10-K 1 bwp10kq42015.htm 10-K BWP 2015 10-K
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, 2015
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, 2015, was approximately $1.8 billion. As of February 19, 2016, the registrant had 250,296,782 common units outstanding.
Documents incorporated by reference.    None.




TABLE OF CONTENTS

2015 FORM 10-K

BOARDWALK PIPELINE PARTNERS, LP



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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, which is conducted by our primary subsidiary, Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries, as described in the diagram below (together, the operating subsidiaries), consists of integrated natural gas, and natural gas liquids and other hydrocarbons (herein referred to together as 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 19, 2016, the common units and general partner interest owned by BPHC represent approximately 51% of our equity interests, excluding the IDRs. Our Partnership Interests, as described 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).


        

                    

                                    
                                                                                                            
                                                                                                                      
                                                  

    




                
                                    
                                                                                                            



 

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The following diagram reflects a simplified version of our current organizational structure:

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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 14,525 miles of natural gas and NGLs pipelines and underground storage caverns having aggregate capacity of approximately 205.0 billion cubic feet (Bcf) of working natural gas and 24.0 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 most of our services related to NGLs are fee-based or based on minimum volume requirements, while others are dependent on actual volumes transported or stored. For the year ended December 31, 2015, approximately 79% 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 9% 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 maximum rates we can charge for most of our natural gas transportation and storage services, as well as the general terms and conditions of those services, 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. The Surface Transportation Board (STB), a division of the United States (U.S.) Department of Transportation (DOT), has authority to regulate the rates we charge for service on our ethylene pipelines. The STB requires that our transportation rates are reasonable and that our practices cannot unreasonably discriminate among our ethylene shippers.

Our Pipeline and Storage Systems

We own and operate approximately 14,090 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 and operate more than 435 miles of NGLs pipelines in Louisiana and Texas. In 2015, our pipeline systems transported approximately 2.4 trillion cubic feet (Tcf) of natural gas and approximately 46.6 MMBbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2015 was approximately 6.7 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of approximately 205.0 Bcf, and our NGLs storage facilities consist of nine salt-dome caverns located in Louisiana with an aggregate storage capacity of approximately 24.0 MMBbls. We also own three salt-dome caverns and a brine pond 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 development of the Marcellus and Utica Shales located in the northeastern U.S., we also receive gas in the Lebanon, Ohio area. Our NGLs pipeline systems 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. We also access ethylene supplies at Port Neches, Texas, which we deliver to petrochemical-industry customers in Louisiana.

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

Gulf South Pipeline Company, LP (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 located across the system, including New Orleans, Louisiana; Jackson, Mississippi; Mobile,

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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 ten natural gas storage facilities. The two natural gas storage facilities located in Bistineau, Louisiana, and Jackson, Mississippi, have approximately 83.5 Bcf of working gas storage capacity from which Gulf South offers firm and interruptible storage service, including no-notice service (NNS), and supports pipeline operations. Gulf South also 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 29.6 Bcf is working gas capacity, and owns undeveloped land which is suitable for up to five additional storage caverns. 

Texas Gas Transmission, LLC (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. The development of the Marcellus and Utica Shales in the Northeast U.S., has resulted in several growth projects which, when completed, will allow for the bi-directional movement of natural gas from north to south on the Texas Gas system.

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 NNS customers. Texas Gas also uses its storage capacity to offer firm and interruptible storage services.

Gulf Crossing Pipeline Company LLC (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 and Southeast, including Florida, through interconnections with Gulf South, Texas Gas and unaffiliated pipelines.

Boardwalk Louisiana Midstream and Boardwalk Petrochemical Pipeline, LLC (collectively, Louisiana Midstream):
Louisiana Midstream provides transportation and storage services for natural gas, NGLs and ethylene, 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 67.1 MMBbls of salt dome storage capacity, including approximately 7.6 Bcf of working natural gas storage capacity; significant brine supply infrastructure; and approximately 270 miles of pipeline assets, including an extensive ethylene distribution system. Louisiana Midstream also owns and operates the Evangeline Pipeline (Evangeline), an approximately 180-mile interstate ethylene pipeline that is capable of transporting approximately 2.6 billion pounds of ethylene per year between Port Neches, Texas, and Baton Rouge, Louisiana, where it interconnects with our ethylene distribution system and storage facilities at the Choctaw Hub. Throughput for Louisiana Midstream was 46.6 MMBbls for the year ended December 31, 2015.

Boardwalk Field Services, LLC (Field Services): Field Services operates natural gas gathering, compression, treating and processing infrastructure primarily in South Texas.
    
    

    

    

    

    
    

    

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The following table provides information for our pipeline and storage systems as of February 19, 2016:
Pipeline and Storage Systems
 
Miles of Pipeline
 
Working Gas Storage Capacity (Bcf)
 
Liquids Storage Capacity (MMBbls)
 
Peak-day Delivery Capacity (Bcf/d)
 
Average Daily Throughput (Bcf/d)
Gulf South
 
7,390

 
113.1

 

 
8.3

 
2.8

Texas Gas
 
6,020

 
84.3

 

 
4.8

 
2.6

Gulf Crossing
 
375

 

 

 
1.9

 
1.2

Louisiana Midstream
 
450

 
7.6

 
24.0

 

 

Field Services
 
290

 

 

 

 
0.1


Current Growth Projects

In response to the changes in the natural gas industry and the growth in the petrochemical industry, we are currently engaged in the following growth projects, which are discussed below. The estimated total costs of these major projects are expected to be approximately as follows (in millions):
 
Estimated
Total Cost(1)
 
Expected
in-service date(1)
 
Approximate weighted-average contract life (in years)
Ohio to Louisiana Access
$
115.0

 
 
Second quarter 2016
 
 
13
 
Southern Indiana Lateral
 
75.0

 
 
Third quarter 2016
 
 
19
 
Western Kentucky Market Lateral
 
80.0

 
 
Third quarter 2016
 
 
20
 
Power Plant Project in South Texas
 
80.0

 
 
Third quarter 2016
 
 
20
 
Northern Supply Access(2)
 
310.0

 
 
First half 2017
 
 
16
 
Sulphur Storage and Pipeline Expansion
 
145.0

 
 
Second half 2017
 
 
Confidential
 
Coastal Bend Header(2)
 
720.0

 
 
2018
 
 
20
 
Brine Development Project(3)
 
45.0

 
 
2018
 
 
15
 

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

(2)
Remains subject to FERC regulatory approval as of the date of this filing.

(3)
The first portion of this project, which consisted of constructing a pipeline to the customer’s facilities, was placed into service in the fourth quarter 2015.

Refer to Item 7: Liquidity and Capital Resources for further discussion of capital expenditures and financing.

Ohio to Louisiana Access Project: Our Ohio to Louisiana Access project will provide long-term firm natural gas transportation primarily from the Marcellus and Utica production areas to Louisiana. This project will not add additional capacity to our natural gas pipeline systems, but will allow us to make a portion of our Texas Gas system bi-directional. The project is supported by firm transportation contracts with producers and end-users.

Southern Indiana Lateral Project: Our Southern Indiana Lateral project consists of the construction of approximately 30 miles of 10-inch pipeline originating from our pipeline in Mt. Vernon, Indiana, to Henderson County, Kentucky. The project will add approximately 0.1 Bcf per day of peak-day transmission capacity to our Texas Gas system.

Western Kentucky Market Lateral Project: Our Western Kentucky Market Lateral project consists of the construction of a pipeline lateral to provide deliveries to a proposed new power plant in Western Kentucky. The pipeline lateral will originate at our compressor station in Muhlenberg County, Kentucky, and extend eastward approximately 19 miles to the plant site. The project will add approximately 0.2 Bcf per day of peak-day transmission capacity to our Texas Gas system.

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Power Plant Project in South Texas: Our South Texas power plant project consists of the addition of compression facilities and modifications of our existing facilities to increase the operating capacity of certain sections of our Gulf South pipeline. The project will provide transportation services of 0.2 Bcf per day to a new power plant in South Texas.

Northern Supply Access Project: Our Northern Supply Access project will increase the peak-day transmission capacity on our Texas Gas system by the addition of compression facilities and other system modifications to make this portion of the system bi-directional. This project is supported by precedent agreements for 0.4 Bcf per day of peak-day transmission capacity. In October 2015, one of the foundation shippers which contracted for 0.1 Bcf per day of peak-day transmission capacity failed to post the required credit support on the contractually required date. We continue to work with the customer as well as explore all of our options for the capacity associated with that customer's precedent agreement, including adjusting the scope of the project to accommodate the reduced volume commitment.

Sulphur Storage and Pipeline Expansion Project: We executed a long-term agreement to provide liquids transportation and storage services to support the development of a new ethane cracker plant in the Lake Charles, Louisiana area. The project will involve significant storage and infrastructure development to serve petrochemical customers near our Sulphur Hub.

Coastal Bend Header Project: We executed precedent agreements with foundation shippers to transport natural gas to serve a planned liquefied natural gas (LNG) liquefaction terminal in Freeport, Texas. As part of the project, we will construct an approximately 65-mile pipeline supply header with an approximate 1.4 Bcf per day of capacity to serve the terminal. Additionally, we will expand and modify our existing Gulf South pipeline facilities that will provide access to additional supply sources through various interconnects in South Texas and in the Louisiana area.

Brine Development Project: We executed agreements with a petrochemical customer in Louisiana to provide brine supply services subject to certain minimum take requirements. The first portion of the project, which was placed into service in the fourth quarter 2015, consisted of constructing a pipeline to the customer’s facilities to supply brine over a three-year period. The second portion, expected to be placed into service in mid-2018, consists of providing brine supply services over a 15-year period through the development of additional wells and associated facilities.

Nature of Contracts
 
We contract with our customers to provide transportation and storage services on a firm and interruptible basis. We provide bundled firm transportation and storage services, which we provide to our natural gas customers as NNS, interruptible PAL services for our natural gas customers, gathering and processing services for our natural gas customers and we also 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 NNS agreements. Firm transportation contracts generally range in term from one to twenty 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 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 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 the contracts for NGLs services are typically fixed-price arrangements with escalation clauses.

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No-Notice Services: NNS consists of a combination of firm natural gas transportation and storage services that allow customers to inject or withdraw natural gas from storage with little or no notice. Customers pay a reservation charge based upon the capacity reserved plus a commodity and a fuel charge based on the volume of gas actually transported. 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 services 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 for end-users. Based on our 2015 transportation, storage and PAL revenues, net of fuel, our customer mix was as follows: natural gas producers (50%), power generators (17%), LDCs (15%), marketers (14%) and industrial end-users and others (4%). Based upon our 2015 transportation, storage and PAL revenues, net of fuel, our deliveries were as follows: pipeline interconnects (55%), LDCs (19%), industrial end-users (9%), storage activities (9%) and power generators (8%). No customer comprises more than 10% of our 2015 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.

Power Generator: Our natural gas pipelines are directly connected to 42 natural-gas-fired power generation facilities in eight states. The demand of the power generating customers generally peaks during the summer cooling season which is counter to the winter season peak demands of the LDCs, although recently we have begun to see an increase in demand from power generators in the winter months as well, due to the overall increase in the use of natural gas over other sources such as coal to generate electricity. Our power-generating customers can use a combination of no-notice, firm and interruptible transportation services.
 
LDCs: Most of our LDC customers use firm natural gas transportation services, including NNS. We serve approximately 170 LDCs at more than 300 delivery locations across our pipeline systems. The demand of these customers peaks during the winter heating season.
    
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.

Industrial End-Users: We provide approximately 188 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 natural gas supply sources that are closer to some of our traditional natural gas market areas. In addition, regulators’ continuing efforts to increase competition in the natural gas industry have increased the natural gas transportation options of our traditional customers. For example, as a result of regulators’ policies, capacity segmentation and capacity release have created an active secondary market which increasingly competes with our own natural gas pipeline services. Further, natural gas competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative fuel sources.

The principal elements of competition among pipelines are availability of capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. In many cases, the elements of competition, in particular flexibility, terms of service and reliability, are key differentiating factors between competitors. This is especially the case with capacity being sold on a longer-term basis. We are focused on finding opportunities to enhance our competitive profile in these areas by increasing the flexibility

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of our pipeline systems, such as modifying them to allow for bi-directional flows, to meet the demands of customers such as power generators and industrial users, and are continually reviewing our services and terms of service to offer customers enhanced service options.

Seasonality

Our revenues can be affected by weather, natural gas price levels, gas price differentials between locations on our pipeline systems (basis spreads), gas price differentials between time periods, such as winter to summer (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 2015, approximately 53% of our operating 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 (NGA) and the Natural Gas Policy Act of 1978. FERC regulates, among other things, the rates and charges for the transportation and storage of natural gas in interstate commerce and the extension, enlargement or abandonment of facilities under its jurisdiction. Where required, 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. 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. 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. FERC has authorized us to charge market-based rates for firm and interruptible storage services for the majority of our natural gas storage facilities.

In October 2014, our Gulf South subsidiary filed a rate case with the FERC pursuant to Section 4 of the NGA (Docket No. RP 15-65), in which Gulf South requested, among other things, a reconfiguration of the transportation rate zones on its system and, in general, an increase in its tariff rates. In 2015, an uncontested settlement was reached with Gulf South’s customers and approved by the FERC. The settlement will become effective March 1, 2016.

The settlement provides for, among other things, (a) a system-wide rate design across the majority of the pipeline system; (b) a fuel tracker for determining future fuel rates; (c) a moratorium which prevents Gulf South or its customers from modifying the settlement rates until May 1, 2023, with certain exceptions; and (d) an extension of all NNS contracts to the end of the moratorium period at maximum rates, subject to each customer’s right to reduce capacity under those agreements from current levels by up to 6% on April 1, 2016, and by up to another 6% of their remaining contract capacity by April 1, 2020. The NNS customers had to elect by December 1, 2015, whether they wanted to reduce their initial contracted capacity. Only two NNS customers elected to reduce their contracted capacity effective on April 1, 2016.

The settled rates were moved into effect on November 1, 2015. Refunds for the difference between the rates as filed and as settled are required to be paid to customers by May 1, 2016. Refer to Gulf South Rate Case in Item 7 and Note 4 in Item 8 of this Report for more information regarding the Gulf South rate case.

U.S. Department of Transportation. We are regulated by DOT, through the Pipeline and Hazardous Material 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 govern the design, installation, testing, construction, operation, replacement and management 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

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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 a total cap of $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through 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. New pipeline safety legislation that will reauthorize the federal pipeline safety programs of PHMSA through 2019 will be under consideration. Passage of new legislation reauthorizing the PHMSA pipeline safety programs is expected to require, among other things, pursuit of those legal mandates included in the 2011 Act but not acted upon by PHMSA.

The STB has authority to regulate the rates we charge for service on our ethylene pipelines. The STB requires that our transportation rates be reasonable and that our practices cannot unreasonably discriminate among our ethylene shippers.

Other. Our operations are also subject to extensive federal, state and local laws and regulations relating to protection of the environment. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases, discharges and emissions of various substances into the environment. Environmental regulations also require that our facilities, sites and other properties be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. The laws our operations are subject to include, for example:
the Clean Air Act (CAA) and analogous state laws, which impose obligations related to air emissions, including, in the case of climate change, greenhouse gas (GHG) emissions and regulations affecting reciprocating engines subject to Maximum Achievable Control Technology standards;
the Federal 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, the occurrence of delays in the development of projects and the issuance of orders enjoining performance of some or all of our operations in affected areas. While we believe that our past operations have not resulted in the incurrence of material costs with respect to these existing environmental laws and regulations, we can provide no assurance that continued compliance with existing requirements will not materially affect us or 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.

Effects of Compliance with Environmental Regulations

Note 4 in Part II, Item 8 of this Report contains information regarding environmental compliance.


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Employee Relations

At December 31, 2015, we had approximately 1,260 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 medical, life and disability coverage. 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 11 in Part II, 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, District of Columbia (D.C.) 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.

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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

Our actual construction and development costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate, which may limit our ability to maintain or increase cash distributions.

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

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

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

Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Credit risk exists in relation to our growth projects, both because the foundation shippers have made long-term commitments to us for capacity on such projects and certain of the foundation shippers have agreed to provide credit support as construction progresses. If a foundation shipper fails to meet the contractual credit requirements, an adjustment to the scope of the project could occur to accommodate a reduced volume commitment or we may be forced to find new customers to replace the defaulting customer, which could reduce the returns on the project. Our exposure also relates to receivables for services provided, future performance under firm agreements and volumes of gas owed by customers for imbalances or gas loaned by us to them under certain NNS and PAL services.

We rely on a limited number of customers for a significant portion of revenues. For 2015, no one customer comprised more than 10% of our operating revenues, and our top ten customers comprised approximately 45% of our revenues. 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, to post the required credit support for construction associated with our growth projects or to repay the gas they owe us, it could have a material adverse effect on our business. In addition, our FERC gas tariffs only allow us to require limited credit support in the event that our transportation customers are unable to pay for our services. Item 7A of this Report contains more information on credit risk arising from gas loaned to customers.

Natural gas producers comprise a significant portion of our revenues and support several of our growth projects. For example, in 2015, approximately 50% of our revenues were generated from contracts with natural gas producers. During 2015, the prices of oil and natural gas declined significantly from an increase in supplies mainly from shale production areas in the U.S. Should the prices of natural gas and oil remain at current levels for a sustained period of time, or decline further, we could be exposed to increased credit risk associated with our producer customer group, which would adversely impact our business.

We may not be able to replace expiring natural gas transportation contracts at attractive rates or on a long-term basis and may not be able to sell short-term services at attractive rates or at all due to market conditions such as narrower basis differentials and sustained changes in the levels of natural gas and oil prices which adversely affect the value of our transportation services.

Transportation rates we are able to charge customers are heavily influenced by longer-term trends in, for example, the amount and geographical location of natural gas production and demand for gas by end-users such as power plants, petrochemical

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facilities and LNG export facilities. As a result of changes in longer-term trends, a sustained narrowing of basis differentials corresponding to traditional flow patterns on our pipeline systems (generally south to north and west to east) has occurred, reducing the transportation rates and adversely impacting other contract terms we can negotiate with our customers for available transportation capacity and for contracts scheduled for renewal.

Each year, a portion of our firm natural gas transportation contracts expire and need to be renewed or replaced. Over the past several years, we have renewed many expiring contracts at lower rates and for shorter terms than in the past, or not at all. We expect this trend to continue, mainly for contracts to transport gas from west to east across our system, and therefore, we 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. The prevailing market conditions may also lead some of our customers, particularly customers that are experiencing financial difficulties, to seek to renegotiate existing contracts to terms that are less attractive to us. These sustained conditions have had, and we expect will continue to have, a materially adverse effect on our revenues, earnings before interest, income taxes, depreciation and amortization (EBITDA) and distributable cash flows.

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 transportation contract expirations than other years. We cannot predict what market conditions will prevail at the time such contracts expire, but if the contracts are renewed, we expect that these contracts will renew at lower transportation rates than when the contracts were initially executed. For example, if these contracts were renewed at current transportation market rates, our revenues earned from these transportation contracts would be materially lower. If we are unable to renew or replace these and other expiring contracts when they expire, or if the terms of any such renewal or replacement contracts are not as favorable as the expiring agreements, our revenues and cash flows could be materially adversely affected. These market factors and conditions have adversely impacted our revenues, EBITDA and distributable cash flow.

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

Our business is not significantly impacted by the short-term change in commodity prices, however, our customers, a significant amount of which are producers, are directly impacted by changes in commodity prices, which can impact our ability to renew contracts at existing capacities or rates or impact the producer’s ability to make payment for the services we provide. The prices of natural gas, oil and NGLs fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors. If the recent dramatic declines in the levels of natural gas, oil and NGLs prices mentioned above were to continue for a sustained period of time, the businesses of our producer customer group would be adversely affected which, in turn, would reduce the demand for our services and could result in defaults or the non-renewal of contracted capacity when existing contracts expire. Conversely, future increases in the price of natural gas and NGLs could make alternative energy and feedstock sources more competitive and reduce demand for natural gas and NGLs. A reduced level of demand for natural gas and NGLs 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 adversely impact our revenues, EBITDA and distributable cash flow.

Legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls, substantial changes to existing integrity management programs, or more stringent enforcement of applicable legal requirements could subject us to increased capital and operating costs and operational delays.

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. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and NGLs pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas (HCAs), such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Compliance with these rules has resulted in an overall increase in our maintenance costs. New laws or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.
    

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The NGPSA and HLPSA were most recently updated by the 2011 Act, which was 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, with a total cap of $2.0 million. The 2011 Act reauthorized the federal pipeline safety programs of PHMSA through 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in more stringent safety controls or inspections or additional natural gas and hazardous liquids pipeline safety rulemaking. Among other things, the 2011 Act directed the Secretary of Transportation to promulgate rules relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, pipeline material strength testing and verification of maximum allowable pressures of certain pipelines. Although a number of the mandates imposed under the 2011 Act have yet to be acted upon by PHMSA, the provisions of the 2011 Act continue to have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs. New pipeline safety legislation that will reauthorize the federal pipeline safety programs of PHMSA through 2019 will be under consideration. Passage of new legislation reauthorizing the PHMSA pipeline safety programs is expected to require, among other things, pursuit of those legal mandates included in the 2011 Act but not acted upon by PHMSA.

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

We may not 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 and the timing of payments, general business conditions and market conditions, which impact, for example, contract renewals, pricing, 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, growth projects and acquisitions;

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;

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; and

unanticipated costs to operate our business, such as for maintenance and regulatory compliance.

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. 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 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

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assets, among others. 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. We may not be successful in acquiring or developing such assets or may do so on terms that ultimately are not profitable. Any such transactions involve 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;

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.

We may not be able to replace expiring gas 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 a sustained narrowing of price spreads between time periods and reduced volatility which adversely affect our storage services.

We own and operate substantial natural gas storage facilities. The market for the storage and PAL services that we offer is impacted by the factors and market conditions discussed above for our transportation services, and is also impacted by natural gas price differentials between time periods, such as winter to summer (time period price spreads), and the volatility in time period price spreads. Market conditions have caused a sustained narrowing of time period price spreads and a sustained decline in the price volatility of natural gas, which has adversely impacted the rates we can charge for our storage and PAL services and the value associated with these services, especially when compared to previous historical levels. These market factors and conditions have adversely impacted our revenues, EBITDA and distributable cash flow.

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

Our operations are subject to stringent federal, regional, state and local laws and regulations relating to protection of worker safety or the environment. These laws include, for example, the CAA, the Clean Water Act, CERCLA, the Resource Conservation and Recovery Act, OSHA and analogous state laws. These laws and regulations may restrict or impact our business activities in many ways, including requiring the acquisition of permits or other approvals to conduct regulated activities, restricting the manner in which we handle or dispose of wastes, imposing remedial obligations to remove or mitigate contamination resulting from a spill or other release, requiring capital expenditures to comply with pollution control requirements, imposing safety and health criteria addressing worker protection, and imposing substantial liabilities for pollution resulting from our operations. Failure

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to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Under certain of these environmental laws and regulations, we could be subject to joint and several or strict liability for the removal or remediation of previously released pollutants or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all laws. We may not be able to recover some or any of the costs incurred from insurance. Stricter environmental or worker safety laws, regulations or enforcement policies could significantly increase our operational or compliance costs and compliance with new or more stringent environmental legal requirements could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment.

Climate change legislation and 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 Environmental Protection Agency (EPA) as well as some states and regional groupings of states have in recent years considered legislation or regulations to reduce emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs. In the absence of federal GHG-limiting legislation, the EPA had adopted rules under authority of the CAA that, among other things, establish Potential for Significant Deterioration (PSD) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting "best available control technology" standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA published a final reporting rule for certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal.

Moreover, the EPA proposed in August 2015 rules that will establish emission standards for methane and volatile organic compounds released from new and modified oil and natural gas production and natural gas processing and transmissions facilities, as part of the current U.S. President's administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. The EPA is expected to finalize those rules in 2016. Furthermore, the EPA has passed a rule, known as the Clean Power Plan, to limit GHGs from power plants but on February 9, 2016, the U.S. Supreme Court stayed this rule while it is being challenged in the federal D.C. Circuit Court of Appeals. If this rule survives legal challenge, then depending on the methods used to implement this rule, it could reduce demand for the oil and natural gas our customers produce. Although it is not possible at this time to predict how legislation or regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Finally, 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.

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.


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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.

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

Our current strategy is to fund our announced growth projects through currently available financing options, including utilizing cash flow from operations, borrowing under our revolving credit facility and accessing proceeds from our subordinated loan agreement and in the near term, to refinance currently maturing debt. 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.

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 5.0 to 1.0, or up to 5.5 to 1.0 in the three quarters following the quarter of an acquisition, 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.


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

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

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

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

We currently possess property, business interruption and general liability insurance, as well as stop-loss insurance for our self-insured medical plans, 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 events, hazards or all potential losses. The impact from health care reform efforts could impact our medical costs including the cost of any stop-loss coverage.

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.

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.


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Our established risk-management policies and procedures may not be effective, and employees may violate our risk-management policies.

We have developed and implemented a comprehensive set of policies and procedures that involve both our senior management and the Audit Committee of our Board of Directors to assist us in managing risks. Our risk policies and procedures are intended to align strategies, processes, people, information technology and business knowledge so that risk is managed throughout the organization. As conditions change and become more complex, current risk measures may fail to assess adequately relevant risks due to changes in the market and the presence of risks previously unknown to us. Additionally, if employees fail to adhere to our policies and procedures or if our policies and procedures are not effective, potentially because of future conditions or risks outside of our control, we may be exposed to greater risk than we had intended.

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 51% 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;

20



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
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.

21




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 material 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 organized as 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 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 administrative, legislative, or judicial changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial changes or differing interpretations at any time. For example, the current U.S. President's administration’s budget proposal for fiscal year 2017 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels, such as us, be taxed as corporations beginning in 2022. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the current U.S. President's administration’s proposal or other similar proposals could eliminate 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 U.S. federal income tax purposes.

On May 5, 2015, the U.S. Treasury Department and the IRS issued proposed regulations (the Proposed Regulations) regarding qualifying income under Section 7704(d)(1)(E) of the Internal Revenue Code (IRC). The Proposed Regulations provide industry-specific rules regarding the qualifying income exception, including whether an activity constitutes the processing or refining of a natural resource. The Proposed Regulations also provide that a partnership may treat income from an activity as qualifying income during a ten year transition period if the partnership received a private letter ruling from the IRS holding that the income from that activity is qualifying income. The U.S. Treasury Department and the IRS have requested comments from industry participants regarding the standards set forth in the Proposed Regulations.

In 2013, we obtained a favorable private letter ruling from the IRS to the effect that income from refining and processing natural gas liquids into olefins and from the transportation, storage and marketing of such olefins constitutes “qualifying income” within the meaning of Section 7704 of the IRC, and we would expect to rely upon this private letter ruling for purposes of the ten year transition rule contained in the Proposed Regulations.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income

22



tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS were to contest 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. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you.
     
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 our counsel’s conclusions or 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. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders.

Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

Our unitholders will be required to pay taxes on their share of our taxable income, including their share of income from the cancellation of debt, 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 due from such unitholders' share of our taxable income.

We may engage in transactions to delever the partnership and manage our liquidity that may result in income to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions or the value of the units. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisor with respect to the consequences to them of COD income.

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.


23



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 (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. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such 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 common units actually 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 U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted for our 2015 taxable year and may not specifically authorize all aspects of our proration method thereafter. 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 securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies in determining unitholders’ allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

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

24



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 announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership 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.



25



Item 1B.  Unresolved Staff Comments

None.

Item 2.  Properties

We are headquartered in approximately 103,000 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 4 in Part II, Item 8 of this Report for a discussion of our legal proceedings.

Item 4.  Mine Safety Disclosures

None.

26



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, 2015, we had outstanding 250.3 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, an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of our IDRs. As of February 19, 2016, the common units and general partner interest held by BPHC represent approximately 51% 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 17, 2016, we had 250.3 million common units outstanding held by approximately 47 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 17, 2016, was $12.46 per unit.
 
Sales Price Range per
Common Unit
 
 
Cash Distributions
per
Common Unit (1)
 
 
High
 
Low
 
 
 
Year Ended December 31, 2015:
 
 
 
 
 
 
 
Fourth quarter
$
13.99


$
10.54


$
0.1000

 
Third quarter
15.08


11.26


 
0.1000

 
Second quarter
17.93


14.26


 
0.1000

 
First quarter
18.32


14.77


 
0.1000

 
Year Ended December 31, 2014:
 

 
 

 
 
 

 
Fourth quarter
$
18.70

 
$
14.67

 
$
0.1000

 
Third quarter
20.51

 
17.81

 
 
0.1000

 
Second quarter
19.12

 
13.28

 
 
0.1000

 
First quarter(2)
25.83

 
11.99

 
 
0.1000

 
(1)
Represents cash distributions attributable to the quarter and declared and paid to limited partner unitholders within 60 days after quarter end. 
(2)
In February 2014, we reduced our distribution to $0.10 per common unit from the previously declared and paid of $0.5325 per common unit, which resulted in a significant drop in our common unit price at the time of the announcement.

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, 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

27



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. Since February 2014, we reduced our distribution below the quarterly target distribution level necessary to pay distributions on behalf of the IDRs. Therefore, in 2015 and 2014 no distributions were paid on behalf of the IDRs. In 2013, we paid $34.6 million in distributions on behalf of our IDRs. Note 12 in Part II, 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 Distributions
 
Marginal Percentage Interest
in Distributions
Target Amount
 
Limited Partner
Unitholders
 
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%

Equity Compensation Plans

For information about our equity compensation plans, see Note 11 in Part II, Item 8 of this Report.

Issuer Purchases of Equity Securities

None.

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Item 6.  Selected Financial Data

The following table presents our selected historical financial and operating data. As used herein, EBITDA means earnings before interest, income taxes, depreciation and amortization. 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 (3) Non-GAAP Financial Measures below. 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 (basic and diluted), Net income per class B unit (basic and diluted), Distributions per common unit and Distributions per class B unit):
 
For the Year Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
Total operating revenues
$
1,249.2

 
$
1,233.8

 
$
1,205.6

 
$
1,185.0

 
$
1,142.9

Net income attributable to controlling interest
222.0

 
233.6

 
253.7

 
306.0

 
217.0

Total assets (1)
8,300.3

 
8,194.3

 
7,900.1

 
7,845.6

 
7,248.5

Long-term debt and capital lease obligation (1)
3,459.3

 
3,677.2

 
3,410.0

 
3,522.3

 
3,380.8

Net income per common unit — basic
0.87

 
0.94

 
1.00

 
1.37

 
1.09

Net income per class B unit — basic (2)

 

 
0.05

 
0.36

 
0.14

Net income per common unit — diluted

 
0.94

 
0.96

 
1.37

 
1.09

Net income per class B unit — diluted (2)

 

 
0.48

 
0.36

 
0.14

Distributions per common unit
0.40

 
0.40

 
2.13

 
2.1275

 
2.095

Distributions per class B unit (2)

 

 
0.90

 
1.20

 
1.20

EBITDA (3)
722.2

 
687.6

 
688.7

 
726.5

 
617.4

Distributable cash flow (3)
413.3

 
449.4

 
558.6

 
497.4

 
407.9


(1)
The amounts presented for the years ended December 31, 2011 through 2014 have been adjusted to conform to the current presentation. Refer to Note 2 in Part II, Item 8 of this Report for further information.
(2)
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.
(3)
Non-GAAP Financial Measures.

We use non-GAAP measures to evaluate our business and performance, including EBITDA and distributable cash flow. 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.

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. Certain items excluded from 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 EBITDA because 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 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

29



or to allocate funds to business or legal purposes rather than making distributions. EBITDA and distributable cash flow are not necessarily comparable to similarly titled measures of another company.

The following table presents a reconciliation of 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,
 
2015
 
2014
 
2013
 
2012
 
2011
Net Income
$
222.0

 
$
146.8

 
$
250.2

 
$
306.0

 
$
217.0

Net loss attributable to noncontrolling interests

 
(86.8
)
 
(3.5
)
 

 

Net income attributable to controlling interests
222.0

 
233.6

 
253.7

 
306.0

 
217.0

Income taxes
0.5

 
0.4

 
0.5

 
0.5

 
0.4

Depreciation and amortization
323.7

 
288.7

 
271.6

 
252.3

 
227.3

Interest expense
176.4

 
165.5

 
163.4

 
168.4

 
159.9

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

 

 

 

 
13.2

EBITDA
$
722.2

 
$
687.6


$
688.7


$
726.5


$
617.4

Less:
 

 
 

 
 

 
 

 
 

Cash paid for interest net of capitalized interest (1)
170.6

 
153.0

 
151.0

 
169.8

 
172.7

Maintenance capital expenditures (2)
142.5

 
91.4

 
69.7

 
79.8

 
94.6

     Base gas capital expenditures

 
14.7

 

 

 

Add:
 

 
 

 
 

 
 

 
 

Proceeds from insurance recoveries and settlements (3)
6.2

 
6.3

 

 
9.2

 
5.0

Proceeds from sale of operating assets
0.8

 
2.9

 
60.7

 
5.9

 
31.5

Net gain on sale of operating assets
(0.5
)
 
(1.1
)
 
(29.5
)
 
(3.3
)
 
(8.6
)
Asset impairment
0.4

 
3.0

 
4.1

 
9.1

 
30.5

Goodwill impairment

 

 
51.5

 

 

Bluegrass project impairment, net of noncontrolling interest

 
10.0

 

 

 

Other (4)
(2.7
)
 
(0.2
)
 
3.8

 
(0.4
)
 
(0.6
)
Distributable Cash Flow
$
413.3

 
$
449.4

 
$
558.6

 
$
497.4

 
$
407.9


(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)
For the year ended December 31, 2015, maintenance capital expenditures were impacted by the pipeline maintenance associated with our brine operations, pipeline integrity upgrades discussed in Item 7 of this Report and continued increased integrity management activities. Maintenance capital expenditures increased in 2014 due to increased integrity management activities. 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, 2015 and 2014, represent amounts associated with legal settlements. The years ended December 31, 2012 and 2011, represent insurance recoveries associated with the Carthage compressor fire and legal settlements. All years exclude proceeds recognized in earnings.
(4)
Includes non-cash items such as the equity component of allowance for funds used during construction and equity in earnings, net of noncontrolling interests. The year ended December 31, 2013, includes the sale of ethylene inventory that was acquired through the acquisition of Louisiana Midstream.

30



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 14,090 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 435 miles of NGLs pipelines serving customers in Louisiana and Texas. In 2015, our pipeline systems transported approximately 2.4 Tcf of natural gas and approximately 46.6 MMBbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2015 was approximately 6.7 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of approximately 205.0 Bcf and our NGLs storage facilities located in Louisiana consist of nine salt-dome caverns with a storage capacity of 24.0 MMBbls. We also have three 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 receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible natural gas transportation, whereby the customer pays to transport gas only when capacity is available and used. We offer firm natural gas storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and PAL services where the customer receives and pays for capacity only when it is available and used. We also transport and store NGLs. Our NGLs contracts for most of our services are fee-based or based on minimum volume requirements, while others are dependent on actual volumes transported. Our NGLs storage rates are market-based 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 natural gas and NGLs prices may impact the volumes of natural gas or NGLs transported and stored by customers on our systems. Due to the capital-intensive nature of our business, 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 and not included in a fuel tracker, which is included in Fuel and transportation expenses on our Consolidated Statements of Income.

Recent Developments

Market Conditions and Contract Renewals

Transportation rates we are able to charge customers are heavily influenced by longer-term trends in, for example, the amount and geographical location of natural gas production and demand for gas by end-users such as power plants, petrochemical facilities and LNG export facilities. Changes in certain longer-term trends, such as the development of gas production from the Marcellus and Utica production areas located in the Northeastern U.S. and changes to related pipeline infrastructure, have resulted in a sustained narrowing of basis differentials corresponding to traditional flow patterns on our natural gas pipeline systems (generally south to north and west to east), reducing the transportation rates and adversely impacting other contract terms we can negotiate with our customers for available transportation capacity and for contracts due for renewal for our transportation services. These conditions have had, and we expect will continue to have, a material adverse effect on our revenues, EBITDA and distributable cash flows. Further, as discussed in Item 1A, during 2015, the prices of oil and natural gas declined significantly from an increase in supplies mainly from shale production areas in the U.S, which has adversely impacted the businesses of certain of our producer customers. If the recent declines in prices were to continue for a sustained period of time, the businesses of other members of our producer customer group could be adversely affected which, in turn, would reduce the demand for our services and could result in the non-renewal of contracted capacity, or the renewal of capacity at lower rates, when existing contracts expire.
 
A substantial portion of our transportation capacity is contracted for under firm transportation agreements. The table shown below sets forth the approximate projected revenues from capacity reservation and minimum bill charges under committed firm transportation agreements in place as of December 31, 2015, for 2016 and 2017, as well as the actual comparative amount recognized in revenues for 2015. The revenues reflected in the table include approximately $25.0 million for 2017 that are anticipated under executed precedent transportation agreements for projects that are subject to regulatory approval to commence construction. The table does not include additional revenues we have recognized and we may receive under firm transportation agreements based on actual utilization of the contracted pipeline facilities or any expected revenues for periods after the expiration dates of

31



the existing agreements or execution of precedent agreements associated with growth projects or events that occurred subsequent to December 31, 2015. For a discussion of risks associated with nonperformance of our customers, refer to Item 1A. Risk Factors - We are exposed to credit risk relating to nonperformance by our customers.
As of
December 31, 2015
(in millions)
2015
 
$
   940.0
2016
 

1,010.0
2017
 

1,030.0

The amounts shown for 2015 and 2016 increased approximately $30 million and $110 million from what was reported in our 2014 10-K. Approximately half of the increase in each year is due to contract renewals during 2015 and new contracts that were entered into in 2015. The remainder is due to the settled Gulf South rate case, which resulted in a general increase in rates and the extension to 2023 of certain NNS contracts. Refer to Gulf South rate case below for further information about the rate case.

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

Demand has increased to transport gas from north to south instead of south to north as had been our traditional flow pattern. This demand is being driven by increases in gas production primarily from the Marcellus and Utica production areas and growing demand for natural gas primarily in the Gulf Coast area from new and planned power plants, petrochemical facilities and LNG export facilities. This flow pattern has resulted in growth opportunities for us that require significant capital expenditures, among other things, to make parts of our system bi-directional, and in many instances, will utilize existing pipeline capacity that has been turned back to us by customers that have not renewed expiring contracts. As discussed in Growth Projects and elsewhere in this Report, these projects have lengthy planning and construction periods and, as a result, will not contribute to our earnings and cash flows until they are placed into service over the next several years. In some instances, the projects remain subject to regulatory approval to commence construction and these projects are subject to the risk that they may not be completed, may be impacted by significant cost overruns or may be materially changed prior to completion as a result of future developments or circumstances that we cannot predict at this time.

The value of our storage and PAL services (comprised of parking gas for customers and/or lending gas to customers) is affected by natural gas price differentials between time periods, such as winter to summer (time period price spreads), price volatility of natural gas and other factors. Our storage and parking services have greater value when the natural gas futures market is in contango (a positive time period price spread, meaning that current price quotes for delivery of natural gas further in the future are higher than in the nearer term), while our lending service has greater value when the futures market is backwardated (a negative time period price spread, meaning that current price quotes for delivery of natural gas in the nearer term are higher than further in the future). The value of both storage and PAL services may also be favorably impacted by increased volatility in the price of natural gas, which allows us to optimize the value of our storage and PAL capacity.

We have seen the value of our storage and PAL services adversely impacted by some of the market factors discussed above, as well as there being fewer market participants from a decrease in the number of marketers taking storage positions, which have contributed to a narrowing of time period price spreads. Although in recent months, we have seen an increase in volatility that has allowed us to lock in favorable price spreads, generally, these factors have reduced the rates we can charge and the capacity we can sell under our storage and PAL services.
    

32



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. PHMSA has proposed more stringent regulations, including expanded integrity management requirements, automatic or remote-controlled valve use, leak detection system installation, pipeline material strength testing and verification of maximum allowable pressures of certain pipelines, which if implemented, could require us to incur significant additional costs. See Item 1A. Risk Factors for further information.

Maintenance costs may be capitalized or expensed, depending on the nature of the activities. For any given reporting period, the mix of projects that we undertake will affect the amounts we record as property, plant and equipment (PPE) on our balance sheet or recognize as expenses, which impacts our earnings. In 2016, we expect to incur approximately $330.0 million to maintain our pipeline systems, of which approximately $130.0 million is expected to be maintenance capital. In 2015, these costs were $352.0 million, of which $142.5 million was recorded as maintenance capital. The projected decrease of approximately $22.0 million is primarily driven by the completion, in 2015, of maintenance activities associated with certain of our brine facilities. The maintenance capital amounts shown above reflect pipeline integrity upgrades associated with certain segments of our natural gas pipelines which will be completed over the next three years. Refer to Capital Expenditures for more information regarding certain of our maintenance costs and additional pipeline integrity upgrades.

Credit Risk

Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. We actively monitor our customers’ credit profiles, as well as the portion of our revenues generated from investment-grade and non-investment-grade customers. Approximately $1.0 billion of our 2015 operating revenues were earned from our top 50 customers. While almost all of these customers are rated investment-grade by at least one of the major credit rating agencies, many oil and gas producers have recently had their ratings placed under review.
 
Credit risk also exists in relation to our growth projects, both because the foundation shippers have made long-term commitments to us for capacity on such projects and certain of the foundation shippers have agreed to provide credit support as construction progresses. A large majority of these foundation shippers are rated investment-grade by at least one of the major credit rating agencies. As discussed elsewhere in this filing, we had one customer fail to post the required credit support on the contractually required date.

    Natural gas producers comprise a significant portion of our revenues. For example, in 2015, approximately 50% of our revenues were generated from contracts with natural gas producers. During 2015, the prices of oil and natural gas declined significantly from an increase in supplies mainly from shale production areas in the U.S. Should the prices of natural gas and oil remain at current levels for a sustained period of time, or decline further, we could be exposed to increased credit risk associated with our producer customer group. We continue to monitor our credit risk carefully, especially as it relates to customers that may be affected by the current oil and natural gas markets. Refer to Item 1A. Risk Factors - We are exposed to credit risk relating to nonperformance by our customers.

Gulf South Rate Case

In October 2014, our Gulf South subsidiary filed a rate case with the FERC pursuant to Section 4 of the NGA (Docket No. RP 15-65), in which Gulf South requested, among other things, a reconfiguration of the transportation rate zones on its system and, in general, an increase in its tariff rates. In 2015, an uncontested settlement was reached with Gulf South’s customers and approved by the FERC. The settlement will become effective March 1, 2016.

33




The settlement provides for, among other things, (a) a system-wide rate design across the majority of the pipeline system; (b) a fuel tracker for determining future fuel rates; (c) a moratorium which prevents Gulf South or its customers from modifying the settlement rates until May 1, 2023, with certain exceptions; and (d) an extension of all NNS contracts to the end of the moratorium period at maximum rates, subject to each customer’s right to reduce capacity under those agreements from current levels by up to 6% on April 1, 2016, and by up to another 6% of their remaining contract capacity by April 1, 2020. The NNS customers had to elect by December 1, 2015, whether they wanted to reduce their initial contracted capacity. Only two NNS customers elected to reduce their contracted capacity effective on April 1, 2016.

The settled rates were moved into effect on November 1, 2015. Refunds for the difference between the rates as filed and as settled are required to be paid to customers by May 1, 2016. Refer to Gulf South Rate Case in Note 4 in Item 8 of this Report for more information regarding the Gulf South rate case.

For the year ended December 31, 2015, we recognized $20.4 million of additional operating revenues as a result of the rate case. Based on current, contracted capacity, and the elections made by Gulf South’s NNS customers, we expect to recognize approximately $30.0 million in net revenues as a result of the rate case in 2016.

Results of Operations
    
The Overview section in this Item 7, and Note 2 of Item 8, contain summaries of our revenues and the related revenue recognition policies. A significant portion of our revenues are fee-based, being derived from capacity reservation charges under firm transportation agreements with customers, which do not vary significantly period to period, but are impacted by longer-term trends in our business such as lower pricing on contract renewals and other factors discussed elsewhere in this MD&A. Our operating costs and expenses do not vary significantly based upon the amount of products transported, with the exception of costs recorded in Fuel and transportation expense, which are typically offset by revenues from retained fuel included in our Transportation revenues. Please refer to Recent Developments above for further discussion of items that have impacted, or could impact in the future, our results of operations, including material trends in our operating revenues and expenses.

2015 Compared with 2014

Our net income attributable to controlling interests for the year ended December 31, 2015, decreased $11.6 million, or 5%, to $222.0 million compared to $233.6 million for the year ended December 31, 2014. In addition to the factors discussed below, net income for 2015 was favorably impacted by $7.6 million from the receipt of additional proceeds related to a business interruption claim for Louisiana Midstream. The 2014 period was impacted by a $10.0 million impairment charge, $7.1 million of which was reflected in operating expenses, related to the terminated Bluegrass project, a project between us, BPHC and The Williams Companies, Inc. (Bluegrass Project).

Operating revenues for the year ended December 31, 2015, increased $15.4 million, or 1%, to $1,249.2 million, compared to $1,233.8 million for the year ended December 31, 2014. Excluding the business interruption claim proceeds discussed above and items offset in fuel and transportation expense, primarily retained fuel and gas sales in 2014 associated with our Flag City processing plant, operating revenues increased $33.2 million, or 3%. The increase was driven by $39.5 million of higher transportation revenues primarily resulting from growth projects recently placed into service, including Evangeline which was acquired in October 2014, and $20.4 million of additional revenues resulting from the Gulf South rate case, partly offset by the comparably warm weather early in the year and the effects of the market conditions discussed above. Storage and PAL revenues were lower by $20.1 million primarily as a result of the effects of unfavorable market conditions on time period price spreads. Fuel retained, less fuel expense, was lower by $3.9 million primarily due to lower natural gas prices.

Operating costs and expenses for the year ended December 31, 2015, increased $17.7 million, or 2%, to $853.4 million, compared to $835.7 million for the year ended December 31, 2014. Excluding items offset in Operating revenues and the 2014 items discussed above, Operating costs and expenses increased $50.2 million, or 7%, when compared to the comparable period in 2014. The increase in operating expenses was driven by higher depreciation expense of $35.0 million from an increase in our asset base, including the Evangeline acquisition, and a change in the estimated lives of certain older, low-pressure assets, an increase in maintenance expenses of $14.7 million from pipeline system maintenance activities as discussed above and the Evangeline acquisition, as well as an increase in administrative and general expenses of $5.4 million primarily from employee-related costs.
 
Total other deductions for the year ended December 31, 2015, decreased $77.6 million, or 31%, to $173.3 million compared to $250.9 million for the 2014 period. The decrease was driven by prior year equity losses in unconsolidated affiliates of $86.5 million resulting from previously capitalized costs associated with the terminated Bluegrass Project that were expensed in 2014,

34



most of which were offset by noncontrolling interests related to that project. The decrease in total other deductions was slightly offset by an increase in interest expense due to higher average debt balances as compared to the 2014 period, lower capitalized interest associated with capital projects and the expensing of previously deferred costs related to the refinancing of our revolving credit facility.

2014 Compared with 2013

Our net income attributable to controlling interests for the year ended December 31, 2014, decreased $20.1 million, or 8%, to $233.6 million compared to $253.7 million for the year ended December 31, 2013. In addition to the factors discussed below, net income for 2014 was impacted by a $10.0 million impairment charge, $7.1 million of which was reflected in operating expenses, related to the Bluegrass Project. Net income for 2014 was also impacted by $2.6 million of costs from the acquisition of the Evangeline system. Net income for 2013 was impacted by a $51.5 million goodwill impairment charge and $29.5 million of gains from the sale of operating assets, including storage gas.

Operating revenues for the year ended December 31, 2014, increased $28.2 million, or 2%, to $1,233.8 million, compared to $1,205.6 million for the year ended December 31, 2013. Excluding items offset in Fuel and transportation expense, primarily retained fuel and gas sales associated with our Flag City processing plant, operating revenues were comparable from year to year. Transportation revenues, excluding retained fuel, increased $22.3 million generally due to the colder than normal winter weather in our market areas and growth projects which were recently placed into service, partly offset by lower firm transportation revenues due to the effects of the market and contract renewal conditions which are discussed above in Market Conditions and Contract Renewals. Storage and PAL revenues were lower by $22.0 million primarily as a result of the effects of unfavorable market conditions on natural gas time period price spreads.
    
Operating costs and expenses for the year ended December 31, 2014, increased $44.6 million, or 6%, to $835.7 million, compared to $791.1 million for the year ended December 31, 2013. Excluding items offset in Operating revenues, discussed above, the $7.1 million impairment charge from the Bluegrass Project, the Evangeline acquisition costs and the 2013 items discussed above, Operating costs and expenses increased $29.4 million, or 4% when compared to the comparable period in 2013. The increase in operating expenses was driven by a $17.1 million increase in depreciation expense primarily due to an increase in our asset base from the Evangeline acquisition and recently completed growth projects and a $12.1 million increase in operation and maintenance expense primarily due to increased pipeline system maintenance discussed above.

Total other deductions for the year ended December 31, 2014, increased $87.1 million, or 53%, to $250.9 million compared to $163.8 million for the 2013 period. The increase was driven by equity losses in unconsolidated affiliates of $85.3 million resulting from previously capitalized costs associated with the Bluegrass Project that were expensed in the first quarter 2014, which losses were mostly offset by noncontrolling interests related to that project.

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, sales of limited partner units and our Subordinated Loan Agreement with BPHC (Subordinated Loan). 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.

We anticipate that for 2016 our existing capital resources, including our revolving credit facility, Subordinated Loan and our cash flows from operating activities, will be adequate to fund our operations, including our growth and maintenance capital expenditures. 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.


35



Equity and Debt Financing

At December 31, 2015, we had $3.1 million of cash on hand, and over $1.1 billion of available borrowing capacity under our revolving credit facility. In 2015, we repaid, at maturity, Gulf South 5.05% notes and Texas Gas 4.60% notes from the proceeds of Boardwalk Pipelines $600 million, 4.95% notes due December 15, 2024 (Boardwalk Pipelines 2024 Notes), $350.0 million of which notes were issued in November 2014 and the remainder were issued in March 2015.

In December 2015, we updated our well-known seasoned issuer registration statement, which was declared effective immediately. We also filed an additional registration statement which covers the issuance of approximately $1.0 billion of our common units and other securities and replaces the expiring registration statement that supports our current equity distribution agreement. This registration statement was declared effective in January 2016.

We have an effective registration statement on file with the SEC, which expires in May 2016, for the issuance of up to $500.0 million of our common units. Under the registration statement, pursuant to an equity distribution agreement between us and certain broker-dealers, we may sell our common units from time to time through the broker-dealers as our sales agents. Sales of common units can be made by means of ordinary brokers’ transactions on the NYSE or as otherwise agreed by us and one or more of the broker-dealers. For the year ended December 31, 2015, we sold 7.0 million common units under our equity distribution agreement and received net proceeds of $115.4 million, including a $2.3 million contribution received from our general partner to maintain its 2% general partner interest.

Credit Ratings

Most of our senior unsecured debt is rated by independent credit rating agencies. Our credit ratings affect our ability to access the public and private debt markets, as well as the terms and the cost of our borrowings. Our ability to satisfy financing requirements or fund planned growth capital expenditures will depend upon our future operating performance and our ability to access the capital markets, which are affected by economic factors in our industry as well as other financial and business factors, some of which are beyond our control. As of February 17, 2016, our credit ratings for our senior unsecured notes and that of our operating subsidiaries having outstanding rated debt were as follows:            
Rating agency
 
Rating
(Us/Operating
 Subsidiaries)
 
Outlook
(Us/Operating
Subsidiaries)
Standard and Poor's(1)
 
BBB-/BBB-
 
Stable/Stable
Moody's Investor Services
 
Baa3/Baa2
 
Stable/Stable
Fitch Ratings, Inc.
 
BBB-/BBB-
 
Stable/Stable

(1) Standard and Poor’s has rated our debt at Boardwalk Pipelines as BB+ with a Stable outlook.

Our credit ratings reflect the view of a rating agency and are not a recommendation to buy, sell or hold any security, and may be revised or withdrawn at any time by the rating agency if it determines that the facts and circumstances warrant such a change. Each credit agency’s rating should be evaluated independently of any other credit agency’s rating.

Revolving Credit Facility

As of December 31, 2015, we had $375.0 million of borrowings outstanding under our revolving credit facility with a weighted-average interest rate of 1.67% and no letters of credit issued thereunder. As of February 17, 2016, we had outstanding borrowings under our revolving credit facility of $470.0 million, resulting in available borrowing capacity of over $1.0 billion.
    
The credit facility, which matures in May 2020, 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 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, 2015. Note 10 in Part II, Item 8 of this Report contains more information regarding our revolving credit facility.
    

36



Subordinated Debt Agreement with Affiliate

In 2014, we entered into a Subordinated Loan Agreement with BPHC under which we can borrow up to $300.0 million through December 31, 2016. The Subordinated Loan bears interest at increasing rates, ranging 5.75% to 9.75%, payable semi-annually in June and December, and matures in July 2024. The Subordinated Loan must be prepaid with the net cash proceeds from the issuance of additional equity securities by us or the incurrence of certain indebtedness by us or our subsidiaries, although BPHC may waive such prepayment. The Subordinated Loan is subordinated in right of payment to our obligations under our revolving credit facility pursuant to the terms of a Subordination Agreement between BPHC and Wells Fargo, N.A., as representative of the lenders under the revolving credit facility. Through the filing date of this Report, we have not borrowed any amounts under the Subordinated Loan.

Capital Expenditures

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

We are currently engaged in several growth projects, described in Item 1, Business - Current Growth Projects, of this Report. A summary of the estimated total costs of these projects and inception to date spending as of December 31, 2015, is as follows (in millions):
 
Estimated
 Total Cost(1)
 
Cash Invested Through December 31, 2015
Ohio to Louisiana Access
$
115.0

 
 
$
54.6

Southern Indiana Lateral
 
75.0

 
 
 
7.5

Western Kentucky Market Lateral
 
80.0

 
 
 
5.3

Power Plant Project in South Texas
 
80.0

 
 
 
12.1

Northern Supply Access (2)
 
310.0

 
 
 
34.4

Sulphur Storage and Pipeline Expansion
 
145.0

 
 
 
34.5

Coastal Bend Header (2)
 
720.0

 
 
 
27.6

Brine Development Project
 
45.0

 
 
 
8.2

Total
$
1,570.0

 
 
$
184.2


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

(2)
Remains subject to FERC regulatory approval as of the date of this filing.

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

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

Growth capital expenditures were $232.0 million, $298.3 million and $225.1 million for the years ended December 31, 2015, 2014 and 2013. Maintenance capital expenditures for the years ended December 31, 2015, 2014 and 2013 were $142.5 million, $91.4 million and $69.7 million. Our maintenance capital spending increased in 2015 from the comparable period in 2014 due to increased integrity management spending and for pipeline maintenance associated with certain of our brine facilities. In 2014, we purchased $14.7 million of natural gas to be used as base gas for our pipelines.

37




We expect total capital expenditures to be approximately $850.0 million in 2016, including approximately $130.0 million for maintenance capital and $720.0 million related to growth projects. Refer to Pipeline System Maintenance included in Recent Developments for further discussion of trends impacting our maintenance capital expenditures.

Contractual Obligations
 
The following table summarizes significant contractual cash payment obligations under firm commitments as of December 31, 2015, 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)
$
3,475.0

 
$
250.0

 
$
760.0

 
$
725.0

 
$
1,740.0

Interest on long-term debt (2)
795.8

 
157.1

 
238.1

 
177.9

 
222.7

Capital commitments (3)
185.9

 
185.9

 

 

 

Pipeline capacity agreements (4)
14.6

 
6.4

 
8.2

 

 

Operating lease commitments
30.3

 
4.6

 
7.9

 
6.3

 
11.5

Capital lease commitments (5)
13.7

 
1.0

 
2.0

 
2.2

 
8.5

Total
$
4,515.3

 
$
605.0

 
$
1,016.2

 
$
911.4

 
$
1,982.7

(1)
Includes our senior unsecured notes, having maturity dates from 2016 to 2027, and $375.0 million of loans outstanding under our revolving credit facility, having a maturity date of May 26, 2020. The amounts included in the Less than 1 Year column are included in long-term debt on our balance sheet. We intend to refinance the notes maturing in 2016 on a long-term basis and have sufficient available capacity under our revolving credit facility to extend the amount that would otherwise come due in less than one year.
(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 1.67% weighted-average interest rate and an unused commitment fee of 0.18% as of December 31, 2015, $8.3 million, $16.6 million and $11.7 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, 2015.
(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 2016, we expect to fund approximately $3.0 million to the Texas Gas pension plan.

Distributions

For the years ended December 31, 2015, 2014 and 2013, we paid distributions of $101.5 million, $99.2 million and $533.9 million to our partners. Note 12 in Part II, Item 8 of this Report contains further discussion regarding our distributions.

Cash Flows from Operating, Investing and Financing Activities

A significant portion of our revenues are fee-based, being derived from capacity reservation charges under firm transportation agreements with customers, and our operating expenses do not vary significantly from period to period. Significant variability in cash flows generally results from changes in capital expenditures, pipeline maintenance expenses and financing transactions from period to period, as well as other longer-term trends in our business which impact earnings, such as lower pricing on contract renewals and other factors, all of which are discussed elsewhere in this MD&A.


38



Changes in cash flow from operating activities

Net cash provided by operating activities increased $62.8 million to $576.4 million for the year ended December 31, 2015, compared to $513.6 million for the comparable 2014 period primarily due to natural gas purchases made in 2014 related to operations and the prepayments received under PAL arrangements in the 2015 period, partially offset by the change in net income, excluding the effects of non-cash items such as depreciation and amortization, asset impairment, equity losses in unconsolidated affiliates and the net gain on sale of operating assets.

Changes in cash flow from investing activities

Net cash used in investing activities decreased $331.7 million to $367.5 million for the year ended December 31, 2015, compared to $699.2 million for the comparable 2014 period. The decrease was primarily driven by a decrease in capital expenditures of $29.9 million primarily due to the completion of the Southeast Market expansion project in 2014 and a decrease in our net investment in the terminated Bluegrass Project of $9.4 million. The 2014 period included the acquisition of the Evangeline system for $294.7 million.

Changes in cash flow from financing activities

Net cash used in financing activities increased $376.1 million to $212.4 million for the year ended December 31, 2015, compared to net cash provided by financing activities of $163.7 million for the comparable 2014 period. The increase in cash used in financing activities resulted primarily from an increase in net repayments of borrowings of $489.4 million, partially offset by proceeds received from the sale of common units of $115.4 million, including related general partner contributions.
 
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 PPE 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, 2015, 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 Part II, 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.


39



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. As discussed above, Gulf South recently settled its rate case. As of December 31, 2015, a rate refund liability of $16.3 million associated with the rate case was recorded on our Consolidated Balance Sheets. As a result of the settlement, the rate refund liability is considered fixed and determinable as of December 31, 2015. As of December 31, 2014, there were no liabilities for any open rate case recorded on our Consolidated Balance Sheets.

When certain criteria are met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates (regulatory accounting). 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 our 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 9 in Part II, Item 8 of this Report contains more information regarding our 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. We use fair value measurements to record our derivatives, asset retirement obligations, impairments and the value of our plan assets associated with our pension and postretirement benefit plans. 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 Part II, Item 8 of this Report. Notes 5 and 11 contain more information regarding our fair value measurements.

Environmental Liabilities

                Our environmental liabilities are based on management’s best estimate of the undiscounted future obligations 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. As of December 31, 2015, we had an accrued liability of approximately $5.6 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 4 in Part II, Item 8 of this Report contains more information regarding our environmental liabilities.


40



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 our reporting units as of November 30, 2015, 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 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 for 2015 and 2014 indicated that the fair value of our reporting units significantly exceeded their carrying amounts and no goodwill impairment charges were recognized for the reporting units. In 2013, the carrying amount of the reporting unit which included goodwill associated with our Petal Gas Storage, LLC 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.

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.

In the first quarter 2014, cost escalations, construction delays and the lack of customer commitments related to our Bluegrass Project indicated that the long-lived assets associated with the Bluegrass Project may be impaired. Accordingly, we evaluated the 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 assets related to the Bluegrass Project were impaired. Refer to Note 3 in Part II, Item 8 of this Report for further information regarding the Bluegrass Project impairment charge.

Defined Benefit Plans

We are required to make a significant number of assumptions in order to estimate the net 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

41



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. Note 11 in Part II, 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.

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

our recently announced growth projects are supported by foundation shippers, many of which are major natural gas producers. The recent decrease in oil and natural gas prices could impact the foundation shippers ability to obtain credit support in the future and cause our counterparty credit risk to increase;

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

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

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

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

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

the impact to our business of our continuing to make distributions on our common units to our unitholders at our current distribution rate;

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

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

volatility or disruptions in the capital or financial markets;

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

42




the success of our strategy to grow and diversify our business, including expansion into new product lines and geographic areas, especially in light of the recently depressed price levels of oil and natural gas prices which can influence the associated production of these commodities;

the impact on our system throughput and revenues from changes in the supply of and demand for natural gas;

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; and

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

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


43



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

With the exception of our revolving credit facility, for which the interest rates are periodically reset, our debt has been issued at fixed rates. For fixed-rate debt, changes in interest rates affect the fair value of the debt instruments but do not directly affect earnings or cash flows. The following table presents market risk associated with our fixed-rate, long-term debt at December 31 (in millions, except interest rates):
 
2015
 
2014
Carrying amount of fixed-rate debt
$
3,085.6

 
$
3,360.1

Fair value of fixed-rate debt
$
2,924.7

 
$
3,467.4

100 basis point increase in interest rates and resulting debt decrease
$
113.3

 
$
135.6

100 basis point decrease in interest rates and resulting debt increase
$
121.1

 
$
145.0

Weighted-average interest rate
5.32
%
 
5.31
%

At December 31, 2015, we had $375.0 million of variable-rate debt outstanding at a weighted-average interest rate of 1.67%. A 1% increase in interest rates would increase our cash payments for interest on our variable-rate debt by $3.8 million on an annualized basis. At December 31, 2014, we had $320.0 million outstanding under variable-rate agreements at a weighted-average interest rate of 1.77%.
    
At December 31, 2015 and 2014, $3.1 million and $6.6 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, 2015 and 2014, approximately $10.5 million and $3.9 million of gas stored underground, which we own and carry as current Gas and liquids stored underground, was available for sale and exposed to commodity price risk. We have historically managed our exposure to commodity price risk through the use of futures, swaps and option contracts; however, at December 31, 2015 and 2014, we had no outstanding derivatives.

Credit risk:

Our credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them, generally under PAL and NNS. 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, 2015, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 7.7 trillion British thermal units (TBtu). Assuming an average market price during December 2015 of $1.86 per million British thermal unit (MMBtu), the market value of that gas was approximately $14.3 million. As of December 31, 2015, the amount of NGLs owed to the operating subsidiaries due to imbalances was less than 0.1 MMBbls, which had a market value of approximately $0.2 million. As of December 31, 2014, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 10.0 TBtu. Assuming an average market price during December 2014 of $3.36 per MMBtu, the market value of this gas at December 31, 2014, would have been approximately $33.6 million. As of December 31, 2014, the amount of NGLs owed to the operating subsidiaries due to imbalances was less than 0.1 MMBbls, which had a market value of approximately $0.6 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

44



cash collateral, post a letter of credit or provide a guarantee from a credit-worthy entity in an amount equaling up to three months of capacity reservation charges. For certain agreements, we have included contractual provisions that require additional credit support should the credit ratings of those customers fall below investment grade.

Natural gas producers comprise a significant portion of our revenues and support several of our growth projects. For example, in 2015, approximately 50% of our revenues were generated from contracts with natural gas producers. During 2015, the prices of oil and natural gas declined significantly from an increase in supplies mainly from shale production areas in the U.S. Should the prices of natural gas and oil remain at current levels for a sustained period of time, or decline further, we could be exposed to increased credit risk associated with our producer customer group. We continue to monitor our credit risk carefully, especially as it relates to customers that may be affected by the current oil and natural gas markets. Refer to Item 1A. Risk Factors - We are exposed to credit risk relating to nonperformance by our customers for further discussion regarding credit risk and the potential effects of declining oil prices on our credit risk.


45



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, 2015 and 2014, 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, 2015. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

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, 2015, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2016, expressed an unqualified opinion on the Partnership's internal control over financial reporting.


/s/ Deloitte & Touche LLP
Houston, Texas
February 19, 2016

46



BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)

 
December 31,
ASSETS
2015
 
2014
Current Assets:
 
 
 
Cash and cash equivalents
$
3.1

 
$
6.6

Receivables:
 

 
 

Trade, net
117.2

 
102.6

Other
12.3

 
8.3

Gas transportation receivables
5.6

 
9.1

Gas and liquids stored underground
10.7

 
4.1

Prepayments
16.9

 
14.5

Other current assets
4.0

 
4.4

Total current assets
169.8

 
149.6

 
 
 
 
Property, Plant and Equipment:
 

 
 

Natural gas transmission and other plant
9,504.7

 
9,250.1

Construction work in progress
201.9

 
105.5

Property, plant and equipment, gross
9,706.6

 
9,355.6

Less—accumulated depreciation and amortization
2,052.2

 
1,766.4

Property, plant and equipment, net
7,654.4

 
7,589.2

 
 
 
 
Other Assets:
 

 
 

Goodwill
237.4

 
237.4

Gas stored underground
97.6

 
86.4

Other
141.1

 
131.7

Total other assets
476.1

 
455.5

 
 
 
 
Total Assets
$
8,300.3

 
$
8,194.3


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

47



BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)

 
December 31,
LIABILITIES AND PARTNERS' CAPITAL
2015
 
2014
Current Liabilities:
 
 
 
Payables:
 
 
 
Trade, net
$
99.1

 
$
51.7

Affiliates
1.3

 
1.5

Other
19.5

 
10.4

Gas payables
4.7

 
8.5

Accrued taxes, other
47.3

 
47.1

Accrued interest
39.7

 
47.4

Accrued payroll and employee benefits
33.2

 
26.3

Deferred income
6.9

 
1.9

Customer rate refunds
16.3

 

Other current liabilities
46.4

 
25.4

Total current liabilities
314.4

 
220.2

 
 
 
 
Long–term debt and capital lease obligation
3,459.3

 
3,677.2

 
 
 
 
Other Liabilities and Deferred Credits:
 

 
 

Pension liability
24.3

 
19.2

Asset retirement obligation
38.1

 
39.9

Provision for other asset retirement
57.2

 
60.5

Payable to affiliate
16.0

 
16.0

Other
64.3

 
59.0

Total other liabilities and deferred credits
199.9

 
194.6

 
 
 
 
Commitments and Contingencies


 


 
 
 
 
Partners’ Capital:
 

 
 

Common units – 250.3 million and 243.3 million units issued
     and outstanding as of December 31, 2015 and 2014
4,326.2

 
4,095.1

General partner
84.8

 
80.0

Accumulated other comprehensive loss
(84.3
)
 
(72.8
)
Total partners’ capital
4,326.7

 
4,102.3

Total Liabilities and Partners' Capital
$
8,300.3

 
$
8,194.3


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



48




BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
(Millions, except per unit amounts)
 
For the Year Ended December 31,
 
2015
 
2014
 
2013
Operating Revenues:
 
 
 
 
 
Transportation
$
1,091.1

 
$
1,065.1

 
$
1,028.0

Parking and lending
11.4

 
23.3

 
23.9

Storage
81.3

 
89.5

 
110.9

Other
65.4

 
55.9

 
42.8

Total operating revenues
1,249.2

 
1,233.8

 
1,205.6

 
 
 
 
 
 
Operating Costs and Expenses:
 

 
 

 
 

Fuel and transportation
99.3

 
124.7

 
97.2

Operation and maintenance
209.5

 
194.8

 
182.7

Administrative and general
130.4

 
125.0

 
117.4

Depreciation and amortization
323.7

 
288.7

 
271.6

Asset impairment
0.4

 
10.1

 
4.1

Goodwill impairment

 

 
51.5

Net gain on sale of operating assets
(0.5
)
 
(1.1
)
 
(29.5
)
Taxes other than income taxes
90.6

 
93.5

 
96.1

Total operating costs and expenses
853.4

 
835.7

 
791.1

 
 
 
 
 
 
Operating income
395.8

 
398.1

 
414.5

 
 
 
 
 
 
Other Deductions (Income):
 

 
 

 
 

Interest expense
176.4

 
165.5

 
163.4

Interest income
(0.4
)
 
(0.6
)
 
(0.5
)
Equity losses in unconsolidated affiliates

 
86.5

 
1.2

Miscellaneous other income
(2.7
)
 
(0.5
)
 
(0.3
)
Total other deductions
173.3

 
250.9

 
163.8

 
 
 
 
 
 
Income before income taxes
222.5

 
147.2

 
250.7

 
 
 
 
 
 
Income taxes
0.5

 
0.4

 
0.5

 
 
 
 
 
 
Net Income
222.0

 
146.8

 
250.2

Net loss attributable to noncontrolling interests

 
(86.8
)
 
(3.5
)
Net income attributable to controlling interests
$
222.0

 
$
233.6

 
$
253.7

Net Income per Unit:
 
 
 

 
 

 
 
 
 
 
 
Basic net income per unit:
 

 
 

 
 

Common units
$
0.87

 
$
0.94

 
$
1.00

Class B units
$

 
$

 
$
0.05

Weighted-average number of units outstanding - basic
 

 
 

 
 

Common units
248.8

 
243.3

 
220.5

Class B units

 

 
17.6

Diluted net income per unit:
 
 
 
 
 
Common units
$

 
$
0.94

 
$
0.96

Class B units
$

 
$

 
$
0.48

Weighted-average number of units outstanding - diluted
 
 
 
 
 
Common units

 
243.3

 
226.8

Class B units

 

 
11.3

Cash distribution declared and paid to common units
$
0.40

 
$
0.40

 
$
2.13

Cash distribution declared and paid to class B units
$

 
$

 
$
0.90


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


49




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

 
For the Year Ended December 31,
 
2015
 
2014
 
2013
Net income
$
222.0

 
$
146.8

 
$
250.2

Other comprehensive income (loss):
 

 
 

 
 

(Loss) gain on cash flow hedges

 
(0.7
)
 
1.6

Reclassification adjustment transferred to Net income from cash flow hedges
2.4

 
2.6

 
1.2

Pension and other postretirement benefit costs
(13.9
)
 
(10.9
)
 
0.7

Total Comprehensive Income
210.5

 
137.8

 
253.7

Comprehensive loss attributable to noncontrolling interests

 
(86.8
)
 
(3.5
)
Comprehensive income attributable to controlling interests
$
210.5

 
$
224.6

 
$
257.2


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


50



BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
 
For the Year Ended
December 31,
OPERATING ACTIVITIES:
2015
 
2014
 
2013
Net income
$
222.0

 
$
146.8

 
$
250.2

Adjustments to reconcile net income to cash provided by operations:
 

 
 
 
 
Depreciation and amortization
323.7

 
288.7

 
271.6

Amortization of deferred costs
7.7

 
5.7

 
5.5

Asset impairment
0.4

 
10.1

 
4.1

Goodwill impairment

 

 
51.5

Net gain on sale of operating assets
(0.5
)
 
(1.1
)
 
(29.5
)
Equity losses in unconsolidated affiliates

 
86.5

 
1.2

Changes in operating assets and liabilities:
 

 
 
 
 
Trade and other receivables
(18.6
)
 
8.3

 
(10.0
)
Other receivables, affiliates

 
1.0

 
0.5

Gas receivables and storage assets
(14.3
)
 
(11.5
)
 
18.0

Costs recoverable from customers
(0.3
)
 
0.5

 
2.6

Other assets
(3.2
)
 
5.8

 
(10.7
)
Trade and other payables
39.4

 
(7.3
)
 
(16.8
)
Other payables, affiliates
(0.7
)
 
0.2

 
0.7

Gas payables
(3.7
)
 
(8.8
)
 
0.5

Accrued liabilities
0.3

 
3.9

 
8.6

Other liabilities
24.2

 
(15.2
)
 
(13.7
)
Net cash provided by operating activities
576.4

 
513.6

 
534.3

INVESTING ACTIVITIES:
 

 
 

 
 

Capital expenditures
(374.5
)
 
(404.4
)
 
(294.8
)
Proceeds from sale of operating assets
0.8

 
2.9

 
60.7

Proceeds from insurance and other recoveries
6.2

 
6.3

 
1.4

Advances to affiliates

 
0.1

 

Investment in unconsolidated affiliates

 
(20.5
)
 
(76.7
)
Distributions from unconsolidated affiliates

 
11.1

 

Acquisition of businesses, net of cash acquired

 
(294.7
)
 

Net cash used in investing activities
(367.5
)
 
(699.2
)
 
(309.4
)
FINANCING ACTIVITIES:
 

 
 

 
 

Proceeds from long-term debt, net of issuance cost
247.1

 
342.9

 

Repayment of borrowings from long-term debt and term loan
(725.0
)
 
(25.0
)
 

Proceeds from borrowings on revolving credit agreement
1,125.0

 
665.0

 
1,128.0

Repayment of borrowings on revolving credit agreement,
    including financing fees
(873.6
)
 
(720.0
)
 
(1,255.0
)
Principal payment of capital lease obligation
(0.4
)
 
(0.4
)
 
(0.2
)
Advances from affiliates
0.6

 
0.1

 
(2.8
)
Distributions paid
(101.5
)
 
(99.2
)
 
(533.9
)
Capital contributions from noncontrolling interests

 
8.2

 
87.1

Proceeds from sale of common units
113.1

 

 
368.7

Capital contributions from general partner
2.3

 

 
7.8

Distributions paid to noncontrolling interests

 
(7.9
)
 

Net cash (used in) provided by financing activities
(212.4
)
 
163.7

 
(200.3
)
(Decrease) increase in cash and cash equivalents
(3.5
)
 
(21.9
)
 
24.6

Cash and cash equivalents at beginning of period
6.6

 
28.5

 
3.9

Cash and cash equivalents at end of period
$
3.1

 
$
6.6

 
$
28.5


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

51



BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions)
 
Partners' Capital
 
 
 
 
 
Common
Units
 
Class B
Units
 
General
Partner
 
Accumulated Other Comp
Income (Loss)
 
Non-controlling Interest
 
Total Equity
Balance January 1, 2013
$
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 income,
    net of tax

 

 

 
3.5

 

 
3.5

Balance December 31, 2013
$
3,963.4

 
$

 
$
77.3

 
$
(63.8
)
 
$
86.5

 
$
4,063.4

Add (deduct):
 
 
 
 
 
 
 
 
 
 
 

Net income (loss)
228.9

 

 
4.7

 

 
(86.8
)
 
146.8

Distributions paid
(97.2
)
 

 
(2.0
)
 

 

 
(99.2
)
Capital contributions from
noncontrolling interests

 

 

 

 
8.2

 
8.2

Distributions paid to
noncontrolling interests

 

 

 

 
(7.9
)
 
(7.9
)
Other comprehensive loss,
     net of tax

 

 

 
(9.0
)
 

 
(9.0
)
Balance December 31, 2014
$
4,095.1

 
$

 
$
80.0

 
$
(72.8
)
 
$

 
$
4,102.3

Add (deduct):
 

 
 

 
 

 
 

 
 
 
 

Net income
217.5