Gulf South Pipeline Company, LP - FORM 10-K

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EXCEL - IDEA: XBRL DOCUMENT - Gulf South Pipeline Company, LP	Financial_Report.xls
EX-32.2 - GS EXHIBIT 32.2 - Gulf South Pipeline Company, LP	gs1410kq4ex322.htm
EX-31.1 - GS EXHIBIT 31.1 - Gulf South Pipeline Company, LP	gs1410kq4ex311.htm
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EX-12.1 - GS EXHIBIT 12.1 - Gulf South Pipeline Company, LP	gs14q410kex121.htm
EX-32.1 - GS EXHIBIT 32.1 - Gulf South Pipeline Company, LP	gs1410kq4ex321.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, 2014

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

For the transition period from _______________ to _______________



Commission file number: 01-32665
GULF SOUTH PIPELINE COMPANY, LP
(Exact name of registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of incorporation or organization)
20-3265614
(I.R.S. Employer Identification No.)
9 Greenway Plaza, Suite 2800 Houston, Texas 77046 (866) 913-2122
(Address and Telephone Number of Registrant’s Principal Executive Office)
Securities registered pursuant to Section 12(b) of the Act: NONE

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No ý

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

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

Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

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

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

Documents incorporated by reference. None.

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

TABLE OF CONTENTS

2014 FORM 10-K

GULF SOUTH PIPELINE COMPANY, LP



PART I	3
Item 1. Business	3
Item 1A. Risk Factors	8
Item 1B. Unresolved Staff Comments	15
Item 2. Properties	15
Item 3. Legal Proceedings	15
Item 4. Mine Safety Disclosures	15
PART II	16
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6. Selected Financial Data	16
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	25
Item 8. Financial Statements and Supplementary Data	26
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	49
Item 9A. Controls and Procedures	49
PART III	50
Item 10. Directors, Executive Officers and Corporate Governance	50
Item 11. Executive Compensation	50
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 13. Certain Relationships and Related Transactions, and Director Independence	50
Item 14. Principal Accounting Fees and Services	50
PART IV	51
Item 15. Exhibits and Financial Statement Schedule	51

PART I

Item 1. Business

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

Introduction

We are a wholly-owned subsidiary of Boardwalk Pipelines, LP (Boardwalk Pipelines), which is a wholly-owned subsidiary of Boardwalk Pipeline Partners, LP (Boardwalk Pipeline Partners or the master limited partnership). Boardwalk Pipeline Partners is a publicly-traded Delaware limited partnership formed in 2005. Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns the majority of the limited partnership units of Boardwalk Pipeline Partners, and through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, Boardwalk Pipeline Partners’ 2% general partner interest and all its incentive distribution rights. In January 2015, Petal Gas Storage, LLC (Petal), a wholly-owned subsidiary of Boardwalk Pipelines, was merged into our operations.

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. Our pipeline transmission system had a peak day delivery capacity of approximately 7.0 billion cubic feet (Bcf) per day and consisted of approximately 7,400 miles of pipeline and ten 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 (NNS). Our Jackson, Mississippi, gas storage facility has approximately 5.5 Bcf of working gas storage capacity, which is used for operational purposes and is not offered for sale to the market. We also own and operate eight high deliverability salt dome natural gas storage caverns in Forrest County, Mississippi, having approximately 28.6 Bcf of working gas capacity, and own undeveloped land which is suitable for up to five additional storage caverns. We placed into service our Southeast Market Expansion in October 2014. The project added approximately 0.5 Bcf per day of peak-day transmission capacity from multiple locations in Texas and Louisiana to Mississippi, Alabama and Florida.

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

We serve a broad mix of customers, including producers of natural gas, local distribution companies (LDCs), marketers, electric power generators, industrial users and interstate and intrastate pipelines. 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, 2014, approximately 76% of our revenues were derived from capacity reservation fees under firm contracts, approximately 16% 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.

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

The principal sources of supply for our natural gas pipeline system are regional supply hubs and market centers located in the Gulf Coast region, including offshore Louisiana, the Perryville, Louisiana area, the Henry Hub in Louisiana and the Carthage, Texas area. Our pipeline in the Carthage, Texas area provides 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. The Henry Hub serves as the designated delivery point for natural gas futures contracts traded on the New York Mercantile Exchange. Our pipeline system also

has access to unconventional supplies such as the Woodford Shale in southeastern Oklahoma through an interconnect with an affiliated pipeline.

Current Growth Projects

We are currently engaged in the following growth projects, which are discussed below and remain subject to FERC regulatory approval. The estimated total costs of these major projects are expected to be approximately, as follows (in millions):



	Estimated Total Cost ₍₁₎		Expected in service date ₍₁₎	Approximate weighted-average contract life (in years)
Coastal Bend Header	$	720.0	2018		20
Power Plant Project in South Texas		80.0	Second half 2016		20


(1)	Estimates are based on internally developed financial models and time-lines. Factors in the estimates include, but are not limited to, those related to pipeline costs based on mileage, size and type of pipe, materials and construction and engineering costs.

Coastal Bend Header Project: In 2014, we executed precedent agreements with foundation shippers to transport approximately 1.4 Bcf per day of natural gas to serve a planned liquefaction terminal in Freeport, Texas. The project will consist of the construction of an approximately 65-mile pipeline supply header to serve the terminal as well as expansion and modifications to our existing pipeline facilities that will provide access to additional supply sources.

Power Plant Project in South Texas: In 2015, we executed a precedent agreement with a foundation shipper for a project which consists of the addition of compression facilities and modifications of our existing facilities to increase the operating capacity of certain sections of our pipeline. The project will provide transportation services of 0.2 Bcf per day to a new power plant in South Texas.

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

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

Customers and Markets Served

We contract directly with producers of natural gas, and with end-use customers including LDCs, marketers, electric power generators, industrial users and interstate and intrastate pipelines who, in turn, provide transportation and storage services to end-users. Based on 2014 revenues, our customer mix was as follows: natural gas producers (45%), interstate and intrastate pipelines (18%), marketers (15%), LDCs (15%), power generators (6%) and industrial end users and others (1%). Based upon 2014 revenues, our deliveries were as follows: pipeline interconnects (69%), LDCs (15%), storage activities (6%), industrial end-users (5%), power generators (4%) and others (1%). One non-affiliated customer, EOG Resources, Inc., accounted for approximately 11% of our 2014 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.

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.

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.

LDCs. Most of our LDC customers use firm natural gas transportation services, including NNS. We serve approximately 85 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 21 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 150 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 natural gas supply sources that are closer to some of our traditional natural gas market areas. In addition, regulators’ continuing efforts to increase competition in the natural gas industry have increased the natural gas transportation options of our traditional customers. As a result of regulators’ policies, capacity segmentation and capacity release have created an active secondary market which increasingly competes with our own natural gas pipeline services. Further, natural gas competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative fuel sources.

The principal elements of competition among pipelines are availability of 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, such as modifying it to allow for bi-directional flows, to meet the demands of customers such as power generators and industrial users, and are continually reviewing our services and terms of service to offer customers enhanced service options.

Government Regulation

Federal Energy Regulatory Commission. FERC regulates us under the Natural Gas Act of 1938 (NGA) 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.

In October 2014, we filed a rate case with FERC pursuant to Section 4 of the NGA (Docket No. RP 15-65), in which we are requesting, among other things, a reconfiguration of the transportation rate zones on our system and, in general, increase in our tariff rates. The new tariff rates are expected to become effective May 1, 2015, subject to refund, which means that we will be responsible for refunds if the FERC later finds that our proposed rates are not just and reasonable. Since the rate case is in the initial stages, the ultimate outcome and impacts on our earnings and cash flows for 2015 and beyond cannot be predicted at this time.

U.S. Department of Transportation (DOT). We are regulated by DOT, through the Pipeline and Hazardous Materials Safety Administration (PHMSA), under the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979 (NGPSA). The NGPSA governs the design, installation, testing, construction, operation, replacement and management of interstate natural gas pipeline facilities. We have received authority from PHMSA to operate certain natural gas pipeline assets under special permits that will allow us to operate those pipeline assets at higher than normal operating pressures of up to 0.80 of the pipe’s Specified Minimum Yield Strength (SMYS). Operating at higher than normal operating pressures will allow us to transport all of the volumes we have contracted for with our customers. PHMSA retains discretion whether to grant or maintain authority for us to operate our natural gas pipeline assets at higher pressures. PHMSA has also developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain high risk areas along our pipeline and take additional measures to protect pipeline segments located in highly populated areas. The NGPSA was most recently amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act) in 2012, with the 2011 Act requiring increased maximum civil penalties for certain violations to $200,000 per violation per day, and an increased total cap of $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in more stringent safety controls or additional natural gas and hazardous liquids pipeline safety rulemaking. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.

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


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


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


•	the Comprehensive Environmental Response, Compensation and Liability Act, commonly referred to as CERCLA, or the Superfund law, and analogous state laws which regulate the cleanup of hazardous substances that may have been

released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;


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


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

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

Effects of Compliance with Environmental Regulations

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

Employee Relations

At December 31, 2014, we had approximately 600 employees. A satisfactory relationship exists between management and labor. We maintain various defined contribution plans covering substantially all of our employees and various other plans which provide regular active employees with medical, life and disability coverage. Note 8 in Part II, Item 8 of this Report contains further information regarding our employee benefits.

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

Our actual construction and development costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate.

We are engaged in multiple significant construction projects involving existing and new assets for which we have expended or will expend significant capital, and we expect to engage in additional growth projects of this type. The construction of new assets involves regulatory, environmental, legal, political, materials and labor cost, operational and other risks that are difficult to predict and beyond our control. Any of these projects may not be completed on time or at all, may be impacted by significant cost overruns or may be materially changed prior to completion as a result of developments or circumstances that we are not aware of when we commit to the project, including the ability of any foundation shippers to provide adequate credit support or to otherwise perform their obligations under any precedent agreements. Any of these factors could result in material unexpected costs or have a material adverse effect on our ability to realize the anticipated benefits from our growth projects.

Our revenues and cash flows may not increase immediately on our expenditure of funds on a particular project. For example, if we build a new pipeline or expand an existing facility, the design, construction and development may occur over an extended period of time and we may not receive any increase in revenue or cash flow from that project until after it is placed in service and customers begin using the new facilities.

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

Transportation rates we are able to charge customers are heavily influenced by longer-term trends in, for example, the amount and geographical location of natural gas production and demand for gas by end-users such as power plants, petrochemical facilities and liquefied natural gas (LNG) export facilities. As a result of changes in longer-term trends such as the development of gas production from the Marcellus and Utica areas located in the Northeastern U. S. and changes to related pipeline infrastructure, basis differentials corresponding to traditional flow patterns on our pipeline system have narrowed significantly in recent years, reducing the transportation rates and adversely impacting other contract terms we can negotiate with our customers for available transportation capacity and for contracts scheduled for renewal for our transportation services. These conditions have and we expect will continue to materially adversely affect our revenues and cash flows.

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

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

We may not be able to sell our storage capacity at attractive rates or at all due to narrowing of price spreads between time periods and reduced volatility which adversely affect our storage services.

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

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. Credit risk exists in relation to one of our recently announced growth projects which requires the foundation shippers to provide credit support as construction progresses. Further, in 2014, approximately 45% of our revenues were generated from contracts with natural gas producers, a significant number of which are integrated oil companies. In the second half of 2014, oil prices declined significantly and the outlook for oil prices indicated that prices could remain depressed for the foreseeable future. Should the price of oil remain at its current level for a sustained period of time, we could be exposed to increased credit risk associated with the producer customer group.

Our exposure also relates to receivables for services provided, future performance under firm agreements and volumes of gas owed by customers for imbalances or gas loaned by us to them under NNS and PAL 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 post the required credit support for our construction efforts, or to repay the gas they owe us, it could have a material adverse effect on our business. In addition, our FERC gas tariff only allows us to require limited credit support in the event that our transportation customers are unable to pay for our services. As contracts expire, the failure of any of our customers could also result in the non-renewal of contracted capacity. Part II, Item 7A of this Report contains more information on credit risk arising from gas loaned to customers.

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

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

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

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

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

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

including construction of our growth projects, reducing our operations to lower expenses and reducing other discretionary uses of cash.

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

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

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

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

We are subject to regulation by PHMSA of the DOT under the NGPSA as amended. The NGPSA governs the design, installation, testing, construction, operation, replacement and management of natural gas pipeline facilities. These amendments have resulted in the adoption of rules through PHMSA, that require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas (HCAs), 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. PHMSA may develop more stringent regulations applicable to integrity management programs and other aspects of our operations, which may be hastened by recently highly-publicized incidents on certain pipelines in the U.S. We could incur significant additional costs if new or more stringent pipeline safety requirements are implemented.

The 2011 Act was enacted and signed into law in early 2012. Under the 2011 Act, maximum civil penalties for certain violations have been increased to $200,000 per violation per day, and from a total cap of $1.0 million to $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in more stringent safety controls or inspections or 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.

Further, we have entered into firm transportation contracts with shippers which utilize the design capacity of certain of our pipeline assets, assuming that we operate those pipeline assets at higher than normal operating pressures of up to 0.80 of the pipeline's SMYS. We have authority from PHMSA to operate those pipeline assets at such higher pressures; however, PHMSA retains discretion to withdraw or modify this authority. If PHMSA were to withdraw or materially modify such authority, we may not be able to transport all of our contracted quantities of natural gas on our pipeline assets and could incur significant additional costs to re-obtain such authority or to develop alternate ways to meet our contractual obligations.

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

Our natural gas transportation and storage 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. FERC can also deny us the right to remove certain facilities from service.

FERC also regulates the rates we can charge for our natural gas transportation and storage operations. For our cost-based services, FERC establishes both the maximum and minimum rates we can charge. The basic elements that FERC considers are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. We may not be able to earn a return or recover all of our costs, including certain costs associated with pipeline integrity, through existing or future rates. In October 2014, we filed a rate case with FERC pursuant to Section 4 of the NGA (Docket No. RP15-65) in which we are requesting, among other things, a reconfiguration of the transportation rate zones on our system and, in general, an increase in our tariff rates. The new tariff rates are expected to become effective May 1, 2015, and subject to refund, which means that we will be responsible for refunds if the FERC later finds that our proposed rates are not just and reasonable. The rate case is in the initial stages and the ultimate outcome and impacts on our operating revenues and cash flows for 2015 and beyond cannot be predicted at this time.

FERC can challenge the existing rates on any of 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.

If we had to defend our rates in a proceeding commenced by FERC, we would be required, among other things, to establish that the inclusion of an income tax allowance in our cost of service is just and reasonable. Under current FERC policy, since Boardwalk Pipeline Partners is a limited partnership and does not pay U.S. federal income taxes, this would require Boardwalk Pipeline Partners' 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.

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

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;


•	new or amended laws and regulations, new regulations adopted by governmental authorities such as the DOT, PHMSA and the U.S. Environmental Protection Agency (EPA), including, for example, greenhouse gas legislation and taxation; and


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

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

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

Our 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 transporting and storing natural gas, such as leaks and other forms of releases, explosions, fires and mechanical problems, some of which could have catastrophic consequences. 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, catastrophic 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 in HCAs, which include populated areas, 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.

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

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

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

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

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

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

We rely on a limited number of customers for a significant portion of revenues. Our largest non-affiliated customer in terms of revenues, EOG Resources, Inc. represented over 11% of our 2014 revenues. Including revenues earned from affiliates, our top ten customers comprised approximately 58% of our revenues in 2014. We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms which could materially reduce our contracted transportation volumes and the rates we can charge for our services.

Failure to comply with existing or new worker safety or 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 worker safety or the environment. These laws include, for example, the CAA, the Clean Water Act, CERCLA, the Resource Conservation and Recovery Act, OSHA and analogous state laws. These laws and regulations may restrict or impact our business activities in many ways, including requiring the acquisition of permits or other approvals to conduct regulated activities, restricting the manner in which we handle or dispose of wastes, requiring remedial action to remove or mitigate contamination resulting from a spill or other release, requiring capital expenditures to comply with pollution control requirements, imposing safety and health criteria addressing worker protection, 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. Under certain of these environmental laws and regulations, we could be subject to joint and several or strict liability for the removal or remediation of previously released pollutants or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all laws. We may not be able to recover some or any of the costs incurred from insurance.

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

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

We compete with other pipelines.

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

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

The continued threat of terrorism and the impact of retaliatory military and other action by the U.S. and its allies might lead to increased political, economic and financial market instability and volatility in prices for natural gas, which could affect the markets for our natural gas transportation and storage services. While we are taking steps that we believe are appropriate to increase the security of our assets, we may not be able to completely secure our assets or completely protect them against a terrorist attack.

Tax Risks

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

Despite the fact that we and Boardwalk Pipeline Partners are organized as limited partnerships under Delaware law, Boardwalk Pipeline Partners would be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based upon Boardwalk Pipeline Partners’ current operations, it believes it satisfies the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause Boardwalk Pipeline Partners to be treated as a corporation for federal income tax purposes or otherwise subject Boardwalk Pipeline Partners to taxation as an entity.

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

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of a similar tax on us or Boardwalk Pipeline Partners in the jurisdictions in which we operate could substantially reduce the cash flow available to service our debt.

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

The present federal income tax treatment of publicly traded partnerships, including Boardwalk Pipeline Partners, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels, such as Boardwalk Pipeline Partners, be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider substantive changes to the existing 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 federal income tax purposes.

In addition, the IRS has been considering changes to its private letter ruling policy concerning which activities give rise to qualifying income within the meaning of section 7704 of the Code. The implementation of changes to this policy could include the modification or revocation of existing rulings, including Boardwalk Pipeline Partners' private letter ruling.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for Boardwalk Pipeline Partners to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the cash flow available to service our debt. Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for Boardwalk Pipeline Partners to meet the qualifying income requirement to be treated as a partnership for federal income tax purposes.

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. Our Business, in 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 Part II, Item 8 of this Report for a discussion of our legal proceedings.

Item 4. Mine Safety Disclosures

None.

PART II

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

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

Item 6. Selected Financial Data

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

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

Overview

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. In January 2015, Petal, a wholly-owned subsidiary of Boardwalk Pipelines, was merged into our operations.

Our pipeline system consists of approximately 7,400 miles of interconnected pipelines with a peak day delivery capacity of approximately 7.0 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 ten natural gas storage facilities located in two states with aggregate working gas capacity of approximately 112.1 Bcf.

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

Recent Developments

Market Conditions and Contract Renewals

Transportation rates we are able to charge customers are heavily influenced by longer-term trends in, for example, the amount and geographical location of natural gas production and demand for gas by end-users such as power plants, petrochemical facilities and liquefied natural gas (LNG) export facilities. As a result of changes in longer-term trends such as the development of gas production from the Marcellus and Utica production areas located in the Northeastern United States and changes to related pipeline infrastructure, basis differentials corresponding to traditional flow patterns on our pipeline system (generally south to north and west to east) have narrowed significantly in recent years, reducing the transportation rates and adversely impacting other contract terms we can negotiate with our customers for available transportation capacity and for contracts due for renewal for our transportation services. These conditions have had and we expect will continue to have, a material adverse effect on our revenues and cash flows.

A substantial portion of our transportation capacity is contracted for under firm transportation agreements. Each year a portion of our firm transportation agreements expire and need to be renewed or replaced. Due to the factors noted above and discussed elsewhere in this Report, in recent periods we have generally seen the renewal of expiring transportation contracts at lower rates and for shorter terms than in the past which has materially adversely impacted our transportation revenues. Capacity not renewed and available for sale on a short-term basis has been and continues to be sold at rates reflective of basis spreads, which generally have been lower than historical rates, under short-term firm or interruptible contracts or in some cases not sold at all. Rates for short-term and interruptible transportation services are influenced by the factors discussed above but can be more heavily affected by shorter-term conditions such as current and forecasted weather. For a discussion of additional risks associated with our revenues, please see Item 1A. Risk Factors - We may not be able to replace expiring gas transportation contracts at attractive rates or on a long-term basis and may not be able to sell short-term services at attractive rates or at all due to narrower basis differentials which adversely affect the value of our transportation services.

We are beginning to experience an increase in demand to transport gas from north to south instead of south to north as has been our traditional flow pattern. This demand is being driven by increases in gas production from primarily the Marcellus and Utica production areas and growing demand for natural gas primarily in the Gulf Coast area from new and planned power plants, petrochemical facilities and LNG export facilities. This new flow pattern is resulting in growth projects for us that require significant capital expenditures, among other things, to make parts of our system bi-directional, and in many instances, will utilize

existing pipeline capacity that has been turned back to us by customers that have not renewed expiring contracts. As discussed elsewhere in this Report, these projects have lengthy planning and construction periods and as a result will not contribute to our earnings and cash flows until they are placed into service over the next several years. In some instances the projects remain subject to regulatory approval to commence construction, and these projects are subject to the risk that they may not be completed, may be impacted by significant cost overruns or may be materially changed prior to completion as a result of future developments or circumstances that we cannot predict at this time.

The value of our storage and PAL services (comprised of parking gas for customers and/or lending gas to customers) is affected by natural gas price differentials between time periods, such as winter to summer (time period price spreads), price volatility of natural gas and other factors. We have seen the value of our storage and PAL services adversely impacted by some of the market factors discussed above which have contributed to a narrowing of time period price spreads, which in turn has reduced the rates we can charge and the capacity we can sell under our storage and PAL services. Our storage and parking services have greater value when the natural gas futures market is in contango (a positive time period price spread, meaning that current price quotes for delivery of natural gas in the future are higher than in the nearer term), while our lending service has greater value when the futures market is backwardated (a negative time period price spread, meaning that current price quotes for delivery of natural gas in the nearer term are higher than further in the future). During the first half 2014, the futures market was significantly backwardated partly reflecting the harsh weather conditions in late 2013 and early 2014, and we earned revenues from lending gas to customers under our PAL services. Since then, the futures market has reverted to a contango market, although time period price spreads remain relatively narrow. Storage market fundamentals can be volatile in a relative short period of time. Based on the current narrowing of time period price spreads and fewer market participants due to a decrease in the number of marketers taking storage positions, we are currently experiencing weakened demand for our storage and PAL services.

Pipeline System Maintenance

We incur substantial costs for ongoing maintenance of our pipeline system and related facilities, including those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. These costs are not dependent on the amount of revenues earned from our natural gas transportation services. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. These regulations have resulted in an overall increase in our ongoing maintenance costs, including maintenance capital and maintenance expense. PHMSA has proposed more stringent regulations, which if implemented, could require us to incur significant additional costs. See Item 1, Business - Government Regulation for further information.

Maintenance costs may be capitalized or expensed, depending on the nature of the activities. For any given reporting period, the mix of projects that we undertake will affect the amounts we record as property, plant and equipment on our balance sheet or recognize as expenses, which impacts our earnings. Refer to Capital Expenditures for more information regarding certain of our maintenance costs and additional pipeline integrity upgrades.

Credit Risk

In the second half of 2014, oil prices declined significantly and the outlook for oil prices indicated that prices could remain depressed for the foreseeable future. In 2014, approximately 45% of our revenues were generated from contracts with natural gas producers, a significant number of which are integrated oil companies. Further, one of our growth projects is supported by contracts with oil companies. Should the price of oil remain at its current level for a sustained period of time, we could be exposed to increased credit risk associated with the producer customer group.

Rate Case

On October 24, 2014, we filed a rate case with FERC pursuant to Section 4 of the NGA (Docket No. RP15-65), in which we are requesting, among other things, a reconfiguration of the transportation rate zones on our system and, in general, an increase in our tariff rates. The new tariff rates are expected to become effective May 1, 2015, subject to refund, which means that we will be responsible for refunds if the FERC later finds that our proposed rates are not just and reasonable. The rate case is in the initial stages, therefore, the ultimate outcome and impacts on our earnings and cash flows for 2015 and beyond cannot be predicted at this time.

Petal Merger

Effective January 1, 2015, Petal, a wholly-owned subsidiary of Boardwalk Pipelines, was merged into our operations upon approval from FERC. Petal owned and operated eight high deliverability salt dome natural gas storage caverns in Forrest County, Mississippi, having approximately 45.5 Bcf of total storage capacity, of which approximately 28.6 Bcf is working gas capacity. Petal also operated approximately 100 miles of pipeline which connects its facilities with several major natural gas pipelines and owned undeveloped land which is suitable for up to five additional storage caverns.

Results of Operations

2014 Compared with 2013

Our net income for the year ended December 31, 2014, decreased $28.3 million, or 32%, to $59.9 million compared to $88.2 million for the year ended December 31, 2013 as a result of the factors discussed below.

Operating revenues for the year ended December 31, 2014, decreased $1.4 million to $467.3 million, compared to $468.7 million for the year ended December 31, 2013. The decrease in revenues was primarily due to $15.1 million of lower storage and PAL revenues as a result of the effects of unfavorable market conditions on time period price spreads. The decrease was mostly offset by an increase in fuel retained of $11.4 million from higher natural gas prices and an increase in transportation revenues generally due to growth projects which were recently placed into service.

Operating costs and expenses for the year ended December 31, 2014, increased $30.2 million, or 9%, to $370.3 million, compared to $340.1 million for the year ended December 31, 2013. The increase in operating expenses was driven by an increase of $15.4 million increase in Fuel and transportation expenses mainly driven by an increase in natural gas prices and a $5.0 million increase in depreciation expense primarily due to an increase in our asset base. The increase was partially offset by $3.9 million of lower Operation and maintenance expense primarily due to a legal settlement and lower major maintenance expense. The 2013 period was favorably impacted by $17.0 million from gains on the sale of storage gas.

Total other deductions for the year ended December 31, 2014, decreased by $3.3 million, or 8%, to $37.1 million compared to $40.4 million for the year ended December 31, 2013, driven by a reduction in interest expense from increased capitalized interest as a result of increased capital project spending.

Liquidity and Capital Resources

Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility, debt issuances and advances from affiliates. We use cash 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 (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 be adequate to maintain our current level of operations and planned operations, including our capital expenditures.

Revolving Credit Facility

Boardwalk Pipelines maintains a revolving credit facility under which we may borrow funds, subject to a sublimit of $200.0 million. As of December 31, 2014, we had no borrowings outstanding under our revolving credit facility, no letters of credit issued thereunder and had $200.0 million of available borrowing capacity under our revolving credit facility.

The credit facility, which matures in April 2017, contains various restrictive covenants and other usual and customary terms and conditions, including the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the credit facility requires Boardwalk Pipelines and its subsidiaries, including us, to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the Amended Credit Agreement) measured for the previous twelve months of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following an acquisition. We were in compliance with all covenant requirements under the credit facility as of December 31, 2014. Note 7 in Part II, Item 8 of this Report contains more information regarding our revolving credit facility.

Capital Expenditures

We capitalize construction costs and expenditures for major renewals and improvements which extend the lives of the respective assets. Consistent with Boardwalk Pipeline Partners’ partnership agreement, growth expenditures are those expenditures associated with projects which are expected to increase an asset’s operating capacity or our revenues or cash flows from that which existed immediately prior to the addition or improvement and which are expected to produce a financial return. Capital expenditures associated with projects that do not meet the preceding criteria are considered maintenance capital expenditures.

We are currently engaged in several growth projects, described in Part I, Item 1, Business - Current Growth Projects, of this Report. A summary of the estimated total costs of these projects and inception to date spending as of December 31, 2014 are as follows (in millions):



	Estimated Total Cost ⁽¹⁾		Cash Invested Through December 31, 2014
Coastal Bend Header	$	720.0	$	2.0
Power Plant Project in South Texas	80.0		—
Other growth projects	35.0		—
Total	$	835.0	$	2.0


(1)	Our cost estimates are based on internally developed financial models and time-lines. Factors in the estimates include, but are not limited to, those related to pipeline costs based on mileage, size and type of pipe, materials and construction and engineering costs.

Our cost and timing estimates for these projects are subject to a variety of risks and uncertainties, including obtaining regulatory approvals; adverse weather conditions; acquiring the right to construct and operate on other owners’ land; delays in obtaining key materials; and shortages of qualified labor. Refer to Part I, Item 1A Risk Factors for additional risks associated with our growth projects and the related financing.

The nature of our existing growth projects will require us has to enhance or modify our existing assets to accommodate increased operating pressures or changing flow patterns. We consider capital expenditures associated with the modification or enhancement of existing assets in the context of a growth project to be growth capital to the extent that the modification would not have been made in the absence of the growth project without regard to the condition of the existing assets.

In January 2015, we experienced a pipeline rupture on our pipeline in a remote area north of Jackson, Mississippi. As a result, we took that pipeline out of service and reduced operating pressures on certain other pipeline sections. The ruptured pipeline has been repaired, though it will not be returned to service until approval has been received from PHMSA. The pipeline rupture occurred at a time when we were beginning to reassess our pipeline integrity plans, particularly for our pipeline in that region, in light of new opportunities to serve demand markets in Texas, for example our Coastal Bend Project and our power plant project. To accommodate these opportunities and otherwise ensure the integrity of our pipeline systems, over the next four years, we will upgrade sections of our pipeline systems, including upgrades needed to reconfigure certain segments of our existing pipelines to flow bi-directionally and to increase the operating capacity of those or other pipeline segments. This will require us to upgrade or replace existing segments that may have otherwise been upgraded or replaced at some point in the future, but are being upgraded

or replaced earlier, or are being upgraded or replaced solely as a result of the growth opportunities. As a result, the expenditures associated with these activities may contain elements of both growth and maintenance capital.

Growth capital expenditures were $229.5 million, $73.6 million and $4.7 million for the years ended December 31, 2014, 2013 and 2012. The 2014 growth capital expenditures primarily relate to our Southeast Market Expansion project which was placed into service in October 2014. We did not incur a material amount of growth expenditures that had elements of both maintenance and growth capital in 2014, 2013 and 2012. Maintenance capital expenditures for the years ended December 31, 2014, 2013 and 2012 were $51.0 million, $39.2 million and $49.6 million. Our maintenance capital spending increased in 2014 from the comparable period in 2013 due to increased integrity management spending. In 2014, we purchased $14.7 million of natural gas to be used as base gas for our storage facilities.

We expect total capital expenditures to be approximately $107.0 million in 2015, including approximately $40.0 million for maintenance capital and $67.0 million for growth projects. Additionally, in 2015, Boardwalk Pipeline Partners expects to incur approximately $50.0 million of capital expenditures related to pipeline integrity upgrades. We expect to incur the majority of these expenditures. As discussed above, these costs have elements of both growth and maintenance capital. Refer to Pipeline System Maintenance included in Recent Developments for further discussion of trends impacting our maintenance capital expenditures.

Contractual Obligations

The following table summarizes significant contractual cash payment obligations under firm commitments as of December 31, 2014, 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	149.0		36.3		58.7		24.0		30.0
Capital commitments ⁽²⁾	25.9		25.9		—		—		—
Pipeline capacity agreements ⁽³⁾	20.6		6.2		12.4		2.0		—
Operating lease commitments	28.1		3.8		6.9		5.6		11.8
Total	$	1,073.6	$	347.2	$	353.0	$	31.6	$	341.8

(1)

Includes our senior unsecured notes, having maturity dates from 2015 to 2022. We currently have no borrowings outstanding under our revolving credit facility, which has a maturity date of April 27, 2017. The amounts included in the Less than 1 Year column were included in long-term debt on our balance sheet. In November 2014, Boardwalk Pipelines received net proceeds of approximately $342.9 million from the issuance of $350.0 million of 4.95% senior unsecured notes due December 15, 2024. The proceeds were used to temporarily reduce borrowings under Boardwalk Pipelines' revolving credit facility until our $275.0 million aggregate principal amount of 5.05% notes reached maturity on February 1, 2015 (2015 Notes), at which time a portion of the proceeds were used to retire our 2015 Notes. We received the proceeds from Boardwalk Pipelines through an advance from the cash management program.

(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, 2014.

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

Changes in cash flow from operating activities

Net cash provided by operating activities decreased $15.7 million to $163.0 million for the year ended December 31, 2014 compared to $178.7 million for the comparable 2013 period, primarily due to a reduction in our earnings as discussed under Results of Operations, excluding the effects of depreciation and amortization, asset impairment and the net gain on sale of operating assets.

Changes in cash flow from investing activities

Net cash used in investing activities decreased $15.5 million to $162.2 million for the year ended December 31, 2014 compared to $177.7 million for the comparable 2013 period. The decrease was primarily driven by a $222.7 million increase in advances from Boardwalk Pipelines under the cash management program, offset by a $182.4 million increase in capital expenditures and a $24.3 million decrease in proceeds received from the sale of operating assets mainly related to the 2013 sale of operating assets, including storage gas.

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, 2014, we had no guarantees of off-balance sheet debt to third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings, and no other off-balance sheet arrangements.

Critical Accounting Estimates and Policies

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

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

Regulation

We are regulated by FERC. Pursuant to FERC regulations certain revenues that we collect may be subject to possible refunds to our customers. Accordingly, during an open rate case, estimates of rate refund reserves are recorded based on regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. In October 2014, as discussed above, we filed a rate case with the FERC pursuant to Section 4 of the NGA (Docket No. RP15-65). At December 31, 2014 and 2013, there were no liabilities for any open rate case recorded on our Balance Sheets.

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 Part II, 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, 2014, we had accrued approximately $4.8 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 Part II, 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 and intangible assets have been impaired when circumstances indicate the carrying amount of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount is not recoverable, an impairment loss is measured as the excess of the asset’s carrying amount over its fair value. Note 5 in Part II, Item 8 of this Report contain more information regarding impairments we have recognized.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this Report, as well as some statements in periodic press releases and some oral statements made by our officials 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 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 recently announced growth projects are supported by foundation shippers, some of which are major integrated oil companies. The recent decrease in oil and natural gas prices could impact the foundation shippers' ability to obtain credit support in the future and cause our counterparty credit risk to increase;


•	we may not complete projects, including growth projects, that we have commenced or will commence, or we may complete projects on materially different terms, cost or timing than anticipated and we may not be able to achieve the intended economic or operational benefits of any such projects, if completed;


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


•	our ability to maintain or replace expiring gas transportation and storage contracts, to contract and physically make our systems bi-directional and to sell short-term capacity on our pipeline;


•	the costs of maintaining and ensuring the integrity and reliability of our pipeline system, the need to remove pipeline and other assets from service as a result of such activities, and the timing and financial impacts of returning any such assets to service;


•	the ability of our customers to pay for our services, including the ability of any foundation shippers on our growth projects to provide required credit support or otherwise comply with the terms of precedent agreements;


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


•	volatility or disruptions in the capital or financial markets;


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


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


•	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;


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


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


•	the future cost of insuring our assets; and


•	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.

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 our 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):



	2014			2013
Carrying amount of fixed-rate debt	$	847.1		$	846.3
Fair value of fixed-rate debt	$	874.8		$	889.7
100 basis point increase in interest rates and resulting debt decrease	$	25.8		$	32.9
100 basis point decrease in interest rates and resulting debt increase	$	27.4		$	35.1
Weighted-average interest rate	5.33		%	5.33		%

At December 31, 2014 and 2013, and at the time of this filing, we had no borrowings outstanding under the revolving credit facility. A significant amount of our debt, including the revolving credit facility, will mature over the next five years. We expect to refinance the debt either prior to or at maturity. Our ability to refinance the debt at interest rates that are currently available is subject to risk at the magnitude illustrated in the table above. We expect to refinance the remainder of our debt that will mature based on our assessment of the term rates of interest available in the market.

Commodity risk:

We do not take title to the natural gas which we transport and store; therefore, we do not assume the related commodity price risk. However, certain volumes of our gas stored underground are available for sale and subject to commodity price risk. We have historically managed our exposure to commodity price risk through the use of futures, swaps and option contracts. At December 31, 2014, we had no gas stored underground available for sale and no outstanding derivatives. Note 4 in Part II, Item 8 contains additional information regarding derivatives.

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 NNS contracts. 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, 2014, 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 2014 of $3.36 per million British thermal units (MMBtu), the market value of that gas was approximately $6.0 million. As of December 31, 2013, the amount of gas loaned out by us or owed to us due to gas imbalances was approximately 2.9 TBtu. Assuming an average market price during December 2013 of $4.17 per MMBtu, the market value of this gas at December 31, 2013, would have been approximately $12.1 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. Refer to Part I, Item 1A. Risk Factors - We are exposed to credit risk relating to nonperformance by our customers - for further discussion regarding credit risk and the potential effects of declining oil prices on our credit risk.

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, 2014 and 2013, and the related statements of income, comprehensive income, cash flows, and changes in partner's capital for each of the three years in the period ended December 31, 2014. 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Houston, Texas

March 10, 2015

GULF SOUTH PIPELINE COMPANY, LP

BALANCE SHEETS

(Millions)



	December 31,
ASSETS	2014		2013
Current Assets:
Cash	$	1.9	$	1.1
Receivables:
Trade		29.1		29.5
Affiliates		5.8		8.9
Other		3.7		7.0
Gas receivables:
Transportation		6.1		4.2
Transportation - affiliates		1.5		2.0
Advances to affiliates		—		192.6
Gas stored underground		0.3		0.3
Prepayments		5.6		4.6
Other current assets		0.9		2.0
Total current assets		54.9		252.2

Property, Plant and Equipment:
Natural gas transmission and other plant		3,702.0		3,342.5
Construction work in progress		42.5		109.6
Property, plant and equipment, gross		3,744.5		3,452.1
Less-accumulated depreciation and amortization		820.2		707.1
Property, plant and equipment, net		2,924.3		2,745.0

Other Assets:
Gas stored underground		3.8		2.3
Advances to affiliates		61.5		—
Other		5.8		5.5
Total other assets		71.1		7.8

Total Assets	$	3,050.3	$	3,005.0

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	2014			2013
Current Liabilities:
Payables:
Trade	$	19.0		$	26.4
Affiliates		3.2			2.5
Other		1.4			1.3
Gas Payables:
Transportation		4.1			5.5
Transportation – affiliates		5.5			6.8
Accrued taxes, other		17.9			19.3
Accrued interest		12.8			12.8
Accrued payroll and employee benefits		15.8			14.5
Construction retainage		5.6			3.6
Deferred income		0.9			7.6
Other current liabilities		6.3			10.4
Total current liabilities		92.5			110.7

Long-term debt		847.1			846.3

Other Liabilities and Deferred Credits:
Asset retirement obligation		17.4			17.8
Other		11.8			13.0
Total other liabilities and deferred credits		29.2			30.8

Commitments and Contingencies

Partner's Capital:
Partner's capital		2,086.5			2,022.7
Accumulated other comprehensive loss		(5.0	)		(5.5	)
Total partner's capital		2,081.5			2,017.2
Total Liabilities and Partner's Capital	$	3,050.3		$	3,005.0

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,
	2014			2013			2012
Operating Revenues:
Transportation	$	360.8		$	348.6		$	387.1
Transportation - affiliates		77.9			75.9			75.0
Parking and lending		16.1			19.9			24.6
Parking and lending - affiliates		—			0.1			—
Gas storage		6.4			17.6			24.5
Other		6.1			6.6			6.0
Total operating revenues		467.3			468.7			517.2

Operating Costs and Expenses:
Fuel and transportation		68.0			55.8			55.8
Fuel and transportation - affiliates		15.8			12.6			14.8
Operation and maintenance		79.7			83.6			86.3
Administrative and general		51.6			50.0			51.1
Depreciation and amortization		114.4			109.4			106.4
Asset impairment		1.0			3.6			6.3
Net gain on sale of operating assets		(0.7	)		(16.6	)		(0.6	)
Taxes other than income taxes		40.5			41.7			41.6
Total operating costs and expenses		370.3			340.1			361.7

Operating income		97.0			128.6			155.5

Other Deductions (Income):
Interest expense		39.4			42.8			47.6
Interest (income) expense - affiliates		(1.7	)		(1.9	)		(1.5	)
Interest income		(0.6	)		(0.5	)		(0.7	)
Total other deductions		37.1			40.4			45.4

Net Income	$	59.9		$	88.2		$	110.1

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,
	2014			2013			2012
Net income	$	59.9		$	88.2		$	110.1
Other comprehensive income (loss):
Loss on cash flow hedges	(0.2		)	(0.1		)	(6.6		)
Reclassification adjustment transferred to Net Income from cash flow hedges	0.7			1.0			0.2
Total Comprehensive Income	$	60.4		$	89.1		$	103.7

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

GULF SOUTH PIPELINE COMPANY, LP

STATEMENTS OF CASH FLOWS

(Millions)



	For the Year Ended December 31,
	2014			2013			2012
OPERATING ACTIVITIES:
Net income	$	59.9		$	88.2		$	110.1
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	114.4			109.4			106.4
Amortization of deferred costs	1.0			0.9			1.1
Asset impairment	1.0			3.6			6.3
Net gain on sale of operating assets	(0.7		)	(16.6		)	(0.6		)
Changes in operating assets and liabilities:
Trade and other receivables	3.6			1.1			1.1
Gas receivables and storage assets	(3.4		)	9.2			(1.9		)
Other assets	2.0			(1.6		)	(3.2		)
Affiliates, net	2.9			1.0			0.7
Trade and other payables	(3.5		)	(7.4		)	(1.9		)
Gas payables	(6.5		)	(3.7		)	11.2
Accrued liabilities	0.8			4.4			(2.9		)
Other liabilities	(8.5		)	(9.8		)	6.8
Net cash provided by operating activities	163.0			178.7			233.2
INVESTING ACTIVITIES:
Capital expenditures	(295.2		)	(112.8		)	(54.3		)
Proceeds from sale of operating assets	1.0			25.3			1.9
Proceeds from insurance and other recoveries	0.9			1.4			6.1
Advances to affiliates	131.1			(91.6		)	(29.8		)
Net cash used in investing activities	(162.2		)	(177.7		)	(76.1		)
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		)
Net cash used in financing activities	—			—			(157.0		)
Increase in cash	0.8			1.0			0.1
Cash at beginning of period	1.1			0.1			—
Cash at end of period	$	1.9		$	1.1		$	0.1

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

GULF SOUTH PIPELINE COMPANY, LP

STATEMENTS OF CHANGES IN PARTNER’S CAPITAL

(Millions)



	Partner's Capital			Accumulated Other Comprehensive Income (Loss)			Total Partner's Capital
Balance January 1, 2012	$	1,855.0		$	—		$	1,855.0
Add (deduct):
Net income	110.1			—			110.1
Distribution of assets	(30.6		)	—			(30.6		)
Other comprehensive loss	—			(6.4		)	(6.4		)
Balance December 31, 2012	1,934.5			(6.4		)	1,928.1
Add (deduct):
Net income	88.2			—			88.2
Other comprehensive gain	—			0.9			0.9
Balance December 31, 2013	2,022.7			(5.5		)	2,017.2
Add (deduct):
Net income	59.9			—			59.9
Contribution of assets	3.9			—			3.9
Other comprehensive gain	—			0.5			0.5
Balance December 31, 2014	$	2,086.5		$	(5.0	)	$	2,081.5

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. Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns the majority of the limited partnership units of Boardwalk Pipeline Partners, and through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, Boardwalk Pipeline Partners’ 2% general partner interest and all its incentive distribution rights. Effective January 1, 2015, Petal Gas Storage, LLC (Petal), a wholly-owned subsidiary of Boardwalk Pipelines, was merged into Gulf South.

Basis of Presentation

The accompanying financial statements of Gulf South were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Certain amounts reported within the 2013 balance sheet have been reclassified to conform to the current presentation.

Note 2: Accounting Policies

Use of Estimates

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

Regulatory Accounting

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

Fair Value Measurements

Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances. Gulf South uses fair value measurements to record derivatives, asset retirement obligations and impairments. Fair value measurements are also used to report fair values for certain items contained in this Report. Gulf South considers any transfers between levels within the fair value hierarchy to have occurred at the beginning of a quarterly reporting period. Gulf South did not recognize any transfers between Level 1 and Level 2 of the fair value hierarchy and did not change its valuation techniques or inputs during the years ended December 31, 2014 and 2013. Notes 4 and 8 contain more information regarding fair value measurements.

Cash

Cash includes demand deposits with banks or other financial institutions. Gulf South had no restricted cash at December 31, 2014 and 2013.

Cash Management

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

Trade and Other Receivables

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

Gas Stored Underground and Gas Receivables and Payables

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

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

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

Materials and Supplies

Materials and supplies are carried at average cost and are included in Other Assets on the Balance Sheets. Gulf South expects its materials and supplies to be used for capital projects related to its property, plant and equipment and for future growth projects. At December 31, 2014 and 2013, Gulf South held approximately $2.4 million and $1.0 million of materials and supplies which were reflected in Other Assets on the Balance Sheets.

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, 2014, 2013 and 2012 was $5.8 million, $2.3 million and $1.0 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, 2014, 2013 and 2012. Gulf South’s tax years 2011 through 2014 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 services 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, 2014 and 2013, Gulf South had deferred revenues of $0.9 million and $7.6 million related to PAL and interruptible storage services. The deferred revenues related to PAL and interruptible storage services at December 31, 2014, will be recognized in 2015 and 2016.

Retained fuel is recognized in revenues at market prices in the month of retention. The related fuel consumed in providing transportation services is recorded in Fuel and transportation expenses on the Statements of Income at market prices in the month consumed. In some cases, customers may elect to pay cash for the cost of fuel used in providing transportation services instead of having fuel retained in-kind. Retained fuel included in Transportation revenues on the Statements of Income for the years ended December 31, 2014, 2013 and 2012 was $56.7 million, $48.1 million and $46.2 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, 2014 and 2013, there were no liabilities for any open rate case recorded on the Balance Sheets.

Asset Retirement Obligations

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

Environmental Liabilities

Gulf South records environmental liabilities based on management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these environmental matters. Note 3 contains more information regarding Gulf South’s environmental liabilities.

Derivative Financial Instruments

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

The changes in fair values of the derivatives designated as cash flow hedges are expected to, and do, have a high correlation to changes in value of the anticipated transactions. Each reporting period Gulf South measures the effectiveness of the cash flow hedge contracts. To the extent the changes in the fair values of the hedge contracts do not effectively offset the changes in the estimated cash flows of the anticipated transactions, the ineffective portion of the hedge contracts is currently recognized in earnings. If it becomes probable that the anticipated transactions will not occur, hedge accounting would be terminated and changes in the fair values of the associated derivative financial instruments would be recognized currently in earnings. Gulf South did not discontinue any cash flow hedges during 2014 and 2013.

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, 2014, 2013, and 2012. Note 4 contains more information regarding Gulf South’s derivative financial instruments.

Note 3: Commitments and Contingencies

Legal Proceedings and Settlements

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

Whistler Junction Matter

Gulf South and several other defendants, including Mobile Gas Service Corporation (MGSC), have been named as defendants in ten lawsuits, including one purported class action suit, commenced by multiple plaintiffs in the Circuit Court of Mobile County, Alabama. The plaintiffs seek unspecified damages for personal injury and property damage related to an alleged release of mercaptan at the Whistler Junction facilities in Eight Mile, Alabama. Gulf South delivers natural gas to MGSC, the local distribution company for that region, at Whistler Junction where MGSC odorizes the gas prior to delivery to end user customers by injecting mercaptan into the gas stream, as required by law. The cases are: Parker, et al. v. MGSC, et al. (Case No. CV-12-900711), Crum, et al. v. MGSC, et al. (Case No. CV-12-901057), Austin, et al. v. MGSC, et al. (Case No. CV-12-901133), Moore, et al. v. MGSC, et al. (Case No. CV-12-901471), Davis, et al. v. MGSC, et al. (Case No. CV-12-901490), Joel G. Reed, et al. v. MGSC, et al. (Case No. CV-2013-922265), The Housing Authority of the City of Prichard, Alabama v. MGSC., et al. (Case No. CV-2013-901002), Robert Evans, et al. v. MGSC, et al. (Case No. CV-2013-902627), Devin Nobles, et al. v. MGSC, et al. (Case No. CV-2013-902786) and Richard Eldridge, et al. v. MGSC., et al. (Case No. CV-2014-903209).

In May 2014, Gulf South and MGSC reached an agreement whereby MGSC fully indemnified Gulf South against all liability related to this matter and the cross-claims between Gulf South and MGSC were settled.

Southeast Louisiana Flood Protection Litigation

Gulf South and Boardwalk Pipeline Partners, along with approximately 100 other energy companies operating in Southern Louisiana, have been named as defendants in a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) by the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (Flood Protection Authority). The case was filed in state court, but was removed to the United States District Court for the Eastern District of New Orleans (Court) in August 2013. The plaintiff has moved for remand back to state court, which motion has been argued and is under consideration by the court. The lawsuit claims include negligence, strict liability, public nuisance, private nuisance, breach of contract, and breach of the natural servitude of drain against the defendants, alleging that the defendants’ drilling, dredging, pipeline and industrial operations since the 1930s have caused increased storm surge risk, increased flood protection costs and unspecified damages to the Flood Protection Authority. In addition to attorney fees and unspecified monetary damages, the lawsuit seeks abatement and restoration of the coastal lands, including backfilling and revegetating of canals dredged and used by the defendants, and abatement and restoration activities such as wetlands creation, reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, bank stabilization, and ridge restoration. On February 13, 2015, the court dismissed the case with prejudice.

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, 2014, and 2013, Gulf South had an accrued liability of approximately $4.8 million and $5.3 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 seven years. As of December 31, 2014, and 2013, approximately $1.1 million and $1.2 million were recorded in Other current liabilities and approximately $3.7 million and $4.1 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.

On November 25, 2014, the EPA proposed to lower the 8-hour ozone standard relevant to non-attainment areas. Under the proposal, the EPA anticipates taking final action by October 1, 2015, designating new non-attainment areas by October 1, 2017, and requiring states to revise implementation plans by October 1, 2020, with compliance dates anticipated between 2021 and 2037 determined by the degree of non-attainment. Since non-attainment area designations will likely be based on 2014-2016 air quality monitoring data and because states will likely pursue various means to achieve the necessary reductions, additional facility impacts cannot be determined at this time. Gulf South will continue to monitor the rulemaking process 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 United States (U.S.) that annually emit 25,000 or more metric tons of greenhouse gases, including carbon dioxide, methane and others. Additionally, Gulf South is required to conduct periodic and various facility surveys across its entire system to comply with the EPA's greenhouse gas emission calculations and reporting regulations. Some states have also adopted laws regulating greenhouse gas emissions, although none of the states in which Gulf South operates have adopted such laws. The federal rules and determinations regarding greenhouse gas emissions have not had, and are not expected to have, a material effect on Gulf South's financial condition, results of operations or cash flows.

Lease Commitments

Gulf South has various operating lease commitments extending through the year 2024 generally covering office space and equipment rentals. Total lease expense for the years ended December 31, 2014, 2013 and 2012 were approximately $2.9 million, $2.5 million and $3.8 million. The following table summarizes minimum future commitments related to these items at December 31, 2014 (in millions):



2015	$	3.8
2016	3.6
2017	3.3
2018	3.0
2019	2.6
Thereafter	11.8
Total	$	28.1

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, 2014, were approximately $25.9 million, all of which are expected to be settled in 2015.

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 $9.5 million, $6.3 million and $6.5 million related to pipeline capacity agreements for the years ended December 31, 2014, 2013 and 2012. The future commitments related to pipeline capacity agreements as of December 31, 2014, were (in millions):



2015	$	6.2
2016	6.2
2017	6.2
2018	2.0
2019	—
Thereafter	—
Total	$	20.6

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

Gulf South’s assets and liabilities which are recorded at fair value on a recurring basis are related to outstanding derivatives. At December 31, 2014, Gulf South had no outstanding derivatives recorded on its Balance Sheets. At December 31, 2013, Gulf South had $0.5 million of commodity derivatives that were recorded in Other current assets and $0.3 million of commodity derivatives recorded in Other current liabilities. The derivatives were measured using a Level 2 input under the fair value hierarchy.

Gulf South's AOCI as of December 31, 2014 and 2013 was $5.0 million and $5.5 million, all of which related to losses on cash flow hedges. Gulf South estimates that approximately $0.7 million of net losses reported in AOCI as of December 31, 2014, are expected to be reclassified into earnings within the next twelve months. The amounts related to cash flow hedges are related to treasury rate locks that were settled in a previous period. The losses associated with the rate locks are being amortized over the terms of the related interest payments, generally the terms of the related debt.

Financial Assets and Liabilities

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

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

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

Long-Term Debt: The estimated fair value of Gulf South's publicly traded debt is based on quoted market prices at December 31, 2014 and 2013. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at December 31, 2014 and 2013.

The carrying amount and estimated fair values of Gulf South's financial assets and liabilities which are not recorded at fair value on the Balance Sheets as of December 31, 2014 and 2013, were as follows (in millions):



As of December 31, 2014			Estimated Fair Value
Financial Assets	Carrying Amount		Level 1		Level 2		Level 3		Total
Cash	$	1.9	$	1.9	$	—	$	—	$	1.9
Advances to affiliates - non-current	61.5		—		61.5		—		61.5

Financial Liabilities
Long-term debt	$	847.1	$	—	$	874.8	$	—	$	874.8



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

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

Note 5: Property, Plant and Equipment (PPE)

The following table presents Gulf South’s PPE as of December 31, 2014 and 2013 (in millions):



Category	2014 Class Amount		Weighted-Average Useful Lives (Years)	2013 Class Amount		Weighted-Average Useful Lives (Years)
Depreciable plant:
Transmission	$	3,353.9	34	$	3,025.1	34
Storage	125.2		34	119.2		34
Gathering	66.2		20	64.2		20
General	93.9		7	89.5		8
Rights of way and other	20.9		35	18.7		35
Total utility depreciable plant	3,660.1		34	3,316.7		34

Non-depreciable:
Construction work in progress	42.5			109.6
Storage	31.4			16.7
Land	10.5			9.1
Total non-depreciable	84.4			135.4

Total PPE	3,744.5			3,452.1
Less: accumulated depreciation	820.2			707.1

Total PPE, net	$	2,924.3		$	2,745.0

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, 2014 and 2013 (in millions):



	2014				2013
	Gross PPE Investment		Accumulated Depreciation		Gross PPE Investment		Accumulated Depreciation
Bistineau storage	$	64.3	$	17.5	$	55.8	$	15.1
Mobile Bay Pipeline	13.0		3.6		11.1		3.1
Offshore and other assets	8.8		3.8		9.0		3.4
Total	$	86.1	$	24.9	$	75.9	$	21.6

Asset Transfers and Impairment Charges

In 2014, an affiliate transferred transmission pipeline with a carrying amount of $3.9 million to Gulf South, which was accounted for as a non-cash contribution. In 2012, Gulf South transferred gathering and transmission pipelines with a carrying amount of $30.6 million to an affiliate, which was accounted for as a non-cash distribution.

Gulf South recognized $1.0 million, $3.6 million and $6.3 million of asset impairment charges for the years ended December 31, 2014, 2013 and 2012.

Gas Sales

For the year ended December 31, 2013, Gulf South recognized a gain of $17.0 million from the sale of approximately 5.0 billion cubic feet of natural gas stored underground with a carrying amount of $2.6 million. The gas was sold to provide capacity for additional parks of customer gas under PAL services. The gain related to the gas sale was recorded in Net gain on sale of operating assets.

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. Gulf South received a total of $12.3 million in insurance proceeds, of which $0.6 million, $1.7 million and $1.2 million were recorded as a reduction in Operation and maintenance expense for the years ended December 31, 2014, 2013 and 2012.

Note 6: Asset Retirement Obligations (ARO)

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

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



	2014			2013
Balance at beginning of year	$	21.4		$	17.7
Liabilities recorded	1.2			3.5
Liabilities settled	(4.2		)	(0.7		)
Accretion expense	0.7			0.9
Balance at end of year	19.1			21.4
Less: Current portion of asset retirement obligations	(1.7		)	(3.6		)
Long-term asset retirement obligations	$	17.4		$	17.8

Note 7: Financing

Long-Term Debt

The following table presents all long-term debt issues outstanding as of December 31, 2014 and 2013 (in millions):



	2014			2013
Notes :
5.05% Notes due 2015 (2015 Notes)	$	275.0		$	275.0
6.30% Notes due 2017	275.0			275.0
4.00% Notes due 2022	300.0			300.0
Total notes	850.0			850.0
Revolving Credit Facility	—			—
	850.0			850.0
Less: unamortized debt discount	(2.9		)	(3.7		)
Total Long-Term Debt	$	847.1		$	846.3

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



2015	$	275.0
2016	—
2017	275.0
2018	—
2019	—
Thereafter	300.0
Total long-term debt	$	850.0

In November 2014, Boardwalk Pipelines received net proceeds of approximately $342.9 million from the issuance of $350.0 million of 4.95% senior unsecured notes due December 15, 2024. The proceeds were used to temporarily reduce borrowings under Boardwalk Pipelines’ revolving credit facility until the 2015 Notes reached maturity on February 1, 2015, at which time a portion of the proceeds were used to retire the 2015 Notes. Gulf South received the proceeds from Boardwalk Pipelines through an advance from the cash management program. The 2015 Notes were reflected as long-term debt on the Balance Sheets since Gulf South refinanced the note on a long-term basis.

Notes

As of December 31, 2014 and 2013, the weighted-average interest rate of Gulf South's notes was 5.33%. For the years ended December 31, 2014, 2013 and 2012, Gulf South completed the following debt issuance (in millions, except interest rates):

Date of

Issuance

Issuing Subsidiary

Amount of Issuance

Purchaser Discounts and Expenses

Net Proceeds

₍₁₎

Interest

Rate

Maturity Date

Interest Payable

June 2012

Gulf South

$300.0

3.5

$296.5

4.00

June 15, 2022

June 15 and December 15


(1)	The net proceeds of this offering were used to reduce borrowings under the revolving credit facility and to redeem $225.0 million of Gulf South's 5.75% notes due 2012 (2012 Notes) discussed below.

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

The indentures governing the notes have restrictive covenants which provide that, with certain exceptions, Gulf South cannot 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, 2014, Gulf South was in compliance with its debt covenants.

Redemption of Notes

In February 2015, the 2015 Notes matured and were retired in full as described above. In August 2012, the 2012 Notes matured and were retired in full. The retirement of the 2012 Notes was financed through the issuance of the 4.00% Gulf South notes due 2022.

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’s sub-limit can be changed at Gulf South’s option as long as the aggregate lending commitments under the facility do not exceed $1.0 billion. Gulf South had no outstanding borrowings under the credit facility as of December 31, 2014 and 2013, and had an available borrowing capacity of $200.0 million.

Interest is determined, at Gulf South's election, by reference to (a) the base rate which is the highest of (1) the prime rate, (2) the federal funds rate plus 0.50%, and (3) the one month Eurodollar Rate plus 1.0%, plus an applicable margin, or (b) 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 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. Boardwalk Pipelines and its subsidiaries, including Gulf South, were in compliance with all covenant requirements under the credit facility as of December 31, 2014.

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 $5.2 million, $4.8 million and $4.7 million for the years ended December 31, 2014, 2013 and 2012.

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 Unit Appreciation Rights (UAR) and Cash Bonus Plan, and previously made grants under the Strategic Long-Term Incentive Plan (SLTIP). The following disclosures provide information regarding these plans, under which Gulf South received an allocation of expenses of $1.2 million, $1.9 million and $2.1 million during 2014, 2013 and 2012 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, 2014 and 2013, and changes during the years ended December 31, 2014 and 2013, is presented below:



	Phantom Common Units		Total Fair Value (in millions)	Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2013 ⁽¹⁾	192,595		$4.7	2.0
Granted	220,808		5.7	2.8
Forfeited	(33,355	)	—	—
Outstanding at December 31, 2013⁽¹⁾	380,048		10.9	1.5
Paid	(171,411	)	(3.5)	—
Forfeited	(8,968	)	—	—
Outstanding at December 31, 2014 ⁽¹⁾	199,669		$4.1	0.9


(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 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, 2014 and 2013 was based on the closing market price of the common unit on those dates of $17.77 and $25.52 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 $1.2 million, $3.2 million and $1.5 million in Administrative and general expenses during 2014, 2013 and 2012 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, 2014 and 2013 was $1.6 million and $6.1 million.

In 2014 and 2013, the general partner of Boardwalk Pipeline Partners purchased 16,064 and 7,484 of Boardwalk Pipeline Partners’ common units in the open market at a price of $12.51 and $26.72 per unit. These units were granted under the LTIP to the independent directors as part of their director compensation. At December 31, 2014, 3,490,160 units were available for grants under the LTIP.

UAR and Cash Bonus Plan

The UAR and Cash Bonus Plan provides for grants of UARs and Long-Term Cash Bonuses to selected employees of Boardwalk Pipeline Partners. In 2014, Boardwalk Pipeline Partners granted to certain employees $9.2 million of Long-Term Cash Bonuses under the UAR and Cash Bonus Plan. Each Long-Term Cash Bonus will become vested and payable to the holder in cash equal to the amount of the grant after the vesting date. Except in limited circumstances, upon termination of employment during the vesting period, any outstanding and unvested awards of Long-Term Cash Bonuses would be cancelled unpaid. Boardwalk Pipeline Partners recorded compensation expense of $2.6 million, $0.5 million and $0.6 million for the years ended December 31, 2014, 2013 and 2012 related to the Long-Term Cash bonuses. As of December 31, 2014, there was $6.6 million of total unrecognized compensation costs related to the Long-Term Cash Bonuses.

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

A summary of the outstanding UARs granted under Boardwalk Pipeline Partners’ UAR and Cash Bonus Plan as of December 31, 2014 and 2013, and changes during 2014 and 2013 is presented below:



	UARs		Weighted- Average Exercise Price		Total Fair Value (in millions)		Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2013 ⁽¹⁾	605,747		$	29.18	$	1.7	1.4
Paid	(359,148	)
Forfeited	(61,400	)
Granted ⁽²⁾	293,809		27.57		1.8		2.8
Outstanding at December 31, 2013 ⁽¹⁾	479,008		27.47		1.9		1.5
Vested⁽³⁾	(203,168	)
Forfeited	(10,348	)
Outstanding at December 31, 2014 ⁽¹⁾	265,492		$	27.57	$	—	0.9


(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 $27.57, the closing price of Boardwalk Pipeline Partners’ common units on the New York Stock Exchange on the grant date on February 7, 2013.


(3)	Units vested and expired with no value.

The fair value of the UARs was based on the computed value of a call on Boardwalk Pipeline Partners’ common units at the exercise price. The following assumptions were used as inputs to the Black-Scholes valuation model for grants made during 2013. No UARs were granted in 2014.



	Grant Date Assumptions for Grants Made in 2013
Expected life (years)	2.8
Risk free interest rate ⁽¹⁾	0.35%
Expected volatility ⁽²⁾	32%


(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.

Due to the significant decrease in Boardwalk Pipeline Partners’ common unit price in 2014, a portion of the previously recognized compensation expense related to the UARs was reversed, which resulted in Boardwalk Pipeline Partners recording compensation income of $0.7 million for the year ended December 31, 2014. Boardwalk Pipeline Partners recorded compensation expense of $0.9 million and $0.3 million for the years ended December 31, 2013 and 2012, related to the UARs. As of December 31, 2014, the UARs had no value. As of December 31, 2013, there was $0.9 million of total unrecognized compensation cost related to the non-vested portion of the UARs.

SLTIP

The SLTIP provided for the issuance of up to 500 phantom general partner units (Phantom GP Units) to selected employees of Boardwalk Pipeline Partners and its subsidiaries. The last grant of the Phantom GP Units was made in 2010, which vested and was settled in 2013. No additional grants of Phantom GP units are expected to be made under the SLTIP. Boardwalk Pipeline Partners recorded $0.2 million and $2.3 million in Administrative and general expenses during 2013 and 2012 for the ratable recognition of the fair value of the GP Phantom Unit awards.

A summary of the status of Boardwalk Pipeline Partners’ SLTIP as of December 31, 2014 and 2013, and changes during the years ended December 31, 2014 and 2013, is presented below:



	Phantom GP Units	Total Fair Value (in millions)			Weighted-Average Vesting Period (in years)
Outstanding at January 1, 2013 ⁽¹⁾	145	$	6.9		0.2
Paid	(145)	(7.2		)	—
Outstanding at December 31, 2013 and 2014	—	—			—


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

Retention Payment Agreements

In light of challenging market conditions, the need to execute on certain key initiatives and a highly competitive market for talent in the energy industry, in 2014, Boardwalk Pipeline Partners entered into retention payment agreements with certain key employees. The total amount of cash payable under the program would be approximately $12.0 million subject to the employees remaining employed by Boardwalk Pipeline Partners or its operating subsidiaries over a period of three years and other conditions. Each retention payment agreement will vest and become payable in cash as follows: 25% vesting and becoming payable on February 28, 2015, 25% vesting and becoming payable on February 29, 2016, and the remaining 50% vesting and coming payable on February 28, 2017. Except in limited circumstances, upon termination of employment during the vesting period, any outstanding and unvested retention payments would be cancelled unpaid. Boardwalk Pipeline Partners recorded compensation expense of $4.8 million for the year ended December 31, 2014 and as of December 31, 2014 there was $7.0 million of total unrecognized compensation expense related to the retention payment agreements. For the year ended December 31, 2014, Gulf South received an allocation of expenses of $1.9 million related to the retention payments.

Note 9: Credit Risk

Major Customers

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



	For the Year Ended December 31,
	2014			2013			2012
	Revenue		%	Revenue		%	Revenue		%
EOG Resources, Inc.	$	49.6	11%	$	50.9	11%	$	51.3	10%

Gas Loaned to Customers

Natural gas price volatility can cause changes in credit risk related to gas loaned to customers. As of December 31, 2014, the amount of gas owed to Gulf South due to gas imbalances and gas loaned under PAL agreements was approximately 1.8 trillion British thermal units (TBtu). Assuming an average market price during December 2014 of $3.36 per million British thermal units (MMBtu), the market value of that gas was approximately $6.0 million. As of December 31, 2013, the amount of gas owed to Gulf South due to gas imbalances and gas loaned under PAL agreements was approximately 2.9 TBtu. Assuming an average market price during December 2013 of $4.17 per MMBtu, the market value of this gas at December 31, 2013, would have been approximately $12.1 million. If any significant customer should have credit or financial problems resulting in a delay or failure to repay the gas owed to Gulf South, it could have a material adverse effect on Gulf South’s financial condition, results of operations or cash flows.

Note 10: Related Party Transactions

Gulf South makes advances to or receives advances from Boardwalk Pipelines under the cash management program described in Note 2. At December 31, 2014 and 2013, advances due to Gulf South from Boardwalk Pipelines totaled $61.5 million which was reflected as a non-current asset and $192.6 million which was reflected as a current asset. 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, 2014, 2013 and 2012, Boardwalk Pipelines charged Gulf South $7.7 million, $7.3 million, and $7.2 million for these services. These costs were based on actual costs incurred and allocated to Gulf South based on the modified Massachusetts formula, which utilizes three components as the basis for allocation: 1) the gross book value of property, plant and equipment; 2) operating revenues; and 3) labor costs. This allocation method has been consistently applied for all periods presented. Management believes the assumptions and allocations were made on a reasonable basis. Due to the nature of the shared costs, it is not practicable to estimate what the costs would have been had Gulf South operated on a stand-alone basis.

In 2014, an affiliate contributed to Gulf South PPE with a carrying amount of $3.9 million. In 2012, Gulf South transferred PPE to an affiliate with a carrying amount of $30.6 million, which transfer occurred by a non-cash distribution to Boardwalk Pipelines.

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



	For the Year Ended December 31,
Affiliate:	2014		2013		2012
Gulf Crossing Pipeline Company, LLC:
Transportation revenue - affiliates	$	75.1	$	73.1	$	71.9
Texas Gas Transmission, LLC:
Transportation revenue - affiliates	$	2.8	$	2.8	$	3.1
Fuel and transportation expense - affiliates	$	12.5	$	12.4	$	13.5
Petal:
Parking and lending revenue - affiliates	$	—	$	0.1	$	—
Fuel and transportation expense - affiliates	$	3.3	$	0.2	$	1.3

Note 11: Recently Issued Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers (Topic 606), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. ASU 2014-09 also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2016. Gulf South is evaluating the impact, if any, that ASU 2014-09 will have on its financial statements.

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



	For the Year Ended December 31,
	2014		2013		2012
Cash paid during the period for:
Interest (net of amount capitalized) ⁽¹⁾	$	37.4	$	40.9	$	57.0
Income taxes, net	$	—	$	0.1	$	0.1
Non-cash adjustments:
Accounts payable and PPE	$	12.9	$	16.1	$	14.3
Transfer of assets	$	3.9	$	—	$	30.6


(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)



	2014
	For the Quarter Ended:
	December 31		September 30		June 30		March 31
Operating revenues	$	115.7	$	105.0	$	115.0	$	131.6
Operating expenses	104.4		90.2		83.7		92.0
Operating income	11.3		14.8		31.3		39.6
Interest expense, net	10.5		8.6		8.6		9.4
Net income	$	0.8	$	6.2	$	22.7	$	30.2



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

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

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Our disclosure controls and procedures are designed to allow timely decisions regarding required disclosure and 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, 2014, 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, 2014, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

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

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

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on this assessment, our management believes that, as of December 31, 2014, our internal control over financial reporting was effective.

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

Part III

Item 10. Directors, Executive Officers and Corporate Governance

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

Item 11. Executive Compensation

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

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

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

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

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

Item 14. Principal Accounting Fees and Services

Audit Fees and Services

The audit fees billed by Deloitte & Touche LLP (Deloitte) related to our annual financial statement audit are included as part of the total audit fees charged to Boardwalk Pipeline Partners, which total audit fees for 2014 and 2013 were $2.6 million and $2.5 million.

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 2014 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, 2014 and 2013

Statements of Income for the years ended December 31, 2014, 2013 and 2012

Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012

Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012

Statements of Changes in Partners’ Capital for the years ended December 31, 2014, 2013 and 2012

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, 2014, 2013 and 2012 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:
2014	$	—	$	—		$	—	$	—	$	—
2013	0.1		(0.1		)	—		—		—
2012	0.1		—			—		—		0.1

(a) 3. Exhibits

The following documents are filed as exhibits to this Report:



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

* Filed herewith

** Furnished herewith

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.



		Gulf South Pipeline Company, LP
		By: GS Pipeline Company, LLC
		its general partner
Dated:	March 10, 2015	By:	/s/ Jamie L. Buskill
			Jamie L. Buskill
			Senior Vice President, Chief Financial and Administrative Officer and Treasurer

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



Dated:	March 10, 2015	/s/ Stanley C. Horton
		Stanley C. Horton President, Chief Executive Officer and Director (principal executive officer)
Dated:	March 10, 2015	/s/ Jamie L. Buskill
		Jamie L. Buskill Senior Vice President, Chief Financial and Administrative Officer and Treasurer (principal financial officer)
Dated:	March 10, 2015	/s/ Steven A. Barkauskas
		Steven A. Barkauskas Senior Vice President, Controller and Chief Accounting Officer (principal accounting officer)
Dated:	March 10, 2015	/s/ Michael E. McMahon
		Michael E. McMahon Director
Dated:	March 10, 2015	/s/ Andrew H. Tisch
		Andrew H. Tisch Director

Attached files

Gulf South Pipeline Company, LP Reports

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