	Revenue		%	Revenue		%	Revenue		%
EOG Resources, Inc.	$	51.3	10%	$	52.3	10%	$	50.1	9%

Gas Loaned to Customers

Natural gas price volatility can cause changes in credit risk related to gas loaned to customers. 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 that gas was approximately $6.0 million. As of December 31, 2011, the amount of gas owed to Gulf South due to gas imbalances and gas loaned under PAL agreements was approximately 1.4 TBtu. Assuming an average market price during December 2011 of $3.14 per MMBtu, the market value of this gas at December 31, 2011, would have been approximately $4.4 million. If any significant customer should have credit or financial problems resulting in a delay or failure to repay the gas owed to the Gulf South, it could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Note 11: 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, 2012 and 2011, advances due to Gulf South from Boardwalk Pipelines totaled $101.0 million and $71.2 million. 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, 2012, 2011 and 2010, Boardwalk Pipelines charged Gulf South $7.2 million, $12.6 million, and $11.7 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) payroll dollars. 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 the Gulf South Statement of Operations are as follows (in millions):



	For the Year Ended December 31,
Affiliate:	2012	2011	2010
Gulf Crossing:
Gas transportation revenue - affiliates	71.9	73.2	74.2
Texas Gas:
Gas transportation revenue - affiliates	3.1	2.9	2.9
PAL revenue - affiliates	—	0.8	3.4
Fuel and gas transportation expense - affiliates	13.5	17.4	29.0
Field Services:
Gas transportation revenue - affiliates	—	5.1	—
Petal Gas Storage, LLC:
Fuel and gas transportation expense - affiliates	1.3	—	—

Note 12: Supplemental Disclosure of Cash Flow Information (in millions):



	For the Year Ended December 31,
	2012		2011		2010
Cash paid during the period for:
Interest (net of amount capitalized) ⁽¹⁾	$	57.0	$	43.3	$	42.7
Income taxes, net	$	0.1	$	0.1	$	—
Non-cash adjustments:
Accounts payable and PPE	$	14.3	$	13.6	$	15.1
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 13: Selected Quarterly Financial Data (Unaudited)



	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

Total Comprehensive Income	$	29.6	$	23.6	$	17.6	$	32.9



	2011
	For the Quarter Ended:
	December 31			September 30		June 30		March 31
Operating revenues	$	138.1		$	135.1	$	127.5	$	148.4
Operating expenses	98.5			101.7		107.8		102.0
Operating income	39.6			33.4		19.7		46.4
Interest expense, net	11.1			10.7		11.1		11.1
Other (income) expense	(0.1		)	—		—		(0.1		)
Net income	$	28.6		$	22.7	$	8.6	$	35.4

Total Comprehensive Income	$	27.8		$	23.3	$	9.1	$	35.5

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

None.

Item 9A. Controls and Procedures

This Annual Report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the company's registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

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, 2012, 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, 2012, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting.

Item 10. Directors, Executive Officers and Corporate Governance

Not Applicable.

Item 11. Executive Compensation

Not Applicable.

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

Not Applicable.

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

Not Applicable.

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 2012 were $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 audits or reviews, mainly including due diligence, consents and comfort letters.

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 2012 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, 2012 and 2011

Statements of Income for the years ended December 31, 2012, 2011 and 2010

Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010

Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010

Statements of Changes in Partners’ Capital for the years ended December 31, 2012, 2011 and 2010

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, 2012, 2011 and 2010 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:
2012	$0.1	$—	$—	$—	$0.1
2011	0.4	0.3	—	(0.6)	0.1
2010	0.2	0.3	—	(0.1)	0.4

(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.

* Filed 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 28, 2013	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 28, 2013	/s/ Stanley C. Horton
		Stanley C. Horton President, Chief Executive Officer and Director (principal executive officer)
Dated:	March 28, 2013	/s/ Jamie L. Buskill
		Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer and Treasurer (principal financial officer)
Dated:	March 28, 2013	/s/ Steven A. Barkauskas
		Steven A. Barkauskas Senior Vice President, Controller and Chief Accounting Officer (principal accounting officer)
Dated:	March 28, 2013	/s/ Michael E. McMahon
		Michael E. McMahon Director
Dated:	March 28, 2013	/s/ Andrew H. Tisch
		Andrew H. Tisch Director

Attached files

Gulf South Pipeline Company, LP Reports

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