10-K 1 bwp10k123113q4.htm 10-K BWP 10K 12.31.13 (Q4)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 FORM 10-K
 (Mark One)
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
OR
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

BOARDWALK PIPELINE PARTNERS, 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:
Title of each class
 
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
 
New York Stock Exchange
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 ý No o

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.    o

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 ý Accelerated filer o Non-accelerated filer o 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

The aggregate market value of the common units of the registrant held by non-affiliates as of June 30, 2013, was approximately $3.6 billion. As of February 24, 2014, the registrant had 243,223,801 common units outstanding.
Documents incorporated by reference.    None.




TABLE OF CONTENTS

2013 FORM 10-K

BOARDWALK PIPELINE PARTNERS, LP



2



PART I

Item 1.  Business

Unless the context otherwise requires, references in this Report to “we,” “our,” “us” or like terms refer to the business of Boardwalk Pipeline Partners, LP and its consolidated subsidiaries.

Introduction

We are a Delaware limited partnership formed in 2005. Our business is conducted by our primary subsidiary, Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South), Texas Gas Transmission, LLC (Texas Gas), Boardwalk Field Services, LLC (Field Services), Petal Gas Storage, LLC (formerly referred to as Boardwalk HP Storage, LLC) (Petal), Boardwalk Louisiana Midstream, LLC (Louisiana Midstream) and Boardwalk Storage Company, LLC (Boardwalk Storage) (together, the operating subsidiaries), and consists of integrated natural gas and natural gas liquids (NGLs) pipeline and storage systems and natural gas gathering and processing. All of our operations are conducted by our operating subsidiaries. Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns 125.6 million of our common units and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, our 2% general partner interest and all of our incentive distribution rights (IDRs). As of February 24, 2014, the common units and general partner interest owned by BPHC represent approximately 53% of our equity interests, excluding the IDRs. Our Partnership Interests, in Item 5 contains more information on how we calculate BPHC’s equity ownership. Our common units are traded under the symbol “BWP” on the New York Stock Exchange (NYSE).

        


3




The following diagram reflects a simplified version of our organizational structure as of December 31, 2013:




4




Our Business

We are a master limited partnership operating in the midstream portion of the natural gas and NGLs industry, providing transportation, storage, gathering and processing services for those commodities. We own approximately 14,450 miles of natural gas and NGLs pipelines, and underground storage caverns having aggregate capacity of approximately 207.0 billion cubic feet (Bcf) of working natural gas and 17.6 million barrels (MMbbls) of NGLs. Our pipeline systems originate in the Gulf Coast region, Oklahoma and Arkansas and extend north and east to the midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio.

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. Contracts for our services related to NGLs are generally fee based and are dependent on actual volumes transported or stored, although in some cases minimum volume requirements apply. For the year ended December 31, 2013, approximately 81% of our revenues were derived from capacity reservation fees under firm contracts, approximately 12% of our revenues were derived from fees based on utilization under firm contracts and approximately 7% of our revenues were derived from interruptible transportation, interruptible storage, parking and lending (PAL) and other services. Item 6 of this Report contains a summary of our revenues from external customers, net income and total assets, all of which were attributable to our pipeline and storage systems operating in one reportable segment.

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 the majority of our natural gas storage capacity pursuant to authority granted by FERC.

Our Pipeline and Storage Systems

We own and operate approximately 14,195 miles of interconnected natural gas pipelines directly serving customers in thirteen states and indirectly serving customers throughout the northeastern and southeastern United States (U.S.) through numerous interconnections with unaffiliated pipelines. We also own and operate more than 255 miles of NGLs pipelines in Louisiana. In 2013, our pipeline systems transported approximately 2.4 trillion cubic feet (Tcf) of natural gas and approximately 7.5 MMbbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2013 was approximately 6.6 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of approximately 207.0 Bcf, and our NGLs storage facilities consist of eight salt-dome caverns located in Louisiana with an aggregate storage capacity of approximately 17.6 MMbbls. We also own two salt-dome caverns for use in providing brine supply services and to support the NGLs storage operations.

The principal sources of supply for our natural gas pipeline systems 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 pipelines in the Carthage, Texas area provide access to natural gas supplies from the Bossier Sands, Barnett Shale, Haynesville Shale and other natural gas producing regions in eastern Texas and northern Louisiana.  The Henry Hub serves as the designated delivery point for natural gas futures contracts traded on the New York Mercantile Exchange. Our pipeline systems also have access to unconventional supplies such as the Woodford Shale in southeastern Oklahoma, the Fayetteville Shale in Arkansas, the Eagle Ford Shale in southern Texas and wellhead supplies in northern and southern Louisiana and Mississippi and, with the recent development of the Marcellus and Utica shales, we also receive gas in the Lebanon, Ohio area. We access the Gulf Coast petrochemical industry through our operations at our Choctaw Hub in the Mississippi River corridor area of Louisiana and the Sulphur Hub in the Lake Charles, Louisiana area.

The following is a summary of each of our principal operating subsidiaries:

Gulf Crossing:  Our Gulf Crossing pipeline system originates near Sherman, Texas, and proceeds to the Perryville, Louisiana area. The market areas are in the Midwest, Northeast, Southeast and Florida through interconnections with Gulf South, Texas Gas and unaffiliated pipelines.

Gulf South:  Our Gulf South pipeline system is located along the Gulf Coast in the states of Texas, Louisiana, Mississippi, Alabama and Florida. The on-system markets directly served by the Gulf South system are generally located in eastern Texas, Louisiana, southern Mississippi, southern Alabama and the Florida Panhandle. These markets include LDCs and municipalities

5



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. Gulf South also has indirect access to off-system markets through numerous interconnections with unaffiliated interstate and intrastate pipelines and storage facilities. These pipeline interconnections provide access to markets throughout the northeastern and southeastern U.S.

Gulf South has two natural gas storage facilities. The natural gas storage facility located in Bistineau, Louisiana, has approximately 78.0 Bcf of working gas storage capacity from which Gulf South offers firm and interruptible storage service, including no-notice service. Gulf South’s Jackson, Mississippi, natural gas storage facility has approximately 5.0 Bcf of working gas storage capacity, which is used for operational purposes and is not offered for sale to the market.

Texas Gas:  Our Texas Gas pipeline system originates in Louisiana, East Texas and Arkansas and runs north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana, and into Ohio, with smaller diameter lines extending into Illinois. Texas Gas directly serves LDCs, municipalities and power generators in its market area, which encompasses eight states in the South and Midwest and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati and Dayton, Ohio; and Evansville and Indianapolis, Indiana metropolitan areas. Texas Gas also has indirect market access to the Northeast through interconnections with unaffiliated pipelines.  A large portion of the gas delivered by the Texas Gas system is used for heating during the winter months.

Texas Gas owns nine natural gas storage fields, of which it owns the majority of the working and base gas. Texas Gas uses this gas to meet the operational requirements of its transportation and storage customers and the requirements of its no-notice service customers. Texas Gas also uses its storage capacity to offer firm and interruptible storage services.

Field Services: Field Services operates natural gas gathering, compression, treating and processing infrastructure primarily in south Texas.

Petal: Petal owns and operates eight high deliverability salt dome natural gas storage caverns in Forrest County, Mississippi, having approximately 46.0 Bcf of total storage capacity, of which approximately 29.0 Bcf is working gas capacity. Petal also operates approximately 100 miles of pipeline which connects its facilities with several major natural gas pipelines and owns undeveloped land which is suitable for up to five additional storage caverns.   

Louisiana Midstream: Louisiana Midstream provides transportation and storage services for natural gas and NGLs, fractionation services for NGLs, and brine supply services for producers and consumers of petrochemicals through two hubs in southern Louisiana - the Choctaw Hub in the Mississippi River Corridor area and the Sulphur Hub in the Lake Charles area. These assets provide approximately 57.8 MMbbls of salt dome storage capacity, including approximately 11.0 Bcf of working natural gas storage capacity; significant brine supply infrastructure; and approximately 270 miles of pipeline assets, including an extensive ethylene distribution system. 

The following table provides information for our pipeline and storage systems as of December 31, 2013:
Pipeline and Storage Systems
 
Miles of Pipeline
 
Working Gas Storage Capacity
 
Peak-day Delivery Capacity
 
Average Daily Throughput
 
 
 
 
(Bcf)
 
(Bcf/d)
 
(Bcf/d)
Gulf Crossing
 
360

 
 
1.7
 
1.2
Gulf South
 
7,200

 
83.0
 
6.9
 
2.5
Texas Gas
 
6,100

 
84.0
 
4.6
 
2.6
Field Services
 
420

 
 
 
0.1
Petal
 
100

 
29.0
 
 
0.2
Louisiana Midstream
 
270

 
   11.0 (1)
 
 

(1)
Louisiana Midstream also has approximately 17.6 MMbbls of salt-dome NGLs storage capacity in addition to the working gas storage capacity. Louisiana Midstream has two salt-dome caverns for use in providing brine supply services.


6



Current Growth Projects and Investments

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

Ohio to Louisiana Access Project: Our Ohio to Louisiana Access Project would provide long-term firm natural gas transportation from the Marcellus and Utica production areas to Louisiana. This project does not add additional capacity to our natural gas pipeline systems, but will reverse the traditional flow of natural gas from northbound to southbound on a portion of
our Texas Gas system. The project is supported by firm transportation contracts for 0.6 Bcf of capacity per day with producers and end-users, with a weighted-average contract life of approximately 13 years. The project is expected to cost approximately $115.0 million and is expected to be placed into service in the first half 2016, subject to FERC approval.

Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects: In 2013, we executed an agreement with the Williams Companies, Inc. (Williams) to develop the Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects - projects that would transport NGLs from the Marcellus and Utica shale plays to the petrochemical and export complex in the Lake Charles, Louisiana area, and the construction of related fractionation, storage and liquefied petroleum gas (LPG) terminal export facilities.

The proposed project would include constructing a new pipeline that would initially provide producers with 200,000 barrels per day of mixed NGLs take-away capacity in Ohio, West Virginia and Pennsylvania to an interconnect with our Texas Gas pipeline in Hardinsburg, Kentucky. Capacity could be increased to 400,000 barrels per day to meet market demand, primarily by adding additional liquids pumping capacity. From the interconnect with Texas Gas to Eunice, La., a portion of the Texas Gas pipeline (Texas Gas Loop Line) would be converted from natural gas service to NGLs service. The proposed project would also include constructing a new large-scale fractionation plant, expanding natural gas liquids storage facilities in Louisiana, constructing a new pipeline connecting these facilities to the converted Texas Gas Loop Line and constructing a new export LPG terminal and related facilities on the Gulf Coast to provide customers access to international markets.

To effectuate the Bluegrass Project: (i) we entered into separate joint venture arrangements with Boardwalk Pipelines Holding Corp. (BPHC) to form Boardwalk Bluegrass Pipeline, LLC (Boardwalk Bluegrass) and Boardwalk Moss Lake, LLC (Boardwalk Moss Lake); and (ii) Boardwalk Bluegrass and Boardwalk Moss Lake, together with affiliates of Williams, formed Bluegrass Pipeline Company LLC (Bluegrass Pipeline), Moss Lake Fractionation LLC (Moss Lake Fractionation) and Moss Lake LPG Terminal LLC (Moss Lake LPG) to continue to pursue and, if approved, develop, own and construct the pipeline, fractionation and LPG terminal export facilities. Boardwalk Bluegrass currently owns 50% of the equity interests in Bluegrass Pipeline, and Boardwalk Moss Lake currently owns 50% of the equity interests in Moss Lake Fractionation and Moss Lake LPG, with affiliates of Williams owning the other 50%.

We have contributed a total of $11.9 million to the capital of Boardwalk Bluegrass and Boardwalk Moss Lake. BPHC has contributed the balance of the capital of these entities and anticipates contributing the additional capital required to fund certain agreed upon pre-construction development costs until such time as BPHC has a 90% equity ownership interest in each entity. Additional capital required for Boardwalk Bluegrass and Boardwalk Moss Lake to continue to pursue the Bluegrass Project is subject to approval by us and BPHC.

Through our agreement, we and Williams are engaged in comprehensive project development activities including project design, cost estimating, economic and risk analysis, permitting, other legal and regulatory approvals and right-of-way acquisition. We and Williams are also continuing ongoing discussions with potential customers regarding commitments for pipeline, fractionation, storage and export services to support this project.

Approval and completion of this project is subject to, among other conditions, execution of customer contracts sufficient to support the project, acquisition of right-of-way along the pipeline route, and the parties' receipt of all necessary approvals, including board approvals and regulatory approvals, such as antitrust clearance under the Hart-Scott-Rodino Antitrust Improvements Act and approvals by the FERC, among others. Before the Texas Gas Loop Line can be converted to NGLs service, Texas Gas must receive abandonment authority from FERC. The abandonment application was filed with FERC in May 2013 and we estimate the abandonment process will take at least twelve months. In addition, each of the parties has the right, under certain circumstances, to withdraw from the project or from portions of the project, in which case the project may be terminated, only portions of the project may be completed, or the parties respective ownership interests in the project may change. We cannot give

7



assurances that this project will be completed, in whole or in part. We and Williams are continuing to evaluate all aspects of the project, including the date we anticipate the project would be placed into service if it is completed.

Nature of Contracts
 
We contract with our customers to provide transportation and storage services on a firm and interruptible basis. We also provide bundled firm transportation and storage services, which we provide to our natural gas customers as no-notice services, and we provide interruptible PAL services for our natural gas customers. We provide brine supply services for certain petrochemical customers and fractionation services.

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

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

No-Notice Services. No-notice services consist of a combination of firm natural gas transportation and storage services that allow customers to withdraw natural gas from storage with little or no notice. Customers pay a reservation charge based upon the capacity reserved plus a commodity and a fuel charge based on the volume of gas actually transported. In accordance with its tariff, Texas Gas loans stored gas to certain of its no-notice customers who are obligated to repay the gas in-kind.

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 systems at a specific location for a specific period of time. Customers pay for PAL service in advance or on a monthly basis depending on the terms of the agreement.

Customers and Markets Served

We contract directly with producers of natural gas, and with end-use customers including LDCs, marketers, electric power generators, industrial users and interstate and intrastate pipelines who, in turn, provide transportation and storage services to end-users. Based on 2013 revenues, our customer mix was as follows: natural gas producers (52%), marketers (20%), LDCs (18%), power generators (7%) and industrial end users and others (3%). Based upon 2013 revenues, our deliveries were as follows: pipeline interconnects (60%), LDCs (18%), storage activities (12%), industrial end-users (5%), power generators (4%) and other (1%). One customer, Devon Gas Services, LP, accounted for approximately 11% of our 2013 operating revenues.

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


8



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 no-notice service. We serve approximately 180 LDCs at more than 300 delivery locations across our pipeline systems. The demand of these customers peaks during the winter heating season.
    
Power Generators. Our natural gas pipelines are directly connected to 40 natural-gas-fired power generation facilities in ten 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 195 industrial facilities with a combination of firm and interruptible natural gas and NGLs transportation and storage services. Our pipeline systems are 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 systems.  We also compete with pipelines that are attached to new natural gas supply sources that are being developed closer to some of our traditional natural gas market areas. In addition, regulators’ continuing efforts to increase competition in the natural gas industry have increased the natural gas transportation options of our traditional customers. As a result of regulators’ policies, capacity segmentation and capacity release have created an active secondary market which increasingly competes with our own natural gas pipeline services. Further, natural gas competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative fuel sources.

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

Seasonality

Our revenues can be affected by weather, natural gas price levels, basis spreads and time period price spreads, and natural gas price volatility. Weather impacts natural gas demand for heating needs and power generation, which in turn influences the short-term value of transportation and storage across our pipeline systems. Colder than normal winters can result in an increase in the demand for natural gas for heating needs and warmer than normal summers can impact cooling needs, both of which typically result in increased pipeline transportation revenues and throughput. While traditionally peak demand for natural gas occurs during the winter months driven by heating needs, the increased use of natural gas for cooling needs during the summer months has partially reduced the seasonality of our revenues. During 2013, approximately 53% of our revenues were recognized in the first and fourth quarters of the year.

Government Regulation

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

The maximum rates that may be charged by our operating subsidiaries that operate under FERC's jurisdiction for all aspects of the natural gas transportation services they provide are established through FERC’s cost-of-service rate-making process.

9



The maximum rates that may be charged by us for storage services on Texas Gas, with the exception of services associated with a portion of the working gas capacity on that system, are also 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 for the majority of our storage facilities. None of our FERC-regulated entities has an obligation to file a new rate case.

U.S. Department of Transportation (DOT). We are regulated by DOT, through the Pipeline and Hazardous Materials Safety Administration (PHMSA), under the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979 (NGPSA), and the Hazardous Liquids Pipeline Safety Act of 1979 (HLPSA). The NGPSA and HLPSA regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas and NGLs 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 pipelines and take additional measures to protect pipeline segments located in highly populated areas. The NGPSA and HLPSA were 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 and analogous state laws which impose obligations related to air emissions, including, in the case of the Clean Air Act, greenhouse gas emissions and regulations affecting reciprocating engines subject to Maximum Achievable Control Technology (MACT) standards;
the Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws which regulate discharge of wastewater from our facilities into state and federal waters;
the Comprehensive Environmental Response, Compensation and Liability Act, commonly referred to as CERCLA, or the Superfund law, and analogous state laws which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;
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, which could diminish our ability to make distributions to our unitholders.


10



Effects of Compliance with Environmental Regulations

Note 5 in Item 8 of this Report contains information regarding environmental compliance.

Employee Relations

At December 31, 2013, we had approximately 1,200 employees, approximately 110 of whom are included in collective bargaining units. 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 group life, hospital, and medical benefits, as well as disability benefits. We also have a non-contributory, defined benefit pension plan and a postretirement medical plan which covers Texas Gas employees hired prior to certain dates. Note 12 in Item 8 of this Report contains further information regarding our employee benefits.

Available Information

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

Interested parties may contact the chairpersons of any of our Board committees, our Board’s independent directors as a group or our full Board in writing by mail to Boardwalk Pipeline Partners, LP, 9 Greenway Plaza, Suite 2800, Houston, TX 77046, Attention: Corporate Secretary. All such communications will be delivered to the director or directors to whom they are addressed.

11



Item 1A. Risk Factors
 
Our business faces many risks. We have described below the material risks which we and our subsidiaries 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, including our ability to make distributions to our unitholders.

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

Business Risks

We may not have sufficient available cash to continue making distributions to unitholders at the current distribution rate, or at all.

The amount of cash we have available to distribute to our unitholders principally depends upon the amount of cash we generate from our operations and financing activities and the amount of cash we require, or determine to use, for other purposes, all of which fluctuate from quarter to quarter based on a number of factors, many of which are beyond our control. Some of the factors that influence the amount of cash we have available for distribution in any quarter include:
fluctuations in cash generated by our operations, including, as a result of the seasonality of our business, customer payment issues, general business conditions and market conditions, which impact, for example, contract renewals, basis spreads, time period price spreads, market rates and supply and demand for natural gas and our services;
the level of capital expenditures we make or anticipate making, including for expansion and growth projects;
the amount of cash necessary to meet current or anticipated debt service requirements and other liabilities;
fluctuations in our working capital needs;
our ability to borrow funds and/or access capital markets on acceptable terms to fund operations or capital expenditures, including acquisitions, and restrictions contained in our debt agreements; and
the cost and form of payment for pending or anticipated acquisitions and growth or expansion projects and the timing and commercial success of any such initiatives.
There is no guarantee that unitholders will receive quarterly distributions from us. Our distributions are determined each quarter by the board of directors of our general partner based on the board’s consideration of our financial position, earnings, cash flow, current and future business needs and other relevant factors at that time. In February 2014, we declared a quarterly distribution of $0.10 per unit, which was less than the quarterly distributions of $0.5325 per unit that we declared and paid in recent prior periods. We may reduce or eliminate distributions at any time we determine that our cash reserves are insufficient or are otherwise required to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment or other business needs.

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

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


12



Transportation Services:

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

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

In 2008 and 2009, we placed into service a number of large new pipelines and expansions of our system, including our East Texas Pipeline, Southeast Expansion, Gulf Crossing Pipeline, and Fayetteville and Greenville Laterals. 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 and 2019, we will have significantly more contract expirations than other years. We cannot predict what market conditions will prevail at the time such contracts expire and what pricing and other terms may be available in the marketplace for renewal or replacement of such contracts. If we are unable to renew or replace these and other expiring contracts when they expire, or if the terms of any such renewal or replacement contracts are not as favorable as the expiring agreements, our revenues and cash flows could be materially adversely affected.

Storage and PAL Services:

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

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

We may not be successful in executing our strategy to grow and diversify our business.

We rely primarily on the revenues generated from our long-haul natural gas transportation and storage services. As a result, negative developments in these services have significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets. We are pursuing a strategy of growing and diversifying our business through acquisition and development of assets in complementary areas of the midstream energy sector, such as liquids transportation and storage assets, among others. We may not be successful in acquiring or developing such assets or may do so on terms that ultimately are not profitable.

In pursuing our growth and diversification strategy, we have been pursuing development (together with a joint venture partner) of a large capital project, which we call our Bluegrass Project, consisting of a pipeline that would deliver NGLs from the Marcellus and Utica shale production areas of Pennsylvania, Ohio and West Virginia to end use markets in the Gulf Coast area, and constructing new fractionation, liquids storage and export facilities located in the Gulf Coast region. We continue to have

13



ongoing discussions with potential customers regarding commitments that would support constructing this project and have not made any external commitments to proceed with the project. We may incur substantial costs in developing this or other projects or otherwise pursuing growth and diversification opportunities; however, we can give no assurance that any such project will be completed, in whole or in part, or, if completed, that any such project or acquisition will be on attractive terms or generate a positive return for us.

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

The prices of natural gas and NGLs fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors, including:
worldwide economic conditions;  
weather conditions, seasonal trends and hurricane disruptions;  
the relationship between the available supplies and the demand for natural gas and NGLs;  
new supply sources;
the availability of adequate transportation capacity;
storage inventory levels;  
the price and availability of oil and other forms of energy;  
the effect of energy conservation measures;  
the nature and extent of, and changes in, governmental regulation, new regulations adopted by the Environmental Protection Agency (EPA), for example, greenhouse gas legislation and taxation; and  
the anticipated future prices of natural gas, oil and other commodities.

It is difficult to predict future changes in natural gas and NGLs 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, EBITDA and distributable cash flow.

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 midstream businesses.

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

Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions or our financial performance deteriorate further, our ability to comply with these covenants may be impaired. If we are not able to incur additional indebtedness we may need to sell additional equity securities to raise needed capital, which would be dilutive to our existing equity holders, or to seek other sources of funding that may be on terms that materially adversely affect our financial condition or our ability to pay future distributions. If we default under our credit agreement or another financing agreement, significant additional restrictions may become applicable, including a restriction on our ability to make distributions to unitholders. 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.


14



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

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

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

Limited access to the debt and equity markets could adversely affect our business.
Changes in the debt and equity 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 and equity markets could limit our ability to grow our business through acquisitions and growth projects. If the debt and equity 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 and equity offerings to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. Any disruption could require us to take additional measures to conserve cash until the markets stabilize or until we can arrange alternative credit arrangements or other funding for our business needs. Such measures could include reducing or delaying business activities, reducing our operations to lower expenses, and reducing other discretionary uses of cash. We may be unable to execute our growth strategy or take advantage of business opportunities, any of which could negatively impact our business.
Changes in the pipeline safety laws and regulations requiring substantial changes to existing integrity management programs or safety technologies could subject us to increased capital and operating costs and require us to use more comprehensive and stringent safety controls.

Our pipelines are subject to regulation by PHMSA of the DOT under the NGPSA with respect to natural gas and the HLPSA with respect to NGLs, both as amended. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and NGLs pipeline facilities. These amendments have resulted in the adoption of rules through PHMSA, that require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas, such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. These regulations have resulted in an overall increase in our maintenance costs. Due to recent highly publicized incidents on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. We could incur significant additional costs if new or more stringent pipeline safety requirements are implemented.
    
The 2011 Act was enacted and signed into law in early 2012. Under the 2011 Act, maximum civil penalties for certain violations have been increased to $200,000 per violation per day, and from a total cap of $1.0 million to $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas and hazardous liquids pipeline safety rulemaking in 2014 or soon thereafter. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.

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


15



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 recover all of our costs, including certain costs associated with pipeline integrity, through existing or future rates.
      
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 any of our pipelines under FERC jurisdiction were to file a rate case, or if they have to defend their 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 we are a limited partnership and do not pay U.S. federal income taxes, this would require us to show that our unitholders (or their ultimate owners) are subject to federal income taxation. To support such a showing, our general partner may elect to require owners of our 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 our unitholders (or their ultimate owners) are subject to U.S. federal income tax liability on the income generated by our jurisdictional pipelines. 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 our pipelines, which could result in a reduction of such maximum rates from current levels.

Investments that we make, whether through acquisitions, growth projects or joint ventures, that appear to be accretive may nevertheless reduce our distributable cash flows.

Our future growth depends on our ability to grow and diversify our business by among other things, investing in assets through acquisitions or joint ventures and organic growth projects. Our ability to grow, diversify and increase distributable cash flows will depend, in part, on our ability to close and execute on accretive acquisitions and projects. Any such transaction involves potential risks that may include, among other things:
the diversion of management's and employees' attention from other business concerns;
inaccurate assumptions about volume, revenues and project costs, including potential synergies;
a decrease in our liquidity as a result of our using available cash or borrowing capacity to finance the acquisition or project;
a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition or project;
inaccurate assumptions about the overall costs of equity or debt;
an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets or the developed assets;
unforeseen difficulties operating in new product areas or new geographic areas; and
changes in regulatory requirements or delays of regulatory approvals.
Additionally, acquisitions contain the following risks:
an inability to integrate successfully the businesses we acquire;

16



the assumption of unknown liabilities for which we are not indemnified, for which our indemnity is inadequate or for which our insurance policies may exclude from coverage;
limitations on rights to indemnity from the seller; and
customer or key employee losses of an acquired business.
There is no certainty that we will be able to complete these acquisitions or projects on schedule, on budget or at all.

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

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

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

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

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

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

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

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

We rely on a limited number of customers for a significant portion of revenues. Our largest customer in terms of revenue, Devon Gas Services, LP, represented over 11% of our 2013 revenues. Our top ten customers comprised approximately 46% of our revenues in 2013. We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms which could materially reduce our contracted transportation volumes and the rates we can charge for our services.


17



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

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

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

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

We compete with other energy companies.

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

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

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

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


18



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.

Partnership Structure Risks

Our general partner and its affiliates own a controlling interest in us, have conflicts of interest and owe us only limited fiduciary duties, which may permit them to favor their own interests.

BPHC, a wholly-owned subsidiary of Loews, owns approximately 53% of our equity interests, excluding the IDRs, and owns and controls our general partner, which controls us. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to BPHC. Furthermore, certain directors and officers of our general partner are also directors or officers of affiliates of our general partner. Conflicts of interest may arise between BPHC and its subsidiaries, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These potential conflicts include, among others, the following situations:  
BPHC and its affiliates may engage in competition with us;
neither our partnership agreement nor any other agreement requires BPHC or its affiliates (other than our general partner) to pursue a business strategy that favors us. Directors and officers of BPHC and its affiliates have a fiduciary duty to make decisions in the best interest of BPHC shareholders, which may be contrary to our interests;
our general partner is allowed to take into account the interests of parties other than us, such as BPHC and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
some officers of our general partner who provide services to us may devote time to affiliates of our general partner and may be compensated for services rendered to such affiliates;
our partnership agreement limits the liability and reduces the fiduciary duties of our general partner and the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
our general partner determines the amount and timing of asset purchases and sales, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;
our general partner determines the amount and timing of any capital expenditures and whether an expenditure is for maintenance capital, which reduces operating surplus, or a capital improvement expenditure, which does not. Such determination can affect the amount of cash that is distributed to our unitholders;
in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
our general partner determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us;
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf, and provides that reimbursement to Loews for amounts allocable to us consistent with accounting and allocation methodologies generally permitted by FERC for rate-making purposes and past business practices is deemed fair and reasonable to us;
our general partner controls the enforcement of obligations owed to us by it and its affiliates;
our general partner intends to limit its liability regarding our contractual obligations;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

19



our general partner may exercise its rights to call and purchase (1) all of our common units if, at any time, it and its affiliates own more than 80% of the outstanding common units or (2) all of our equity securities (including common units), if it and its affiliates own more than 50% in the aggregate of the outstanding common units and any other classes of equity securities and it receives an opinion of outside legal counsel to the effect that our being a pass-through entity for tax purposes has or is reasonably likely to have a material adverse effect on the maximum applicable rates we can charge our customers.

Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:  
permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or any limited partner. Decisions made by our general partner in its individual capacity will be made by a majority of the owners of our general partner, and not by the board of directors of our general partner. Examples of these kinds of decisions include the exercise of its call rights, its voting rights with respect to the units it owns and its registration rights and the determination of whether to consent to any merger or consolidation of the partnership;  
provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the partnership;  
generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions.

We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies.

Tax Risks    

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, or if we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, we would be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we

20



satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our 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. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
 
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to a material amount of entity-level taxation for federal, state or local income tax purposes, the target distribution amounts will be adjusted to reflect the impact of that law on us. 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 in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our unitholders.

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

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial or administrative changes and differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing 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 we rely for our treatment as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.
     
The IRS may adopt positions that differ from the positions that we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner, because the costs will reduce our cash available for distribution to our unitholders.

Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.
 
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to such unitholders' share of our taxable income or even equal to the actual tax liability that results from such unitholders' share of our taxable income.


21



Tax gain or loss on the disposition of our common units could be more or less than expected.
 
If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder's allocable share of our net taxable income result in a decrease to such unitholder's tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing a gain, may be taxed as ordinary income due to potential recapture of depreciation deductions and certain other items. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as "IRAs") and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Allocations and/or distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective tax rate applicable to non-U.S. persons, and each non-U.S. person will be required to file federal tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
     
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder's sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. If the IRS were to successfully challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are the subject of a securities loan, (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.


22



We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profit interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year, and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby a publicly traded partnership that has technically terminated may be permitted to provide only a single Schedule K-1 to unitholders for the two tax years within the fiscal year in which the termination occurs.

Our unitholders may be subject to state and local taxes and return filing requirements as a result of investing in our common units.

     In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in thirteen states. We may own property or conduct business in other states or foreign countries in the future. It is our unitholders' responsibility to file all federal, state and local tax returns.



23



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 also have approximately 60,000 square feet of leased office space in Owensboro, Kentucky. Our operating subsidiaries own their respective pipeline systems in fee. However, substantial portions of these systems are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Our Pipeline and Storage Systems, 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 5 in Item 8 of this report for a discussion of our legal proceedings.

Item 4.  Mine Safety Disclosures

None.

24



PART II

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

Our Partnership Interests

As of December 31, 2013, we had outstanding 243.3 million common units, a 2% general partner interest and IDRs. The common units represent all of our limited partner interests and 98% of our total ownership interests, in each case excluding our IDRs. As discussed below under Our Cash Distribution Policy—Incentive Distribution Rights, the IDRs represent the right for the holder to receive varying percentages of quarterly distributions of available cash from operating surplus in excess of certain specified target quarterly distribution levels. As such, the IDRs cannot be expressed as a constant percentage of our total ownership interests.

BPHC, a wholly-owned subsidiary of Loews, owns 125.6 million of our common units and, through Boardwalk GP, LP, an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the IDRs. As of February 24, 2014, the common units and general partner interest held by BPHC represent approximately 53% of our equity interests, excluding IDRs. The additional interest represented by the IDRs is not included in such ownership percentage because, as noted above, the IDRs cannot be expressed as a constant percentage of our ownership.

Market Information

As of February 20, 2014, we had 243.3 million common units outstanding held by approximately 76 holders of record. Our common units are traded on the NYSE under the symbol “BWP.”

The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the NYSE Composite Transactions Tape, and information regarding our quarterly distributions. The closing sales price of our common units on the NYSE on February 20, 2014, was $13.00 per unit.
 
Sales Price Range per
Common Unit
 
Cash Distributions
per
Common Unit (1) (2)
 
High
 
Low
 
Year ended December 31, 2013:
 
 
 
 
 
Fourth quarter
$
31.91

 
$
24.07

 
$
0.1000

Third quarter
33.00

 
29.06

 
0.5325

Second quarter
31.74

 
28.02

 
0.5325

First quarter
29.33

 
25.32

 
0.5325

Year ended December 31, 2012:
 

 
 

 
 

Fourth quarter
$
28.04

 
$
23.55

 
$
0.5325

Third quarter
29.16

 
26.40

 
0.5325

Second quarter
28.10

 
25.15

 
0.5325

First quarter
29.43

 
26.09

 
0.5325

(1)
Represents cash distributions attributable to the quarter and declared and paid to limited partner unitholders within 60 days after quarter end. 
(2)
We also paid cash distributions to our general partner with respect to its 2% general partner interest and, with respect to that portion of the distribution in excess of $0.4025 per unit, its IDRs described below. Our class B units converted into common units on a one-for-one basis on October 9, 2013, pursuant to the terms of our partnership agreement. Prior to the conversion, the class B unitholder participated in distributions on a pari passu basis with our common units up to $0.30 per quarter. The class B units did not participate in quarterly distributions above $0.30 per unit.

Our Cash Distribution Policy

Our cash distribution policy is consistent with the terms of our partnership agreement which requires us to distribute our “available cash,” as that term is defined in our partnership agreement, on a quarterly basis. Our distributions are determined by the board of directors of our general partner based on our financial position, earnings, cash flow and other relevant factors. However,

25



there is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions or limitations, including, among others, our general partner’s broad discretion to establish reserves which could reduce cash available for distributions, FERC regulations which place restrictions on various types of cash management programs employed by companies in the energy industry, including our operating subsidiaries subject to FERC jurisdiction, the requirements of applicable state partnership and limited liability company laws, and the requirements of our revolving credit facility which would prohibit us from making distributions to unitholders if an event of default were to occur. In addition, we may lack sufficient cash to pay distributions to unitholders due to a number of factors, including those described in Item 1A, Risk Factors, of this Report.

Incentive Distribution Rights

IDRs represent a limited partner ownership interest and include the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the target distribution levels have been achieved, as defined in our partnership agreement. Our general partner currently holds all of our IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. In 2013, 2012 and 2011, we paid $34.6 million, $30.1 million and $22.3 million in distributions on behalf of our IDRs. Note 13 in Item 8 of this Report contains more information regarding our distributions.

Assuming we do not issue any additional classes of units and our general partner maintains its 2% general partner interest, we will distribute any available cash from operating surplus for that quarter among the unitholders and our general partner as follows:
 
Total Quarterly Distribution
 
Marginal Percentage Interest
in Distributions
Target Amount
 
Limited Partner
Unitholders
(1)
 
General
Partner and IDRs
First Target Distribution
up to $0.4025
 
98%
 
2%
Second Target Distribution
above $0.4025
 up to $0.4375
 
85%
 
15%
Third Target Distribution
above $0.4375
 up to $0.5250
 
75%
 
25%
Thereafter
above $0.5250
 
50%
 
50%
(1)
Our class B units converted into common units on a one-for-one basis on October 9, 2013, pursuant to the terms of our partnership agreement. Prior to the conversion, distributions to our limited partner unitholders included distributions on behalf of our class B units. The class B units shared in quarterly distributions of available cash from operating surplus on a pari passu basis with our common units, until each common unit and class B unit received a quarterly distribution of $0.30. The class B units did not participate in quarterly distributions above $0.30 per unit.

Equity Compensation Plans

For information about our equity compensation plans, see Note 12 in Item 8 of this Report.

Issuer Purchases of Equity Securities

None.

26



Item 6.  Selected Financial Data

The following table presents our selected historical financial and operating data. As used herein, Adjusted EBITDA means earnings before interest, income taxes, depreciation and amortization. Adjusted EBITDA and distributable cash flow are not calculated or presented in accordance with accounting principles generally accepted in the U.S. (GAAP). We explain these measures below and reconcile them to the most directly comparable financial measures calculated and presented in accordance with GAAP in (2) Non-GAAP Financial Measures. The financial data below should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in Item 8 of this Report (in millions, except Net income per common unit, Net income per class B unit, Distributions per common unit and Distributions per class B unit):

 
For the Year Ended December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
Total operating revenues
$
1,205.6

 
$
1,185.0

 
$
1,142.9

 
$
1,116.8

 
$
909.2

Net income attributable to controlling interest
253.7

 
306.0

 
217.0

 
289.4

 
162.7

Total assets
7,914.5

 
7,862.5

 
7,266.4

 
6,878.0

 
6,895.8

Long-term debt
3,424.4

 
3,539.2

 
3,398.7

 
3,252.3

 
3,100.0

Net income per common unit - basic
1.00

 
1.37

 
1.09

 
1.47

 
0.88

Net income per class B unit - basic (1)
0.05

 
0.36

 
0.14

 
0.62

 
0.08

Net income per common unit - diluted
0.96

 
1.37

 
1.09

 
1.47

 
0.88

Net income per class B unit - diluted (1)
0.48

 
0.36

 
0.14

 
0.62

 
0.08

Distributions per common unit
2.13

 
2.1275

 
2.095

 
2.030

 
1.950

Distributions per class B unit (1)
0.90

 
1.20

 
1.20

 
1.20

 
1.20

Adjusted EBITDA (2)
688.7

 
726.5

 
617.4

 
658.2

 
498.0

Distributable cash flow (2)
558.6

 
497.4

 
407.9

 
467.5

 
322.5


(1)
On October 9, 2013, the class B units converted to common units on a one-for-one basis pursuant to the terms of our partnership agreement.
(2)
Non-GAAP Financial Measures.

We use non-GAAP measures to evaluate our business and performance, including Adjusted EBITDA and distributable cash flow. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess:
our financial performance without regard to financing methods, capital structure or historical cost basis; 
our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; 
our operating performance and return on invested capital as compared to those of other companies in the midstream portion of the natural gas and NGLs industry, without regard to financing methods and capital structure; and  
the viability of acquisitions and capital expenditure projects.
Distributable cash flow is used as a supplemental measure by management and by external users of our financial statements, as defined above, to assess our ability to make cash distributions to our unitholders and our general partner.

Adjusted EBITDA and distributable cash flow should not be considered alternatives to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, or as indicators of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA and distributable cash flow are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets. We have included information concerning Adjusted EBITDA because Adjusted EBITDA provides additional information as to our ability to meet our fixed charges and is presented solely as a supplemental measure. Likewise, we have included information concerning distributable cash flow as a supplemental financial measure we use to assess our ability to make distributions to our unitholders and general partner. However, viewing Adjusted EBITDA and distributable cash flow as indicators of our ability to make cash distributions on our common units should be done with caution, as we might be required to conserve funds or to allocate funds to business or legal

27



purposes other than making distributions. Adjusted EBITDA and distributable cash flow are not necessarily comparable to similarly titled measures of another company.

The following table presents a reconciliation of Adjusted EBITDA and distributable cash flow to net income, the most directly comparable GAAP financial measure for each of the periods presented below (in millions):

 
For the Year Ended December 31,
 
2013
 
2012 (5)
 
2011 (5)
 
2010
 
2009
Net income attributable to controlling interest
$
253.7

 
$
306.0

 
$
217.0

 
$
289.4

 
$
162.7

Income taxes
0.5

 
0.5

 
0.4

 
0.5

 
0.3

Depreciation and amortization
271.6

 
252.3

 
227.3

 
217.9

 
203.1

Interest expense
163.4

 
168.4

 
159.9

 
151.0

 
132.1

Interest income
(0.5
)
 
(0.7
)
 
(0.4
)
 
(0.6
)
 
(0.2
)
Loss on debt extinguishment

 

 
13.2

 

 

Adjusted EBITDA
$
688.7

 
$
726.5

 
$
617.4

 
$
658.2

 
$
498.0

Less:
 

 
 

 
 

 
 

 
 

Cash paid for interest net of capitalized interest (1)
151.0

 
169.8

 
172.7

 
146.3

 
124.4

Maintenance capital expenditures (2)
69.7

 
79.8

 
94.6

 
63.0

 
58.9

Add:
 

 
 

 
 

 
 

 
 

Proceeds from insurance recoveries and settlements (3)

 
9.2

 
5.0

 

 

Proceeds from sale of operating assets
60.7

 
5.9

 
31.5

 
30.9

 

Net (gain) loss on sale of operating assets
(29.5
)
 
(3.3
)
 
(8.6
)
 
(17.7
)
 
8.2

Asset impairment
4.1

 
9.1

 
30.5

 
5.8

 

Goodwill impairment
51.5

 

 

 

 

Other (4)
3.8

 
(0.4
)
 
(0.6
)
 
(0.4
)
 
(0.4
)
Distributable Cash Flow
$
558.6

 
$
497.4

 
$
407.9

 
$
467.5

 
$
322.5


(1)
The year ended December 31, 2012, included $9.6 million of payments related to the settlements of interest rate derivatives and the year ended December 31, 2011, included $21.0 million of premiums paid for the early extinguishment of debt.
(2)
The year ended December 31, 2011, included $14.3 million of maintenance capital expenditures related to repairs associated with a fire at our Carthage compressor station.
(3)
The years ended December 31, 2012 and 2011 represent insurance recoveries associated with the Carthage compressor fire and a legal settlement. All years exclude proceeds recognized in earnings.
(4)
Includes non-cash items such as the equity component of allowance for funds used during construction. The year ended December 31, 2013, includes ethylene inventory that was acquired through the acquisition of Louisiana Midstream and subsequently sold.
(5)
Certain amounts were reclassified within Total operating costs and expenses in the Consolidated Statements of Income for the 2012 and 2011 periods. Note 1 in Item 8 of this Report contains more information regarding the reclassification.




28



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

Overview

We are a master limited partnership operating in the midstream portion of the natural gas and NGLs industry, providing transportation, storage, gathering and processing services for those commodities. Our pipeline systems originate in the Gulf Coast region, Oklahoma and Arkansas and extend north and east to the midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio.
    
Our pipeline systems contain approximately 14,195 miles of interconnected natural gas pipelines, directly serving customers in thirteen states and indirectly serving customers throughout the northeastern and southeastern U.S. through numerous interconnections with unaffiliated pipelines. We also own approximately 255 miles of NGLs pipelines serving customers in Louisiana. In 2013, our pipeline systems transported approximately 2.4 Tcf of natural gas and approximately 7.5 MMbbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2013 was approximately 6.6 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of approximately 207.0 Bcf and our NGLs storage facilities located in Louisiana consist of eight salt dome caverns with a storage capacity of 17.6 MMbbls. We also have two salt-dome caverns for use in providing brine supply services and to support NGLs cavern operations. We conduct all of our business through our operating subsidiaries as one reportable segment.

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

Recent Developments

Market Conditions and Contract Renewals

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

29



adversely impacted our firm and interruptible transportation revenues. In light of the market conditions discussed above, natural gas transportation contracts we have renewed or entered into in 2013 and in recent years have been at lower rates, and any remaining available capacity generally has been marketed and sold at lower rates under short-term firm or interruptible contracts, or in some cases not sold at all. As a result, capacity reservation charges under firm transportation agreements for the year ended December 31, 2013, were lower by $45.4 million than they were for the comparable 2012 period. We expect this trend to continue and therefore may not be able to sell our available capacity, extend expiring contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts, all of which would continue to adversely impact our transportation revenues, EBITDA and distributable cash flows and could impact us on a long-term basis. 

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

In February 2014, we declared a quarterly distribution of $0.10 per unit, which was less than the quarterly distributions of $0.5325 per unit that we declared and paid in recent prior periods, which reflects the market conditions described above and the resulting cumulative impact on our business from the decline in transportation and storage revenues. We intend to use the increase in cash not distributed to unitholders to fund growth and/or to repay indebtedness. BPHC has also offered us up to $300.0 million of subordinated loans to fund growth, if it is needed. We intend to use those sources of capital to fund our growth and reduce our leverage (including our Debt-to-EBITDA ratio) in lieu of issuing additional limited partnership units which would be dilutive to our unitholders. We cannot give assurances that we will complete future growth projects or acquisitions or, if completed, that they will be accretive to our earnings and cash flow, that we will be successful in reducing our leverage, or that we will not issue and sell additional limited partnership units to fund our growth or for other partnership purposes.
    
Pipeline System Maintenance

We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, including those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. These costs are not dependent on the amount of revenues earned from our natural gas transportation services. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. These regulations have resulted in an overall increase in our ongoing maintenance costs, including maintenance capital and maintenance expense. Due to recent widely-known incidents that have occurred on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. We could incur significant additional costs if new or more stringently interpreted pipeline safety requirements are implemented.
    
Results of Operations
    
2013 Compared with 2012

Our net income attributable to controlling interests for the year ended December 31, 2013, decreased $52.3 million, or 17%, to $253.7 million compared to $306.0 million for the year ended December 31, 2012. The decrease in net income was primarily a result of the effects of unfavorable market conditions on our transportation and storage revenues and a goodwill impairment charge. See Critical Accounting Estimates and Policies for more information regarding the goodwill impairment charge.

Operating revenues for the year ended December 31, 2013, increased $20.6 million, or 2%, to $1,205.6 million, compared to $1,185.0 million for the year ended December 31, 2012. The increase was primarily due to $62.6 million of revenues from Louisiana Midstream, which was acquired on October 1, 2012, and increased revenues from fuel of $9.2 million resulting mainly from higher natural gas prices. The increase in revenues was partially offset by the market conditions discussed above, resulting in lower transportation revenues, excluding fuel, of $52.6 million and $3.6 million of reduced storage and PAL revenues.

Operating costs and expenses for the year ended December 31, 2013, increased $79.9 million, or 11%, to $791.1 million, compared to $711.2 million for the year ended December 31, 2012. The increase in operating expenses was driven by a $51.5 million goodwill impairment charge, the acquisition of Louisiana Midstream, which incurred $37.6 million of operating expenses, an increase of depreciation and property taxes of $8.9 million due to an increase in our asset base, and increased fuel costs of $6.0 million due to higher natural gas prices. These expenses were partially offset by a $29.9 million gain from the sale of storage gas.
 
Total other deductions for the year ended December 31, 2013, decreased by $3.5 million, or 2%, to $163.8 million compared to $167.3 million for the 2012 period, driven by lower interest expense due to lower average outstanding debt levels and lower interest rates.

2012 Compared with 2011

Our net income for the year ended December 31, 2012, increased $89.0 million, or 41%, to $306.0 million compared to $217.0 million for the year ended December 31, 2011. The increase in net income was primarily the result of the acquisitions of Petal, which occurred on December 1, 2011, and Louisiana Midstream, items which negatively impacted the 2011 period, and other items noted below.

Operating revenues for the year ended December 31, 2012, increased $42.1 million, or 4%, to $1,185.0 million, compared to $1,142.9 million for the year ended December 31, 2011. The increase was due to $62.5 million of revenues from Petal and Louisiana Midstream and higher PAL and storage revenues of $13.6 million, resulting from improved market conditions. The increase in revenues was partially offset by a decrease in retained fuel of $33.9 million primarily due to lower natural gas prices.
    
Operating costs and expenses for the year ended December 31, 2012, decreased $42.5 million, or 6%, to $711.2 million, compared to $753.7 million for the year ended December 31, 2011. The primary drivers of the decrease were lower fuel costs of $21.3 million primarily due to lower natural gas prices, lower administrative and general expenses of $16.0 million as a result of cost management activities, particularly with regard to outside services, corporate fees and labor and $10.8 million lower operation and maintenance expenses primarily from lower maintenance project costs and outside services. These decreases were partially offset by $37.9 million of expenses incurred by the acquired entities, $19.3 million of which was from depreciation and amortization. We also recorded $9.1 million of asset impairment charges in 2012, of which $2.8 million was related to our Owensboro, Kentucky, office facilities and the remainder related to the expected retirement of certain small-diameter pipeline assets. The 2011 period was unfavorably impacted by an impairment charge of $28.8 million related to materials and supplies which were subsequently sold, a $5.0 million charge related to a fire at our Carthage compressor station and a $3.7 million natural gas storage loss at our Bistineau facility, and favorably impacted by $9.2 million of gains from the sale of storage gas.

Total other deductions for the year ended December 31, 2012, decreased by $4.5 million, or 3%, to $167.3 million compared to $171.8 million for the year ended December 31, 2011 driven by a $13.2 million loss on the early extinguishment of debt recognized in the 2011 period, partially offset by higher interest expense of $8.5 million resulting from increased debt levels in 2012 and interest rate derivatives.

Liquidity and Capital Resources

We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility, debt issuances and sales of limited partner units. Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as needed, borrowings under our revolving credit facility to service outstanding indebtedness and make distributions or advances to us to fund our distributions to unitholders. We have no material guarantees of debt or other similar commitments to unaffiliated parties. BPHC has also offered us up to $300.0 million of subordinated loans to fund growth. We intend to use those sources of liquidity in an effort to fund our growth and reduce our leverage.


30



Capital Expenditures

Maintenance capital expenditures for the years ended December 31, 2013, 2012 and 2011 were $69.7 million $79.8 million and $94.6 million. Growth capital expenditures were $225.1 million, $147.1 million and $47.3 million for the years ended December 31, 2013, 2012 and 2011. We expect our total capital expenditures to be approximately $420.0 million in 2014, including approximately $90.0 million for maintenance capital.
    
Our more significant growth projects for 2014 consist of:

Southeast Market Expansion: We expect to spend approximately $300.0 million to construct an interconnection between our Gulf South and Petal subsidiaries, add additional compression facilities to our system and construct approximately 70 miles of 24-inch and 30-inch pipeline in southeastern Mississippi. To date, we have spent $53.8 million on this project and expect to spend an additional $248.9 million in 2014.

Ohio to Louisiana Access Project: We expect to spend approximately $115.0 million to allow us to reverse the traditional flow of a portion of our Texas Gas pipeline from northbound to southbound in order to provide long-term firm natural gas transportation from the Marcellus and Utica production areas to delivery markets in Louisiana. We expect to spend approximately $22.8 million in 2014 related to this project.

Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects: We have contributed a total of $11.9 million to the capital of Boardwalk Bluegrass and Boardwalk Moss Lake. BPHC has contributed the balance of the capital of these entities and anticipates contributing the additional capital required to fund certain agreed upon pre-construction development costs until such time as BPHC has a 90% equity ownership interest in each entity. Additional capital required for Boardwalk Bluegrass and Boardwalk Moss Lake to continue to pursue the Bluegrass Project is subject to approval by us and BPHC. We do not expect to spend significant amounts of capital on these projects until approvals have been received and the parties have determined to proceed with construction of the Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG projects.

Refer to Item 1 for further discussion of these projects.

Equity and Debt Financing

We anticipate that our existing capital resources, including our revolving credit facility and future cash flows will be adequate to fund our operations, including our maintenance capital expenditures in 2014. To help fund growth in 2014, a subsidiary of Loews has offered to provide us with up to $300.0 million in subordinated debt if it is required. Although we anticipate that our existing capital resources including the subordinated loan will be adequate to fund our current growth projects, we may seek to access the capital markets to fund some or all capital expenditures for future growth projects or acquisitions, or to repay or refinance all or a portion of our indebtedness, a significant amount of which matures in the next five years. Our ability to access the capital markets for equity and debt financing under reasonable terms depends on our financial condition, credit ratings and market conditions.
    
In May 2013, we completed a public offering of 12.7 million of our common units at a price of $30.12 per unit. We received net cash proceeds of approximately $376.5 million after deducting underwriting discounts and offering expenses of $12.3 million and including a $7.8 million contribution received from our general partner to maintain its 2% general partner interest. The net proceeds were used to repay borrowings under our revolving credit facility.

On October 9, 2013, all of the 22.9 million class B units were converted into common units on a one-for-one basis, pursuant to the terms of the partnership agreement. After the conversion, we had 243.3 million outstanding common units.

Revolving Credit Facility

As of December 31, 2013, we had $175.0 million of borrowings outstanding under our revolving credit facility with a weighted-average interest rate of 1.29% and no letters of credit issued thereunder. As of February 21, 2014, we had outstanding borrowings under our revolving credit facility of $250.0 million, resulting in available borrowing capacity of $750.0 million.
    
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 require us and our subsidiaries 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

31



more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following an acquisition. We and our subsidiaries were in compliance with all covenant requirements under the credit facility as of December 31, 2013. Note 11 in Item 8 of this Report contains more information regarding our revolving credit facility.

Contractual Obligations
 
The following table summarizes significant contractual cash payment obligations under firm commitments as of December 31, 2013, by period (in millions):
 
Total
 
Less than
1 Year
 
1-3 Years
 
3-5 Years
 
More than
5 Years
Principal payments on long-term debt (1)
$
3,425.0

 
$

 
$
775.0

 
$
1,160.0

 
$
1,490.0

Interest on long-term debt (2)
822.0

 
152.8

 
267.9

 
178.8

 
222.5

Capital commitments (3)
86.1

 
86.1

 

 

 

Pipeline capacity agreements (4)
43.9

 
10.9

 
19.6

 
13.4

 

Operating lease commitments
19.2

 
5.3

 
9.7

 
4.0

 
0.2

Capital lease commitments (5)
15.6

 
1.0

 
2.0

 
2.0

 
10.6

Total
$
4,411.8

 
$
256.1

 
$
1,074.2

 
$
1,358.2

 
$
1,723.3

(1)
Includes our senior unsecured notes, having maturity dates from 2015 to 2027, $175.0 million of loans outstanding under our revolving credit facility, having a maturity date of April 27, 2017, and $225.0 million of loans outstanding under our term-loan, having a maturity date of October 1, 2017.
(2)
Interest obligations represent interest due on our senior unsecured notes at fixed rates. Future interest obligations under our revolving credit facility are uncertain, due to the variable interest rate and fluctuating balances. Based on a 1.29% weighted-average interest rate and an unused commitment fee of 0.16% as of December 31, 2013, $3.5 million, $7.1 million and $1.2 million would be due in less than one year, 1-3 years and 3-5 years. Interest obligations under the Term Loan are also subject to variable interest rates.  Based on a 1.92% weighted-average interest rate on amounts outstanding under the Term Loan as of December 31, 2013, $4.3 million, $8.6 million and $3.2 million would be due in less than one year, 1-3 years and 3-5 years.
(3)
Capital commitments represent binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at December 31, 2013.
(4)
The amounts shown are associated with pipeline capacity agreements on third-party pipelines that allow our operating subsidiaries to transport gas to off-system markets on behalf of our customers.
(5)
Capital lease commitments represent future non-cancelable minimum lease payments under a capital lease agreement.

Pursuant to the settlement of the Texas Gas rate case in 2006, we are required to annually fund an amount to the Texas Gas pension plan equal to the amount of actuarially determined net periodic pension cost, including a minimum of $3.0 million. In 2014, we expect to fund approximately $3.0 million to the Texas Gas pension plan.

Distributions

For the years ended December 31, 2013, 2012 and 2011, we paid distributions of $533.9 million, $478.9 million and $419.9 million to our partners. Note 13 in Item 8 of this report contains further discussion regarding our distributions.

Changes in cash flow from operating activities

Net cash provided by operating activities decreased $41.2 million to $534.3 million for the year ended December 31, 2013, compared to $575.5 million for the comparable 2012 period, primarily due to a reduction in our earnings as discussed under Results of Operations.


32



Changes in cash flow from investing activities

Net cash used in investing activities decreased $521.4 million to $309.4 million for the year ended December 31, 2013, compared to $830.8 million for the comparable 2012 period. The change was driven by the 2012 acquisition of Louisiana Midstream of $620.2 million and an increase in proceeds from the sale of assets and insurance recoveries of $45.8 million, primarily from the sale of storage gas. These items were partially offset by an increase in capital expenditures of $67.9 million and the investment in the Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG projects of $76.7 million.

Changes in cash flow from financing activities

Net cash used in financing activities was $200.3 million for the year ended December 31, 2013, compared to net cash provided by financing activities of $237.3 million for the comparable 2012 period, a net use of cash of $437.6 million. The increase in cash used in financing activities resulted primarily from a decrease of $489.2 million from the issuance and sale of common units, including related general partner contributions, and a $55.0 million increase in distributions to our partners.
 
Impact of Inflation

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

Off-Balance Sheet Arrangements

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

Critical Accounting Estimates and Policies

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

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

Regulation

Most of our natural gas pipeline subsidiaries 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. At December 31, 2013 and 2012, there were no liabilities for any open rate case recorded on our Consolidated Balance Sheets. Currently, none of our regulated companies are involved in an open general rate case.

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). This basis of accounting is applicable to operations of our Texas Gas subsidiary which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refund to customers in future periods, but is not applicable to operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate agreements and a portion of the storage capacity due to the regulatory treatment associated with the rates charged for that capacity. Regulatory accounting is not applicable to our other FERC-regulated entities.

We monitor the regulatory and competitive environment in which we operate to determine that any regulatory assets continue to be probable of recovery. If we were to determine that all or a portion of our regulatory assets no longer met the criteria for recognition as regulatory assets, that portion which was not recoverable would be written off, net of any regulatory liabilities. Note 10 in Item 8 of this Report contains more information regarding our regulatory assets and liabilities.
 
In the course of providing transportation and storage services to customers, the natural gas pipelines 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 for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage for operations where regulatory accounting is applicable, consistent with the regulatory treatment.

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 perform our goodwill impairment testing and report fair values for certain items in the Notes to the Consolidated Financial Statements in Item 8 of this Report. Notes 6 and 12 contain more information regarding our fair value measurements.

Environmental Liabilities

Our environmental liabilities are based on management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of our operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these environmental matters. At December 31, 2013, we had accrued approximately $6.5 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 5 in Item 8 of this Report contains more information regarding our environmental liabilities.

Goodwill

Goodwill is tested for impairment at the reporting unit level at least annually or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Accounting requirements provide that a reporting entity may perform an optional qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If an initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or the optional qualitative assessment is not performed, a quantitative analysis is performed under a two-step impairment test to measure whether the fair value of the reporting unit is less than its carrying amount. If the fair value of the reporting unit is determined to be less than its carrying amount, including goodwill, the reporting entity must perform an analysis of the fair value of all of the assets and liabilities of the reporting unit. If the implied fair value of the reporting unit's goodwill is determined to be less than its carrying amount, an impairment loss is recognized for the difference. The implied fair value of goodwill is the excess of the fair value of the reporting unit over the fair value amounts assigned to all of the assets and liabilities of that unit as if the reporting unit was acquired in a business combination and the fair value of the reporting unit represented the purchase price.

We performed a quantitative goodwill impairment test for each of our three reporting units as of November 30, 2013, which corresponds with the preparation of our five-year financial plan operating results. The fair value measurement of the reporting units was derived based on judgments and assumptions we believe market participants would use in assessing the fair value of the reporting units. These judgments and assumptions included the valuation premise, use of a discounted cash flow model to

33



estimate fair value and inputs to the valuation model. The inputs included our five-year financial plan operating results, the long-term outlook for growth in natural gas demand in the U.S. and measures of the risk-free rate, equity premium and systematic risk used in the calculation of the applied discount rate under the capital asset pricing model. The use of alternate judgments and assumptions could substantially change the results of our goodwill impairment analysis, including the recognition of an impairment charge in our consolidated financial statements.

The results of the quantitative goodwill impairment test indicated that the fair value of two of our reporting units significantly exceeded their carrying amounts and no goodwill impairment charges were recognized for those reporting units. The carrying amount of the third reporting unit, which included goodwill associated with our Petal acquisition, exceeded the estimated fair value and the second step of the goodwill impairment test was performed. In the fourth quarter 2013, we recognized a goodwill impairment charge of $51.5 million, representing the carrying amount of the goodwill for that reporting unit. The fair value of the reporting unit declined from the amount determined in 2012 due primarily to the recent narrowing of time period price spreads and reduced volatility which negatively affects the value of our storage and PAL services and the cumulative effect of reduced basis spreads on the value of our transportation services, as discussed under Market Conditions and Contract Renewals. No impairment charge related to goodwill was recorded for any of our reporting units during 2012 or 2011.

Impairment of Long-Lived Assets (including Tangible and Definite-Lived Intangible 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.

During the fourth quarter of 2013, we considered the goodwill impairment of one of our reporting units an indicator of impairment related to the long-lived assets associated with the reporting unit’s asset group. Accordingly, we evaluated the reporting unit’s asset group for impairment based on undiscounted cash flow projections expected over the remaining useful life of the reporting unit’s primary assets and concluded that the long-lived assets were not impaired.

Defined Benefit Plans

We are required to make a significant number of assumptions in order to estimate the liabilities and costs related to our pension and postretirement benefit obligations to employees under our benefit plans. The assumptions that have the most impact on our pension and postretirement benefit costs are the discount rate, the expected return on plan assets and the rate of compensation increases. These assumptions are evaluated relative to current market factors in the U.S. such as inflation, interest rates and fiscal and monetary policies, as well as our policies regarding management of the plans such as the allocation of plan assets among investment options. Changes in these assumptions can have a material impact on obligations and related expense associated with these plans.

In determining the discount rate assumption, we utilize current market information and liability information provided by our plan actuaries, including a discounted cash flow analysis of our pension and postretirement obligations. In particular, the basis for our discount rate selection was the yield on indices of highly rated fixed income debt securities with durations comparable to that of our plan liabilities. The Merrill Lynch AA-rated Corporate Bond Index is consistently used as the basis for the change in discount rate from the last measurement date with this measure confirmed by the yield on other broad bond indices. Additionally, we supplement our discount rate decision with a yield curve analysis. The yield curve is applied to expected future retirement plan payments to adjust the discount rate to reflect the cash flow characteristics of the plans. The yield curve is developed by the plans' actuaries and is a hypothetical AA/Aa yield curve represented by a series of annualized discount rates reflecting bond issues having a rating of Aa or better by Moody's Investors Service, Inc. or a rating of AA or better by Standard & Poor's. Note 12 in Item 8 of this Report contains more information regarding our pension and postretirement benefit obligations.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this Report, as well as some statements in periodic press releases and some oral statements made by our officials and our subsidiaries 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 our partnership or our subsidiaries, are also forward-looking statements.


34



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

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

the impact to our business of our declaring a lower distribution rate on our common units;

the costs of maintaining and ensuring the integrity and reliability of our pipeline systems;

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

volatility or disruptions in the capital or financial markets;

the impact of FERC rate-making policies and actions on the services we offer, the rates we charge, our ability to recover the full cost of operating our pipelines, including earning a reasonable return, and overall business strategies such as converting a portion of the Texas Gas pipeline to NGLs service;

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

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

the success of our strategy to grow and diversify our business, including expansion into new product lines and geographic areas;

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

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

the future cost of insuring our assets;

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

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

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


35



Item 7A.  Quantitative and Qualitative Disclosures About Market Risk
 
Interest rate risk:

With the exception of our revolving credit facility and our term loan, for which the interest rates are periodically reset, our debt has been issued at fixed rates. For fixed-rate debt, changes in interest rates affect the fair value of the debt instruments but do not directly affect earnings or cash flows. The following table presents market risk associated with our fixed-rate long-term debt at December 31 (in millions, except interest rates):
 
2013
 
2012
Carrying amount of fixed-rate debt
$
3,014.4

 
$
3,012.2

Fair value of fixed-rate debt
$
3,173.8

 
$
3,314.1

100 basis point increase in interest rates and resulting debt decrease
$
134.6

 
$
167.7

100 basis point decrease in interest rates and resulting debt increase
$
143.8

 
$
180.6

Weighted-average interest rate
5.32
%
 
5.32
%

At December 31, 2013, we had $400.0 million of variable-rate debt outstanding at a weighted-average interest rate of 1.64%. A 1% increase in interest rates would increase our cash payments for interest on our variable-rate debt by $4.0 million on an annualized basis. At December 31, 2012, we had $527.0 million outstanding under variable-rate agreements at a weighted-average interest rate of 1.60%.
    
At December 31, 2013 and 2012, $28.5 million and $3.9 million of our undistributed cash, shown on the balance sheets as Cash and cash equivalents, was primarily invested in Treasury fund accounts. Due to the short-term nature of the Treasury fund accounts, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the fair market value of our Cash and cash equivalents.

Commodity risk:

Our pipelines do not take title to the natural gas and NGLs which they transport and store, therefore they do not assume the related commodity price risk associated with the products. However, certain volumes of our gas stored underground are available for sale and subject to commodity price risk. At December 31, 2013 and 2012, approximately $0.3 million and $7.0 million of gas stored underground, which we own and carry as current Gas stored underground, was available for sale and exposed to commodity price risk. We manage our exposure to commodity price risk through the use of futures, swaps and option contracts. Note 6 of Item 8 contains additional information regarding our derivative contracts.

Credit risk:

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

As of December 31, 2013, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 19.6 trillion British thermal units (TBtu). Assuming an average market price during December 2013 of $4.17 per million British thermal units (MMBtu), the market value of that gas was approximately $81.7 million. As of December 31, 2012, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 11.7 TBtu. Assuming an average market price during December 2012 of $3.32 per MMBtu, the market value of this gas at December 31, 2012, would have been approximately $38.8 million. As of December 31, 2013, there were no outstanding imbalances owed to the operating subsidiaries from NGLs. As of December 31, 2012, the amount of NGLs owed to the operating subsidiaries due to imbalances was approximately 0.1 MMbbls, which had a market value of approximately $6.8 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

36



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.


37



Item 8.  Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Boardwalk GP, LLC
and the Partners of Boardwalk Pipeline Partners, LP

We have audited the accompanying consolidated balance sheets of Boardwalk Pipeline Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows and changes in equity for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated financial statements present fairly, in all material respects, the financial position of Boardwalk Pipeline Partners, LP and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2014, expressed an unqualified opinion on the Partnership's internal control over financial reporting.


/s/ Deloitte & Touche LLP
Houston, Texas
February 24, 2014

38



BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)

 
December 31,
ASSETS
2013
 
2012
Current Assets:
 
 
 
Cash and cash equivalents
$
28.5

 
$
3.9

Receivables:
 

 
 

Trade, net
103.5

 
105.3

Affiliates
1.1

 

Other
15.7

 
6.9

Gas transportation receivables
7.8

 
9.0

Costs recoverable from customers
0.8

 
3.3

Gas and liquids stored underground
0.7

 
10.8

Prepayments
12.9

 
15.2

Other current assets
6.1

 
2.6

Total current assets
177.1

 
157.0

 
 
 
 
Property, Plant and Equipment:
 

 
 

Natural gas transmission and other plant
8,548.8

 
8,165.3

Construction work in progress
174.5

 
258.0

Property, plant and equipment, gross
8,723.3

 
8,423.3

Less—accumulated depreciation and amortization
1,489.2

 
1,234.1

Property, plant and equipment, net
7,234.1

 
7,189.2

 
 
 
 
Other Assets:
 

 
 

Goodwill
215.5

 
267.0

Gas stored underground
79.7

 
109.7

Investment in unconsolidated affiliates
78.6

 

Other
129.5

 
139.6

Total other assets
503.3

 
516.3

 
 
 
 
Total Assets
$
7,914.5

 
$
7,862.5


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

39



BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)

 
December 31,
LIABILITIES AND EQUITY
2013
 
2012
Current Liabilities:
 
 
 
Payables:
 
 
 
Trade
$
65.1

 
$
69.8

Affiliates
1.2

 
2.7

Other
5.7

 
19.2

Gas Payables:
 

 
 

Transportation
8.8

 
10.4

Storage
0.2

 
3.5

Accrued taxes, other
46.1

 
40.5

Accrued interest
45.4

 
42.5

Accrued payroll and employee benefits
26.4

 
25.2

Deferred income
9.3

 
19.9

Other current liabilities
27.8

 
22.1

Total current liabilities
236.0

 
255.8

 
 
 
 
Long–term debt and capital lease obligation
3,424.4

 
3,539.2

 
 
 
 
Other Liabilities and Deferred Credits:
 

 
 

Pension liability
17.1

 
26.8

Asset retirement obligation
39.3

 
33.2

Provision for other asset retirement
57.6

 
57.4

Payable to affiliate
16.0

 
16.0

Other
60.7

 
57.0

Total other liabilities and deferred credits
190.7

 
190.4

 
 
 
 
Commitments and Contingencies


 


 
 
 
 
Equity:
 
 
 
Partners’ Capital:
 

 
 

Common units – 243.3 million and 207.7 million units issued and
     outstanding as of  December 31, 2013 and 2012
3,963.4

 
3,190.3

Class B units – 22.9 million units issued and outstanding as of
     December 31, 2012

 
678.3

General partner
77.3

 
75.8

Accumulated other comprehensive loss
(63.8
)
 
(67.3
)
Total partners’ capital
3,976.9

 
3,877.1

Noncontrolling interest
86.5

 

Total Equity
4,063.4

 
3,877.1

Total Liabilities and Equity
$
7,914.5

 
$
7,862.5


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


BOARDWALK PIPELINE PARTNERS, LP

40



CONSOLIDATED STATEMENTS OF INCOME
(Millions, except per unit amounts)
 
For the Year Ended December 31,
 
2013
 
2012
 
2011
Operating Revenues:
 
 
 
 
 
Transportation
$
1,028.0

 
$
1,058.3

 
$
1,067.2

Parking and lending
23.9

 
28.0

 
12.0

Storage
110.9

 
84.7

 
52.2

Other
42.8

 
14.0

 
11.5

Total operating revenues
1,205.6

 
1,185.0

 
1,142.9

 
 
 
 
 
 
Operating Costs and Expenses:
 

 
 

 
 

Fuel and transportation
93.4

 
79.4

 
102.8

Operation and maintenance
186.5

 
167.2

 
175.2

Administrative and general
117.4

 
115.3

 
137.2

Depreciation and amortization
271.6

 
252.3

 
227.3

Asset impairment
4.1

 
9.1

 
30.5

Goodwill impairment
51.5

 

 

Net gain on sale of operating assets
(29.5
)
 
(3.3
)
 
(8.6
)
Taxes other than income taxes
96.1

 
91.2

 
89.3

Total operating costs and expenses
791.1

 
711.2

 
753.7

 
 
 
 
 
 
Operating income
414.5

 
473.8

 
389.2

 
 
 
 
 
 
Other Deductions (Income):
 

 
 

 
 

Interest expense
163.4

 
161.5

 
151.9

Interest expense – affiliates

 
6.9

 
8.0

Loss on early retirement of debt

 

 
13.2

Interest income
(0.5
)
 
(0.7
)
 
(0.4
)
Equity losses in unconsolidated affiliates
1.2

 

 

Miscellaneous other income
(0.3
)
 
(0.4
)
 
(0.9
)
Total other deductions
163.8

 
167.3

 
171.8

 
 
 
 
 
 
Income before income taxes
250.7

 
306.5

 
217.4

 
 
 
 
 
 
Income taxes
0.5

 
0.5

 
0.4

 
 
 
 
 
 
Net Income
250.2

 
306.0

 
217.0

Net loss attributable to noncontrolling interests
(3.5
)
 

 

Net income attributable to controlling interests
$
253.7

 
$
306.0

 
$
217.0

Net Income per Unit:
 
 
 

 
 

 
 
 
 
 
 
Basic net income per unit:
 

 
 

 
 

Common units
$
1.00

 
$
1.37

 
$
1.09

Class B units
$
0.05

 
$
0.36

 
$
0.14

Weighted-average number of units outstanding - basic
 

 
 

 
 

Common units
220.5

 
191.9

 
173.3

Class B units
17.6

 
22.9

 
22.9

Diluted net income per unit:
 
 
 
 
 
Common units
$
0.96

 
$
1.37

 
$
1.09

Class B units
$
0.48

 
$
0.36

 
$
0.14

Weighted-average number of units outstanding - diluted
 
 
 
 
 
Common units
226.8

 
191.9

 
173.3

Class B units
11.3

 
22.9

 
22.9

Cash distribution declared and paid to common units
$
2.13

 
$
2.1275

 
$
2.095

Cash distribution declared and paid to class B units
$
0.90

 
$
1.20

 
$
1.20


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


41




BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions)

 
For the Year Ended December 31,
 
2013
 
2012
 
2011
Net income
$
250.2

 
$
306.0

 
$
217.0

Other comprehensive income (loss):
 

 
 

 
 

Gain (loss) on cash flow hedges
1.6

 
(7.1
)
 
3.1

Reclassification adjustment transferred to Net Income from cash flow hedges
1.2

 
2.0

 
0.2

Pension and other postretirement benefit costs
0.7

 
(12.8
)
 
(13.2
)
Total Comprehensive Income
$
253.7

 
$
288.1

 
$
207.1

Comprehensive loss attributable to noncontrolling interests
(3.5
)
 

 

Comprehensive income attributable to controlling interests
$
257.2

 
$
288.1

 
$
207.1


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


42



BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
 
For the Year Ended
 December 31,
OPERATING ACTIVITIES:
2013
 
2012
 
2011
Net income
$
250.2

 
$
306.0

 
$
217.0

Adjustments to reconcile net income to cash provided by operations:
 

 
 
 
 
Depreciation and amortization
271.6

 
252.3

 
227.3

Amortization of deferred costs
5.5

 
6.4

 
9.3

Asset impairment
4.1

 
9.1

 
30.5

Goodwill impairment
51.5

 

 

Loss on early retirement of debt

 

 
13.2

Storage gas loss

 

 
3.7

Net gain on sale of operating assets
(29.5
)
 
(3.3
)
 
(8.6
)
Equity losses in unconsolidated affiliates
1.2

 

 

Changes in operating assets and liabilities:
 

 
 
 
 
Trade and other receivables
(10.0
)
 
5.4

 
(15.7
)
Other receivables, affiliates
0.5

 
0.1

 

Gas receivables and storage assets
18.0

 
(10.4
)
 
15.9

Costs recoverable from customers
2.6

 
6.5

 
(2.6
)
Other assets
(10.7
)
 
(1.7
)
 
(26.4
)
Trade and other payables
(16.8
)
 
8.3

 
(4.1
)
Other payables, affiliates
0.7

 
(3.1
)
 

Gas payables
0.5

 
13.5

 
(17.2
)
Accrued liabilities
8.6

 
(1.5
)
 
7.3

Other liabilities
(13.7
)
 
(12.1
)
 
4.3

Net cash provided by operating activities
534.3

 
575.5

 
453.9

INVESTING ACTIVITIES:
 

 
 

 
 

Capital expenditures
(294.8
)
 
(226.9
)
 
(141.9
)
Proceeds from sale of operating assets
60.7

 
5.9

 
31.5

Proceeds from insurance and other recoveries
1.4

 
10.4

 
9.6

Investment in unconsolidated affiliates
(76.7
)
 

 

Acquisition of businesses, net of cash acquired

 
(620.2
)
 
(545.5
)
Net cash used in investing activities
(309.4
)
 
(830.8
)
 
(646.3
)
FINANCING ACTIVITIES:
 

 
 

 
 

Proceeds from long-term debt and term loans

 
818.0

 
636.8

Repayment of borrowings from long-term debt, term loans and
     subordinated debt

 
(525.0
)
 
(250.0
)
Payments of premiums on extinguishment of long-term debt

 

 
(21.0
)
Proceeds from borrowings on revolving credit agreement
1,128.0

 
2,135.0

 
585.0

Repayment of borrowings on revolving credit agreement,
    including financing costs
(1,255.0
)
 
(2,295.3
)
 
(830.0
)
Contribution received related to predecessor equity

 
269.2

 
284.8

Principal payment of capital lease obligation
(0.2
)
 

 

Repayment of contribution received related to predecessor equity

 
(554.0
)
 

Advances from affiliate
(2.8
)
 
2.6

 

Distributions paid
(533.9
)
 
(478.9
)
 
(419.9
)
Capital contributions from noncontrolling interests
87.1

 

 

Proceeds from sale of common units
368.7

 
847.7

 
170.0

Capital contribution from general partner
7.8

 
18.0

 
3.6

Net cash (used in) provided by financing activities
(200.3
)
 
237.3

 
159.3

Increase (decrease) in cash and cash equivalents
24.6

 
(18.0
)
 
(33.1
)
Cash and cash equivalents at beginning of period
3.9

 
21.9

 
55.0

Cash and cash equivalents at end of period
$
28.5

 
$
3.9

 
$
21.9

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

43



BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions)
 
Partners' Capital
 
 
 
 
 
Common
Units
 
Class B
Units
 
General
Partner
 
Predecessor Equity
 
Accumulated Other Comp
Income (Loss)
 
Non-controlling Interests
 
Total Equity
Balance January 1, 2011
$
2,534.4

 
$
683.6

 
$
62.9

 
$

 
$
(39.5
)
 

 
$
3,241.4

Add (deduct):
 
 
 
 
 
 
 
 
 
 
 
 
 

Net income (loss)
171.4

 
22.6

 
26.2

 
(3.2
)
 

 

 
217.0

Distributions paid
(361.7
)
 
(27.5
)
 
(30.7
)
 

 

 

 
(419.9
)
Sale of common units, net of
    related transaction costs
170.0

 

 

 

 

 

 
170.0

Capital contribution from
    general partner

 

 
3.6

 

 

 

 
3.6

Contribution received related
    to predecessor equity

 

 

 
284.8

 

 

 
284.8

Other comprehensive loss,
    net of tax

 

 

 

 
(9.9
)
 

 
(9.9
)
Balance December 31, 2011
$
2,514.1

 
$
678.7

 
$
62.0

 
$
281.6

 
$
(49.4
)
 
$

 
$
3,487.0

Add (deduct):
 
 
 
 
 
 
 
 
 
 
 
 
 

Net income (loss)
245.0

 
27.5

 
35.7

 
(2.2
)
 

 

 
306.0

Distributions paid
(411.8
)
 
(27.4
)
 
(39.7
)
 

 

 

 
(478.9
)
Sale of common units, net of
    related transaction costs
847.7

 

 

 

 

 

 
847.7

Capital contribution from
    general partner

 

 
18.0

 

 

 

 
18.0

Contribution received related
    to predecessor equity

 

 

 
269.2

 

 

 
269.2

Predecessor equity carrying
    amount of acquired entities

 

 

 
(548.6
)
 

 

 
(548.6
)
Excess purchase price over
    net acquired assets
(4.7
)
 
(0.5
)
 
(0.2
)
 

 

 

 
(5.4
)
Other comprehensive loss,
    net of tax

 

 

 

 
(17.9
)
 

 
(17.9
)
Balance December 31, 2012
$
3,190.3

 
$
678.3

 
$
75.8

 
$

 
$
(67.3
)
 
$

 
$
3,877.1

Add (deduct):
 

 
 

 
 

 
 
 
 

 
 
 
 

Net income (loss)
194.5

 
20.2

 
39.0

 

 

 
(3.5
)
 
250.2

Distributions paid
(468.0
)
 
(20.6
)
 
(45.3
)
 

 

 

 
(533.9
)
Sale of common units, net
    of related transaction
    costs
368.7

 

 

 

 

 

 
368.7

Capital contribution from
    general partner

 

 
7.8

 

 

 

 
7.8

Conversion of class B units to common units
677.9

 
(677.9
)
 

 

 

 

 

Capital contributions from
    noncontrolling interests

 

 

 

 

 
90.0

 
90.0

Other comprehensive loss,
   net of tax

 

 

 

 
3.5

 

 
3.5

Balance December 31, 2013
$
3,963.4

 
$

 
$
77.3

 
$

 
$
(63.8
)
 
$
86.5

 
$
4,063.4


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

44



BOARDWALK PIPELINE PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1:  Corporate Structure

Boardwalk Pipeline Partners, LP (the Partnership) is a Delaware limited partnership formed in 2005 to own and operate the business conducted by its primary subsidiary Boardwalk Pipelines, LP (Boardwalk Pipelines), and its operating subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South), Texas Gas Transmission, LLC (Texas Gas), Boardwalk Field Services, LLC (Field Services), Petal Gas Storage, LLC (formerly referred to as Boardwalk HP Storage, LLC) (Petal), Boardwalk Louisiana Midstream, LLC (Louisiana Midstream) and Boardwalk Storage Company, LLC (Boardwalk Storage) (together, the operating subsidiaries), and consists of integrated natural gas and natural gas liquids (NGLs) pipeline and storage systems and natural gas gathering and processing. All of the Partnership’s operations are conducted by its operating subsidiaries.

As of February 24, 2014, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned 125.6 million of the Partnership’s common units, and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the incentive distribution rights (IDRs). As of February 24, 2014, the common units and general partner interest owned by BPHC represent approximately 53% of the Partnership’s equity interests, excluding the IDRs. The Partnership's Class B limited partner interests converted to common units on a one-for-one basis on October 9, 2013. The Partnership’s common units are traded under the symbol “BWP” on the New York Stock Exchange.

Basis of Presentation

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

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

Note 2:  Accounting Policies

Principles of Consolidation

The consolidated financial statements include the Partnership’s accounts and those of its wholly-owned subsidiaries after elimination of intercompany transactions. The Partnership also consolidates variable interest entities (VIEs) in which the Partnership is the primary beneficiary. Third party or affiliate ownership interests in the Partnership's subsidiaries and consolidated VIEs are presented as noncontrolling interests.

The Partnership applies the equity method of accounting for investments in unconsolidated affiliates in which it owns 20 percent to 50 percent of the voting interests or otherwise exercises significant influence, but not control, over operating and financial policies of the investee. Under this method, the carrying amounts of the Partnership's equity investments are increased by a proportionate share of the investee's net income and contributions made, and decreased by a proportionate share of the investee's net losses and distributions received.

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. The Partnership 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.


45



Segment Information

The Partnership operates in one reportable segment - the operation of interstate natural gas and natural gas liquids (NGLs) pipeline systems including integrated storage facilities. This segment consists of interstate natural gas pipeline systems which originate in the Gulf Coast region, Oklahoma and Arkansas, and extend north and east through the Midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio and NGLs pipelines and storage facilities in Louisiana.

Regulatory Accounting

Most of the Partnership's natural gas pipeline subsidiaries are 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). This basis of accounting is applicable to operations of the Partnership’s Texas Gas subsidiary which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refund to customers in future periods, but is not applicable to operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate agreements and a portion of the storage capacity due to the regulatory treatment associated with the rates charged for that capacity. Regulatory accounting is not applicable to the Partnership’s other FERC-regulated entities.

The Partnership monitors the regulatory and competitive environment in which it operates to determine that its regulatory assets continue to be probable of recovery. If the Partnership were to determine that all or a portion of its regulatory assets no longer met the criteria for recognition as regulatory assets, that portion which was not recoverable would be written off, net of any regulatory liabilities.

Note 10 contains more information regarding the Partnership’s regulatory assets and liabilities.

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. The Partnership uses fair value measurements to record derivatives, asset retirement obligations and impairments. Fair value measurements are also used to perform goodwill impairment testing and report fair values for certain items contained in this Report. The Partnership considers any transfers between levels within the fair value hierarchy to have occurred at the beginning of a quarterly reporting period.  The Partnership did not recognize any transfers between Level 1 and Level 2 of the fair value hierarchy and did not change its valuation techniques or inputs during the year ended December 31, 2013.

Notes 6 and 12 contain more information regarding fair value measurements.

Cash and Cash Equivalents

Cash equivalents are highly liquid investments with an original maturity of three months or less and are stated at cost plus accrued interest, which approximates fair value. The Partnership had no restricted cash at December 31, 2013 and 2012.

Cash Management

The operating subsidiaries participate in an intercompany cash management program with those that are FERC-regulated participating to the extent they are permitted under FERC regulations. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, Boardwalk Pipelines either provides cash to them or they provide 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. 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. The Partnership establishes an allowance for doubtful accounts on a case-by-case basis when it believes the required payment of specific

46



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

Certain of the Partnership's operating subsidiaries have 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 the operating subsidiaries, 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.

The operating subsidiaries provide storage services whereby they store natural gas or NGLs on behalf of customers and also periodically hold customer gas under PAL services. Since the customers retain title to the gas held by the Partnership in providing these services, the Partnership does not record the related gas on its balance sheet. Certain of the Partnership's operating subsidiaries also periodically lend gas and NGLs to customers.

In the course of providing transportation and storage services to customers, the operating subsidiaries 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 receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage for operations where regulatory accounting is applicable.

Materials and Supplies

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

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

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

Depreciation of PPE related to operations for which regulatory accounting does not apply is provided for 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. Depreciation of PPE related to operations for which regulatory accounting is applicable is provided for primarily on the straight-line method at FERC-prescribed rates over estimated useful lives of 5 to 62 years. Reflecting the application of composite depreciation, gains and losses from the ordinary sale or retirement of PPE for these assets are not recognized in earnings and generally do not impact PPE, net.
    
Note 7 contains more information regarding the Partnership’s PPE.


47



Goodwill and Intangible Assets

Goodwill represents the excess of the cost of an acquisition over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is tested for impairment at the reporting unit level at least annually, as of November 30, or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Accounting requirements provide that a reporting entity may perform an optional qualitative assessment on an annual basis to determine whether events occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its carrying amount. If an initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or the optional qualitative assessment is not performed, a quantitative analysis is performed under a two-step impairment test to measure whether the fair value of the reporting unit is less than its carrying amount. If based upon a quantitative analysis the fair value of the reporting unit is less than its carrying amount, including goodwill, the Partnership performs an analysis of the fair value of all the assets and liabilities of the reporting unit. If the implied fair value of the reporting unit's goodwill is determined to be less than its carrying amount, an impairment loss is recognized for the difference.

Intangible assets are those assets which provide future economic benefit but have no physical substance. The Partnership recorded intangible assets for customer relationships obtained through the purchases of Petal and Louisiana Midstream. The customer relationships, which are included in Other Assets on the Consolidated Balance Sheets, have a finite life and are being amortized in a systematic and rational manner over their estimated useful lives.

Note 8 contains additional information regarding the Partnership's goodwill and intangible assets.

Impairment of Long-lived Assets (including Tangible and Definite-lived Intangible Assets)

The Partnership evaluates its long-lived and intangible 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 and Allowance for Funds Used During Construction (AFUDC)

The Partnership records capitalized interest, which represents the cost of borrowed funds used to finance construction activities for operations where regulatory accounting is not applicable. The Partnership records AFUDC, which represents the cost of funds, including equity funds, applicable to regulated natural gas transmission plant under construction as permitted by FERC regulatory practices, in connection with the Partnership’s operations where regulatory accounting is applicable. Capitalized interest and the allowance for borrowed funds used during construction are recognized as a reduction to Interest expense and the allowance for equity funds used during construction is included in Miscellaneous other income, net within the Consolidated Statements of Income. The following table summarizes capitalized interest and the allowance for borrowed funds and allowance for equity funds used during construction (in millions):
 
For the Year Ended
December 31,
 
2013
 
2012
 
2011
Capitalized interest and allowance for borrowed funds used during construction
$
6.4

 
$
4.7

 
$
2.0

Allowance for equity funds used during construction
0.2

 
0.4

 
0.6


Income Taxes

The Partnership is not a taxable entity for federal income tax purposes.  As such, it does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated Statements of Income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes related to the Partnership. The subsidiaries of the Partnership directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income.


48



Note 14 contains more information regarding the Partnership’s income taxes.

Revenue Recognition

The maximum rates that may be charged by the majority of the Partnership's operating subsidiaries for their services are established through FERC’s cost-based rate-making process; however, rates charged by those operating subsidiaries 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, 2013 and 2012, the Partnership had deferred revenues of $7.9 million and $17.3 million related to PAL and interruptible storage services and $4.6 million and $5.6 million related to a firm transportation agreement that was paid in advance. The deferred revenues related to PAL and interruptible storage services will be recognized in 2014 and 2015 and the deferred revenues related to the firm transportation agreement will be recognized through 2018.

Retained fuel is recognized in revenues at market prices in the month of retention for operations where regulatory accounting is not applicable. The related fuel consumed in providing transportation services is recorded in Fuel and transportation expenses at market prices in the month consumed. In some cases, customers may elect to pay cash for the cost of fuel used in providing transportation services instead of having fuel retained in-kind. Retained fuel included in Transportation on the Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011 was $76.9 million, $71.8 million and $105.6 million.

In certain of the Partnership's operations, the Partnership has contractual retainage provisions in some of its storage contracts that provide for the Partnership to retain ownership of 0.5% of customer inventory volumes injected into storage wells. The contract allows the Partnership to sell the retainage volumes if commercially marketable volumes of the Partnership's retainage are on hand. The Partnership recognizes revenue for retainage volumes upon the physical sale of such volumes.

Under FERC regulations, certain revenues that the operating subsidiaries collect may be subject to possible refunds to their customers. Accordingly, during a rate case, estimates of rate refund liabilities are recorded considering regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. At December 31, 2013 and 2012, there were no liabilities for any open rate case recorded on the Consolidated 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 Consolidated 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 9 contains more information regarding the Partnership’s asset retirement obligations.

Environmental Liabilities

The Partnership records environmental liabilities based on management’s 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 5 contains more information regarding the Partnership’s environmental liabilities.


49



Defined Benefit Plans

The Partnership maintains certain postretirement benefit plans for certain employees. The Partnership funds these plans through periodic contributions which are invested until the benefits are paid out to the participants. The net benefit cost of the plan is recorded in the Consolidated Statements of Income. The Partnership records an asset or liability based on the overfunded or underfunded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability or recorded as a component of accumulated other comprehensive income (AOCI) until those gains or losses are recognized in the Consolidated Statements of Income.

Note 12 contains more information regarding the Partnership’s pension and postretirement benefit obligations.

Unit-Based and Other Long-Term Compensation

The Partnership provides awards of phantom common units (Phantom Common Units) to certain employees under its Long-Term Incentive Plan (LTIP). The Partnership also provides to certain employees awards of unit appreciation rights (UARs) and long-term cash bonuses (Long-Term Cash Bonuses) under the Boardwalk Pipeline Partners Unit Appreciation Rights and Cash Bonus Plan.

The Partnership measures the cost of an award issued in exchange for employee services based on the grant-date fair value of the award, or the stated amount in the case of the Long-Term Cash Bonuses. All outstanding awards are either required or expected to be settled in cash and are classified as a liability until settlement. The unit-based compensation awards are remeasured each reporting period until the final amount of awards is determined. The related compensation expense, less applicable estimates of forfeitures, is recognized over the period that employees are required to provide services in exchange for the awards, usually the vesting period.

Note 12 contains additional information regarding the Partnership’s unit-based and other long-term compensation.

Partner Capital Accounts

For purposes of maintaining capital accounts, items of income and loss of the Partnership are allocated among the partners each year, or portion thereof, in accordance with the partnership agreement. Generally, net income for each period is allocated among the partners based on their respective ownership interests after deducting any priority allocations in the form of cash distributions paid to the general partner as the holder of IDRs.

Derivative Financial Instruments

The Partnership 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 contract