10-K 1 form10_k123111.htm BWP 10K 12.31.11 form10_k123111.htm

 
 

 


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 
FORM 10-K
 
                          (Mark One)
x  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011

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 x  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  x

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  x    Noo

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 x  Noo

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.      x

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  x                                               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 x

The aggregate market value of the common units of the registrant held by non-affiliates as of June 30, 2011, was approximately $2.1 billion. As of February 21, 2012, the registrant had 184,921,916 common units outstanding and 22,866,667 Class B units outstanding.

Documents incorporated by reference.    None.



 
 

 




TABLE OF CONTENTS

 2011 FORM 10-K

BOARDWALK PIPELINE PARTNERS, LP


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 

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

Introduction

We are a Delaware limited partnership formed in 2005. Our business is conducted by our primary subsidiary, Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, the operating subsidiaries), which consist of integrated natural gas pipeline and storage systems. In 2011, we formed Boardwalk Midstream, LP (Midstream), and its operating subsidiary, Boardwalk Field Services, LLC (Field Services), which is engaged in the natural gas gathering and processing business. Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns 102.7 million of our common units, all 22.9 million of our class B units and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of our incentive distribution rights (IDRs). As of February 21, 2012, the common units, class B units and general partner interest owned by BPHC represent approximately 61% of our equity interests, excluding the IDRs. Our Partnership Interests, in Item 5 contains more information on how we calculate BPHC’s equity ownership. Our common units are traded under the symbol “BWP” on the New York Stock Exchange (NYSE).

In December 2011, Boardwalk HP Storage Company, LLC (HP Storage), a joint venture between Boardwalk Pipelines and BPHC, acquired Petal Gas Storage, L.L.C. (Petal), Hattiesburg Gas Storage Company (Hattiesburg) and related entities for approximately $550.0 million in cash. HP Storage funded the acquisition with borrowings under a new $200.0 million five-year bank loan and equity contributions from Boardwalk Pipelines and BPHC. BPHC contributed $280.0 million towards the purchase price for an 80% equity ownership interest in HP Storage and Boardwalk Pipelines contributed $70.0 million for a 20% equity ownership interest. Petal and Hattiesburg own high deliverability salt dome natural gas storage caverns and a natural gas transmission pipeline in Forrest County, Mississippi.
 
 
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The following diagram reflects a simplified version of our organizational structure as of December 31, 2011:

BWP Org Chart 12.31.11
 
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Our Business

We own and operate three interstate natural gas pipeline systems including integrated storage facilities. 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, local distribution companies (LDCs), marketers, electric power generators, direct industrial users and interstate and intrastate pipelines. We provide a significant portion of our pipeline transportation and storage services through firm contracts under which our customers pay monthly capacity reservation charges (which are charges owed regardless of actual pipeline or storage capacity utilization). Other charges are based on actual utilization of the capacity under firm contracts and contracts for interruptible services. For the twelve months ended December 31, 2011, approximately 82% of our revenues were derived from capacity reservation charges under firm contracts, approximately 14% of our revenues were derived from charges based on actual utilization under firm contracts and approximately 4% 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 earned by our pipeline and storage systems.

Our transportation and storage rates and general terms and conditions of service are established by, and subject to review and revision by, the Federal Energy Regulatory Commission (FERC). These rates are based upon certain assumptions to allow us the opportunity to recover the cost of providing our transportation and storage services and earn a reasonable return on equity. However, it is possible that we may not recover those costs or earn a reasonable return. Our firm and interruptible storage rates for Gulf South and the storage services associated with a portion of the working gas capacity on Texas Gas are market-based pursuant to authority granted by FERC.

Our Pipeline and Storage Systems

Our operating subsidiaries own and operate approximately 14,200 miles of pipelines, directly serving customers in twelve states and indirectly serving customers throughout the northeastern and southeastern United States (U.S.) through numerous interconnections with unaffiliated pipelines. In 2011, our pipeline systems transported approximately 2.7 trillion cubic feet (Tcf) of gas. Average daily throughput on our pipeline systems during 2011 was approximately 7.3 billion cubic feet (Bcf). Our natural gas storage facilities are comprised of eleven underground storage fields located in four states with aggregate working gas capacity of approximately 167.0 Bcf. In December 2011, we acquired a 20% equity interest in HP Storage which owns seven high deliverability salt dome natural gas storage caverns and related assets in Forrest County, Mississippi, having approximately 29.0 Bcf of total storage capacity, of which approximately 18.6 Bcf is working gas capacity. We operate the assets of HP Storage on behalf of the joint venture.

The principal sources of supply for our 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 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 mid-continent supplies such as the Woodford Shale in southeastern Oklahoma and the Fayetteville Shale in Arkansas. We also access the Eagle Ford Shale in southern Texas; wellhead supplies in northern and southern Louisiana and Mississippi; and Canadian natural gas through an unaffiliated pipeline interconnect at Whitesville, Kentucky.

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

Gulf South:  Our Gulf South pipeline system is located along the Gulf Coast in the states of Texas, Louisiana, Mississippi, Alabama and Florida. The on-system markets directly served by the Gulf South system are generally located in eastern Texas, Louisiana, southern Mississippi, southern Alabama, and the Florida Panhandle. These markets include LDCs and municipalities located across the system, including New Orleans, Louisiana; Jackson, Mississippi; Mobile, Alabama; and Pensacola, Florida, and other end-users located across the system, including the Baton Rouge to New Orleans industrial corridor and Lake Charles, Louisiana. Gulf South also has indirect access to off-system markets through numerous interconnections with unaffiliated interstate and intrastate pipelines and storage facilities. These pipeline interconnections provide access to markets throughout the northeastern and southeastern U.S.

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

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

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

The following table provides information for our pipeline systems as of December 31, 2011:

Pipeline
 
Miles of Pipeline
   
Working Gas Storage Capacity
   
Peak-day Delivery Capacity
   
Average Daily Throughput
 
         
(Bcf)
   
(Bcf/d)
   
(Bcf/d)
 
Gulf Crossing
    360       -       1.7       1.2  
Gulf South
    7,600       83.0       6.9       4.3  
Texas Gas
    6,100       84.0       4.6       3.2  

Field Services:  In 2011, we formed our Field Services subsidiary and transferred to it approximately 100 miles of gathering and transmission pipeline. In early 2012 we transferred to Field Services an additional 240 miles of pipeline and two compressor stations. These facilities were modified so that condensate-rich Eagle Ford Shale gas can be accepted into the pipeline. As discussed in more detail below, in addition to operating this pipeline, Field Services is currently developing gathering and processing capabilities in south Texas and Pennsylvania.

Current Expansion Projects

South Texas Eagle Ford Expansion:  As discussed above, we have transferred approximately 340 miles of pipeline and two compressor stations to Field Services and modified the pipeline to accept condensate-rich Eagle Ford Shale gas. In February 2012, we announced that Field Services would construct 55 miles of additional gathering pipeline and a cryogenic processing plant in south Texas. This system will have the capability of gathering in excess of 0.3 Bcf per day of liquids rich gas in Karnes and Dewitt counties, which reside in the Eagle Ford Shale production area, and processing up to 150 million cubic feet (MMcf) per day of wet gas. Field Services will also provide re-delivery of processed residue gas to a number of interstate and intrastate pipelines, including Gulf South. The plant and new pipeline are estimated to cost approximately $180.0 million and are expected to be placed in service in early 2013. We have executed a fixed price contract with Exterran Energy Solutions, L.P. to design, manufacture and construct the processing plant and long-term fee-based gathering and processing agreements with Statoil Natural Gas LLC and Talisman Energy USA, Inc., under which these customers have committed to approximately 50% of the plant’s processing capacity.

 
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Marcellus Gathering System: Field Services and Southwestern Energy Production Company have executed a fifteen year definitive gas gathering agreement which will require construction of a natural gas gathering system in Susquehanna and Lackawanna Counties, Pennsylvania. We will own the gas gathering system that will support Southwestern’s development of Marcellus Shale gas. The gathering system, which will have a delivery capacity of approximately 0.3 Bcf/day, will be comprised of approximately 26 miles of twelve-inch high pressure gas pipeline, a low pressure in-field gathering pipeline, compression and dehydration and will interconnect with Tennessee Gas pipeline in Susquehanna County. The project is expected to cost approximately $90.0 million and the first portion of the system is expected to be placed in service in April 2012.

           HP Storage:  HP Storage, a joint venture with BPHC of which we own a 20% interest, is in the process of leaching a new salt dome storage cavern which is expected to add working gas capacity of approximately 5.0 Bcf. We expect the additional capacity to be placed in service in the first quarter 2013 and to cost approximately $35.0 million.

Nature of Contracts
 
We contract with our customers to provide transportation services and storage services on a firm and interruptible basis. We also provide bundled firm transportation and storage services, which we refer to as no-notice services. In addition, we provide interruptible PAL services.
 
Transportation Services. We offer transportation services on both a firm and interruptible basis. Our 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. Firm transportation customers reserve a specific amount of pipeline capacity at specified receipt and delivery points on our system. Firm 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 gas actually transported. Capacity reservation revenues derived from a firm service contract are generally consistent during the contract term, but can be higher in winter periods than the rest of the year, especially for no-notice service agreements. Firm transportation contracts generally range in term from one to ten years, although we may enter into shorter or longer term contracts. In providing interruptible transportation service, we agree to transport gas for a customer when capacity is available. Interruptible transportation service customers pay a commodity charge only for the volume of gas actually transported, plus a fuel charge. Interruptible transportation agreements have terms ranging from day-to-day to multiple years, with rates that change on a daily, monthly or seasonal basis.
 
Storage Services. We offer customers storage services on both a firm and interruptible basis. Firm storage customers reserve a specific amount of storage capacity, including injection and withdrawal rights, while interruptible customers receive storage capacity and injection and withdrawal rights when it is available. Similar to firm transportation customers, firm storage customers generally pay fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically range in term from one to ten years. Interruptible storage customers pay for the volume of gas actually stored plus injection and withdrawal fees. Generally, interruptible storage agreements are for monthly terms. FERC has authorized Gulf South to charge market-based rates for its firm and interruptible storage services and Texas Gas is authorized to charge market-based rates for the firm and interruptible storage services associated with approximately 8.3 Bcf of its storage capacity.

No-Notice Services. No-notice services consist of a combination of firm transportation and storage services that allow customers to withdraw 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) gas into or out of our pipeline systems at a specific location for a specific period of time. Customers pay for PAL service in advance or on a monthly basis depending on the terms of the agreement.
 
 
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Customers and Markets Served
 
We transport natural gas for a broad mix of customers, including producers, LDCs, marketers, electric power generators, direct industrial users and interstate and intrastate pipelines, located throughout the Gulf Coast, Midwest and Northeast regions of the U.S.
 
We contract directly with end-use customers and with producers, marketers and other third parties who provide transportation and storage services to end-users. Based on 2011 revenues, our customer mix was as follows: producers (54%), LDCs (22%), marketers (18%), power generators (5%), and industrial end users and others (1%). Based upon 2011 revenues, our deliveries were as follows: pipeline interconnects (67%), LDCs (18%), storage activities (6%), power generators (4%), industrial end-users (3%), and other (2%). One customer, Devon Gas Services, LP, accounted for approximately 12% of our 2011 operating revenues.

Producers. Producers of natural gas use our services to transport gas supplies from producing areas, primarily from the Gulf Coast region, including shale plays 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.

LDCs. Most of our LDC customers use firm transportation services, including no-notice service. We serve approximately 175 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 supply management, transportation and storage services to support the needs of the other customer groups. Some of the marketers are sponsored by LDCs or producers.

Power Generators. We are directly connected to 39 natural-gas-fired power generation facilities in ten states. The demand of the power generating customers peaks during the summer cooling season which is counter to the winter season peak demands of the LDCs. Most of our power-generating customers use a combination of no-notice, firm and interruptible transportation services.

Pipelines (off-system). Our pipeline systems serve as feeder pipelines for long-haul interstate pipelines serving markets throughout the midwestern, northeastern and southeastern portions of the U.S. We have numerous interconnects with third-party interstate and intrastate pipelines.
 
Industrial End Users. We provide approximately 165 industrial facilities with a combination of firm and interruptible transportation services. Our 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 pipelines.
 
Competition
 
We compete with numerous other pipelines that provide natural gas transportation and storage services at many locations along our pipeline systems.  We also compete with pipelines that are attached to new gas supply sources that are being developed closer to some of our traditional market areas and that customers can access through third-party pipelines. In addition, regulators’ continuing efforts to increase competition in the natural gas industry have increased the natural gas transportation options of our traditional customers. As a result of the regulators’ policies, segmentation and capacity release have created an active secondary market which increasingly competes with our 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.
 
 
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The principal elements of competition among pipelines are available capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. In many cases, the elements of competition other than pricing, in particular flexibility, terms of service and reliability, are key differentiating factors between competitors.  This is especially the case with capacity being sold on a longer-term basis.  We are focused on finding opportunities to enhance our competitive profile in these areas by increasing the flexibility of our pipeline systems to meet the demands of customers, such as power generators, and industrial users, and are continually reviewing our services and terms of service to offer customers enhanced service options.
 
Seasonality
 
Our revenues can be affected by weather and natural gas price levels and 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 2011, approximately 53% of our revenues and 60% of our operating income, excluding asset impairments and gains and losses on the disposal of operating assets, were recognized in the first and fourth quarters of the year.

Government Regulation

Federal Energy Regulatory Commission. FERC regulates our operating subsidiaries under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. FERC regulates, among other things, the rates and charges for the transportation and storage of natural gas in interstate commerce and the extension, enlargement or abandonment of facilities under its jurisdiction. Where required, our operating 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 operating subsidiaries which is separately reported pursuant to forms filed with FERC. The regulatory books and records and other activities of our operating subsidiaries may be periodically audited by FERC.

The maximum rates that may be charged by our operating subsidiaries for all aspects of the gas transportation services we provide are established through FERC’s cost-of-service rate-making process. The maximum rates that may be charged by us for storage services on Texas Gas, with the exception of services associated with a portion of the working gas capacity on that system, are also established through FERC’s cost-of-service rate-making process. Key determinants in FERC’s cost-of-service rate-making process are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. FERC has authorized Gulf South to charge market-based rates for its firm and interruptible storage. Texas Gas is authorized to charge market-based rates for the firm and interruptible storage services associated with approximately 8.3 Bcf of its storage capacity. Neither Gulf South nor Texas Gas has an obligation to file a new rate case. In January 2012, Gulf Crossing filed with FERC a cost-and-revenue study to justify its rates as mandated in the initial order approving the construction and operation of that pipeline. Although FERC could open a proceeding under Section 5 of the Natural Gas Act to review our rates in response to the filing, the outcome of this filing is not expected to have a material impact on our business, financial condition, results of operations or cash flows.

U.S. Department of Transportation (DOT). We are regulated by DOT under the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas pipelines. We have received authority from the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency of DOT, to operate certain pipeline assets under special permits that will allow us to operate those pipeline assets at higher than normal operating pressures of up to 0.80 of the pipe’s Specified Minimum Yield Strength (SMYS). Operating at higher than normal operating pressures will allow us to transport all of the volumes we have contracted for with our customers. PHMSA retains discretion whether to grant or maintain authority for us to operate our pipeline assets at higher pressures. PHMSA has also developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in highly populated areas. A recently enacted pipeline safety bill could result in increased regulatory requirements.

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

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

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

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

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


 
Effects of Compliance with Environmental Regulations

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

Employee Relations

At December 31, 2011, we had approximately 1,170 employees, approximately 115 of whom are included in collective bargaining units. A satisfactory relationship exists between management and labor. We maintain various defined contribution plans covering substantially all of our employees and various other plans which provide regular active employees with group life, hospital, and medical benefits, as well as disability benefits. We also have a non-contributory, defined benefit pension plan and a postretirement medical plan which covers Texas Gas employees hired prior to certain dates. Note 9 in Item 8 of this Report contains further information regarding our employee benefits.

Available Information

Our website is located at www.bwpmlp.com. We make available free of charge through our website our annual reports on Form 10-K, which include our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as we electronically file such material with the Securities and Exchange Commission (SEC). These documents are also available at the SEC’s website at www.sec.gov. 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.

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

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

Business Risks

We may not be able to maintain or replace expiring gas transportation and storage contracts at attractive rates or on a long-term basis.

We are exposed to market risk when our transportation contracts expire and need to be renewed or replaced. We may not be able to extend contracts with existing customers or obtain replacement contracts at attractive rates or on a long-term basis. Key drivers that influence the rates and terms of our transportation contracts include the current and anticipated basis differentials between physical locations on our pipeline systems, which can be affected by, among other things, the availability and supply of natural gas, competition from other pipelines, including pipelines under development, available capacity, storage inventories, regulatory developments, weather and general market demand in the respective areas. The new sources of natural gas that have been identified throughout the U.S. have created changes in pricing dynamics between supply basins, pooling points and market areas. As a result of the increase in overall pipeline capacity and the new sources of supply, basis spreads on our pipeline systems have narrowed over the past several years. Basis spreads have impacted, and will continue to impact, the rates we can negotiate with our customers on contracts due for renewal for our firm transportation services, especially the rates we are able to charge for our interruptible and short-term firm transportation services.

Continued development of new supply sources impacts demand for our services.

Supplies of natural gas in production areas that are closer to key end-user market areas than our supply sources may compete with gas originating in production areas connected to our system. For example, the Marcellus Shale in Pennsylvania, New York, West Virginia and Ohio, may cause gas in supply areas connected to our system to be diverted to market areas other than our traditional market areas and may adversely affect capacity utilization on our systems and our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows. In addition, natural gas supplies from the Rocky Mountains and Canada may compete with and displace volumes from Gulf Coast and Mid-Continent supply sources where we are located, which may also adversely affect our transportation volumes and the rates we can charge for our services.

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

We rely on a limited number of customers for a significant portion of revenues. Our largest customer in terms of revenue, Devon Gas Services, LP, represented over 12% of our 2011 revenues and we expect this customer to account for more than 10% of our 2012 revenues. Our top ten customers comprised approximately 47% of our revenues in 2011. We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms which could materially reduce our contracted transportation volumes and the rates we can charge for our services.

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

Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Our exposure generally relates to receivables for services provided, future performance under firm agreements and volumes of gas owed by customers for imbalances or gas loaned by us to them under certain no-notice and PAL services. 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. If any of our significant customers have credit or financial problems which result in a delay or failure to pay for services provided by us or contracted for with us, or to repay the gas they owe us, it could have a material adverse effect on our business. In addition, as contracts expire, the credit or financial failure of any of our customers could also result in the non-renewal of contracted capacity, which could have a material adverse effect on our business. Item 7A of this Report contains more information on credit risk arising from gas loaned to customers.

 
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We may incur higher than expected costs to maintain our pipeline systems.

We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, some of which reflect increased regulatory requirements applicable to all interstate pipelines, including the pipeline integrity programs monitored by PHMSA. These costs may be capitalized or expensed, depending on the nature of the activity, and include those incurred for pipeline integrity management activities, equipment overhauls, general maintenance and repairs. Although we expect to complete the implementation of our current pipeline integrity program by the end of 2012, we could continue to incur substantial capital and operating expenditures beyond 2012 relating to the integrity and safety of our pipelines. In addition, there is a risk that new regulations associated with pipeline safety and integrity issues will be adopted that could require us to incur additional expenditures in the future.

We continue to pursue complex expansion projects which involve significant risks.

               We may undertake large development projects in the future as we continue to pursue our growth strategy, including projects in new market areas or product lines. The successful completion of such projects, and the returns we may realize from those projects after completion, are subject to many significant risks, including cost overruns; delays in obtaining regulatory approvals; difficult construction conditions, including adverse weather conditions; delays in obtaining key materials; shortages of qualified labor; and escalating costs of labor and materials, particularly in the event there is a high level of construction activity in the pipeline industry at that time. As a result, we may not be able to complete future projects on the expected terms, cost or schedule, or at all. In addition, we cannot be certain that, if completed, we will be able to operate these projects, or that they will perform, in accordance with our expectations. Other areas of our business may suffer as a result of the diversion of our management’s attention and other resources from our other business concerns to our projects. Any of these factors could impair our ability to realize the benefits we had anticipated from the projects.

Our future growth could be limited.

During the past several years, we completed a number of large development projects to enlarge and enhance our pipeline and storage systems. We plan to continue to grow and diversify our business by among other things, investing in new assets through acquisition, developing a broader midstream service capability and accessing new markets such as the Marcellus Shale. Our ability to grow, diversify and increase distributable cash flow per unit will depend, in part, on our ability to close and execute on accretive projects.  We might not complete these large projects for any of the following reasons:

·  
inability to identify opportunities with favorable projected financial returns;
·  
inefficiencies and complexities that can occur because of unfamiliarity with new product lines or new markets;
·  
inability to raise financing for identified opportunities; or
·  
inability to secure sufficient commitments from potential customers due to competition from other companies or for other reasons.

We compete with other natural gas pipelines.

The principal elements of competition among pipelines are availability of capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. Additionally, FERC’s policies promote competition in natural gas markets by increasing the number of gas transportation options available to our customer base. Increased competition could reduce the volumes of gas transported by our pipeline systems or, in instances where we do not have long-term contracts with fixed rates, could cause us to decrease the transportation or storage rates charged to our customers. Competition could intensify the negative impact of factors that could significantly decrease demand for natural gas in the markets served by our operating subsidiaries, such as a recession or adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

 
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Significant changes in energy prices could affect natural gas market supply and demand, or potentially reduce the competitiveness of natural gas compared with other forms of energy available to our customers, which could reduce system throughput and adversely affect our revenues and available cash.

We are currently experiencing extraordinarily low natural gas prices, which are being driven by the abundance of supply and increased infrastructure. Due to the natural decline in traditional gas production connected to our system, our success depends on our ability to obtain access to new sources of natural gas, which is dependent on factors beyond our control including the price level of natural gas. In general terms, the price of natural gas fluctuates in response to changes in supply and demand, market uncertainty and a variety of additional factors, including:
 
·  
worldwide economic conditions;  
 
·  
weather conditions, seasonal trends and hurricane disruptions;  
 
·  
the relationship between the available supplies and the demand for natural gas;  
 
·  
new supply sources;
 
·  
the availability of adequate transportation capacity;
 
·  
storage inventory levels;  
 
·  
the price and availability of other forms of energy;  
 
·  
the effect of energy conservation measures;  
 
·  
the nature and extent of, and changes in, governmental regulation, for example greenhouse gas legislation and taxation; and  
 
·  
the anticipated future prices of natural gas and other commodities.

It is difficult to predict future changes in gas prices. However, the abundance of natural gas supply discoveries over the last few years and global economic slowdown would generally indicate a bias toward downward pressure on prices. Downward movement in gas prices could negatively impact producers in nontraditional supply areas such as the Barnett Shale, the Bossier Sands, the Woodford Shale, the Fayetteville Shale and the Haynesville Shale, including producers who have contracted for capacity with us. Significant financial difficulties experienced by our producer customers could impact their ability to pay for services rendered or otherwise reduce their demand for our services.

High natural gas prices may result in a reduction in the demand for natural gas. A reduced level of demand for natural gas could reduce the utilization of capacity on our systems, reduce the demand for our services and could result in the non-renewal of contracted capacity as contracts expire.

A significant portion of our debt will mature over the next twelve to eighteen months.

Our revolving credit facility, $225.0 million of 5.75% senior unsecured Gulf South notes and $100.0 million of subordinated loans with BPHC are due to mature in 2012. While we expect to refinance this indebtedness prior to or upon maturity, we may not be able to refinance this indebtedness or refinancing may not be available on commercially reasonable terms. The financial terms or covenants of the new credit facility or any other indebtedness may not be as favorable as those under our existing indebtedness.

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 earnings before interest, taxes, depreciation and amortization (as defined in the agreement) of no more than five to one, which limits the amount of additional indebtedness we can incur. Future financing agreements we may enter into may contain similar or more restrictive covenants.

 
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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, 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. 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.

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

There are a variety of operating risks inherent in our natural gas transportation and storage operations such as leaks, explosions, fires and mechanical problems. Additionally, the nature and location of our business may make us susceptible to catastrophic losses from hurricanes or other named storms, particularly with regard to our assets in the Gulf Coast region, windstorms, earthquakes, hail, explosions, severe winter weather and fires. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from some of these risks.
 
We currently possess property, business interruption and general liability insurance, but proceeds from such insurance coverage may not be adequate for all liabilities or expenses incurred or revenues lost. Moreover, such insurance may not be available in the future at commercially reasonable costs and terms. The insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or all potential losses.

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

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

Regulatory Risks

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

We have entered into firm transportation contracts with shippers which utilize the design capacity of certain of our pipeline assets, assuming that we operate those pipeline assets at higher than normal operating pressures (up to 0.80 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.

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

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

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

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

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

Our business operations are subject to extensive regulation by FERC, including with respect to 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. The federal regulatory approval and compliance process could raise the costs of such projects to the point where they are no longer sufficiently timely or cost competitive when compared to competing projects that are not subject to the federal regulatory regime.

We are also subject to strict safety regulations imposed by PHMSA, including those requiring us to develop and maintain integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in what are referred to as high consequence areas where a leak or rupture could potentially do the most harm. In the past several years, there have been several integrity-related incidents on pipelines not affiliated with us that could lead to increased regulation of natural gas pipelines by PHMSA. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.

Our operations are also subject to extensive federal, state and local laws and regulations relating to protection of the environment. These laws include, for example, the Clean Air Act, the Water Pollution Control Act, commonly referred to as the Clean Water Act, CERCLA or the Superfund law, the Resource Conservation and Recovery Act and analogous state laws. The existing environmental regulations could be revised or reinterpreted in the future and new laws and regulations could be adopted or become applicable to our operations or facilities. Compliance with current and future laws and regulations could require significant expenditures or we could be delayed in or prevented from obtaining required environmental regulatory approvals for certain projects, which could require us to shut down certain facilities or pay additional costs.

 
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Should we fail to comply with all applicable laws and regulations, we could also be subject to penalties and fines and/or otherwise incur significant costs to restore compliance.

We face risks associated with global climate change.

In 2009, the Environmental Protection Agency, (EPA) made a determination that greenhouse gases are a threat to the public health and the environment and may be regulated as “air pollutants” under the Clean Air Act (CAA). In 2011, we began filing reports with the EPA regarding greenhouse gas emissions from our compressor stations, pursuant to final rules issued by the EPA regarding the reporting of greenhouse gas emissions from sources in the U.S. that annually emit 25,000 or more metric tons of greenhouse gases, including carbon dioxide, methane and others. Additionally, we conducted various facility surveys across our entire system to comply with the EPA’s greenhouse gas emission calculations and reporting regulations and will continue to do so annually as required by the rule. Additional government or legislative action may be initiated to reduce greenhouse gas emissions along with other government actions that may have the effect of requiring or encouraging reduced consumption or production of natural gas. Some states have also adopted laws regulating greenhouse gas emissions, although none of the states in which we operate have adopted such laws.

Federal legislation, which could consist of an emissions cap and trade system, may be enacted in the U.S. in the near future. Depending on the particular regulation adopted, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations (for example, our compressor units). In addition, compliance with any new federal or state laws and regulations requiring adoption of greenhouse gas control programs or imposing restrictions on emissions of carbon dioxide in areas of the U.S. in which we conduct business could adversely affect the demand for and the cost to produce and transport natural gas which would adversely affect our business.

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 61% 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;
 
 
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·  
our partnership agreement limits the liability and reduces the fiduciary duties of our general partner and the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
 
·  
our general partner determines the amount and timing of asset purchases and sales, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;
 
·  
our general partner determines the amount and timing of any capital expenditures and whether an expenditure is for maintenance capital, which reduces operating surplus, or a capital improvement expenditure, which does not. Such determination can affect the amount of cash that is distributed to our unitholders;
 
·  
in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
 
·  
our general partner determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us;
 
·  
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf, and provides that reimbursement to Loews for amounts allocable to us consistent with accounting and allocation methodologies generally permitted by FERC for rate-making purposes and past business practices is deemed fair and reasonable to us;
 
·  
our general partner controls the enforcement of obligations owed to us by it and its affiliates;
 
·  
our general partner intends to limit its liability regarding our contractual obligations;
 
·  
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
 
·  
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;  

 
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·  
generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and  

·  
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

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

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

Tax Risks

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

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. 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.
 
Current tax law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to additional amounts of entity-level taxation for state tax purposes. For example, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of such a tax on us would reduce the cash available for distribution to unitholders.
 
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, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

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

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial or administrative changes and differing interpretations at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Recently, members of Congress have considered substantive changes to the existing U.S. tax laws that would affect certain publicly traded partnerships. Although it does not appear that the legislation considered would have affected our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will be reconsidered or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted, and the costs of any contest will reduce our cash distributions to our unitholders.
 
The IRS has not made determinations with respect to all the federal income tax matters affecting us or our unitholders. The IRS may adopt positions that differ from the positions that we take. Therefore, it may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and even then a court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, because the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, any such contest will result in a reduction in cash available for distribution.

Our unitholders may be required to pay taxes on their share of our income even if such unitholders do not receive any cash distributions from us.
 
Our unitholders will be treated as partners to whom we will allocate taxable income and who 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 such unitholders receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to such unitholders’ share of our taxable income or even equal to the actual tax liability that results from such unitholders’ share of our taxable income.

Tax gain or loss on the disposition of our common units could be different than expected.
 
If our unitholders sell their common units, such unitholders will recognize gain or loss equal to the difference between the amount realized and such unitholders’ tax basis in those common units. Distributions in excess of our unitholders’ allocable share of our net taxable income decrease their tax basis in their common units. Accordingly, to the extent a unitholder’s distributions have exceeded such unitholder’s allocable share of our net taxable income, the sale of units by such unitholder will produce taxable income to them 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 items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and could be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. 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.

 
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We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in a decrease in the value of the common units.
 
Because we cannot match transferors and transferees of common units we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. These positions may result in an understatement of deductions and an overstatement of income to our unitholders. A successful IRS challenge to those positions could decrease 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 any 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 prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. If the IRS were to 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 loaned 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 a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, 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 to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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

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

 
21

 
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 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 our filing two tax returns for one fiscal year, and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby a publicly traded partnership that has technically terminated may be permitted to provide only a single Schedule K-1 to unitholders for the two tax years within the fiscal year 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, 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 twelve 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.



 
22

 


None.



We are headquartered in approximately 108,000 square feet of leased office space located in Houston, Texas. We also have approximately 108,000 square feet of office space in Owensboro, Kentucky, in a building that we own. 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.


 
None.



None.


 
23

 



Our Partnership Interests

As of December 31, 2011, we had outstanding 175.7 million common units, 22.9 million class B units, a 2% general partner interest and IDRs. Subsequent to December 31, 2011, we issued an additional 9.2 million common units to the public, increasing our outstanding common units to 184.9 million. The common units and class B units together 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 102.7 million of our common units, all 22.9 million of our class B units and, through Boardwalk GP, LP, an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the IDRs. As of February 21, 2012, the common units, class B units and general partner interest held by BPHC represent approximately 61% 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, 2012, we had 184.9 million common units outstanding held by approximately 56 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, 2012, was $27.05 per unit.

   
Sales Price Range per
Common Unit
   
Cash
Distributions
 
   
High
   
Low
   
per Common Unit
(1) (2)
 
Year ended December 31, 2011:
                 
Fourth quarter
  $ 29.12     $ 23.82     $ 0.5300  
Third quarter
    29.32       23.54       0.5275  
Second quarter
    33.47       27.01       0.5250  
First quarter
    33.50       31.01       0.5225  
                         
Year ended December 31, 2010:
                       
Fourth quarter
  $ 34.23     $ 29.80     $ 0.520  
Third quarter
    32.72       29.51       0.515  
Second quarter
    30.57       14.49       0.510  
First quarter
    31.44       28.26       0.505  

(1)
Represents cash distributions attributable to the quarter and declared and paid to limited partner unitholders within 60 days after quarter end.
 
(2)
We also paid cash distributions to our general partner with respect to its 2% general partner interest and, with respect to that portion of the distribution in excess of $0.4025 per unit, its IDRs described below. The class B unitholder participates in distributions on a pari passu basis with our common units up to $0.30 per quarter. The class B units do not participate in quarterly distributions above $0.30 per unit.


 
24

 
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.  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 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, the requirements of applicable state partnership and limited liability company laws, and the requirements of our revolving credit facility which would prohibit us from making distributions to unitholders if an event of default were to occur. In addition, we may lack sufficient cash to pay distributions to unitholders due to a number of factors, including those described in Item 1A, Risk Factors, of this Report.

Incentive Distribution Rights

           IDRs represent a limited partner ownership interest and include the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the target distribution levels have been achieved, as defined in our partnership agreement. Our general partner currently holds all of our IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. In 2011, 2010 and 2009, we paid $22.3 million, $18.2 million and $13.3 million in distributions on behalf of our IDRs. Note 10 in Item 8 of this Report contains more information regarding our distributions.
 
Assuming we do not issue any additional classes of units and our general partner maintains its 2% general partner interest, we will distribute any available cash from operating surplus for that quarter among the unitholders and our general partner as follows:

 
  
  
Total Quarterly Distribution
 
Marginal Percentage Interest in
Distributions
Target Amount
Limited Partner
Unitholders
(1)
 
General Partner
and
IDRs
First Target Distribution
  
up to $0.4025
  
98%
 
2%
Second Target Distribution
  
above $0.4025 up to $0.4375
  
85%
 
15%
Third Target Distribution
  
above $0.4375 up to $0.5250
  
75%
 
25%
Thereafter
  
above $0.5250
  
50%
 
50%

(1) Distributions to our limited partner unitholders include distributions on behalf of our class B units. The class B units share in quarterly distributions of available cash from operating surplus on a pari passu basis with our common units, until each common unit and class B unit has received a quarterly distribution of $0.30. The class B units do not participate in quarterly distributions above $0.30 per unit.
 

Equity Compensation Plans

For information about our equity compensation plans, see Securities Authorized for Issuance under Equity Compensation Plans in Item 12 of this Report.


Issuer Purchases of Equity Securities

None.

 
25

 

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. The financial data below should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in Item 8 of this Report (in millions, except Net income per common unit, Net income per class B unit, Net income per subordinated unit, Distributions per common unit and Distributions per Class B unit):

   
For the Year Ended December 31,
 
   
2011
   
2010
   
2009
   
2008
   
2007
 
Total operating revenues
  $ 1,138.8     $ 1,116.8     $ 909.2     $ 784.8     $ 643.2  
Net income
    220.0       289.4       162.7       294.0       227.7  
Total assets
    6,770.6       6,878.0       6,895.8       6,721.6       4,122.0  
Long-term debt
    3,198.7       3,252.3       3,100.0       2,889.4       1,847.9  
Net income per common unit
    1.09       1.47       0.88       2.09       1.91  
Net income per class B unit (1)
    0.14       0.62       0.08       0.60       -  
Net income per subordinated unit (1)
    -       -       -       1.68       1.86  
Distributions per common unit (2)
    2.095       2.030       1.950       1.870       1.740  
Distributions per class B unit (1)
    1.20       1.20       1.20       0.30       -  
EBITDA (3)
    617.7       658.2       498.0       474.6       349.8  
Distributable cash flow (3)
    390.9       454.3       314.3       385.3       272.8  

(1)  
In June 2008, we issued and sold approximately 22.9 million class B units. These class B units began sharing in earnings allocations on July 1, 2008 and began participating in distributions with the distribution attributable to the third quarter 2008. In November 2008, all of the 33.1 million subordinated units converted to common units.

(2)  
Distributions per subordinated unit were the same as the distributions per common unit for the years ended December 31, 2008 and 2007.

(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 natural gas transportation, gathering and storage business, 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.

 
26

 
EBITDA and distributable cash flow should not be considered alternatives to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, or as indicators of our operating performance or liquidity. Certain items excluded from 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 or to allocate funds to business or legal purposes other 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,
 
   
2011
   
2010
   
2009
   
2008
   
2007
 
Net income
  $ 220.0     $ 289.4     $ 162.7     $ 294.0     $ 227.7  
Income taxes
    0.4       0.5       0.3       1.0       0.8  
Depreciation and amortization
    225.2       217.9       203.1       124.8       81.8  
Interest expense
    159.3       151.0       132.1       57.7       61.0  
Interest income
    (0.4 )     (0.6 )     (0.2 )     (2.9 )     (21.5 )
Loss on debt extinguishment
    13.2       -       -       -       -  
EBITDA
  $ 617.7     $ 658.2     $ 498.0     $ 474.6     $ 349.8  
Less:
                                       
    Cash paid for interest (1)
    171.7       146.3       124.4       42.8       46.1  
    Maintenance capital expenditures (2)
    94.6       63.0       58.9       50.5       47.1  
    Other (3)
    0.6       0.4       0.4       (1.0 )     3.0  
Add:
                                       
    Cash received for settlements (4)
    9.6       -       -       -       -  
    Asset impairment
    30.5       5.8       -       3.0       19.2  
Distributable Cash Flow
  $ 390.9     $ 454.3     $ 314.3     $ 385.3     $ 272.8  
                                         

 
(1)  
The year ended December 31, 2011, includes $21.0 million of premiums paid for the early extinguishment of debt.
 
(2)  
The year ended December 31, 2011, includes $14.3 million of maintenance capital expenditures related to repairs associated with a fire at our Carthage compressor station.
 
(3)  
Includes non-cash items such as the equity component of allowance for funds used during construction.
 
(4)  
Represents proceeds received related to insurance recoveries associated with the Carthage compressor station incident and a legal settlement.
 




 
27

 



Overview

We own and operate three interstate natural gas pipeline systems, including integrated storage facilities. Our pipeline systems originate in the Gulf Coast region, Oklahoma and Arkansas, and extend northeasterly to the Midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio.

Our pipeline systems contain approximately 14,200 miles of interconnected pipelines, directly serving customers in twelve states and indirectly serving customers throughout the northeastern and southeastern U.S. through numerous interconnections with unaffiliated pipelines. In 2011, our pipeline systems transported approximately 2.7 Tcf of gas. Average daily throughput on our pipeline systems during 2011 was approximately 7.3 Bcf. Our natural gas storage facilities are comprised of eleven underground storage fields located in four states with aggregate working gas capacity of approximately 167.0 Bcf. We conduct all of our natural gas transportation and integrated storage operations through our operating subsidiaries as one segment.

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

Recent Developments

In December 2011, HP Storage, a joint venture between us and BPHC of which we own a 20% interest, acquired Petal and Hattiesburg and related entities for $550.0 million. Petal and Hattiesburg own seven high deliverability salt dome natural gas storage caverns and related assets in Forrest County, Mississippi. The storage caverns have approximately 29.0 Bcf of total storage capacity, of which approximately 18.6 Bcf is working gas capacity. The other assets include a leaching plant, freshwater and brine disposal wells, approximately 69,000 horsepower of compression and approximately 105 miles of pipeline which connect the storage facilities with several major natural gas pipelines, including our Gulf South pipeline. We operate the assets of HP Storage on behalf of the joint venture. HP Storage is in the process of leaching a new salt dome storage cavern which will add approximately 5.0 Bcf of working gas capacity and is expected to be placed in service in the first quarter 2013.

In late 2011 and early 2012, we transferred 340 miles of pipeline and two compressor stations to Boardwalk Field Services. These facilities were modified so that condensate-rich Eagle Ford Shale gas can be accepted into the pipeline. In February 2012, Field Services entered into a definitive agreement to construct a cryogenic gas processing plant and approximately 55 miles of gathering pipeline to serve producers in the Eagle Ford Shale producing area. This project is supported by long-term, fee-based gathering and processing agreements with Statoil Natural Gas LLC and Talisman Energy USA, Inc.

In October 2011, Field Services and Southwestern Energy Production Company executed a fifteen-year definitive gas gathering agreement which will require construction of high-pressure gas pipeline, a low-pressure gathering pipeline, compression and dehydration assets in Susquehanna and Lackawanna Counties, Pennsylvania.

Refer to Item 1 for further discussion of these projects.

 
28

 
Market Conditions and Contract Renewals

The majority of our revenues are derived from capacity reservation charges under firm agreements that are not impacted by the volume of natural gas transported or stored, and a smaller portion of our revenues are derived from charges based on actual volumes transported under firm and interruptible services. For example, for the twelve months ended December 31, 2011, approximately 82% of our revenues were derived from capacity reservation charges and 18% of our revenues were derived from charges based on actual volumes transported or stored.

As of December 31, 2011, a substantial portion of our transportation capacity has been contracted for under firm agreements having a weighted-average remaining life of approximately 6.0 years. However, an important aspect of our business is our ability to market available short-term firm or interruptible transportation capacity and renew existing longer-term transportation contracts. We actively market our available capacity which includes reserved capacity not fully utilized. The revenues we will be able to earn from that available capacity and from renewals of expiring contracts will be influenced by basis spreads and other factors discussed below.

Our ability to market available transportation capacity is impacted by supply and demand for natural gas, competition from other pipelines, natural gas price volatility, the price differential between physical locations on our pipeline systems (basis spreads), economic conditions and other factors. Over the past several years, new sources of natural gas have been identified throughout the U.S. and new pipeline infrastructure has been developed, which has led to changes in pricing dynamics between supply basins, pooling points and market areas and an overall weakening of basis spreads across our pipeline systems.

The narrowing of basis spreads on our pipeline systems has made it more difficult to renew expiring long-term firm transportation contracts at previously contracted rates because, as basis spreads decrease, the rates customers are willing to pay decrease. In addition, as rates decline customers typically seek longer-term agreements while we generally seek shorter terms. Changing basis spreads do not have as significant or immediate of an impact on long-term firm agreements as they do on short-term or interruptible services because long-term agreements are also influenced by other factors, such as baseload supply needs, certainty of delivery, predictability of long-term costs, the ability to manage those costs through the capacity release mechanism and the terms of service. The changes in the pricing dynamics and weakening of basis spreads have contributed to decreases in our operating profitability especially with regard to short-term and interruptible services. However, in 2011, revenues from power customers increased and we continue to see additional interest from this customer group.

Our ability to market available storage capacity and PAL is impacted by many of the factors indicated above, as well as natural gas price differentials between time periods, such as winter to summer (time period price spreads). These time period price spreads have declined over the 2010 to 2011 periods and have resulted in a significant reduction in our PAL and interruptible storage revenues in 2011 as compared to 2010.

Pipeline System Maintenance

We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, some of which reflect increased regulatory requirements applicable to all interstate pipelines. These costs include those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. A recently enacted pipeline safety bill could result in increased regulatory requirements.

In 2012, we expect to incur costs of approximately $260.0 million to maintain our pipeline systems, of which approximately $91.3 million is expected to be recorded as maintenance capital. In 2011, these costs were approximately $250.0 million, of which approximately $80.3 million was recorded as maintenance capital, excluding the capital costs incurred for repairs associated with a fire at our Carthage compressor station. The projected increase of $10.0 million is primarily related to pipeline integrity projects and general pipeline maintenance and repairs which are necessary to comply with regulatory requirements.
 
 
29

 

Results of Operations

2011 Compared with 2010

Our net income for the year ended December 31, 2011, decreased $69.4 million, or 24%, to $220.0 million compared to $289.4 million for the year ended December 31, 2010. The decrease in net income was a result of a charge related to our materials and supplies, decreased PAL and storage revenues, increased operations and maintenance expenses and a loss on the early extinguishment of debt. These unfavorable impacts to net income were partially offset by higher gas transportation revenues from increased capacities.

Operating revenues for the year ended December 31, 2011, increased $22.0 million, or 2%, to $1,138.8 million, compared to $1,116.8 million for the year ended December 31, 2010. Gas transportation revenues, excluding fuel, increased $59.6 million primarily from increased capacities resulting from the completion of several compression projects in 2010 and operating our Fayetteville Lateral at its design capacity. PAL and storage revenues decreased $21.6 million due to decreased parking opportunities from unfavorable natural gas price spreads between time periods and fuel retained decreased $16.0 million primarily due to lower natural gas prices.

Operating costs and expenses for the year ended December 31, 2011, increased $69.2 million, or 10%, to $746.1 million, compared to $676.9 million for the year ended December 31, 2010. In 2011, we recognized an impairment charge of $28.8 million related to materials and supplies, most of which was subsequently sold. Operation and maintenance expenses increased by $17.8 million primarily due to maintenance projects for pipeline integrity management and reliability spending and lower amounts of labor capitalized from fewer growth projects. Other drivers for the increased operating expenses were higher depreciation and property taxes of $12.0 million associated with an increase in our asset base and reduced gains from the sale of storage gas needed to support operations of $8.3 million. These increases were partially offset by lower fuel consumed of $8.8 million primarily due to lower natural gas prices.

Total other deductions increased by $22.3 million, or 15%, to $172.3 million for the year ended December 31, 2011, compared to $150.0 million for the 2010 period, driven by a $13.2 million loss on the early extinguishment of debt and higher interest expense of $8.3 million resulting from higher average interest rates on our long-term debt and lower capitalized interest.

2010 Compared with 2009

Our net income for the year ended December 31, 2010, increased $126.7 million, or 78%, to $289.4 million compared to $162.7 million for the year ended December 31, 2009. The primary drivers were higher transportation revenues from our pipeline expansion projects and gains on gas sales associated with our Western Kentucky Storage Expansion project and a reduction in storage gas needed to support no-notice services, partially offset by increased operating expenses related to higher depreciation and property taxes associated with the pipeline expansion projects and increased interest expense. In 2009, gas transportation revenues and throughput were negatively impacted due to operating our pipeline expansion projects at reduced operating pressures and portions of the pipeline expansion projects being shut down for periods of time following the discovery and remediation of anomalies in certain joints of pipe.

Operating revenues for the year ended December 31, 2010, increased $207.6 million, or 23%, to $1,116.8 million, compared to $909.2 million for the year ended December 31, 2009. Gas transportation revenues, excluding fuel, increased $199.1 million and fuel retained increased $31.2 million primarily due to our pipeline expansion projects. The increases were partially offset by $13.7 million of lower interruptible and short-term firm transportation services resulting from lower basis spreads between delivery points on our pipeline systems. PAL and storage revenues decreased $9.0 million due to decreased parking opportunities from unfavorable natural gas price spreads between time periods.

Operating costs and expenses for the year ended December 31, 2010, increased $62.2 million, or 10%, to $676.9 million, compared to $614.7 million for the year ended December 31, 2009. The primary drivers of the increase were increased fuel consumed of $46.9 million from our pipeline expansion projects and higher natural gas prices. Depreciation and property taxes increased by $24.1 million associated with an increase in our asset base. Operation and maintenance expenses increased $9.9 million primarily due to an increase in major maintenance projects. Impairment losses of $5.8 million were recognized in 2010 primarily related to the sale of assets in the Overton Field area in northeast Texas and a portion of pipe materials which we expect to dispose of by sale. The increased expenses were partly offset by a $17.9 million gain from the sale of gas related to our Western Kentucky Storage Expansion project and a reduction in storage gas needed to support no-notice services. The 2009 period was unfavorably impacted by $7.5 million as a result of pipeline investigation and retirement costs related to the East Texas Pipeline.

 
30

 
Total other deductions increased by $18.5 million, or 14%, to $150.0 million for the year ended December 31, 2010, compared to $131.5 million for the 2009 period, driven by higher interest expense of $18.9 million resulting from increased debt levels in 2010 and lower capitalized interest due to the completion of our pipeline expansion projects.

Liquidity and Capital Resources

We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility, debt issuances and sales of limited partner units. Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as needed, borrowings under our revolving credit facility to service outstanding indebtedness and make distributions or advances to us to fund our distributions to unitholders. We have no material guarantees of debt or other similar commitments to unaffiliated parties.

Capital Expenditures

Maintenance capital expenditures for the years ended December 31, 2011, 2010 and 2009 were $94.6 million $63.0 million and $58.9 million. Growth capital expenditures, including costs associated with our recently completed pipeline expansion projects, were $46.6 million, $160.7 million and $754.2 million for the years ended December 31, 2011, 2010 and 2009. We expect our 2012 maintenance capital expenditures to be approximately $91.3 million, $43.0 million of which is for system maintenance primarily related to pipeline integrity management.

Our more significant growth projects for 2012 are discussed above in Recent Developments and consist of:

South Texas Eagle Ford Expansion: We expect to spend approximately $180.0 million to construct a gathering pipeline and a cryogenic processing plant in south Texas, of which we expect to spend approximately $173.0 million in 2012.

Marcellus Gathering System: We expect to spend approximately $90.0 million to construct a gathering pipeline in Pennsylvania, of which we expect to spend approximately $70.0 million in 2012.

           HP Storage:  HP Storage expects to spend approximately $35.0 million to leach a new salt dome storage cavern which will add working gas capacity of approximately 5.0 Bcf, all of which is expected to be spent in 2012. We currently own a 20% equity interest in HP Storage. If it makes economic sense for us and BPHC, we could seek to acquire the remaining 80% equity interest in HP Storage that we do not currently own. Neither we nor BPHC is under any obligation with respect to such a transaction.

Refer to Item 1 for further discussion of these projects.

Equity and Debt Financing

We may seek to access the capital markets to fund some or all of the growth capital expenditures described above. In addition, we have the following indebtedness maturing over the next 12 months which we expect to refinance through capital market transactions or bank loans: (i)  our revolving credit facility matures in June 2012, however all revolving loans outstanding at maturity may, at our election, be converted to term loans which mature in June 2013; (ii) $225.0 million of 5.75% senior unsecured Gulf South notes mature in August 2012; and (iii) our $100.0 million subordinated loan from BPHC matures in December 2012, but is extendable by us for up to a year if we extend the term on our revolving credit facility. Our ability to access the capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions.

 
31

 
We anticipate that our existing capital resources, including our revolving credit facility, and future cash flows will be adequate to fund our operations, including our maintenance capital expenditures. We expect to issue and sell debt and/or equity securities and to incur other indebtedness for the purposes described above and may also do so for general corporate purposes, or to fund potential acquisitions and new growth opportunities.

In February 2012, we completed a public offering of 9.2 million of our common units at a price of $27.55 per unit. We received net cash proceeds of approximately $250.2 million after deducting underwriting discounts and offering expenses of $8.5 million and including a $5.2 million contribution received from our general partner to maintain its 2% general partner interest. The net proceeds were used to repay borrowings under our revolving credit facility, which increased our available borrowing capacity under the facility.

In January 2011, we received net proceeds of approximately $322.0 million after deducting initial purchaser discounts and offering expenses of $3.0 million from the sale of $325.0 million of 4.50% senior unsecured notes of Texas Gas due February 1, 2021 (2021 Notes). In June 2011, we issued an additional $115.0 million of the 2021 Notes. The additional issuance was priced at a premium resulting in net proceeds of $115.6 million after deducting underwriter discounts and offering expenses of $1.0 million. We used the proceeds from both offerings to repay borrowings under our revolving credit facility and redeem Texas Gas’ 5.50% notes due April 1, 2013 (2013 Notes) for which we paid premiums of $21.0 million. Note 7 in Item 8 of this report contains more information about the 2021 Notes and redemption of the 2013 Notes.

In June 2011, we completed a public offering of 6.0 million of our common units at a price of $29.33 per unit. We received net cash proceeds of approximately $173.6 million after deducting underwriting discounts and offering expenses of $6.0 million and including a $3.6 million contribution received from our general partner to maintain its 2% general partner interest. The net proceeds were used to repay borrowings under our revolving credit facility.

 
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Revolving Credit Facility

We maintain a revolving credit facility which has aggregate lending commitments of $950.0 million, under which Boardwalk Pipelines, Gulf South and Texas Gas each may borrow funds, up to applicable sub-limits. Interest on amounts drawn under the credit facility is payable at a floating rate equal to an applicable spread per annum over the London Interbank Offered Rate or a base rate defined as the greater of the prime rate or the Federal funds rate plus 50 basis points. The revolving credit facility has a maturity date of June 29, 2012, however all outstanding revolving loans on such date may be converted to term loans having a maturity date of June 29, 2013. As of December 31, 2011, we had $458.5 million of loans outstanding under our revolving credit facility with a weighted-average interest rate of 0.52% and no letters of credit issued thereunder. Subsequent to December 31, 2011, we repaid $115.0 million of borrowings, which decreased borrowings to $343.5 million, resulting in available borrowing capacity of $606.5 million.

Our revolving credit facility contains customary negative covenants, including, among others, limitations on the payment of cash dividends and other restricted payments, the incurrence of additional debt, sale-leaseback transactions and transactions with our affiliates. The facility also contains a financial covenant that requires us and our subsidiaries to maintain a ratio of total consolidated debt to consolidated EBITDA (as defined in the credit agreement), measured for the preceding twelve months, of not more than five to one. We and our subsidiaries were in compliance with all covenant requirements under our credit facility at December 31, 2011. Although we do not believe that these covenants have had, or will have, a material impact on our business and financing activities or our ability to obtain the financing to maintain operations and continue our capital investments, they could restrict us in some circumstances as stated in Item 1A, Risk Factors. Note 7 in Item 8 of this Report contains more information regarding our revolving credit facility.

Contractual Obligations
 
The following table summarizes significant contractual cash payment obligations under firm commitments as of December 31, 2011, 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)
  $ 3,208.5     $ 783.5     $ -     $ 775.0     $ 1,650.0  
Interest on long-term debt (2)
    906.2       151.7       261.4       223.6       269.5  
Capital commitments (3)
    16.7       16.7       -       -       -  
Pipeline capacity agreements (4)
    48.5       9.0       17.0       14.4       8.1  
Operating lease commitments
    19.2       4.4       7.5       6.3       1.0  
Total
  $ 4,199.1     $ 965.3     $ 285.9     $ 1,019.3     $ 1,928.6  
                                         
(1)  
Includes our senior unsecured notes, having maturity dates from 2012 to 2027, $458.5 million of loans outstanding under our revolving credit facility, having a maturity date of June 29, 2012, and our Subordinated Loans which mature initially on December 29, 2012. Amounts outstanding under the revolving credit facility are extendable by us for an additional year and the maturity date of the Subordinated Loans may be extended by a year if we elect to extend the term of the revolving credit facility. We have reflected the $225.0 million of Gulf South notes due August 2012 (Gulf South 2012 Notes) as due in less than one year. The Gulf South 2012 Notes are included in long-term debt on our balance sheet, because we expect to refinance these notes on a long-term basis and we 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 0.52% weighted-average interest rate on amounts outstanding under our revolving credit facility as of December 31, 2011, $1.2 million would be due under the credit facility in less than one year.

 
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(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, 2011.

(4)  
The amounts shown are associated with various pipeline capacity agreements on third-party pipelines that allow our operating subsidiaries to transport gas to off-system markets on behalf of our customers.

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 2012, we expect to fund approximately $9.0 million to the Texas Gas pension plan.

Distributions

For the twelve months ended December 31, 2011, 2010 and 2009, we paid distributions of $419.9 million, $398.1 million and $360.6 million to our partners. Note 10 in Item 8 of this report contains further discussion regarding our distributions.

Changes in cash flow from operating activities

Net cash provided by operating activities decreased $11.3 million to $453.4 million for the year ended December 31, 2011, compared to $464.7 million for the comparable 2010 period, primarily due to a decrease in net income, excluding the non-cash materials and supplies impairment charge.

Changes in cash flow from investing activities

Net cash used in investing activities decreased $24.6 million to $171.8 million for the year ended December 31, 2011, compared to $196.4 million for the comparable 2010 period. The decrease was driven by an $85.6 million decrease in capital expenditures primarily related to compression projects which were completed in 2010. The decrease was partly offset by uses of cash which included $71.2 million of contributions related to our interest in HP Storage.

Changes in cash flow from financing activities

Net cash used in financing activities increased $65.6 million to $324.7 million for the year ended December 31, 2011, compared to $259.1 million for the comparable 2010 period. The increase in cash used in financing activities resulted from net repayments of $207.4 million of long-term debt, including net repayments under our revolving credit facility, a $21.0 million premium paid on the early extinguishment of long-term debt and a $21.8 million increase in distributions to our partners. The increase in the use of cash was partly offset by a $173.6 million increase in proceeds from the issuance and sale of equity, including related general partner contributions, and $10.7 million of payments made under our registration rights agreement in 2010.

Impact of Inflation

The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant and equipment and materials and supplies 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.

 
34

 
Off-Balance Sheet Arrangements

At December 31, 2011, 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 Policies

           Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities in our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with third parties and other methods we consider reasonable. Nevertheless, actual results may differ significantly from our 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.

Regulation

Our subsidiaries are regulated by FERC. Pursuant to FERC regulations certain revenues that we collect may be subject to possible refunds to our customers. Accordingly, during an open rate case, estimates of rate refund reserves are recorded based on regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. At December 31, 2011 and 2010, there were no liabilities for any open rate case recorded on our Consolidated Balance Sheets. Currently, neither Gulf South nor Texas Gas is involved in an open general rate case; however Gulf Crossing filed a cost and revenue study to justify its initial firm transportation rates in January 2012. The outcome of this filing is not expected to have a material impact on our business, financial condition, results of operations or cash flows.

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 Gulf Crossing due to discounts under negotiated rate agreements, or Gulf South because competition in the market areas of Gulf South has resulted in discounts from the maximum allowable cost-based rates being granted to customers and certain services provided by Gulf South are priced using market-based rates.

We monitor the regulatory and competitive environment in which we operate to determine that any regulatory assets continue to be probable of recovery. If we were to determine that all or a portion of our regulatory assets no longer met the criteria for recognition as regulatory assets, that portion which was not recoverable would be written off, net of any regulatory liabilities. Note 6 in Item 8 of this Report contains more information regarding our regulatory assets and liabilities.
 
In the course of providing transportation and storage services to customers, the pipelines may receive different quantities of gas from shippers and operators than the quantities delivered by the pipelines on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are primarily settled in cash or the receipt or delivery of gas in the future. Settlement of imbalances requires agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. The receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage for operations where regulatory accounting is applicable, consistent with the regulatory treatment.

 
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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.

Our financial statements and certain disclosures include fair value measurements. Notes 4, 5, 8, 9 and 12 contain more information regarding our fair value measurements.

Environmental Liabilities

Our environmental liabilities are based on management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of our operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these environmental matters. At December 31, 2011, we had accrued approximately $8.8 million for environmental matters. Our environmental accrued liabilities could change substantially in the future due to factors such as the nature and extent of any contamination, changes in remedial requirements, technological changes, discovery of new information, and the involvement of and direction taken by the EPA, FERC and other governmental authorities on these matters. We continue to conduct environmental assessments and are implementing a variety of remedial measures that may result in increases or decreases in the total estimated environmental costs. Note 3 in Item 8 of this Report contains more information regarding our environmental liabilities.

Impairment of Long-Lived Assets

We periodically evaluate whether the carrying amount of long-lived assets has been impaired when circumstances indicate the carrying amount of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections expected to be realized over the remaining useful life of the asset. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount is not recoverable, the impairment loss is measured as the excess of the asset’s carrying amount over its fair value. Note 4 in Item 8 of this Report contains more information regarding impairments we have recognized.

Goodwill

 In September 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-08 (ASU 2011-08), which amended the rules for testing goodwill for impairment. Under the new rules, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. In accordance with new GAAP requirements, beginning in 2011, we have elected to perform a qualitative assessment on an annual basis to determine whether events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If indications are that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is performed to measure whether the fair value of the reporting unit is less than its carrying amount. If the fair value is less than the carrying amount an additional step is taken to measure the amount of goodwill impairment, if any.

As of December 31, 2011, we assessed qualitative factors to determine whether it was more likely than not that the fair value of the reporting unit associated with our goodwill was less than its carrying amount. We concluded that more likely than not the fair value of the reporting unit associated with our goodwill was not less than its carrying amount. Accordingly, the quantitative goodwill impairment analysis was not performed and no impairment of goodwill was recorded during 2011. No impairment of goodwill was recorded during 2010 or 2009. Our qualitative included an analysis of factors requiring estimates and judgments. The use of alternate judgments and/or assumptions could substantially change the results of the assessment, requiring a quantitative test to be performed and potentially result in the recognition of an impairment charge in our financial statements.

 
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Defined Benefit Plans

We are required to make a significant number of assumptions in order to estimate the liabilities and costs related to our pension and postretirement benefit obligations to employees under our benefit plans. The assumptions that have the most impact on 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 Moody’s Aa Corporate Bond Index is consistently used as the basis for the change in discount rate from the last measurement date with this measure confirmed by the yield on other broad bond indices. Additionally, we supplement our discount rate decision with a yield curve analysis. The yield curve is applied to expected future retirement plan payments to adjust the discount rate to reflect the cash flow characteristics of the plans. The yield curve is developed by the plans’ actuaries and is a hypothetical AA/Aa yield curve represented by a series of annualized discount rates reflecting bond issues having a rating of Aa or better by Moody’s Investors Service, Inc. or a rating of AA or better by Standard & Poor’s. Note 9 in Item 8 of this Report contains more information regarding our pension and postretirement benefit obligations.

Forward-Looking Statements

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

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:

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

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

·  
the impact of changes to laws and regulations, such as the proposed greenhouse gas legislation and the re-authorization by Congress of the Pipeline and Hazardous Materials Safety Administration, the recently enacted pipeline safety bill, and regulatory changes that result from that legislation applicable to interstate pipelines, on our business, including our costs, liabilities and revenues;

 
37

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

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

·  
the expansion into new product lines and geographic areas;

·  
volatility or disruptions in the capital or financial markets;

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

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

·  
the future cost of insuring our assets;

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

·  
the consummation of contemplated transactions and agreements; and

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


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

 
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Interest rate risk:

With the exception of our revolving credit facility, for which the interest rate is 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, including our Subordinated Loans, at December 31 (in millions, except interest rates):
 
   
2011
   
2010
 
Carrying value of fixed-rate debt
  $ 2,740.2     $ 2,548.8  
Fair value of fixed-rate debt
  $ 2,985.1     $ 2,717.0  
100 basis point increase in interest rates and resulting debt decrease
  $ 135.6     $ 126.0  
100 basis point decrease in interest rates and resulting debt increase
  $ 148.8     $ 126.5  
Weighted-average interest rate, including Subordinated Loan
    5.78 %     5.97 %

At December 31, 2011, we had $458.5 million outstanding under our revolving credit facility at a weighted-average interest rate of 0.52% which rate is reset periodically. A 1% increase in interest rates would increase our cash payments for interest on the credit facility by $4.6 million on an annualized basis. At December 31, 2010, we had $703.5 million outstanding under our revolving credit facility at a weighted-average interest rate of 0.53%.

A significant portion of our debt, including our revolving credit facility, will mature over the next five years.  We expect to refinance the debt either prior to or at maturity. Our ability to refinance the debt at interest rates that are currently available is subject to risk at the magnitude illustrated in the table. We expect to refinance the remainder of our debt that will mature based on our assessment of the term rates of interest available in the market.

At December 31, 2011 and 2010, $11.9 million and $55.0 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 which they transport and store in rendering firm and interruptible transportation and storage services, therefore they do not assume the related natural gas commodity price risk associated with that gas. However, certain volumes of our gas stored underground are available for sale and subject to commodity price risk. At December 31, 2011 and 2010, approximately $1.7 million and $3.6 million of gas stored underground, which we own and carry as current Gas stored underground, was available for sale and exposed to commodity price risk. Additionally, at December 31, 2010, we had 4.5 Bcf of gas with a book value of $10.3 million that had become available for sale as a result of a change in the storage working gas needed to support operations and no-notice services at our Texas Gas subsidiary. We often utilize derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas, however, at December 31, 2011, we had no outstanding derivatives. Subsequent to December 31, 2011, we hedged approximately 1.9 Bcf of anticipated future sales of natural gas and cash for fuel reimbursement. The derivatives qualify for cash flow hedge accounting and are designated as such.




 
39

 

Market risk:

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

We compete with numerous interstate and intrastate pipelines. Our ability to market available transportation capacity is impacted by supply and demand for natural gas, competition from other pipelines, natural gas price volatility, the price differential between physical locations on our pipeline systems (basis spreads), economic conditions and other factors. Over the past several years, new sources of natural gas have been identified throughout the U.S. and new pipeline infrastructure has been developed which has led to changes in pricing dynamics between supply basins, pooling points and market areas and an overall weakening of basis spreads across our pipeline systems.

The narrowing of basis spreads on our pipeline systems has made it more difficult to renew expiring long-term firm transportation contracts at previously contracted rates because, as basis spreads decrease, the rates customers are willing to pay decrease. In addition, as rates decline customers typically seek longer-term agreements while we generally seek shorter terms. Changing basis spreads do not have as significant or immediate impacts on long-term firm agreements as they do on short-term or interruptible services because long-term agreements are also influenced by other factors, such as baseload supply needs, certainty of delivery, predictability of long-term costs, the ability to manage those costs through the capacity release mechanism and the terms of service. The changes in the pricing dynamics and weakening of basis spreads have contributed to decreases in our operating profitability, especially with regard to short-term and interruptible services. However, in 2011, revenues from power customers increased and we continue to see additional interest from this customer group, especially as power producers increase their reliance on natural gas. 

Credit risk:

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

As of December 31, 2011, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 8.3 trillion British thermal units (TBtu). Assuming an average market price during December 2011 of $3.14 per million British thermal units (MMBtu), the market value of that gas was approximately $26.1 million. As of December 31, 2010, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 13.0 TBtu. Assuming an average market price during December 2010 of $4.21 per MMBtu, the market value of this gas at December 31, 2010, would have been approximately $54.7 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 pipeline tariffs contain language that allow us to require a customer that does not meet certain credit criteria to provide cash collateral, post a letter of credit or provide a guarantee from a credit-worthy entity in an amount equaling up to three months of capacity reservation charges. For certain agreements, we have included contractual provisions that require additional credit support should the credit ratings of those customers fall below investment grade.

 
40

 



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, 2011 and 2010, and the related consolidated statements of income, changes in partners’ capital, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Boardwalk Pipeline Partners, LP and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2012, expressed an unqualified opinion on the Partnership's internal control over financial reporting.




/s/ Deloitte & Touche LLP
Houston, Texas
February 21, 2012

 
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 BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED BALANCE SHEETS
(Millions)


   
December 31,
 
ASSETS
 
2011
   
2010
 
Current Assets:
           
Cash and cash equivalents
  $ 11.9     $ 55.0  
   Receivables:
               
Trade, net
    98.0       101.0  
Affiliate
    0.3       -  
Other
    20.2       5.2  
   Gas transportation receivables
    5.8       12.2  
Costs recoverable from customers
    9.8       11.3  
Gas stored underground
    1.7       3.6  
Prepayments
    13.3       11.4  
Other current assets
    1.8       3.5  
Total current assets
    162.8       203.2  
                 
Property, Plant and Equipment:
               
  Natural gas transmission and other plant
    7,049.7       6,933.9  
  Construction work in progress
    110.4       109.9  
      Property, plant and equipment, gross
    7,160.1       7,043.8  
  Less—accumulated depreciation and amortization
    997.1       785.8  
Property, plant and equipment, net
    6,163.0       6,258.0  
                 
Other Assets:
               
Goodwill
    163.5       163.5  
Gas stored underground
    107.5       125.8  
Costs recoverable from customers
    15.3       15.7  
Investment in unconsolidated affiliate
    70.1       -  
Other
    88.4       111.8  
Total other assets
    444.8       416.8  
                 
Total Assets
  $ 6,770.6     $ 6,878.0  



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

 
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BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED BALANCE SHEETS
(Millions)

   
December 31,
 
LIABILITIES AND PARTNERS’ CAPITAL
 
2011
   
2010
 
Current Liabilities:
           
Payables:
           
Trade
  $ 42.8     $ 48.8  
Affiliates
    3.2       3.2  
Other
    6.3       10.1  
Gas Payables:
               
      Transportation
    5.0       20.5  
      Storage
    0.1       4.2  
Accrued taxes, other
    40.6       40.4  
Accrued interest
    45.2       40.5  
Accrued payroll and employee benefits
    18.4       17.0  
Construction retainage
    3.5       8.3  
Deferred income
    9.4       6.3  
Other current liabilities
    17.5       14.5  
Total current liabilities
    192.0       213.8  
                 
Long–term debt
    3,098.7       3,152.3  
Long–term debt – affiliate
    100.0       100.0  
Total long-term debt
    3,198.7       3,252.3  
                 
Other Liabilities and Deferred Credits:
               
Pension liability
    27.3       27.0  
Asset retirement obligation
    16.7       17.2  
Provision for other asset retirement
    54.5       51.7  
Payable to affiliate
    16.0       16.0  
Other
    60.2       58.6  
Total other liabilities and deferred credits
    174.7       170.5  
                 
Commitments and Contingencies
               
                 
Partners’ Capital:
               
Common units – 175.7 million and 169.7 million units issued and outstanding as of  December 31, 2011, and December 31, 2010
    2,513.8       2,534.4  
Class B units – 22.9 million units issued and outstanding as of December 31, 2011, and December 31, 2010
    678.7       683.6  
General partner
    62.1       62.9  
Accumulated other comprehensive loss
    (49.4 )     (39.5 )
Total partners’ capital
    3,205.2       3,241.4  
Total Liabilities and Partners’ Capital
  $ 6,770.6     $ 6,878.0  


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

 
43

 

BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME
(Millions, except per unit amounts)

   
For the Year Ended December 31,
 
   
2011
   
2010
   
2009
 
Operating Revenues:
                 
Gas transportation
  $ 1,065.5     $ 1,015.4     $ 794.9  
Parking and lending
    12.0       28.1       34.9  
Gas storage
    49.9       55.4       57.6  
Other
    11.4       17.9       21.8  
Total operating revenues
    1,138.8       1,116.8       909.2  
                         
Operating Costs and Expenses:
                       
Fuel and gas transportation
    102.7       109.4       61.9  
Operation and maintenance
    168.5       149.6       142.2  
Administrative and general
    132.7       126.6       122.0  
Depreciation and amortization
    225.2       217.9       203.1  
Asset impairment
    30.5       5.8       -  
Net (gain) loss on disposal of operating assets
    (2.4 )     (16.6 )     8.2  
Taxes other than income taxes
    88.9       84.2       77.3  
Total operating costs and expenses
    746.1       676.9       614.7  
 
                       
Operating income
    392.7       439.9       294.5  
                         
Other Deductions (Income):
                       
Interest expense
    151.3       142.9       125.3  
Interest expense – affiliates
    8.0       8.1       6.8  
Loss on early retirement of debt
    13.2       -       -  
Interest income
    (0.4 )     (0.6 )     (0.2 )
Equity losses from unconsolidated affiliate
    1.1       -       -  
Miscellaneous other income, net
    (0.9 )     (0.4 )     (0.4 )
Total other deductions
    172.3       150.0       131.5  
                         
Income before income taxes
    220.4       289.9       163.0  
                         
Income taxes
    0.4       0.5       0.3  
                         
Net Income
  $ 220.0     $ 289.4     $ 162.7  
                         
Net Income per Unit:
                       
                         
Basic and diluted net income per unit:
                       
   Common units
  $ 1.09     $ 1.47     $ 0.88  
   Class B units
  $ 0.14     $ 0.62     $ 0.08  
Cash distribution declared and paid to common units
  $ 2.095     $ 2.03     $ 1.95  
Cash distribution declared and paid to class B units
  $ 1.20     $ 1.20     $ 1.20  
Weighted-average number of units outstanding:
                       
   Common units
    173.3       169.7       161.6  
   Class B units
    22.9       22.9       22.9  



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

 
44

 

BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions)

   
For the Year Ended December 31,
 
   
2011
   
2010
   
2009
 
Net income
  $ 220.0     $ 289.4     $ 162.7  
Other comprehensive income (loss):
                       
Gain on cash flow hedges
    3.1       6.0       10.5  
Reclassification adjustment transferred to Net income from cash flow hedges
    0.2       (13.0 )     (16.5 )
Pension and other postretirement benefit costs
    (13.2 )     (7.1 )     (3.9 )
Total Comprehensive Income
  $ 210.1     $ 275.3     $ 152.8  


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


 
45

 

BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
   
For the Year Ended December 31,
 
OPERATING ACTIVITIES:
 
2011
   
2010
   
2009
 
Net income
  $ 220.0     $ 289.4     $ 162.7  
Adjustments to reconcile to cash provided by operations:
                       
Depreciation and amortization
    225.2       217.9       203.1  
Amortization of deferred costs
    9.3       8.1       9.4  
Asset impairment
    30.5       5.8       -  
Loss on debt extinguishment
    13.2       -       -  
Storage gas loss
    3.7       -       -  
Net (gain) loss on disposal of operating assets
    (2.4 )     (16.6 )     8.2  
Equity losses in unconsolidated affiliate
    1.1       -       -  
Changes in operating assets and liabilities:
                       
Trade and other receivables
    (12.9 )     (9.7 )     (23.4 )
Other receivables, affiliates
    (0.3 )     -       -  
Gas receivables and storage assets
    16.3       (10.5 )     (5.0 )
Costs recoverable from customers
    (2.6 )     (5.4 )     (1.6 )
Other assets
    (31.3 )     23.1       (18.0 )
Trade and other payables
    (5.1 )     (27.4 )     25.9  
Other payables, affiliates
    -       0.7       0.7  
Gas payables
    (17.4 )     10.0       2.4  
Accrued liabilities
    6.9       0.9       4.3  
Other liabilities
    (0.8 )     (21.6 )     31.8  
Net cash provided by operating activities
    453.4       464.7       400.5  
INVESTING ACTIVITIES:
                       
Capital expenditures
    (141.7 )     (227.3 )     (846.8 )
Proceeds from sale of operating assets
    31.5       30.9       -  
Proceeds from insurance and other recoveries
    9.6       -       -  
Sales of short-term investments
    -       -       175.0  
Investment in unconsolidated affiliate
    (71.2 )     -       -  
Net cash used in investing activities
    (171.8 )     (196.4 )     (671.8 )
FINANCING ACTIVITIES:
                       
Proceeds from long-term debt, net of issuance costs
    437.6       -       346.7  
Repayment of borrowings from long-term debt
    (250.0 )     -       -  
Payments of premiums on extinguishment of long-term debt
    (21.0 )        -       -  
Proceeds from borrowings on revolving credit agreement
    585.0       175.0       411.5  
Repayment of borrowings on revolving credit agreement
    (830.0 )     (25.0 )     (650.0 )
Payments on note payable
    -       (0.3 )     (1.3 )
Proceeds from long-term debt – affiliate
    -       -       200.0  
Repayment of long-term debt – affiliate
    -       -       (100.0 )
Payments associated with registration rights agreement
    -       (10.7 )     -  
Distributions paid
    (419.9 )     (398.1 )     (360.6 )
Proceeds from sale of common units
    170.0       -       326.3  
Capital contribution from general partner
    3.6       -       6.8  
Net cash (used in) provided by financing activities
    (324.7 )     (259.1 )     179.4  
(Decrease) increase in cash and cash equivalents
    (43.1 )     9.2       (91.9 )
Cash and cash equivalents at beginning of period
    55.0       45.8       137.7  
Cash and cash equivalents at end of period
  $ 11.9     $ 55.0     $ 45.8  
The accompanying notes are an integral part of these consolidated financial statements.

 
46

 

BOARDWALK PIPELINE PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN
PARTNERS’ CAPITAL
(Millions)

   
Common
Units
   
Class B
Units
   
General
Partner
   
Accumulated Other Comp Income (Loss)
   
Total Partners’ Capital
 
Balance January 1, 2009
  $ 2,504.8     $ 692.8     $ 62.9     $ (15.5 )   $ 3,245.0  
Add (deduct):
                                       
Net income
    128.2       18.2       16.3       -       162.7  
    Distributions paid
    (312.7 )     (27.4 )     (20.5 )     -       (360.6 )
Sale of common units, net of
   related transaction costs
    320.2       -       -       -       320.2  
Capital contribution from general partner
    -       -       6.8       -       6.8  
Other comprehensive loss, net of tax
    -       -       -       (9.9 )     (9.9 )
Balance December 31, 2009
  $ 2,640.5     $ 683.6     $ 65.5     $ (25.4 )   $ 3,364.2  
Add (deduct):
                                       
Net income
    238.4       27.4       23.6       -       289.4  
Distributions paid
    (344.5 )     (27.4 )     (26.2 )     -       (398.1 )
Other comprehensive loss, net of tax
    -       -       -       (14.1 )     (14.1 )
Balance December 31, 2010
  $ 2,534.4     $ 683.6     $ 62.9     $ (39.5 )   $ 3,241.4  
Add (deduct):
                                       
Net income
    171.1       22.6       26.3       -       220.0  
Distributions paid
    (361.7 )     (27.5 )     (30.7 )     -       (419.9 )
Sale of common units, net of related transaction costs
    170.0       -       -       -       170.0  
Capital contribution from general partner
    -       -       3.6       -       3.6  
        Other comprehensive loss, net of tax
    -       -       -       (9.9 )     (9.9 )
Balance December 31, 2011
  $ 2,513.8     $ 678.7     $ 62.1     $ (49.4 )   $ 3,205.2  



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



 
47

 


BOARDWALK PIPELINE PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 1:  Corporate Structure

Boardwalk Pipeline Partners, LP (the Partnership) is a Delaware limited partnership formed in 2005 to own and operate the business conducted by its primary subsidiary Boardwalk Pipelines, LP (Boardwalk Pipelines), and its subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, the operating subsidiaries), which consist of integrated natural gas pipeline and storage systems. In 2011, the Partnership formed Boardwalk Midstream, LP (Midstream), and its operating subsidiary, Boardwalk Field Services, LLC (Field Services), which is engaged in the natural gas gathering and processing business. As of December 31, 2011, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned 102.7 million of the Partnership’s common units, all 22.9 million of the Partnership’s class B units and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the incentive distribution rights (IDRs). As of February 21, 2012, the common units, class B units and general partner interest owned by BPHC represent approximately 61% of the Partnership’s equity interests, excluding the IDRs. The Partnership’s common units are traded under the symbol “BWP” on the New York Stock Exchange.

Basis of Presentation

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


Note 2:  Accounting Policies

Principles of Consolidation

The consolidated financial statements include the Partnership’s accounts and those of its wholly-owned subsidiaries after elimination of intercompany transactions. The Partnership applies the equity method of accounting for investments in unconsolidated affiliates in which the Partnership owns 20 percent to 50 percent of the voting interests or otherwise exercises significant influence, but not control, over operating and financial policies of the investee. Under this method, the carrying amounts of the Partnership’s equity investments are increased by a proportionate share of the investee’s net income and contributions made, and decreased by a proportionate share of the investee’s net losses and distributions received.

Use of Estimates

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

 
48

 
Segment Information

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

Regulatory Accounting

The operating subsidiaries are regulated by the Federal Energy Regulatory Commission (FERC). When certain criteria are met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates (regulatory accounting). This basis of accounting is applicable to operations of the Partnership’s Texas Gas subsidiary which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refund to customers in future periods, but is not applicable to operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate agreements and a portion of the storage capacity due to the regulatory treatment associated with the rates charged for that capacity. Regulatory accounting is not applicable to the Partnership’s Gulf Crossing subsidiary due to discounts under negotiated rate agreements, or Gulf South because competition in its market area has resulted in discounts from the maximum allowable cost-based rates being granted to customers and certain services provided by Gulf South are priced using market-based rates.

The Partnership monitors the regulatory and competitive environment in which it operates to determine that its regulatory assets continue to be probable of recovery. If the Partnership were to determine that all or a portion of its regulatory assets no longer met the criteria for recognition as regulatory assets, that portion which was not recoverable would be written off, net of any regulatory liabilities. Note 6 contains more information regarding the Partnership’s regulatory assets and liabilities.

Cash and Cash Equivalents

Cash equivalents are highly liquid investments with an original maturity of three months or less and are stated at cost plus accrued interest, which approximates fair value. The Partnership had no restricted cash at December 31, 2011 and 2010.

Cash Management

The operating subsidiaries participate in an intercompany cash management program to the extent they are permitted under FERC regulations. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, Boardwalk Pipelines either provides cash to them or they provide cash to Boardwalk Pipelines. The transactions are represented by demand notes and are stated at historical carrying amounts. Interest income and expense is recognized on an accrual basis when collection is reasonably assured. The interest rate on intercompany demand notes is London Interbank Offered Rate (LIBOR) plus one percent and is adjusted every three months.

Trade and Other Receivables

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

 
49

 

Gas Stored Underground and Gas Receivables and Payables

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

Gulf South and Texas Gas provide storage services whereby they store gas on behalf of customers and also periodically hold customer gas under PAL services. Since the customers retain title to the gas held by the Partnership in providing these services, the Partnership does not record the related gas on its balance sheet. The Partnership held for storage or under PAL agreements approximately 104.1 trillion British thermal units (TBtu) of gas owned by third parties as of December 31, 2011. Assuming an average market price during December 2011 of $3.14 per million British thermal units (MMBtu), the market value of gas held on behalf of others was approximately $326.9 million. As of December 31, 2010, the Partnership held for storage or under PAL agreements approximately 82.9 TBtu of gas owned by third parties. Gulf South and Texas Gas also periodically lend gas to customers under PAL services.

In the course of providing transportation and storage services to customers, the operating subsidiaries may receive different quantities of gas from shippers and operators than the quantities delivered on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are settled in cash or the receipt or delivery of gas in the future. Settlement of imbalances requires agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.  The receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage for operations where regulatory accounting is applicable.

Materials and Supplies

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

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

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

            Depreciation of PPE related to operations for which regulatory accounting does not apply is provided for using the straight-line method of depreciation over the estimated useful lives of the assets, which range from 3 to 35 years. The ordinary sale or retirement of PPE for these assets could result in a gain or loss. Depreciation of PPE related to operations for which regulatory accounting is applicable is provided for primarily on the straight-line method at FERC-prescribed rates over estimated useful lives of 5 to 62 years. Reflecting the application of composite depreciation, gains and losses from the ordinary sale or retirement of PPE for these assets are not recognized in earnings and generally do not impact PPE, net. Note 4 contains more information regarding the Partnership’s PPE.

Impairment of Long-lived Assets

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

 
50

 
Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)

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

 
For the Year Ended
December 31,
 
 
2011
 
2010
 
2009
 
Capitalized interest and allowance for borrowed funds used during construction
  $ 2.0     $ 4.2     $ 10.3  
Allowance for equity funds used during construction
    0.6       0.4       0.4  

Income Taxes

The Partnership is not a taxable entity for federal income tax purposes.  As such, it does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated Statements of Income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes related to the Partnership. The subsidiaries of the Partnership directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income. Note 11 contains more information regarding the Partnership’s income taxes.

Revenue Recognition

The maximum rates that may be charged by the operating subsidiaries for their services are established through FERC’s cost-based rate-making process, however rates charged by the operating subsidiaries may be less than those allowed by FERC. Revenues from the transportation and storage of gas are recognized in the period the service is provided based on contractual terms and the related volumes transported or stored. In connection with some PAL and interruptible storage service agreements, cash is received at inception of the service period resulting in the recording of deferred revenues which are recognized in revenues over the period the services are provided. At December 31, 2011 and 2010, the Partnership had deferred revenues of $8.4 million and $5.6 million related to PAL and interruptible storage services and $6.5 million and $7.4 million related to a firm transportation agreement that was paid in advance. The deferred revenues related to PAL and interruptible storage services will be recognized in 2012 and 2013 and the deferred revenues related to the firm transportation agreement will be recognized through 2018.

Retained fuel is recognized in revenues at market prices in the month of retention for operations where regulatory accounting is not applicable. The related fuel consumed in providing transportation services is recorded in Fuel and gas transportation expenses at market prices in the month consumed. Customers may elect to pay cash for the cost of fuel used in providing transportation services instead of having fuel retained in-kind. Retained fuel included in Gas transportation on the Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009 was $105.6 million, $114.2 million and $77.5 million.

 
51

 
Under FERC regulations, certain revenues that the operating subsidiaries collect may be subject to possible refunds to their customers. Accordingly, during a rate case, estimates of rate refund liabilities are recorded considering regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. At December 31, 2011 and 2010, there were no liabilities for any open rate case recorded on the Consolidated Balance Sheets.

Asset Retirement Obligations

The accounting requirements for existing legal obligations associated with the future retirement of long-lived assets require entities to record the fair value of a liability for an asset retirement obligation in the period during which the liability is incurred. The liability is initially recognized at fair value and is increased with the passage of time as accretion expense is recorded, until the liability is ultimately settled. An amount corresponding to the amount of the initial liability is capitalized as part of the carrying amount of the related long-lived asset and depreciated over the useful life of that asset. Note 5 contains more information regarding the Partnership’s asset retirement obligations.

Unit-Based and Other Long-Term Compensation

 The Partnership provides awards of phantom common units (Phantom Common Units) to certain employees under its Long-Term Incentive Plan (LTIP). The Partnership also provides to certain employees awards of unit appreciation rights (UARs) and long-term cash bonuses (Long-Term Cash Bonuses) under the Boardwalk Pipeline Partners Unit Appreciation Rights and Cash Bonus Plan, which was established in 2010. Prior to 2010, awards of phantom general partner units (Phantom GP units) were made under the Partnership’s Strategic Long-Term Incentive Plan (SLTIP).

The Partnership measures the cost of an award issued in exchange for employee services based on the grant-date fair value of the award, or the stated amount in the case of the Long-Term Cash Bonuses. All outstanding awards are either required or expected to be settled in cash and are classified as a liability until settlement. The unit-based compensation awards are remeasured each reporting period until the final amount of awards is determined. The related compensation expense, less applicable estimates of forfeitures, is recognized over the period that employees are required to provide services in exchange for the awards, usually the vesting period. Note 9 contains additional information regarding the Partnership’s unit-based and other long-term compensation.

Partner Capital Accounts

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

Derivative Financial Instruments

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

The changes in fair values of the derivatives designated as cash flow hedges are expected to, and do, have a high correlation to changes in value of the anticipated transactions. Each reporting period the Partnership measures the effectiveness of the cash flow hedge contracts. To the extent the changes in the fair values of the hedge contracts do not effectively offset the changes in the estimated cash flows of the anticipated transactions, the ineffective portion of the hedge contracts is currently recognized in earnings. If it becomes probable that the anticipated transactions will not occur, hedge accounting would be terminated and changes in the fair values of the associated derivative financial instruments would be recognized currently in earnings. The Partnership did not discontinue any cash flow hedges during the years ended December 31, 2011 and 2010.

 
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The effective component of gains and losses resulting from changes in fair values of the derivatives designated as cash flow hedges are deferred as a component of AOCI. The deferred gains and losses associated with the anticipated operational sale of gas reported as current Gas stored underground are recognized in operating revenues when the anticipated transactions affect earnings. In situations where continued reporting of a loss in AOCI would result in recognition of a future loss on the combination of the derivative and the hedged transaction, the loss is required to be immediately recognized in earnings for the amount that is not expected to be recovered. No such losses were recognized in the years ended December 31, 2011 and 2010. The Partnership had no outstanding derivatives at December 31, 2011. Note 8 contains more information regarding the Partnership’s derivative financial instruments.

Fair Value Measurements

Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances.

The Partnership’s financial statements and certain disclosures include fair value measurements. Notes 4, 5, 8, 9 and 12 contain more information regarding the Partnership’s fair value measurements.

Goodwill

In September 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-08 (ASU 2011-08), which amended the rules for testing goodwill for impairment. Under the new rules, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. In accordance with new GAAP requirements, beginning in 2011, the Partnership first performs a qualitative assessment to determine whether events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If indications are that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the Partnership performs a quantitative analysis to measure whether the fair value of the reporting unit is less than its carrying amount. If the fair value is less than the carrying amount an additional step is taken to measure the amount of goodwill impairment, if any. The Partnership also performs a quantitative assessment, other than annually on December 31, whenever events or changes in circumstances indicate that more likely than not the fair value of a reporting unit is less than its carrying amount.

As of December 31, 2011, the Partnership assessed qualitative factors to determine whether it was more likely than not that the fair value of the reporting unit associated with the Partnership’s goodwill was less than its carrying amount. The qualitative factors considered included a comparison of key drivers of the fair value of the reporting unit, such as the Partnership’s five-year financial plan operating results, the long-term outlook for growth in natural gas demand in the United States, industry and market considerations, macroeconomic conditions and specific events related to the reporting unit. The Partnership concluded that more likely than not the fair value of the reporting unit associated with the Partnership’s goodwill was not less than its carrying amount. Accordingly, the quantitative goodwill impairment analysis was not performed and no impairment of goodwill was recorded during 2011.

Prior to 2011, the Partnership performed an annual quantitative review of goodwill for impairment on December 31, and whenever events or changes in circumstances indicated that carrying amount of goodwill may not be recoverable. No impairment of goodwill was recorded during 2010 or 2009.

 
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Note 3: Commitments and Contingencies

Legal Proceedings and Settlements

The Partnership's subsidiaries are parties to various legal actions arising in the normal course of business. Management believes the disposition of these outstanding legal actions will not have a material impact on the Partnership's financial condition, results of operations or cash flows.

 
Environmental and Safety Matters

The operating subsidiaries are subject to federal, state, and local environmental laws and regulations in connection with the operation and remediation of various operating sites. As of December 31, 2011, and 2010, the Partnership had an accrued liability of approximately $8.8 million and $11.2 million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury, groundwater protection measures and other costs. The liability represents management’s estimate of the undiscounted future obligations based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these matters. The related expenditures are expected to occur over the next nine years. As of December 31, 2011, and 2010, approximately $2.2 million and $3.6 million were recorded in Other current liabilities and approximately $6.6 million and $7.6 million were recorded in Other Liabilities and Deferred Credits.

Clean Air Act

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

In 2008, the EPA adopted regulations lowering the 8-hour ozone standard relevant to non-attainment areas. Under the regulations, new non-attainment areas were to be identified which may have required additional emission controls for compliance at as many as 12 facilities operated by the operating subsidiaries. The EPA subsequently proposed to lower the 8-hour ozone standard again in 2011, but instead withdrew the proposed revision and presently intends to proceed with non-attainment area designations according to the 2008 standard. The EPA expects to finalize the initial non-attainment area designations by mid-2012. The 8-hour ozone standard is due for review in 2013.  The EPA has stated that any necessary revisions to the standard will be proposed in the fall of 2013, with final rulemaking in 2014. These revisions could lower the 8-hour ozone standard set in 2008 with a compliance deadline between 2014 and 2031. The Partnership continues to monitor this regulation relative to potentially impacted facilities and associated costs for compliance.  

In 2011, the Partnership filed reports with the EPA regarding greenhouse gas emissions from its compressor stations, pursuant to final rules issued by the EPA regarding the reporting of greenhouse gas emissions from sources in the U.S. that annually emit 25,000 or more metric tons of greenhouse gases, including carbon dioxide, methane and others. Additionally, the Partnership conducted various facility surveys across its entire system to comply with the EPA’s greenhouse gas emission calculations and reporting regulations and will continue to do so annually as required by the rule. Some states have also adopted laws regulating greenhouse gas emissions, although none of the states in which the Partnership operates have adopted such laws. The new federal rules and determinations regarding greenhouse gas emissions have not had, and are not expected to have, a material effect on the Partnership’s financial condition, results of operations or cash flows.
 
 
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In 2010, the EPA adopted regulations requiring further emission controls for air toxics, specifically formaldehyde, from certain compression engines utilizing MACT. The Partnership estimates that certain of its compression engines will require the installation of certain emission controls by late 2013. The Partnership does not believe the regulation will have a material effect on its financial condition, results of operations or cash flows.
 
Lease Commitments

The Partnership has various operating lease commitments extending through the year 2018 generally covering office space and equipment rentals. Total lease expense for the years ended December 31, 2011, 2010 and 2009 were approximately $4.5 million, $4.0 million and $4.8 million. The following table summarizes minimum future commitments related to these items at December 31, 2011 (in millions):

2012
  $ 4.4  
2013
    4.1  
2014
    3.4  
2015
    3.2  
2016
    3.1  
Thereafter
    1.0  
Total
  $ 19.2  

Commitments for Construction

The Partnership’s future capital commitments are comprised of binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements. The commitments as of December 31, 2011, were approximately $16.7 million, all of which are expected to be settled in 2012.

Pipeline Capacity Agreements

The Partnership’s operating subsidiaries have entered into pipeline capacity agreements with third-party pipelines that allow the subsidiaries to transport gas to off-system markets on behalf of customers. The Partnership incurred expenses of $9.8 million, $11.1 million and $10.8 million related to pipeline capacity agreements for the years ended December 31, 2011, 2010 and 2009. The future commitments related to pipeline capacity agreements as of December 31, 2011 were (in millions):

2012
  $ 9.0  
2013
    8.7  
2014
    8.3  
2015
    7.7  
2016
    6.7  
Thereafter
    8.1  
Total
  $ 48.5  

 
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Note 4: Property, Plant and Equipment (PPE)

The following table presents the Partnership’s PPE as of December 31, 2011 and 2010 (in millions):

Category
 
2011 Class
Amount
   
Weighted-Average
Useful Lives
(Years)
   
2010 Class
Amount
   
Weighted-Average
Useful Lives
 (Years)
 
Depreciable plant:
                       
Transmission
  $ 6,365.7       38     $ 6,282.2       37  
Storage
    275.8       45       250.4       46  
Gathering
    90.0       19       88.5       19  
General
    126.4       18       121.2       18  
Rights of way and other
    112.7       31       110.0       30  
Total utility depreciable plant
    6,970.6       37       6,852.3       37