Item 1. Business
Unless the context otherwise requires, references in this Report to “we,” “our,” “us” or like terms refer to the business of Boardwalk Pipeline Partners, LP and its consolidated subsidiaries.
Introduction
We are a Delaware limited partnership formed in 2005. Our business is conducted by our primary subsidiary, Boardwalk Pipelines, LP (Boardwalk Pipelines) and its operating subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South), Texas Gas Transmission, LLC (Texas Gas), Boardwalk Field Services, LLC (Field Services), Petal Gas Storage, LLC (formerly referred to as Boardwalk HP Storage, LLC) (Petal), Boardwalk Louisiana Midstream, LLC (Louisiana Midstream) and Boardwalk Storage Company, LLC (Boardwalk Storage) (together, the operating subsidiaries), and consists of integrated natural gas and natural gas liquids (NGLs) pipeline and storage systems and natural gas gathering and processing. All of our operations are conducted by our operating subsidiaries. Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns 125.6 million of our common units and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, our 2% general partner interest and all of our incentive distribution rights (IDRs). As of February 24, 2014, the common units and general partner interest owned by BPHC represent approximately 53% of our equity interests, excluding the IDRs. Our Partnership Interests, in Item 5 contains more information on how we calculate BPHC’s equity ownership. Our common units are traded under the symbol “BWP” on the New York Stock Exchange (NYSE).
The following diagram reflects a simplified version of our organizational structure as of December 31, 2013:
Our Business
We are a master limited partnership operating in the midstream portion of the natural gas and NGLs industry, providing transportation, storage, gathering and processing services for those commodities. We own approximately 14,450 miles of natural gas and NGLs pipelines, and underground storage caverns having aggregate capacity of approximately 207.0 billion cubic feet (Bcf) of working natural gas and 17.6 million barrels (MMbbls) of NGLs. Our pipeline systems originate in the Gulf Coast region, Oklahoma and Arkansas and extend north and east to the midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio.
We serve a broad mix of customers, including producers of natural gas, local distribution companies (LDCs), marketers, electric power generators, industrial users and interstate and intrastate pipelines. We provide a significant portion of our natural gas pipeline transportation and storage services through firm contracts under which our customers pay monthly capacity reservation fees which are fees owed regardless of actual pipeline or storage capacity utilization. Other fees are based on actual utilization of the capacity under firm contracts and contracts for interruptible services. Contracts for our services related to NGLs are generally fee based and are dependent on actual volumes transported or stored, although in some cases minimum volume requirements apply. For the year ended December 31, 2013, approximately 81% of our revenues were derived from capacity reservation fees under firm contracts, approximately 12% of our revenues were derived from fees based on utilization under firm contracts and approximately 7% of our revenues were derived from interruptible transportation, interruptible storage, parking and lending (PAL) and other services. Item 6 of this Report contains a summary of our revenues from external customers, net income and total assets, all of which were attributable to our pipeline and storage systems operating in one reportable segment.
The majority of our natural gas transportation and storage rates and general terms and conditions of service are established by, and subject to review and revision by, the Federal Energy Regulatory Commission (FERC). These rates are based upon certain assumptions to allow us the opportunity to recover the cost of providing these services and earn a reasonable return on equity. However, it is possible that we may not recover all of our costs or earn a return. We are authorized to charge market-based rates for the majority of our natural gas storage capacity pursuant to authority granted by FERC.
Our Pipeline and Storage Systems
We own and operate approximately 14,195 miles of interconnected natural gas pipelines directly serving customers in thirteen states and indirectly serving customers throughout the northeastern and southeastern United States (U.S.) through numerous interconnections with unaffiliated pipelines. We also own and operate more than 255 miles of NGLs pipelines in Louisiana. In 2013, our pipeline systems transported approximately 2.4 trillion cubic feet (Tcf) of natural gas and approximately 7.5 MMbbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2013 was approximately 6.6 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of approximately 207.0 Bcf, and our NGLs storage facilities consist of eight salt-dome caverns located in Louisiana with an aggregate storage capacity of approximately 17.6 MMbbls. We also own two salt-dome caverns for use in providing brine supply services and to support the NGLs storage operations.
The principal sources of supply for our natural gas pipeline systems are regional supply hubs and market centers located in the Gulf Coast region, including offshore Louisiana, the Perryville, Louisiana area, the Henry Hub in Louisiana and the Carthage, Texas area. Our pipelines in the Carthage, Texas area provide access to natural gas supplies from the Bossier Sands, Barnett Shale, Haynesville Shale and other natural gas producing regions in eastern Texas and northern Louisiana. The Henry Hub serves as the designated delivery point for natural gas futures contracts traded on the New York Mercantile Exchange. Our pipeline systems also have access to unconventional supplies such as the Woodford Shale in southeastern Oklahoma, the Fayetteville Shale in Arkansas, the Eagle Ford Shale in southern Texas and wellhead supplies in northern and southern Louisiana and Mississippi and, with the recent development of the Marcellus and Utica shales, we also receive gas in the Lebanon, Ohio area. We access the Gulf Coast petrochemical industry through our operations at our Choctaw Hub in the Mississippi River corridor area of Louisiana and the Sulphur Hub in the Lake Charles, Louisiana area.
The following is a summary of each of our principal operating subsidiaries:
Gulf Crossing: Our Gulf Crossing pipeline system originates near Sherman, Texas, and proceeds to the Perryville, Louisiana area. The market areas are in the Midwest, Northeast, Southeast and Florida through interconnections with Gulf South, Texas Gas and unaffiliated pipelines.
Gulf South: Our Gulf South pipeline system is located along the Gulf Coast in the states of Texas, Louisiana, Mississippi, Alabama and Florida. The on-system markets directly served by the Gulf South system are generally located in eastern Texas, Louisiana, southern Mississippi, southern Alabama and the Florida Panhandle. These markets include LDCs and municipalities
located across the system, including New Orleans, Louisiana; Jackson, Mississippi; Mobile, Alabama; and Pensacola, Florida, and other end-users located across the system, including the Baton Rouge to New Orleans industrial corridor and Lake Charles, Louisiana. Gulf South also has indirect access to off-system markets through numerous interconnections with unaffiliated interstate and intrastate pipelines and storage facilities. These pipeline interconnections provide access to markets throughout the northeastern and southeastern U.S.
Gulf South has two natural gas storage facilities. The natural gas storage facility located in Bistineau, Louisiana, has approximately 78.0 Bcf of working gas storage capacity from which Gulf South offers firm and interruptible storage service, including no-notice service. Gulf South’s Jackson, Mississippi, natural gas storage facility has approximately 5.0 Bcf of working gas storage capacity, which is used for operational purposes and is not offered for sale to the market.
Texas Gas: Our Texas Gas pipeline system originates in Louisiana, East Texas and Arkansas and runs north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana, and into Ohio, with smaller diameter lines extending into Illinois. Texas Gas directly serves LDCs, municipalities and power generators in its market area, which encompasses eight states in the South and Midwest and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati and Dayton, Ohio; and Evansville and Indianapolis, Indiana metropolitan areas. Texas Gas also has indirect market access to the Northeast through interconnections with unaffiliated pipelines. A large portion of the gas delivered by the Texas Gas system is used for heating during the winter months.
Texas Gas owns nine natural gas storage fields, of which it owns the majority of the working and base gas. Texas Gas uses this gas to meet the operational requirements of its transportation and storage customers and the requirements of its no-notice service customers. Texas Gas also uses its storage capacity to offer firm and interruptible storage services.
Field Services: Field Services operates natural gas gathering, compression, treating and processing infrastructure primarily in south Texas.
Petal: Petal owns and operates eight high deliverability salt dome natural gas storage caverns in Forrest County, Mississippi, having approximately 46.0 Bcf of total storage capacity, of which approximately 29.0 Bcf is working gas capacity. Petal also operates approximately 100 miles of pipeline which connects its facilities with several major natural gas pipelines and owns undeveloped land which is suitable for up to five additional storage caverns.
Louisiana Midstream: Louisiana Midstream provides transportation and storage services for natural gas and NGLs, fractionation services for NGLs, and brine supply services for producers and consumers of petrochemicals through two hubs in southern Louisiana - the Choctaw Hub in the Mississippi River Corridor area and the Sulphur Hub in the Lake Charles area. These assets provide approximately 57.8 MMbbls of salt dome storage capacity, including approximately 11.0 Bcf of working natural gas storage capacity; significant brine supply infrastructure; and approximately 270 miles of pipeline assets, including an extensive ethylene distribution system.
The following table provides information for our pipeline and storage systems as of December 31, 2013:
(1)
Louisiana Midstream also has approximately 17.6 MMbbls of salt-dome NGLs storage capacity in addition to the working gas storage capacity. Louisiana Midstream has two salt-dome caverns for use in providing brine supply services.
Current Growth Projects and Investments
Southeast Market Expansion: Our Southeast Market Expansion project consists of constructing an interconnection between Gulf South and Petal, adding additional compression facilities to our system and constructing approximately 70 miles of 24-inch and 30-inch pipeline in southeastern Mississippi. The project will add approximately 0.5 Bcf per day of peak-day transmission capacity to our Gulf South system from multiple locations in Texas and Louisiana to Mississippi, Alabama and Florida and is fully contracted with a weighted-average contract life of approximately 10 years. The project, which was approved by the FERC, is expected to cost approximately $300.0 million and to be placed in service in the fourth quarter 2014.
Ohio to Louisiana Access Project: Our Ohio to Louisiana Access Project would provide long-term firm natural gas transportation from the Marcellus and Utica production areas to Louisiana. This project does not add additional capacity to our natural gas pipeline systems, but will reverse the traditional flow of natural gas from northbound to southbound on a portion of
our Texas Gas system. The project is supported by firm transportation contracts for 0.6 Bcf of capacity per day with producers and end-users, with a weighted-average contract life of approximately 13 years. The project is expected to cost approximately $115.0 million and is expected to be placed into service in the first half 2016, subject to FERC approval.
Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects: In 2013, we executed an agreement with the Williams Companies, Inc. (Williams) to develop the Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects - projects that would transport NGLs from the Marcellus and Utica shale plays to the petrochemical and export complex in the Lake Charles, Louisiana area, and the construction of related fractionation, storage and liquefied petroleum gas (LPG) terminal export facilities.
The proposed project would include constructing a new pipeline that would initially provide producers with 200,000 barrels per day of mixed NGLs take-away capacity in Ohio, West Virginia and Pennsylvania to an interconnect with our Texas Gas pipeline in Hardinsburg, Kentucky. Capacity could be increased to 400,000 barrels per day to meet market demand, primarily by adding additional liquids pumping capacity. From the interconnect with Texas Gas to Eunice, La., a portion of the Texas Gas pipeline (Texas Gas Loop Line) would be converted from natural gas service to NGLs service. The proposed project would also include constructing a new large-scale fractionation plant, expanding natural gas liquids storage facilities in Louisiana, constructing a new pipeline connecting these facilities to the converted Texas Gas Loop Line and constructing a new export LPG terminal and related facilities on the Gulf Coast to provide customers access to international markets.
To effectuate the Bluegrass Project: (i) we entered into separate joint venture arrangements with Boardwalk Pipelines Holding Corp. (BPHC) to form Boardwalk Bluegrass Pipeline, LLC (Boardwalk Bluegrass) and Boardwalk Moss Lake, LLC (Boardwalk Moss Lake); and (ii) Boardwalk Bluegrass and Boardwalk Moss Lake, together with affiliates of Williams, formed Bluegrass Pipeline Company LLC (Bluegrass Pipeline), Moss Lake Fractionation LLC (Moss Lake Fractionation) and Moss Lake LPG Terminal LLC (Moss Lake LPG) to continue to pursue and, if approved, develop, own and construct the pipeline, fractionation and LPG terminal export facilities. Boardwalk Bluegrass currently owns 50% of the equity interests in Bluegrass Pipeline, and Boardwalk Moss Lake currently owns 50% of the equity interests in Moss Lake Fractionation and Moss Lake LPG, with affiliates of Williams owning the other 50%.
We have contributed a total of $11.9 million to the capital of Boardwalk Bluegrass and Boardwalk Moss Lake. BPHC has contributed the balance of the capital of these entities and anticipates contributing the additional capital required to fund certain agreed upon pre-construction development costs until such time as BPHC has a 90% equity ownership interest in each entity. Additional capital required for Boardwalk Bluegrass and Boardwalk Moss Lake to continue to pursue the Bluegrass Project is subject to approval by us and BPHC.
Through our agreement, we and Williams are engaged in comprehensive project development activities including project design, cost estimating, economic and risk analysis, permitting, other legal and regulatory approvals and right-of-way acquisition. We and Williams are also continuing ongoing discussions with potential customers regarding commitments for pipeline, fractionation, storage and export services to support this project.
Approval and completion of this project is subject to, among other conditions, execution of customer contracts sufficient to support the project, acquisition of right-of-way along the pipeline route, and the parties' receipt of all necessary approvals, including board approvals and regulatory approvals, such as antitrust clearance under the Hart-Scott-Rodino Antitrust Improvements Act and approvals by the FERC, among others. Before the Texas Gas Loop Line can be converted to NGLs service, Texas Gas must receive abandonment authority from FERC. The abandonment application was filed with FERC in May 2013 and we estimate the abandonment process will take at least twelve months. In addition, each of the parties has the right, under certain circumstances, to withdraw from the project or from portions of the project, in which case the project may be terminated, only portions of the project may be completed, or the parties respective ownership interests in the project may change. We cannot give
assurances that this project will be completed, in whole or in part. We and Williams are continuing to evaluate all aspects of the project, including the date we anticipate the project would be placed into service if it is completed.
Nature of Contracts
We contract with our customers to provide transportation and storage services on a firm and interruptible basis. We also provide bundled firm transportation and storage services, which we provide to our natural gas customers as no-notice services, and we provide interruptible PAL services for our natural gas customers. We provide brine supply services for certain petrochemical customers and fractionation services.
Transportation Services. We offer natural gas transportation services on both a firm and interruptible basis. Our natural gas customers choose, based upon their particular needs, the applicable mix of services depending upon availability of pipeline capacity, the price of services and the volume and timing of the customer’s requirements. Our natural gas firm transportation customers reserve a specific amount of pipeline capacity at specified receipt and delivery points on our system. Firm natural gas customers generally pay fees based on the quantity of capacity reserved regardless of use, plus a commodity and a fuel charge paid on the volume of natural gas actually transported. Capacity reservation revenues derived from a firm service contract are generally consistent during the contract term, but can be higher in winter periods than the rest of the year, especially for no-notice service agreements. Firm transportation contracts generally range in term from one to ten years, although we may enter into shorter or longer term contracts. In providing interruptible natural gas transportation service, we agree to transport natural gas for a customer when capacity is available. Interruptible natural gas transportation service customers pay a commodity charge only for the volume of gas actually transported, plus a fuel charge. Interruptible transportation agreements have terms ranging from day-to-day to multiple years, with rates that change on a daily, monthly or seasonal basis. Our NGLs transportation services are generally fee based and are dependent on actual volumes transported or stored, although in some cases minimum volume requirements apply.
Storage Services. We offer customers natural gas storage services on both a firm and interruptible basis. Firm storage customers reserve a specific amount of storage capacity, including injection and withdrawal rights, while interruptible customers receive storage capacity and injection and withdrawal rights when it is available. Similar to firm transportation customers, firm storage customers generally pay fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically range in term from one to ten years. Interruptible storage customers pay for the volume of gas actually stored plus injection and withdrawal fees. Generally, interruptible storage agreements are for monthly terms. We are able to charge market-based rates for the majority of our natural gas storage capacity pursuant to authority granted by FERC. Our NGLs storage rates are market-based rates and contracts are typically fixed-price arrangements with escalation clauses.
No-Notice Services. No-notice services consist of a combination of firm natural gas transportation and storage services that allow customers to withdraw natural gas from storage with little or no notice. Customers pay a reservation charge based upon the capacity reserved plus a commodity and a fuel charge based on the volume of gas actually transported. In accordance with its tariff, Texas Gas loans stored gas to certain of its no-notice customers who are obligated to repay the gas in-kind.
Parking and Lending Service. PAL is an interruptible service offered to customers providing them the ability to park (inject) or borrow (withdraw) natural gas into or out of our pipeline systems at a specific location for a specific period of time. Customers pay for PAL service in advance or on a monthly basis depending on the terms of the agreement.
Customers and Markets Served
We contract directly with producers of natural gas, and with end-use customers including LDCs, marketers, electric power generators, industrial users and interstate and intrastate pipelines who, in turn, provide transportation and storage services to end-users. Based on 2013 revenues, our customer mix was as follows: natural gas producers (52%), marketers (20%), LDCs (18%), power generators (7%) and industrial end users and others (3%). Based upon 2013 revenues, our deliveries were as follows: pipeline interconnects (60%), LDCs (18%), storage activities (12%), industrial end-users (5%), power generators (4%) and other (1%). One customer, Devon Gas Services, LP, accounted for approximately 11% of our 2013 operating revenues.
Natural Gas Producers. Producers of natural gas use our services to transport gas supplies from producing areas, primarily from the Gulf Coast and Mid Continent regions, including shale natural gas production areas in Texas, Louisiana, Oklahoma and Arkansas, to supply pools and to other customers on and off of our systems. Producers contract with us for storage services to store excess production and to optimize the ultimate sales prices for their gas.
Marketers. Natural gas marketing companies utilize our services to provide services to our other customer groups as well as to customer groups in off-system markets. The services may include combined gas transportation and storage services to support the needs of the other customer groups. Some of the marketers are sponsored by LDCs or producers.
LDCs. Most of our LDC customers use firm natural gas transportation services, including no-notice service. We serve approximately 180 LDCs at more than 300 delivery locations across our pipeline systems. The demand of these customers peaks during the winter heating season.
Power Generators. Our natural gas pipelines are directly connected to 40 natural-gas-fired power generation facilities in ten states. The demand of the power generating customers peaks during the summer cooling season which is counter to the winter season peak demands of the LDCs. Most of our power-generating customers use a combination of no-notice, firm and interruptible transportation services.
Industrial End Users. We provide approximately 195 industrial facilities with a combination of firm and interruptible natural gas and NGLs transportation and storage services. Our pipeline systems are directly connected to industrial facilities in the Baton Rouge to New Orleans industrial corridor; Lake Charles, Louisiana; Mobile, Alabama and Pensacola, Florida. We can also access the Houston Ship Channel through third-party natural gas pipelines.
Competition
We compete with numerous other pipelines that provide transportation storage and other services at many locations along our pipeline systems. We also compete with pipelines that are attached to new natural gas supply sources that are being developed closer to some of our traditional natural gas market areas. In addition, regulators’ continuing efforts to increase competition in the natural gas industry have increased the natural gas transportation options of our traditional customers. As a result of regulators’ policies, capacity segmentation and capacity release have created an active secondary market which increasingly competes with our own natural gas pipeline services. Further, natural gas competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative fuel sources.
The principal elements of competition among pipelines are available capacity, rates, terms of service, access to gas supplies, flexibility and reliability of service. In many cases, the elements of competition, in particular flexibility, terms of service and reliability, are key differentiating factors between competitors. This is especially the case with capacity being sold on a longer-term basis. We are focused on finding opportunities to enhance our competitive profile in these areas by increasing the flexibility of our pipeline systems to meet the demands of customers such as power generators and industrial users, and are continually reviewing our services and terms of service to offer customers enhanced service options.
Seasonality
Our revenues can be affected by weather, natural gas price levels, basis spreads and time period price spreads, and natural gas price volatility. Weather impacts natural gas demand for heating needs and power generation, which in turn influences the short-term value of transportation and storage across our pipeline systems. Colder than normal winters can result in an increase in the demand for natural gas for heating needs and warmer than normal summers can impact cooling needs, both of which typically result in increased pipeline transportation revenues and throughput. While traditionally peak demand for natural gas occurs during the winter months driven by heating needs, the increased use of natural gas for cooling needs during the summer months has partially reduced the seasonality of our revenues. During 2013, approximately 53% of our revenues were recognized in the first and fourth quarters of the year.
Government Regulation
Federal Energy Regulatory Commission. FERC regulates our natural gas operating subsidiaries under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. FERC regulates, among other things, the rates and charges for the transportation and storage of natural gas in interstate commerce and the extension, enlargement or abandonment of facilities under its jurisdiction. Where required, our interstate natural gas pipeline subsidiaries hold certificates of public convenience and necessity issued by FERC covering certain of their facilities, activities and services. FERC also prescribes accounting treatment for our interstate natural gas pipeline subsidiaries which is separately reported pursuant to forms filed with FERC. The regulatory books and records and other activities of our subsidiaries that operate under FERC's jurisdiction may be periodically audited by FERC.
The maximum rates that may be charged by our operating subsidiaries that operate under FERC's jurisdiction for all aspects of the natural gas transportation services they provide are established through FERC’s cost-of-service rate-making process.
The maximum rates that may be charged by us for storage services on Texas Gas, with the exception of services associated with a portion of the working gas capacity on that system, are also established through FERC’s cost-of-service rate-making process. Key determinants in FERC’s cost-of-service rate-making process are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. FERC has authorized us to charge market-based rates for firm and interruptible storage services for the majority of our storage facilities. None of our FERC-regulated entities has an obligation to file a new rate case.
U.S. Department of Transportation (DOT). We are regulated by DOT, through the Pipeline and Hazardous Materials Safety Administration (PHMSA), under the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979 (NGPSA), and the Hazardous Liquids Pipeline Safety Act of 1979 (HLPSA). The NGPSA and HLPSA regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas and NGLs pipeline facilities. We have received authority from PHMSA to operate certain natural gas pipeline assets under special permits that will allow us to operate those pipeline assets at higher than normal operating pressures of up to 0.80 of the pipe’s Specified Minimum Yield Strength (SMYS). Operating at higher than normal operating pressures will allow us to transport all of the volumes we have contracted for with our customers. PHMSA retains discretion whether to grant or maintain authority for us to operate our natural gas pipeline assets at higher pressures. PHMSA has also developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain high risk areas along our pipelines and take additional measures to protect pipeline segments located in highly populated areas. The NGPSA and HLPSA were most recently amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act) in 2012, with the 2011 Act requiring increased maximum civil penalties for certain violations to $200,000 per violation per day, and an increased total cap of $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in more stringent safety controls or additional natural gas and hazardous liquids pipeline safety rulemaking. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.
Other. Our operations are also subject to extensive federal, state, and local laws and regulations relating to protection of the environment. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases, discharges and emissions of various substances into the environment. Environmental regulations also require that our facilities, sites and other properties be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.The laws our operations are subject to include, for example:
•
the Clean Air Act and analogous state laws which impose obligations related to air emissions, including, in the case of the Clean Air Act, greenhouse gas emissions and regulations affecting reciprocating engines subject to Maximum Achievable Control Technology (MACT) standards;
•
the Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws which regulate discharge of wastewater from our facilities into state and federal waters;
•
the Comprehensive Environmental Response, Compensation and Liability Act, commonly referred to as CERCLA, or the Superfund law, and analogous state laws which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;
•
the Resource Conservation and Recovery Act, and analogous state laws which impose requirements for the handling and discharge of solid and hazardous waste from our facilities; and
•
the Occupational Safety and Health Act (OSHA) and analogous state laws, which establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of orders enjoining performance of some or all of our operations. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that the current regulatory standards will not become more onerous in the future, resulting in more significant costs to maintain compliance or increased exposure to significant liabilities, which could diminish our ability to make distributions to our unitholders.
Effects of Compliance with Environmental Regulations
Note 5 in Item 8 of this Report contains information regarding environmental compliance.
Employee Relations
At December 31, 2013, we had approximately 1,200 employees, approximately 110 of whom are included in collective bargaining units. A satisfactory relationship exists between management and labor. We maintain various defined contribution plans covering substantially all of our employees and various other plans which provide regular active employees with group life, hospital, and medical benefits, as well as disability benefits. We also have a non-contributory, defined benefit pension plan and a postretirement medical plan which covers Texas Gas employees hired prior to certain dates. Note 12 in Item 8 of this Report contains further information regarding our employee benefits.
Available Information
Our website is located at www.bwpmlp.com. We make available free of charge through our website our annual reports on Form 10-K, which include our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as we electronically file such material with the Securities and Exchange Commission (SEC). These documents are also available at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549 or at the SEC's website at www.sec.gov. You can obtain additional information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Additionally, copies of these documents, excluding exhibits, may be requested at no cost by contacting Investor Relations, Boardwalk Pipeline Partners, LP, 9 Greenway Plaza, Suite 2800, Houston, TX 77046.
We also make available within the “Governance” section of our website our corporate governance guidelines, the charter of our Audit Committee and our Code of Business Conduct and Ethics. Requests for copies may be directed in writing to: Boardwalk Pipeline Partners, LP, 9 Greenway Plaza, Suite 2800, Houston, TX 77046, Attention: Corporate Secretary.
Interested parties may contact the chairpersons of any of our Board committees, our Board’s independent directors as a group or our full Board in writing by mail to Boardwalk Pipeline Partners, LP, 9 Greenway Plaza, Suite 2800, Houston, TX 77046, Attention: Corporate Secretary. All such communications will be delivered to the director or directors to whom they are addressed.
Item 1A.
Item 1A. Risk Factors
Our business faces many risks. We have described below the material risks which we and our subsidiaries face. Each of the risks and uncertainties described below could lead to events or circumstances that may have a material adverse effect on our business, financial condition, results of operations or cash flows, including our ability to make distributions to our unitholders.
All of the information included in this report and any subsequent reports we may file with the SEC or make available to the public should be carefully considered and evaluated before investing in any securities issued by us.
Business Risks
We may not have sufficient available cash to continue making distributions to unitholders at the current distribution rate, or at all.
The amount of cash we have available to distribute to our unitholders principally depends upon the amount of cash we generate from our operations and financing activities and the amount of cash we require, or determine to use, for other purposes, all of which fluctuate from quarter to quarter based on a number of factors, many of which are beyond our control. Some of the factors that influence the amount of cash we have available for distribution in any quarter include:
•
fluctuations in cash generated by our operations, including, as a result of the seasonality of our business, customer payment issues, general business conditions and market conditions, which impact, for example, contract renewals, basis spreads, time period price spreads, market rates and supply and demand for natural gas and our services;
•
the level of capital expenditures we make or anticipate making, including for expansion and growth projects;
•
the amount of cash necessary to meet current or anticipated debt service requirements and other liabilities;
•
fluctuations in our working capital needs;
•
our ability to borrow funds and/or access capital markets on acceptable terms to fund operations or capital expenditures, including acquisitions, and restrictions contained in our debt agreements; and
•
the cost and form of payment for pending or anticipated acquisitions and growth or expansion projects and the timing and commercial success of any such initiatives.
There is no guarantee that unitholders will receive quarterly distributions from us. Our distributions are determined each quarter by the board of directors of our general partner based on the board’s consideration of our financial position, earnings, cash flow, current and future business needs and other relevant factors at that time. In February 2014, we declared a quarterly distribution of $0.10 per unit, which was less than the quarterly distributions of $0.5325 per unit that we declared and paid in recent prior periods. We may reduce or eliminate distributions at any time we determine that our cash reserves are insufficient or are otherwise required to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment or other business needs.
We may not be able to replace expiring gas transportation and storage contracts at attractive rates or on a long-term basis and may not be able to sell short-term services at attractive rates or at all due to narrower basis differentials which adversely affect the value of our transportation services and narrowing of price spreads between time periods and reduced volatility which adversely affect our storage services.
New sources of natural gas continue to be identified and developed in the U.S., including the Marcellus and Utica shale plays which are closer to the traditional high value markets we serve than the supply basins connected to our facilities. As a result, pipeline infrastructure has been, and continues to be, developed to move gas and NGLs from these supply basins to market areas, resulting in changes in pricing dynamics between supply basins, pooling points and market areas. Additionally, these new supplies of natural gas have reduced production or slowed production growth from supply areas connected to our pipelines and have caused some of the gas production that is supplied to our system to be diverted to other market areas. These factors have adversely affected, and are expected to continue to adversely affect, the value of our transportation and storage services and have lowered the volumes we have transported on our pipelines, as further discussed below.
Transportation Services:
A key market driver that influences the rates and terms of our transportation contracts is the current and anticipated basis differentials - generally meaning the difference in the price of natural gas at receipt and delivery points on our natural gas pipelines - which influence how much customers are willing to pay to transport gas between those points. Basis differentials can be affected by, among other things, the availability and supply of natural gas, the proximity of supply areas to end use markets, competition from other pipelines, including pipelines under development, available transportation and storage capacity, storage inventories, regulatory developments, weather and general market demand in markets served by our pipeline systems. As a result of the new sources of supply and related pipeline infrastructure discussed above, basis differentials on our pipeline systems have narrowed significantly in recent years, reducing the transportation rates and other contract terms we can negotiate with our customers for available transportation capacity and for contracts due for renewal for our firm transportation services. The narrowing of basis differentials has also adversely affected the rates we are able to charge for our interruptible and short-term firm transportation services.
Each year, a portion of our firm natural gas transportation contracts expire and need to be renewed or replaced. For the reasons discussed above and elsewhere in this Report, in recent periods we have renewed many expiring contracts at lower rates and for shorter terms than in the past, which has materially adversely impacted our transportation revenues. We expect this trend to continue and therefore may not be able to sell our available capacity, extend expiring contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts, which would continue to adversely affect our business.
In 2008 and 2009, we placed into service a number of large new pipelines and expansions of our system, including our East Texas Pipeline, Southeast Expansion, Gulf Crossing Pipeline, and Fayetteville and Greenville Laterals. These projects were supported by firm transportation agreements with anchor shippers, typically having a term of ten years and pricing and other terms negotiated based on then current market conditions, which included wider basis spreads and, correspondingly, higher transportation rates than those prevailing in the current market. As a result, in 2018 and 2019, we will have significantly more contract expirations than other years. We cannot predict what market conditions will prevail at the time such contracts expire and what pricing and other terms may be available in the marketplace for renewal or replacement of such contracts. If we are unable to renew or replace these and other expiring contracts when they expire, or if the terms of any such renewal or replacement contracts are not as favorable as the expiring agreements, our revenues and cash flows could be materially adversely affected.
Storage and PAL Services:
We own and operate substantial natural gas storage facilities. The market for the storage and PAL services that we offer is also impacted by the factors discussed above, as well as natural gas price differentials between time periods, such as winter to summer (time period price spreads), and the volatility in time period price spreads. Recently, the market conditions described above have caused time period price spreads to narrow considerably and price volatility of natural gas to decline significantly, reducing the rates we can charge for our storage and PAL services and adversely impacting the value of these services. These market conditions, together with regulatory changes in the financial services industry, have also caused a number of gas marketers, which have traditionally been large consumers of our storage and PAL services, to exit the market, further impacting the market for those services.
We expect the conditions described above to continue in 2014 and cannot give assurances they will not continue beyond 2014. These market factors and conditions adversely impact our revenues, earnings before interest, taxes, depreciation and amortization (EBITDA) and distributable cash flow and could impact us on a long-term basis.
We may not be successful in executing our strategy to grow and diversify our business.
We rely primarily on the revenues generated from our long-haul natural gas transportation and storage services. As a result, negative developments in these services have significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets. We are pursuing a strategy of growing and diversifying our business through acquisition and development of assets in complementary areas of the midstream energy sector, such as liquids transportation and storage assets, among others. We may not be successful in acquiring or developing such assets or may do so on terms that ultimately are not profitable.
In pursuing our growth and diversification strategy, we have been pursuing development (together with a joint venture partner) of a large capital project, which we call our Bluegrass Project, consisting of a pipeline that would deliver NGLs from the Marcellus and Utica shale production areas of Pennsylvania, Ohio and West Virginia to end use markets in the Gulf Coast area, and constructing new fractionation, liquids storage and export facilities located in the Gulf Coast region. We continue to have
ongoing discussions with potential customers regarding commitments that would support constructing this project and have not made any external commitments to proceed with the project. We may incur substantial costs in developing this or other projects or otherwise pursuing growth and diversification opportunities; however, we can give no assurance that any such project will be completed, in whole or in part, or, if completed, that any such project or acquisition will be on attractive terms or generate a positive return for us.
Changes in the prices of natural gas and NGLs impacts supply of and demand for those commodities, which impact our business.
The prices of natural gas and NGLs fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors, including:
•
worldwide economic conditions;
•
weather conditions, seasonal trends and hurricane disruptions;
•
the relationship between the available supplies and the demand for natural gas and NGLs;
•
new supply sources;
•
the availability of adequate transportation capacity;
•
storage inventory levels;
•
the price and availability of oil and other forms of energy;
•
the effect of energy conservation measures;
•
the nature and extent of, and changes in, governmental regulation, new regulations adopted by the Environmental Protection Agency (EPA), for example, greenhouse gas legislation and taxation; and
•
the anticipated future prices of natural gas, oil and other commodities.
It is difficult to predict future changes in natural gas and NGLs prices. However, the economic environment that has existed over the last several years generally indicates a bias toward continued downward pressure on natural gas prices. Sustained low natural gas prices could negatively impact producers, including those directly connected to our pipelines that have contracted for capacity with us which could adversely impact our revenues, EBITDA and distributable cash flow.
Conversely, future increases in the price of natural gas could make alternative energy sources more competitive and reduce demand for natural gas. A reduced level of demand for natural gas could reduce the utilization of capacity on our systems, reduce the demand for our services and could result in the non-renewal of contracted capacity as contracts expire and affect our midstream businesses.
Our revolving credit facility contains operating and financial covenants that restrict our business and financing activities.
Our revolving credit facility contains operating and financial covenants that may restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our credit agreement limits our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate or engage in asset sales, or grant liens or make negative pledges. The agreement also requires us to maintain a ratio of consolidated debt to consolidated EBITDA (as defined in the agreement) of no more than five to one, which limits the amount of additional indebtedness we can incur, including to grow our business, and could require us to prepay indebtedness if our EBITDA decreases to a level that would cause us to breach this covenant. Future financing agreements we may enter into may contain similar or more restrictive covenants or may not be as favorable as those under our existing indebtedness.
Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions or our financial performance deteriorate further, our ability to comply with these covenants may be impaired. If we are not able to incur additional indebtedness we may need to sell additional equity securities to raise needed capital, which would be dilutive to our existing equity holders, or to seek other sources of funding that may be on terms that materially adversely affect our financial condition or our ability to pay future distributions. If we default under our credit agreement or another financing agreement, significant additional restrictions may become applicable, including a restriction on our ability to make distributions to unitholders. In addition, a default could result in a significant portion of our indebtedness becoming immediately due and payable, and our lenders could terminate their commitment to make further loans to us. In such event, we would not have, and may not be able to obtain, sufficient funds to make these accelerated payments.
A significant portion of our debt will mature over the next five years and will need to be paid or refinanced.
A significant portion of our debt is set to mature in the next five years, including our revolving credit facility. We may not be able to refinance our maturing debt upon commercially reasonable terms, or at all, depending on numerous factors, including our financial condition and prospects at the time and the then current state of the bank and capital markets in the U.S. Further, our liquidity may be adversely affected if we are unable to replace our revolving credit facility upon acceptable terms when it matures.
In addition, most of our debt is rated by independent credit rating agencies. Our borrowing costs can be affected by ratings assigned by the rating agencies. In February 2014, two of the major rating agencies that rate our indebtedness lowered our credit ratings, citing the challenges to our business discussed above. These ratings decreases, and any further decrease in our credit ratings, could increase our cost of borrowing and make it more difficult to refinance our debt.
Limited access to the debt and equity markets could adversely affect our business.
Changes in the debt and equity markets, including market disruptions, limited liquidity, and interest rate volatility, may increase the cost of financing as well as the risks of refinancing maturing debt. Instability in the financial markets may increase our cost of capital while reducing the availability of funds. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations or growth projects. Reduced access to the debt and equity markets could limit our ability to grow our business through acquisitions and growth projects. If the debt and equity markets were not available, it is not certain if other adequate financing options would be available to us on terms and conditions that are acceptable.
We have historically relied on our cash flow from operations, borrowings under our revolving credit facility and proceeds from debt and equity offerings to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. Any disruption could require us to take additional measures to conserve cash until the markets stabilize or until we can arrange alternative credit arrangements or other funding for our business needs. Such measures could include reducing or delaying business activities, reducing our operations to lower expenses, and reducing other discretionary uses of cash. We may be unable to execute our growth strategy or take advantage of business opportunities, any of which could negatively impact our business.
Changes in the pipeline safety laws and regulations requiring substantial changes to existing integrity management programs or safety technologies could subject us to increased capital and operating costs and require us to use more comprehensive and stringent safety controls.
Our pipelines are subject to regulation by PHMSA of the DOT under the NGPSA with respect to natural gas and the HLPSA with respect to NGLs, both as amended. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and NGLs pipeline facilities. These amendments have resulted in the adoption of rules through PHMSA, that require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas, such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. These regulations have resulted in an overall increase in our maintenance costs. Due to recent highly publicized incidents on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. We could incur significant additional costs if new or more stringent pipeline safety requirements are implemented.
The 2011 Act was enacted and signed into law in early 2012. Under the 2011 Act, maximum civil penalties for certain violations have been increased to $200,000 per violation per day, and from a total cap of $1.0 million to $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in additional natural gas and hazardous liquids pipeline safety rulemaking in 2014 or soon thereafter. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs.
Further, we have entered into firm transportation contracts with shippers which utilize the design capacity of certain of our pipeline assets, assuming that we operate those pipeline assets at higher than normal operating pressures (up to 0.80 of the pipeline's SMYS). We have authority from PHMSA to operate those pipeline assets at such higher pressures, however PHMSA retains discretion to withdraw or modify this authority. If PHMSA were to withdraw or materially modify such authority, we may not be able to transport all of our contracted quantities of natural gas on our pipeline assets and could incur significant additional costs to re-obtain such authority or to develop alternate ways to meet our contractual obligations.
Our natural gas transportation and storage operations are subject to extensive regulation by FERC, including rules and regulations related to the rates we can charge for our services and our ability to construct or abandon facilities. FERC's rate-making policies could limit our ability to recover the full cost of operating our pipelines, including earning a reasonable return.
Our natural gas transportation and storage operations are subject to extensive regulation by FERC, including the types and terms of services we may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities, recordkeeping and relationships with affiliated companies. FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to FERC's regulations. FERC can also deny us the right to remove certain facilities from service.
FERC also regulates the rates we can charge for our natural gas transportation and storage operations. For our cost-based services, FERC establishes both the maximum and minimum rates we can charge. The basic elements that FERC considers are the costs of providing service, the volumes of gas being transported, the rate design, the allocation of costs between services, the capital structure and the rate of return a pipeline is permitted to earn. We may not be able to recover all of our costs, including certain costs associated with pipeline integrity, through existing or future rates.
FERC can challenge the existing rates on any of our pipelines. Such a challenge against us could adversely affect our ability to charge rates that would cover future increases in our costs or even to continue to collect rates to maintain our current revenue levels that are designed to permit a reasonable opportunity to recover current costs and depreciation and earn a reasonable return.
If any of our pipelines under FERC jurisdiction were to file a rate case, or if they have to defend their rates in a proceeding commenced by FERC, we would be required, among other things, to establish that the inclusion of an income tax allowance in our cost of service is just and reasonable. Under current FERC policy, since we are a limited partnership and do not pay U.S. federal income taxes, this would require us to show that our unitholders (or their ultimate owners) are subject to federal income taxation. To support such a showing, our general partner may elect to require owners of our units to re-certify their status as being subject to U.S. federal income taxation on the income generated by us or we may attempt to provide other evidence. We can provide no assurance that the evidence we might provide to FERC will be sufficient to establish that our unitholders (or their ultimate owners) are subject to U.S. federal income tax liability on the income generated by our jurisdictional pipelines. If we are unable to make such a showing, FERC could disallow a substantial portion of the income tax allowance included in the determination of the maximum rates that may be charged by our pipelines, which could result in a reduction of such maximum rates from current levels.
Investments that we make, whether through acquisitions, growth projects or joint ventures, that appear to be accretive may nevertheless reduce our distributable cash flows.
Our future growth depends on our ability to grow and diversify our business by among other things, investing in assets through acquisitions or joint ventures and organic growth projects. Our ability to grow, diversify and increase distributable cash flows will depend, in part, on our ability to close and execute on accretive acquisitions and projects. Any such transaction involves potential risks that may include, among other things:
•
the diversion of management's and employees' attention from other business concerns;
•
inaccurate assumptions about volume, revenues and project costs, including potential synergies;
•
a decrease in our liquidity as a result of our using available cash or borrowing capacity to finance the acquisition or project;
•
a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition or project;
•
inaccurate assumptions about the overall costs of equity or debt;
•
an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets or the developed assets;
•
unforeseen difficulties operating in new product areas or new geographic areas; and
•
changes in regulatory requirements or delays of regulatory approvals.
Additionally, acquisitions contain the following risks:
•
an inability to integrate successfully the businesses we acquire;
•
the assumption of unknown liabilities for which we are not indemnified, for which our indemnity is inadequate or for which our insurance policies may exclude from coverage;
•
limitations on rights to indemnity from the seller; and
•
customer or key employee losses of an acquired business.
There is no certainty that we will be able to complete these acquisitions or projects on schedule, on budget or at all.
Our business requires the retention and recruitment of a skilled workforce and the loss of such workforce could result in the failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. We compete with other companies for this skilled workforce. In addition, many of our current employees are approaching retirement age and have significant institutional knowledge that must be transferred to other employees. If we are unable to (a) retain our current employees, (b) successfully complete the knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.
A failure in our computer systems or a cyber security attack on any of our facilities, or those of third parties, may affect adversely our ability to operate our business.
We have become more reliant on technology to help increase efficiency in our businesses. Our businesses are dependent upon our operational and financial computer systems to process the data necessary to conduct almost all aspects of our business, including the operation of our pipeline and storage facilities and the recording and reporting of commercial and financial transactions. Any failure of our computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our business.
It has been reported that unknown entities or groups have mounted so-called “cyber attacks” on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. Any cyber attacks that affect our facilities, or those of our customers, suppliers or others with whom we do business could have a material adverse effect on our business, cause us a financial loss and/or damage our reputation.
We are exposed to credit risk relating to nonperformance by our customers.
Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Our exposure generally relates to receivables for services provided, future performance under firm agreements and volumes of gas or other products owed by customers for imbalances or product loaned by us to them under certain of our services. For our FERC-regulated business, our tariffs only allow us to require limited credit support in the event that our transportation customers are unable to pay for our services. If any of our significant customers have credit or financial problems which result in a delay or failure to pay for services provided by us or contracted for with us, or to repay the product they owe us, it could have a material adverse effect on our business. In addition, as contracts expire, the credit or financial failure of any of our customers could also result in the non-renewal of contracted capacity, which could have a material adverse effect on our business. Item 7A of this Report contains more information on credit risk arising from products loaned to customers.
We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues.
We rely on a limited number of customers for a significant portion of revenues. Our largest customer in terms of revenue, Devon Gas Services, LP, represented over 11% of our 2013 revenues. Our top ten customers comprised approximately 46% of our revenues in 2013. We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms which could materially reduce our contracted transportation volumes and the rates we can charge for our services.
Failure to comply with existing or new environmental laws or regulations or an accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.
Our operations are subject to extensive federal, regional, state and local laws and regulations relating to protection of the environment. These laws include, for example, the Clean Air Act (CAA), the Clean Water Act, CERCLA, the Resource Conservation and Recovery Act, Occupational Safety and Health Administration and analogous state laws. These laws and regulations may restrict or impact our business activities in many ways, including requiring the acquisition of permits or other approvals to conduct regulated activities, restricting the manner in which we dispose of wastes, requiring remedial action to remove or mitigate contamination resulting from a spill or other release, requiring capital expenditures to comply with pollution control requirements, and imposing substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating and capital costs and reduced demand for our pipeline and storage services.
The U.S. Congress and the EPA as well as some states and regional groupings of states have in recent years considered legislation or regulations to reduce emissions of greenhouse gases (GHG). These efforts have included cap-and-trade programs, carbon taxes and GHG reporting and tracking programs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. In addition, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets and operations.
We compete with other energy companies.
The principal elements of competition among pipeline systems are availability of capacity, rates, terms of service, access to supplies, flexibility and reliability of service. Additionally, FERC's policies promote competition in natural gas markets by increasing the number of natural gas transportation options available to our customer base. Increased competition could reduce the volumes of product we transport or store or, in instances where we do not have long-term contracts with fixed rates, could cause us to decrease the transportation or storage rates we can charge our customers. Competition could intensify the negative impact of factors that adversely affect the demand for our services, such as adverse economic conditions, weather, higher fuel costs and taxes or other regulatory actions that increase the cost, or limit the use, of products we transport and store.
Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are a variety of operating risks inherent in our transportation and storage operations such as leaks and other forms of releases, explosions, fires and mechanical problems. Additionally, the nature and location of our business may make us susceptible to catastrophic losses from hurricanes or other named storms, particularly with regard to our assets in the Gulf Coast region, windstorms, earthquakes, hail, and severe winter weather. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from some of these risks.
We currently possess property, business interruption and general liability insurance, but proceeds from such insurance coverage may not be adequate for all liabilities or expenses incurred or revenues lost. Moreover, such insurance may not be available in the future at commercially reasonable costs and terms. The insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or all potential losses.
Possible terrorist activities or military actions could adversely affect our business.
The continued threat of terrorism and the impact of retaliatory military and other action by the U.S. and its allies might lead to increased political, economic and financial market instability and volatility in prices for natural gas, which could affect the markets for our natural gas transportation and storage services. While we are taking steps that we believe are appropriate to increase the security of our assets, we may not be able to completely secure our assets or completely protect them against a terrorist attack.
Partnership Structure Risks
Our general partner and its affiliates own a controlling interest in us, have conflicts of interest and owe us only limited fiduciary duties, which may permit them to favor their own interests.
BPHC, a wholly-owned subsidiary of Loews, owns approximately 53% of our equity interests, excluding the IDRs, and owns and controls our general partner, which controls us. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to BPHC. Furthermore, certain directors and officers of our general partner are also directors or officers of affiliates of our general partner. Conflicts of interest may arise between BPHC and its subsidiaries, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These potential conflicts include, among others, the following situations:
•
BPHC and its affiliates may engage in competition with us;
•
neither our partnership agreement nor any other agreement requires BPHC or its affiliates (other than our general partner) to pursue a business strategy that favors us. Directors and officers of BPHC and its affiliates have a fiduciary duty to make decisions in the best interest of BPHC shareholders, which may be contrary to our interests;
•
our general partner is allowed to take into account the interests of parties other than us, such as BPHC and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
•
some officers of our general partner who provide services to us may devote time to affiliates of our general partner and may be compensated for services rendered to such affiliates;
•
our partnership agreement limits the liability and reduces the fiduciary duties of our general partner and the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
•
our general partner determines the amount and timing of asset purchases and sales, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;
•
our general partner determines the amount and timing of any capital expenditures and whether an expenditure is for maintenance capital, which reduces operating surplus, or a capital improvement expenditure, which does not. Such determination can affect the amount of cash that is distributed to our unitholders;
•
in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
•
our general partner determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us;
•
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf, and provides that reimbursement to Loews for amounts allocable to us consistent with accounting and allocation methodologies generally permitted by FERC for rate-making purposes and past business practices is deemed fair and reasonable to us;
•
our general partner controls the enforcement of obligations owed to us by it and its affiliates;
•
our general partner intends to limit its liability regarding our contractual obligations;
•
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
•
our general partner may exercise its rights to call and purchase (1) all of our common units if, at any time, it and its affiliates own more than 80% of the outstanding common units or (2) all of our equity securities (including common units), if it and its affiliates own more than 50% in the aggregate of the outstanding common units and any other classes of equity securities and it receives an opinion of outside legal counsel to the effect that our being a pass-through entity for tax purposes has or is reasonably likely to have a material adverse effect on the maximum applicable rates we can charge our customers.
Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
•
permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or any limited partner. Decisions made by our general partner in its individual capacity will be made by a majority of the owners of our general partner, and not by the board of directors of our general partner. Examples of these kinds of decisions include the exercise of its call rights, its voting rights with respect to the units it owns and its registration rights and the determination of whether to consent to any merger or consolidation of the partnership;
•
provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the partnership;
•
generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
•
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions.
We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, or if we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are a limited partnership under Delaware law, we would be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we
satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to a material amount of entity-level taxation for federal, state or local income tax purposes, the target distribution amounts will be adjusted to reflect the impact of that law on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial or administrative changes and differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions that we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner, because the costs will reduce our cash available for distribution to our unitholders.
Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to such unitholders' share of our taxable income or even equal to the actual tax liability that results from such unitholders' share of our taxable income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder's allocable share of our net taxable income result in a decrease to such unitholder's tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing a gain, may be taxed as ordinary income due to potential recapture of depreciation deductions and certain other items. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as "IRAs") and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Allocations and/or distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective tax rate applicable to non-U.S. persons, and each non-U.S. person will be required to file federal tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder's sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. If the IRS were to successfully challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan, (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profit interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year, and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby a publicly traded partnership that has technically terminated may be permitted to provide only a single Schedule K-1 to unitholders for the two tax years within the fiscal year in which the termination occurs.
Our unitholders may be subject to state and local taxes and return filing requirements as a result of investing in our common units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We conduct business in thirteen states. We may own property or conduct business in other states or foreign countries in the future. It is our unitholders' responsibility to file all federal, state and local tax returns.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
We are headquartered in approximately 108,000 square feet of leased office space located in Houston, Texas. We also have approximately 60,000 square feet of leased office space in Owensboro, Kentucky. Our operating subsidiaries own their respective pipeline systems in fee. However, substantial portions of these systems are constructed and maintained on property owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Our Pipeline and Storage Systems, in Item 1 of this Report contains additional information regarding our material property, including our pipelines and storage facilities.
Item 3.
Item 3. Legal Proceedings
Refer to Note 5 in Item 8 of this report for a discussion of our legal proceedings.
Item 4.
Item 4. Mine Safety Disclosures
None.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Partnership Interests
As of December 31, 2013, we had outstanding 243.3 million common units, a 2% general partner interest and IDRs. The common units represent all of our limited partner interests and 98% of our total ownership interests, in each case excluding our IDRs. As discussed below under Our Cash Distribution Policy-Incentive Distribution Rights, the IDRs represent the right for the holder to receive varying percentages of quarterly distributions of available cash from operating surplus in excess of certain specified target quarterly distribution levels. As such, the IDRs cannot be expressed as a constant percentage of our total ownership interests.
BPHC, a wholly-owned subsidiary of Loews, owns 125.6 million of our common units and, through Boardwalk GP, LP, an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the IDRs. As of February 24, 2014, the common units and general partner interest held by BPHC represent approximately 53% of our equity interests, excluding IDRs. The additional interest represented by the IDRs is not included in such ownership percentage because, as noted above, the IDRs cannot be expressed as a constant percentage of our ownership.
Market Information
As of February 20, 2014, we had 243.3 million common units outstanding held by approximately 76 holders of record. Our common units are traded on the NYSE under the symbol “BWP.”
The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the NYSE Composite Transactions Tape, and information regarding our quarterly distributions. The closing sales price of our common units on the NYSE on February 20, 2014, was $13.00 per unit.
(1)
Represents cash distributions attributable to the quarter and declared and paid to limited partner unitholders within 60 days after quarter end.
(2)
We also paid cash distributions to our general partner with respect to its 2% general partner interest and, with respect to that portion of the distribution in excess of $0.4025 per unit, its IDRs described below. Our class B units converted into common units on a one-for-one basis on October 9, 2013, pursuant to the terms of our partnership agreement. Prior to the conversion, the class B unitholder participated in distributions on a pari passu basis with our common units up to $0.30 per quarter. The class B units did not participate in quarterly distributions above $0.30 per unit.
Our Cash Distribution Policy
Our cash distribution policy is consistent with the terms of our partnership agreement which requires us to distribute our “available cash,” as that term is defined in our partnership agreement, on a quarterly basis. Our distributions are determined by the board of directors of our general partner based on our financial position, earnings, cash flow and other relevant factors. However,
there is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions or limitations, including, among others, our general partner’s broad discretion to establish reserves which could reduce cash available for distributions, FERC regulations which place restrictions on various types of cash management programs employed by companies in the energy industry, including our operating subsidiaries subject to FERC jurisdiction, the requirements of applicable state partnership and limited liability company laws, and the requirements of our revolving credit facility which would prohibit us from making distributions to unitholders if an event of default were to occur. In addition, we may lack sufficient cash to pay distributions to unitholders due to a number of factors, including those described in Item 1A, Risk Factors, of this Report.
Incentive Distribution Rights
IDRs represent a limited partner ownership interest and include the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the target distribution levels have been achieved, as defined in our partnership agreement. Our general partner currently holds all of our IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. In 2013, 2012 and 2011, we paid $34.6 million, $30.1 million and $22.3 million in distributions on behalf of our IDRs. Note 13 in Item 8 of this Report contains more information regarding our distributions.
Assuming we do not issue any additional classes of units and our general partner maintains its 2% general partner interest, we will distribute any available cash from operating surplus for that quarter among the unitholders and our general partner as follows:
(1)
Our class B units converted into common units on a one-for-one basis on October 9, 2013, pursuant to the terms of our partnership agreement. Prior to the conversion, distributions to our limited partner unitholders included distributions on behalf of our class B units. The class B units shared in quarterly distributions of available cash from operating surplus on a pari passu basis with our common units, until each common unit and class B unit received a quarterly distribution of $0.30. The class B units did not participate in quarterly distributions above $0.30 per unit.
Equity Compensation Plans
For information about our equity compensation plans, see Note 12 in Item 8 of this Report.
Issuer Purchases of Equity Securities
None.
Item 6.
Item 6. Selected Financial Data
The following table presents our selected historical financial and operating data. As used herein, Adjusted EBITDA means earnings before interest, income taxes, depreciation and amortization. Adjusted EBITDA and distributable cash flow are not calculated or presented in accordance with accounting principles generally accepted in the U.S. (GAAP). We explain these measures below and reconcile them to the most directly comparable financial measures calculated and presented in accordance with GAAP in (2) Non-GAAP Financial Measures. The financial data below should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in Item 8 of this Report (in millions, except Net income per common unit, Net income per class B unit, Distributions per common unit and Distributions per class B unit):
(1)
On October 9, 2013, the class B units converted to common units on a one-for-one basis pursuant to the terms of our partnership agreement.
(2)
Non-GAAP Financial Measures.
We use non-GAAP measures to evaluate our business and performance, including Adjusted EBITDA and distributable cash flow. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess:
•
our financial performance without regard to financing methods, capital structure or historical cost basis;
•
our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;
•
our operating performance and return on invested capital as compared to those of other companies in the midstream portion of the natural gas and NGLs industry, without regard to financing methods and capital structure; and
•
the viability of acquisitions and capital expenditure projects.
Distributable cash flow is used as a supplemental measure by management and by external users of our financial statements, as defined above, to assess our ability to make cash distributions to our unitholders and our general partner.
Adjusted EBITDA and distributable cash flow should not be considered alternatives to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, or as indicators of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA and distributable cash flow are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets. We have included information concerning Adjusted EBITDA because Adjusted EBITDA provides additional information as to our ability to meet our fixed charges and is presented solely as a supplemental measure. Likewise, we have included information concerning distributable cash flow as a supplemental financial measure we use to assess our ability to make distributions to our unitholders and general partner. However, viewing Adjusted EBITDA and distributable cash flow as indicators of our ability to make cash distributions on our common units should be done with caution, as we might be required to conserve funds or to allocate funds to business or legal
purposes other than making distributions. Adjusted EBITDA and distributable cash flow are not necessarily comparable to similarly titled measures of another company.
The following table presents a reconciliation of Adjusted EBITDA and distributable cash flow to net income, the most directly comparable GAAP financial measure for each of the periods presented below (in millions):
(1)
The year ended December 31, 2012, included $9.6 million of payments related to the settlements of interest rate derivatives and the year ended December 31, 2011, included $21.0 million of premiums paid for the early extinguishment of debt.
(2)
The year ended December 31, 2011, included $14.3 million of maintenance capital expenditures related to repairs associated with a fire at our Carthage compressor station.
(3)
The years ended December 31, 2012 and 2011 represent insurance recoveries associated with the Carthage compressor fire and a legal settlement. All years exclude proceeds recognized in earnings.
(4)
Includes non-cash items such as the equity component of allowance for funds used during construction. The year ended December 31, 2013, includes ethylene inventory that was acquired through the acquisition of Louisiana Midstream and subsequently sold.
(5)
Certain amounts were reclassified within Total operating costs and expenses in the Consolidated Statements of Income for the 2012 and 2011 periods. Note 1 in Item 8 of this Report contains more information regarding the reclassification.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are a master limited partnership operating in the midstream portion of the natural gas and NGLs industry, providing transportation, storage, gathering and processing services for those commodities. Our pipeline systems originate in the Gulf Coast region, Oklahoma and Arkansas and extend north and east to the midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio.
Our pipeline systems contain approximately 14,195 miles of interconnected natural gas pipelines, directly serving customers in thirteen states and indirectly serving customers throughout the northeastern and southeastern U.S. through numerous interconnections with unaffiliated pipelines. We also own approximately 255 miles of NGLs pipelines serving customers in Louisiana. In 2013, our pipeline systems transported approximately 2.4 Tcf of natural gas and approximately 7.5 MMbbls of NGLs. Average daily throughput on our natural gas pipeline systems during 2013 was approximately 6.6 Bcf. Our natural gas storage facilities are comprised of fourteen underground storage fields located in four states with aggregate working gas capacity of approximately 207.0 Bcf and our NGLs storage facilities located in Louisiana consist of eight salt dome caverns with a storage capacity of 17.6 MMbbls. We also have two salt-dome caverns for use in providing brine supply services and to support NGLs cavern operations. We conduct all of our business through our operating subsidiaries as one reportable segment.
Our transportation services consist of firm natural gas transportation, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible natural gas transportation, whereby the customer pays to transport gas only when capacity is available and used. We offer firm natural gas storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and PAL services where the customer receives and pays for capacity only when it is available and used. Our NGLs contracts are generally fee-based and are dependent on actual volumes transported or stored, although in some cases minimum volume requirements apply. Our NGLs storage rates are market based rates and contracts are typically fixed-price arrangements with escalation clauses. We are not in the business of buying and selling natural gas and NGLs other than for system management purposes, but changes in the level of natural gas and NGLs prices may impact the volumes of gas transported and stored on our pipeline systems. Our operating costs and expenses typically do not vary significantly based upon the amount of products transported, with the exception of fuel consumed at our compressor stations, which is included in Fuel and gas transportation expenses on our Consolidated Statements of Income.
Recent Developments
Market Conditions and Contract Renewals
We provide natural gas transportation services to customers that are directly connected to our pipeline system and, through interconnects with third-party pipelines to customers that are not directly connected to our system. Transportation rates that we can charge customers we serve through interconnects with third-party pipelines are heavily influenced by current and anticipated basis differentials. Basis differentials, generally the difference in the price of natural gas at receipt and delivery points across our natural gas pipeline system, influence how much customers are willing to pay to transport gas between those points. Basis differentials can be affected by, among other things, the availability and supply of natural gas, the proximity of supply areas to end use markets, competition from other pipelines, including pipelines under development, available transportation and storage capacity, storage inventories, regulatory developments, weather and general market demand in markets served by our pipeline systems. New sources of natural gas continue to be identified and developed in the U.S., including the Marcellus and the Utica shale plays which are closer to the traditional high value markets we serve, than the supply basins connected to our facilities. As a result, pipeline infrastructure has been and continues to be developed to move natural gas and NGLs from these supply basins to market areas, resulting in changes in pricing dynamics between supply basins, pooling points and market areas. Additionally, these new supplies of natural gas have reduced production or slowed production growth from supply areas connected to our pipelines and have caused some of the gas production that is supplied to our system to be diverted to other market areas. As a result of the new sources of supply and related pipeline infrastructure discussed above, basis differentials on our pipeline systems have narrowed significantly in recent years, reducing the transportation rates and other contract terms we can negotiate with our customers for available transportation capacity and for contracts due for renewal for our interruptible and firm transportation services.
A substantial portion of our transportation capacity is contracted for under firm transportation agreements. Each year a portion of our firm transportation agreements expire and needs to be renewed or replaced. Due to the factors noted above, in recent periods we have renewed many expiring contracts at lower rates and for shorter terms than in the past, which has materially
adversely impacted our firm and interruptible transportation revenues. In light of the market conditions discussed above, natural gas transportation contracts we have renewed or entered into in 2013 and in recent years have been at lower rates, and any remaining available capacity generally has been marketed and sold at lower rates under short-term firm or interruptible contracts, or in some cases not sold at all. As a result, capacity reservation charges under firm transportation agreements for the year ended December 31, 2013, were lower by $45.4 million than they were for the comparable 2012 period. We expect this trend to continue and therefore may not be able to sell our available capacity, extend expiring contracts with existing customers or obtain replacement contracts at attractive rates or for the same term as the expiring contracts, all of which would continue to adversely impact our transportation revenues, EBITDA and distributable cash flows and could impact us on a long-term basis.
More recently, we have seen the value of our storage and PAL services adversely impacted by the factors discussed above, which have contributed to a narrowing of natural gas price differentials between time periods, such as winter to summer (time period price spreads), and the price volatility of natural gas to decline significantly, reducing the rates we can charge for our storage and PAL services. Based on the current forward pricing curve, which is backwardated, time period price spreads for 2013 have significantly deteriorated from the 2012 levels and we expect such conditions to persist. In recent months, we have seen the deterioration of storage spreads accelerate and that trend is expected to continue into 2014. These market conditions, together with regulatory changes in the financial services industry, have also caused a number of gas marketers, which have traditionally been large consumers of our storage and PAL services, to exit the market, further negatively impacting the market for those services. A reduced need for storage as supply increases, narrowing time period price spreads and fewer market participants has caused, and could continue to cause demand for our storage and PAL services to decline on a long-term basis.
In February 2014, we declared a quarterly distribution of $0.10 per unit, which was less than the quarterly distributions of $0.5325 per unit that we declared and paid in recent prior periods, which reflects the market conditions described above and the resulting cumulative impact on our business from the decline in transportation and storage revenues. We intend to use the increase in cash not distributed to unitholders to fund growth and/or to repay indebtedness. BPHC has also offered us up to $300.0 million of subordinated loans to fund growth, if it is needed. We intend to use those sources of capital to fund our growth and reduce our leverage (including our Debt-to-EBITDA ratio) in lieu of issuing additional limited partnership units which would be dilutive to our unitholders. We cannot give assurances that we will complete future growth projects or acquisitions or, if completed, that they will be accretive to our earnings and cash flow, that we will be successful in reducing our leverage, or that we will not issue and sell additional limited partnership units to fund our growth or for other partnership purposes.
Pipeline System Maintenance
We incur substantial costs for ongoing maintenance of our pipeline systems and related facilities, including those incurred for pipeline integrity management activities, equipment overhauls, general upkeep and repairs. These costs are not dependent on the amount of revenues earned from our natural gas transportation services. PHMSA has developed regulations that require transportation pipeline operators to implement integrity management programs to comprehensively evaluate certain areas along pipelines and take additional measures to protect pipeline segments located in highly populated areas. These regulations have resulted in an overall increase in our ongoing maintenance costs, including maintenance capital and maintenance expense. Due to recent widely-known incidents that have occurred on certain pipelines in the U.S., it is possible that PHMSA may develop more stringent regulations. We could incur significant additional costs if new or more stringently interpreted pipeline safety requirements are implemented.
Results of Operations
2013 Compared with 2012
Our net income attributable to controlling interests for the year ended December 31, 2013, decreased $52.3 million, or 17%, to $253.7 million compared to $306.0 million for the year ended December 31, 2012. The decrease in net income was primarily a result of the effects of unfavorable market conditions on our transportation and storage revenues and a goodwill impairment charge. See Critical Accounting Estimates and Policies for more information regarding the goodwill impairment charge.
Operating revenues for the year ended December 31, 2013, increased $20.6 million, or 2%, to $1,205.6 million, compared to $1,185.0 million for the year ended December 31, 2012. The increase was primarily due to $62.6 million of revenues from Louisiana Midstream, which was acquired on October 1, 2012, and increased revenues from fuel of $9.2 million resulting mainly from higher natural gas prices. The increase in revenues was partially offset by the market conditions discussed above, resulting in lower transportation revenues, excluding fuel, of $52.6 million and $3.6 million of reduced storage and PAL revenues.
Operating costs and expenses for the year ended December 31, 2013, increased $79.9 million, or 11%, to $791.1 million, compared to $711.2 million for the year ended December 31, 2012. The increase in operating expenses was driven by a $51.5 million goodwill impairment charge, the acquisition of Louisiana Midstream, which incurred $37.6 million of operating expenses, an increase of depreciation and property taxes of $8.9 million due to an increase in our asset base, and increased fuel costs of $6.0 million due to higher natural gas prices. These expenses were partially offset by a $29.9 million gain from the sale of storage gas.
Total other deductions for the year ended December 31, 2013, decreased by $3.5 million, or 2%, to $163.8 million compared to $167.3 million for the 2012 period, driven by lower interest expense due to lower average outstanding debt levels and lower interest rates.
2012 Compared with 2011
Our net income for the year ended December 31, 2012, increased $89.0 million, or 41%, to $306.0 million compared to $217.0 million for the year ended December 31, 2011. The increase in net income was primarily the result of the acquisitions of Petal, which occurred on December 1, 2011, and Louisiana Midstream, items which negatively impacted the 2011 period, and other items noted below.
Operating revenues for the year ended December 31, 2012, increased $42.1 million, or 4%, to $1,185.0 million, compared to $1,142.9 million for the year ended December 31, 2011. The increase was due to $62.5 million of revenues from Petal and Louisiana Midstream and higher PAL and storage revenues of $13.6 million, resulting from improved market conditions. The increase in revenues was partially offset by a decrease in retained fuel of $33.9 million primarily due to lower natural gas prices.
Operating costs and expenses for the year ended December 31, 2012, decreased $42.5 million, or 6%, to $711.2 million, compared to $753.7 million for the year ended December 31, 2011. The primary drivers of the decrease were lower fuel costs of $21.3 million primarily due to lower natural gas prices, lower administrative and general expenses of $16.0 million as a result of cost management activities, particularly with regard to outside services, corporate fees and labor and $10.8 million lower operation and maintenance expenses primarily from lower maintenance project costs and outside services. These decreases were partially offset by $37.9 million of expenses incurred by the acquired entities, $19.3 million of which was from depreciation and amortization. We also recorded $9.1 million of asset impairment charges in 2012, of which $2.8 million was related to our Owensboro, Kentucky, office facilities and the remainder related to the expected retirement of certain small-diameter pipeline assets. The 2011 period was unfavorably impacted by an impairment charge of $28.8 million related to materials and supplies which were subsequently sold, a $5.0 million charge related to a fire at our Carthage compressor station and a $3.7 million natural gas storage loss at our Bistineau facility, and favorably impacted by $9.2 million of gains from the sale of storage gas.
Total other deductions for the year ended December 31, 2012, decreased by $4.5 million, or 3%, to $167.3 million compared to $171.8 million for the year ended December 31, 2011 driven by a $13.2 million loss on the early extinguishment of debt recognized in the 2011 period, partially offset by higher interest expense of $8.5 million resulting from increased debt levels in 2012 and interest rate derivatives.
Liquidity and Capital Resources
We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility, debt issuances and sales of limited partner units. Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as needed, borrowings under our revolving credit facility to service outstanding indebtedness and make distributions or advances to us to fund our distributions to unitholders. We have no material guarantees of debt or other similar commitments to unaffiliated parties. BPHC has also offered us up to $300.0 million of subordinated loans to fund growth. We intend to use those sources of liquidity in an effort to fund our growth and reduce our leverage.
Capital Expenditures
Maintenance capital expenditures for the years ended December 31, 2013, 2012 and 2011 were $69.7 million $79.8 million and $94.6 million. Growth capital expenditures were $225.1 million, $147.1 million and $47.3 million for the years ended December 31, 2013, 2012 and 2011. We expect our total capital expenditures to be approximately $420.0 million in 2014, including approximately $90.0 million for maintenance capital.
Our more significant growth projects for 2014 consist of:
Southeast Market Expansion: We expect to spend approximately $300.0 million to construct an interconnection between our Gulf South and Petal subsidiaries, add additional compression facilities to our system and construct approximately 70 miles of 24-inch and 30-inch pipeline in southeastern Mississippi. To date, we have spent $53.8 million on this project and expect to spend an additional $248.9 million in 2014.
Ohio to Louisiana Access Project: We expect to spend approximately $115.0 million to allow us to reverse the traditional flow of a portion of our Texas Gas pipeline from northbound to southbound in order to provide long-term firm natural gas transportation from the Marcellus and Utica production areas to delivery markets in Louisiana. We expect to spend approximately $22.8 million in 2014 related to this project.
Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects: We have contributed a total of $11.9 million to the capital of Boardwalk Bluegrass and Boardwalk Moss Lake. BPHC has contributed the balance of the capital of these entities and anticipates contributing the additional capital required to fund certain agreed upon pre-construction development costs until such time as BPHC has a 90% equity ownership interest in each entity. Additional capital required for Boardwalk Bluegrass and Boardwalk Moss Lake to continue to pursue the Bluegrass Project is subject to approval by us and BPHC. We do not expect to spend significant amounts of capital on these projects until approvals have been received and the parties have determined to proceed with construction of the Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG projects.
Refer to Item 1 for further discussion of these projects.
Equity and Debt Financing
We anticipate that our existing capital resources, including our revolving credit facility and future cash flows will be adequate to fund our operations, including our maintenance capital expenditures in 2014. To help fund growth in 2014, a subsidiary of Loews has offered to provide us with up to $300.0 million in subordinated debt if it is required. Although we anticipate that our existing capital resources including the subordinated loan will be adequate to fund our current growth projects, we may seek to access the capital markets to fund some or all capital expenditures for future growth projects or acquisitions, or to repay or refinance all or a portion of our indebtedness, a significant amount of which matures in the next five years. Our ability to access the capital markets for equity and debt financing under reasonable terms depends on our financial condition, credit ratings and market conditions.
In May 2013, we completed a public offering of 12.7 million of our common units at a price of $30.12 per unit. We received net cash proceeds of approximately $376.5 million after deducting underwriting discounts and offering expenses of $12.3 million and including a $7.8 million contribution received from our general partner to maintain its 2% general partner interest. The net proceeds were used to repay borrowings under our revolving credit facility.
On October 9, 2013, all of the 22.9 million class B units were converted into common units on a one-for-one basis, pursuant to the terms of the partnership agreement. After the conversion, we had 243.3 million outstanding common units.
Revolving Credit Facility
As of December 31, 2013, we had $175.0 million of borrowings outstanding under our revolving credit facility with a weighted-average interest rate of 1.29% and no letters of credit issued thereunder. As of February 21, 2014, we had outstanding borrowings under our revolving credit facility of $250.0 million, resulting in available borrowing capacity of $750.0 million.
The credit facility, which matures in April 2017, contains various restrictive covenants and other usual and customary terms and conditions, including the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the credit facility require us and our subsidiaries to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the Amended Credit Agreement) measured for the previous twelve months of not
more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following an acquisition. We and our subsidiaries were in compliance with all covenant requirements under the credit facility as of December 31, 2013. Note 11 in Item 8 of this Report contains more information regarding our revolving credit facility.
Contractual Obligations
The following table summarizes significant contractual cash payment obligations under firm commitments as of December 31, 2013, by period (in millions):
(1)
Includes our senior unsecured notes, having maturity dates from 2015 to 2027, $175.0 million of loans outstanding under our revolving credit facility, having a maturity date of April 27, 2017, and $225.0 million of loans outstanding under our term-loan, having a maturity date of October 1, 2017.
(2)
Interest obligations represent interest due on our senior unsecured notes at fixed rates. Future interest obligations under our revolving credit facility are uncertain, due to the variable interest rate and fluctuating balances. Based on a 1.29% weighted-average interest rate and an unused commitment fee of 0.16% as of December 31, 2013, $3.5 million, $7.1 million and $1.2 million would be due in less than one year, 1-3 years and 3-5 years. Interest obligations under the Term Loan are also subject to variable interest rates. Based on a 1.92% weighted-average interest rate on amounts outstanding under the Term Loan as of December 31, 2013, $4.3 million, $8.6 million and $3.2 million would be due in less than one year, 1-3 years and 3-5 years.
(3)
Capital commitments represent binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at December 31, 2013.
(4)
The amounts shown are associated with pipeline capacity agreements on third-party pipelines that allow our operating subsidiaries to transport gas to off-system markets on behalf of our customers.
(5)
Capital lease commitments represent future non-cancelable minimum lease payments under a capital lease agreement.
Pursuant to the settlement of the Texas Gas rate case in 2006, we are required to annually fund an amount to the Texas Gas pension plan equal to the amount of actuarially determined net periodic pension cost, including a minimum of $3.0 million. In 2014, we expect to fund approximately $3.0 million to the Texas Gas pension plan.
Distributions
For the years ended December 31, 2013, 2012 and 2011, we paid distributions of $533.9 million, $478.9 million and $419.9 million to our partners. Note 13 in Item 8 of this report contains further discussion regarding our distributions.
Changes in cash flow from operating activities
Net cash provided by operating activities decreased $41.2 million to $534.3 million for the year ended December 31, 2013, compared to $575.5 million for the comparable 2012 period, primarily due to a reduction in our earnings as discussed under Results of Operations.
Changes in cash flow from investing activities
Net cash used in investing activities decreased $521.4 million to $309.4 million for the year ended December 31, 2013, compared to $830.8 million for the comparable 2012 period. The change was driven by the 2012 acquisition of Louisiana Midstream of $620.2 million and an increase in proceeds from the sale of assets and insurance recoveries of $45.8 million, primarily from the sale of storage gas. These items were partially offset by an increase in capital expenditures of $67.9 million and the investment in the Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG projects of $76.7 million.
Changes in cash flow from financing activities
Net cash used in financing activities was $200.3 million for the year ended December 31, 2013, compared to net cash provided by financing activities of $237.3 million for the comparable 2012 period, a net use of cash of $437.6 million. The increase in cash used in financing activities resulted primarily from a decrease of $489.2 million from the issuance and sale of common units, including related general partner contributions, and a $55.0 million increase in distributions to our partners.
Impact of Inflation
The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant and equipment is subject to rate-making treatment, and under current FERC practices, recovery is limited to historical costs. Amounts in excess of historical cost are not recoverable unless a rate case is filed. However, cost-based regulation, along with competition and other market factors, may limit our ability to price jurisdictional services to ensure recovery of inflation’s effect on costs.
Off-Balance Sheet Arrangements
At December 31, 2013, we had no guarantees of off-balance sheet debt to third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings, and no other off-balance sheet arrangements.
Critical Accounting Estimates and Policies
Our significant accounting policies are described in Note 2 to the Consolidated Financial Statements included in Item 8 of this Report. The preparation of these consolidated financial statements in accordance with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. Estimates are based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. The result of this process forms the basis for making judgments about the carrying amount of assets and liabilities that are not readily apparent from other sources. We review our estimates and judgments on a regular, ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the periods in which the facts that give rise to the revisions become known.
The following accounting policies and estimates are considered critical due to the potentially material impact that the estimates, judgments and uncertainties affecting the application of these policies might have on our reported financial information.
Regulation
Most of our natural gas pipeline subsidiaries are regulated by FERC. Pursuant to FERC regulations certain revenues that we collect may be subject to possible refunds to our customers. Accordingly, during an open rate case, estimates of rate refund reserves are recorded based on regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. At December 31, 2013 and 2012, there were no liabilities for any open rate case recorded on our Consolidated Balance Sheets. Currently, none of our regulated companies are involved in an open general rate case.
When certain criteria are met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates (regulatory accounting). This basis of accounting is applicable to operations of our Texas Gas subsidiary which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refund to customers in future periods, but is not applicable to operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate agreements and a portion of the storage capacity due to the regulatory treatment associated with the rates charged for that capacity. Regulatory accounting is not applicable to our other FERC-regulated entities.
We monitor the regulatory and competitive environment in which we operate to determine that any regulatory assets continue to be probable of recovery. If we were to determine that all or a portion of our regulatory assets no longer met the criteria for recognition as regulatory assets, that portion which was not recoverable would be written off, net of any regulatory liabilities. Note 10 in Item 8 of this Report contains more information regarding our regulatory assets and liabilities.
In the course of providing transportation and storage services to customers, the natural gas pipelines may receive different quantities of gas from shippers and operators than the quantities delivered by the pipelines on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are primarily settled in cash or the receipt or delivery of gas in the future. Settlement of natural gas imbalances requires agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. The receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage for operations where regulatory accounting is applicable, consistent with the regulatory treatment.
Fair Value Measurements
Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances. We use fair value measurements to record our derivatives, asset retirement obligations and impairments. We also use fair value measurements to perform our goodwill impairment testing and report fair values for certain items in the Notes to the Consolidated Financial Statements in Item 8 of this Report. Notes 6 and 12 contain more information regarding our fair value measurements.
Environmental Liabilities
Our environmental liabilities are based on management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of our operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these environmental matters. At December 31, 2013, we had accrued approximately $6.5 million for environmental matters. Our environmental accrued liabilities could change substantially in the future due to factors such as the nature and extent of any contamination, changes in remedial requirements, technological changes, discovery of new information, and the involvement of and direction taken by the EPA, FERC and other governmental authorities on these matters. We continue to conduct environmental assessments and are implementing a variety of remedial measures that may result in increases or decreases in the estimated environmental costs. Note 5 in Item 8 of this Report contains more information regarding our environmental liabilities.
Goodwill
Goodwill is tested for impairment at the reporting unit level at least annually or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Accounting requirements provide that a reporting entity may perform an optional qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If an initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or the optional qualitative assessment is not performed, a quantitative analysis is performed under a two-step impairment test to measure whether the fair value of the reporting unit is less than its carrying amount. If the fair value of the reporting unit is determined to be less than its carrying amount, including goodwill, the reporting entity must perform an analysis of the fair value of all of the assets and liabilities of the reporting unit. If the implied fair value of the reporting unit's goodwill is determined to be less than its carrying amount, an impairment loss is recognized for the difference. The implied fair value of goodwill is the excess of the fair value of the reporting unit over the fair value amounts assigned to all of the assets and liabilities of that unit as if the reporting unit was acquired in a business combination and the fair value of the reporting unit represented the purchase price.
We performed a quantitative goodwill impairment test for each of our three reporting units as of November 30, 2013, which corresponds with the preparation of our five-year financial plan operating results. The fair value measurement of the reporting units was derived based on judgments and assumptions we believe market participants would use in assessing the fair value of the reporting units. These judgments and assumptions included the valuation premise, use of a discounted cash flow model to
estimate fair value and inputs to the valuation model. The inputs included our five-year financial plan operating results, the long-term outlook for growth in natural gas demand in the U.S. and measures of the risk-free rate, equity premium and systematic risk used in the calculation of the applied discount rate under the capital asset pricing model. The use of alternate judgments and assumptions could substantially change the results of our goodwill impairment analysis, including the recognition of an impairment charge in our consolidated financial statements.
The results of the quantitative goodwill impairment test indicated that the fair value of two of our reporting units significantly exceeded their carrying amounts and no goodwill impairment charges were recognized for those reporting units. The carrying amount of the third reporting unit, which included goodwill associated with our Petal acquisition, exceeded the estimated fair value and the second step of the goodwill impairment test was performed. In the fourth quarter 2013, we recognized a goodwill impairment charge of $51.5 million, representing the carrying amount of the goodwill for that reporting unit. The fair value of the reporting unit declined from the amount determined in 2012 due primarily to the recent narrowing of time period price spreads and reduced volatility which negatively affects the value of our storage and PAL services and the cumulative effect of reduced basis spreads on the value of our transportation services, as discussed under Market Conditions and Contract Renewals. No impairment charge related to goodwill was recorded for any of our reporting units during 2012 or 2011.
Impairment of Long-Lived Assets (including Tangible and Definite-Lived Intangible Assets)
We evaluate whether the carrying amounts of our long-lived and intangible assets have been impaired when circumstances indicate the carrying amount of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount is not recoverable, an impairment loss is measured as the excess of the asset’s carrying amount over its fair value.
During the fourth quarter of 2013, we considered the goodwill impairment of one of our reporting units an indicator of impairment related to the long-lived assets associated with the reporting unit’s asset group. Accordingly, we evaluated the reporting unit’s asset group for impairment based on undiscounted cash flow projections expected over the remaining useful life of the reporting unit’s primary assets and concluded that the long-lived assets were not impaired.
Defined Benefit Plans
We are required to make a significant number of assumptions in order to estimate the liabilities and costs related to our pension and postretirement benefit obligations to employees under our benefit plans. The assumptions that have the most impact on our pension and postretirement benefit costs are the discount rate, the expected return on plan assets and the rate of compensation increases. These assumptions are evaluated relative to current market factors in the U.S. such as inflation, interest rates and fiscal and monetary policies, as well as our policies regarding management of the plans such as the allocation of plan assets among investment options. Changes in these assumptions can have a material impact on obligations and related expense associated with these plans.
In determining the discount rate assumption, we utilize current market information and liability information provided by our plan actuaries, including a discounted cash flow analysis of our pension and postretirement obligations. In particular, the basis for our discount rate selection was the yield on indices of highly rated fixed income debt securities with durations comparable to that of our plan liabilities. The Merrill Lynch AA-rated Corporate Bond Index is consistently used as the basis for the change in discount rate from the last measurement date with this measure confirmed by the yield on other broad bond indices. Additionally, we supplement our discount rate decision with a yield curve analysis. The yield curve is applied to expected future retirement plan payments to adjust the discount rate to reflect the cash flow characteristics of the plans. The yield curve is developed by the plans' actuaries and is a hypothetical AA/Aa yield curve represented by a series of annualized discount rates reflecting bond issues having a rating of Aa or better by Moody's Investors Service, Inc. or a rating of AA or better by Standard & Poor's. Note 12 in Item 8 of this Report contains more information regarding our pension and postretirement benefit obligations.
Forward-Looking Statements
Investors are cautioned that certain statements contained in this Report, as well as some statements in periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are “forward-looking.” Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will likely result,” and similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by our partnership or our subsidiaries, are also forward-looking statements.
Forward-looking statements are based on current expectations and projections about future events and their potential impact on us. While management believes that these forward-looking statements are reasonable as and when made, there is no assurance that future events affecting us will be those that we anticipate. All forward-looking statements are inherently subject to a variety of risks and uncertainties, many of which are beyond our control that could cause actual results to differ materially from those anticipated or projected. These risks and uncertainties include, among others:
•
our ability to maintain or replace expiring gas transportation and storage contracts and to sell short-term capacity on our pipelines;
•
the impact to our business of our declaring a lower distribution rate on our common units;
•
the costs of maintaining and ensuring the integrity and reliability of our pipeline systems;
•
the impact of new pipelines or new gas supply sources on competition and basis spreads on our pipeline systems;
•
volatility or disruptions in the capital or financial markets;
•
the impact of FERC rate-making policies and actions on the services we offer, the rates we charge, our ability to recover the full cost of operating our pipelines, including earning a reasonable return, and overall business strategies such as converting a portion of the Texas Gas pipeline to NGLs service;
•
the successful negotiation, consummation and completion of contemplated transactions, projects and agreements, including obtaining all necessary regulatory approvals, or the timing, cost, scope and financial performance of our recent, current and future acquisitions and growth projects;
•
the impact of changes to laws and regulations, such as the proposed greenhouse gas legislation and other changes in environmental legislations, the pipeline safety bill, and regulatory changes that result from that legislation applicable to interstate pipelines, on our business, including our costs, liabilities and revenues;
•
the success of our strategy to grow and diversify our business, including expansion into new product lines and geographic areas;
•
our ability to access the bank and capital markets on acceptable terms to refinance our outstanding indebtedness and to fund our capital needs;
•
operational hazards, litigation and unforeseen interruptions for which we may not have adequate or appropriate insurance coverage;
•
the future cost of insuring our assets;
•
our ability to access new sources of natural gas and the impact on us of any future decreases in supplies of natural gas in our supply areas; and
•
the impact on our system throughput and revenues from changes in the supply of and demand for natural gas, including as a result of commodity price changes.
Developments in any of these areas could cause our results to differ materially from results that have been or may be anticipated or projected. Forward-looking statements speak only as of the date of this Report and we expressly disclaim any obligation or undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest rate risk:
With the exception of our revolving credit facility and our term loan, for which the interest rates are periodically reset, our debt has been issued at fixed rates. For fixed-rate debt, changes in interest rates affect the fair value of the debt instruments but do not directly affect earnings or cash flows. The following table presents market risk associated with our fixed-rate long-term debt at December 31 (in millions, except interest rates):
At December 31, 2013, we had $400.0 million of variable-rate debt outstanding at a weighted-average interest rate of 1.64%. A 1% increase in interest rates would increase our cash payments for interest on our variable-rate debt by $4.0 million on an annualized basis. At December 31, 2012, we had $527.0 million outstanding under variable-rate agreements at a weighted-average interest rate of 1.60%.
At December 31, 2013 and 2012, $28.5 million and $3.9 million of our undistributed cash, shown on the balance sheets as Cash and cash equivalents, was primarily invested in Treasury fund accounts. Due to the short-term nature of the Treasury fund accounts, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the fair market value of our Cash and cash equivalents.
Commodity risk:
Our pipelines do not take title to the natural gas and NGLs which they transport and store, therefore they do not assume the related commodity price risk associated with the products. However, certain volumes of our gas stored underground are available for sale and subject to commodity price risk. At December 31, 2013 and 2012, approximately $0.3 million and $7.0 million of gas stored underground, which we own and carry as current Gas stored underground, was available for sale and exposed to commodity price risk. We manage our exposure to commodity price risk through the use of futures, swaps and option contracts. Note 6 of Item 8
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Boardwalk GP, LLC
and the Partners of Boardwalk Pipeline Partners, LP
We have audited the accompanying consolidated balance sheets of Boardwalk Pipeline Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, cash flows and changes in equity for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Boardwalk Pipeline Partners, LP and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2014, expressed an unqualified opinion on the Partnership's internal control over financial reporting.
/s/ Deloitte & Touche LLP
Houston, Texas
February 24, 2014
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Millions)
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
(Millions, except per unit amounts)
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions)
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions)
The accompanying notes are an integral part of these consolidated financial statements.
BOARDWALK PIPELINE PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: Corporate Structure
Boardwalk Pipeline Partners, LP (the Partnership) is a Delaware limited partnership formed in 2005 to own and operate the business conducted by its primary subsidiary Boardwalk Pipelines, LP (Boardwalk Pipelines), and its operating subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South), Texas Gas Transmission, LLC (Texas Gas), Boardwalk Field Services, LLC (Field Services), Petal Gas Storage, LLC (formerly referred to as Boardwalk HP Storage, LLC) (Petal), Boardwalk Louisiana Midstream, LLC (Louisiana Midstream) and Boardwalk Storage Company, LLC (Boardwalk Storage) (together, the operating subsidiaries), and consists of integrated natural gas and natural gas liquids (NGLs) pipeline and storage systems and natural gas gathering and processing. All of the Partnership’s operations are conducted by its operating subsidiaries.
As of February 24, 2014, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owned 125.6 million of the Partnership’s common units, and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the incentive distribution rights (IDRs). As of February 24, 2014, the common units and general partner interest owned by BPHC represent approximately 53% of the Partnership’s equity interests, excluding the IDRs. The Partnership's Class B limited partner interests converted to common units on a one-for-one basis on October 9, 2013. The Partnership’s common units are traded under the symbol “BWP” on the New York Stock Exchange.
Basis of Presentation
The accompanying consolidated financial statements of the Partnership were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).
Certain amounts reported within Total operating costs and expenses in the Consolidated Statements of Income for the 2012 and 2011 period have been reclassified to conform to the current presentation. The effect of the reclassification increased Operation and maintenance expense and decreased Net gain on sale of operating assets, by $1.0 million and $6.2 million for the years ended December 31, 2012 and 2011, with no impact on Total operating costs and expenses, Operating income or Net Income.
Note 2: Accounting Policies
Principles of Consolidation
The consolidated financial statements include the Partnership’s accounts and those of its wholly-owned subsidiaries after elimination of intercompany transactions. The Partnership also consolidates variable interest entities (VIEs) in which the Partnership is the primary beneficiary. Third party or affiliate ownership interests in the Partnership's subsidiaries and consolidated VIEs are presented as noncontrolling interests.
The Partnership applies the equity method of accounting for investments in unconsolidated affiliates in which it owns 20 percent to 50 percent of the voting interests or otherwise exercises significant influence, but not control, over operating and financial policies of the investee. Under this method, the carrying amounts of the Partnership's equity investments are increased by a proportionate share of the investee's net income and contributions made, and decreased by a proportionate share of the investee's net losses and distributions received.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities and the fair values of certain items. The Partnership bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.
Segment Information
The Partnership operates in one reportable segment - the operation of interstate natural gas and natural gas liquids (NGLs) pipeline systems including integrated storage facilities. This segment consists of interstate natural gas pipeline systems which originate in the Gulf Coast region, Oklahoma and Arkansas, and extend north and east through the Midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio and NGLs pipelines and storage facilities in Louisiana.
Regulatory Accounting
Most of the Partnership's natural gas pipeline subsidiaries are regulated by the Federal Energy Regulatory Commission (FERC). When certain criteria are met, GAAP requires that certain rate-regulated entities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates (regulatory accounting). This basis of accounting is applicable to operations of the Partnership’s Texas Gas subsidiary which records certain costs and benefits as regulatory assets and liabilities in order to provide for recovery from or refund to customers in future periods, but is not applicable to operations associated with the Fayetteville and Greenville Laterals due to rates charged under negotiated rate agreements and a portion of the storage capacity due to the regulatory treatment associated with the rates charged for that capacity. Regulatory accounting is not applicable to the Partnership’s other FERC-regulated entities.
The Partnership monitors the regulatory and competitive environment in which it operates to determine that its regulatory assets continue to be probable of recovery. If the Partnership were to determine that all or a portion of its regulatory assets no longer met the criteria for recognition as regulatory assets, that portion which was not recoverable would be written off, net of any regulatory liabilities.
Note 10 contains more information regarding the Partnership’s regulatory assets and liabilities.
Fair Value Measurements
Fair value refers to an exit price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability assuming its highest and best use. A fair value hierarchy has been established that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances. The Partnership uses fair value measurements to record derivatives, asset retirement obligations and impairments. Fair value measurements are also used to perform goodwill impairment testing and report fair values for certain items contained in this Report. The Partnership considers any transfers between levels within the fair value hierarchy to have occurred at the beginning of a quarterly reporting period. The Partnership did not recognize any transfers between Level 1 and Level 2 of the fair value hierarchy and did not change its valuation techniques or inputs during the year ended December 31, 2013.
Notes 6 and 12 contain more information regarding fair value measurements.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with an original maturity of three months or less and are stated at cost plus accrued interest, which approximates fair value. The Partnership had no restricted cash at December 31, 2013 and 2012.
Cash Management
The operating subsidiaries participate in an intercompany cash management program with those that are FERC-regulated participating to the extent they are permitted under FERC regulations. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, Boardwalk Pipelines either provides cash to them or they provide cash to Boardwalk Pipelines. The transactions are represented by demand notes and are stated at historical carrying amounts. Interest income and expense is recognized on an accrual basis when collection is reasonably assured. The interest rate on intercompany demand notes is London Interbank Offered Rate (LIBOR) plus one percent and is adjusted every three months.
Trade and Other Receivables
Trade and other receivables are stated at their historical carrying amount, net of allowances for doubtful accounts. The Partnership establishes an allowance for doubtful accounts on a case-by-case basis when it believes the required payment of specific
amounts owed is unlikely to occur. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise unrealizable.
Gas Stored Underground and Gas Receivables and Payables
Certain of the Partnership's operating subsidiaries have underground gas in storage which is utilized for system management and operational balancing, as well as for services including firm and interruptible storage associated with certain no-notice and parking and lending (PAL) services. Gas stored underground includes the historical cost of natural gas volumes owned by the operating subsidiaries, at times reduced by certain operational encroachments upon that gas. Current gas stored underground represents net retained fuel remaining after providing transportation and storage services which is available for resale and is valued at the lower of weighted-average cost or market.
The operating subsidiaries provide storage services whereby they store natural gas or NGLs on behalf of customers and also periodically hold customer gas under PAL services. Since the customers retain title to the gas held by the Partnership in providing these services, the Partnership does not record the related gas on its balance sheet. Certain of the Partnership's operating subsidiaries also periodically lend gas and NGLs to customers.
In the course of providing transportation and storage services to customers, the operating subsidiaries may receive different quantities of gas from shippers and operators than the quantities delivered on behalf of those shippers and operators. This results in transportation and exchange gas receivables and payables, commonly known as imbalances, which are settled in cash or the receipt or delivery of gas in the future. Settlement of imbalances requires agreement between the pipelines and shippers or operators as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. The receivables and payables are valued at market price for operations where regulatory accounting is not applicable and are valued at the historical value of gas in storage for operations where regulatory accounting is applicable.
Materials and Supplies
Materials and supplies are carried at average cost and are included in Other Assets on the Consolidated Balance Sheets. The Partnership expects its materials and supplies to be used for capital projects related to its property, plant and equipment and for future growth projects.
Property, Plant and Equipment (PPE) and Repair and Maintenance Costs
PPE is recorded at its original cost of construction or fair value of assets purchased. Construction costs and expenditures for major renewals and improvements which extend the lives of the respective assets are capitalized. Construction work in progress is included in the financial statements as a component of PPE. All repair and maintenance costs are expensed as incurred.
Depreciation of PPE related to operations for which regulatory accounting does not apply is provided for using the straight-line method of depreciation over the estimated useful lives of the assets, which range from 3 to 35 years. The ordinary sale or retirement of PPE for these assets could result in a gain or loss. Depreciation of PPE related to operations for which regulatory accounting is applicable is provided for primarily on the straight-line method at FERC-prescribed rates over estimated useful lives of 5 to 62 years. Reflecting the application of composite depreciation, gains and losses from the ordinary sale or retirement of PPE for these assets are not recognized in earnings and generally do not impact PPE, net.
Note 7 contains more information regarding the Partnership’s PPE.
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquisition over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is tested for impairment at the reporting unit level at least annually, as of November 30, or more frequently when events occur and circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Accounting requirements provide that a reporting entity may perform an optional qualitative assessment on an annual basis to determine whether events occurred or circumstances changed that would more likely than not reduce the fair value of a reporting unit below its carrying amount. If an initial qualitative assessment identifies that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or the optional qualitative assessment is not performed, a quantitative analysis is performed under a two-step impairment test to measure whether the fair value of the reporting unit is less than its carrying amount. If based upon a quantitative analysis the fair value of the reporting unit is less than its carrying amount, including goodwill, the Partnership performs an analysis of the fair value of all the assets and liabilities of the reporting unit. If the implied fair value of the reporting unit's goodwill is determined to be less than its carrying amount, an impairment loss is recognized for the difference.
Intangible assets are those assets which provide future economic benefit but have no physical substance. The Partnership recorded intangible assets for customer relationships obtained through the purchases of Petal and Louisiana Midstream. The customer relationships, which are included in Other Assets on the Consolidated Balance Sheets, have a finite life and are being amortized in a systematic and rational manner over their estimated useful lives.
Note 8 contains additional information regarding the Partnership's goodwill and intangible assets.
Impairment of Long-lived Assets (including Tangible and Definite-lived Intangible Assets)
The Partnership evaluates its long-lived and intangible assets for impairment when, in management’s judgment, events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the remaining economic useful life of the asset is compared to the carrying amount of the asset to determine whether an impairment has occurred. If an impairment of the carrying amount has occurred, the amount of impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss to the extent that the carrying amount exceeds the estimated fair value.
Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)
The Partnership records capitalized interest, which represents the cost of borrowed funds used to finance construction activities for operations where regulatory accounting is not applicable. The Partnership records AFUDC, which represents the cost of funds, including equity funds, applicable to regulated natural gas transmission plant under construction as permitted by FERC regulatory practices, in connection with the Partnership’s operations where regulatory accounting is applicable. Capitalized interest and the allowance for borrowed funds used during construction are recognized as a reduction to Interest expense and the allowance for equity funds used during construction is included in Miscellaneous other income, net within the Consolidated Statements of Income. The following table summarizes capitalized interest and the allowance for borrowed funds and allowance for equity funds used during construction (in millions):
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 14 contains more information regarding the Partnership’s income taxes.
Revenue Recognition
The maximum rates that may be charged by the majority of the Partnership's operating subsidiaries for their services are established through FERC’s cost-based rate-making process; however, rates charged by those operating subsidiaries may be less than those allowed by FERC. Revenues from transportation and storage services are recognized in the period the service is provided based on contractual terms and the related volumes transported or stored. In connection with some PAL and interruptible storage service agreements, cash is received at inception of the service period resulting in the recording of deferred revenues which are recognized in revenues over the period the services are provided. At December 31, 2013 and 2012, the Partnership had deferred revenues of $7.9 million and $17.3 million related to PAL and interruptible storage services and $4.6 million and $5.6 million related to a firm transportation agreement that was paid in advance. The deferred revenues related to PAL and interruptible storage services will be recognized in 2014 and 2015 and the deferred revenues related to the firm transportation agreement will be recognized through 2018.
Retained fuel is recognized in revenues at market prices in the month of retention for operations where regulatory accounting is not applicable. The related fuel consumed in providing transportation services is recorded in Fuel and transportation expenses at market prices in the month consumed. In some cases, customers may elect to pay cash for the cost of fuel used in providing transportation services instead of having fuel retained in-kind. Retained fuel included in Transportation on the Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011 was $76.9 million, $71.8 million and $105.6 million.
In certain of the Partnership's operations, the Partnership has contractual retainage provisions in some of its storage contracts that provide for the Partnership to retain ownership of 0.5% of customer inventory volumes injected into storage wells. The contract allows the Partnership to sell the retainage volumes if commercially marketable volumes of the Partnership's retainage are on hand. The Partnership recognizes revenue for retainage volumes upon the physical sale of such volumes.
Under FERC regulations, certain revenues that the operating subsidiaries collect may be subject to possible refunds to their customers. Accordingly, during a rate case, estimates of rate refund liabilities are recorded considering regulatory proceedings, advice of counsel and estimated risk-adjusted total exposure, as well as other factors. At December 31, 2013 and 2012, there were no liabilities for any open rate case recorded on the Consolidated Balance Sheets.
Asset Retirement Obligations
The accounting requirements for existing legal obligations associated with the future retirement of long-lived assets require entities to record the fair value of a liability for an asset retirement obligation in the period during which the liability is incurred. The liability is initially recognized at fair value and is increased with the passage of time as accretion expense is recorded, until the liability is ultimately settled. The accretion expense is included within Operation and maintenance costs within the Consolidated Statements of Income. An amount corresponding to the amount of the initial liability is capitalized as part of the carrying amount of the related long-lived asset and depreciated over the useful life of that asset.
Note 9 contains more information regarding the Partnership’s asset retirement obligations.
Environmental Liabilities
The Partnership records environmental liabilities based on management’s estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of operating sites. These estimates are based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these environmental matters.
Note 5 contains more information regarding the Partnership’s environmental liabilities.
Defined Benefit Plans
The Partnership maintains certain postretirement benefit plans for certain employees. The Partnership funds these plans through periodic contributions which are invested until the benefits are paid out to the participants. The net benefit cost of the plan is recorded in the Consolidated Statements of Income. The Partnership records an asset or liability based on the overfunded or underfunded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability or recorded as a component of accumulated other comprehensive income (AOCI) until those gains or losses are recognized in the Consolidated Statements of Income.
Note 12 contains more information regarding the Partnership’s pension and postretirement benefit obligations.
Unit-Based and Other Long-Term Compensation
The Partnership provides awards of phantom common units (Phantom Common Units) to certain employees under its Long-Term Incentive Plan (LTIP). The Partnership also provides to certain employees awards of unit appreciation rights (UARs) and long-term cash bonuses (Long-Term Cash Bonuses) under the Boardwalk Pipeline Partners Unit Appreciation Rights and Cash Bonus Plan.
The Partnership measures the cost of an award issued in exchange for employee services based on the grant-date fair value of the award, or the stated amount in the case of the Long-Term Cash Bonuses. All outstanding awards are either required or expected to be settled in cash and are classified as a liability until settlement. The unit-based compensation awards are remeasured each reporting period until the final amount of awards is determined. The related compensation expense, less applicable estimates of forfeitures, is recognized over the period that employees are required to provide services in exchange for the awards, usually the vesting period.
Note 12 contains additional information regarding the Partnership’s unit-based and other long-term compensation.
Partner Capital Accounts
For purposes of maintaining capital accounts, items of income and loss of the Partnership are allocated among the partners each year, or portion thereof, in accordance with the partnership agreement. Generally, net income for each period is allocated among the partners based on their respective ownership interests after deducting any priority allocations in the form of cash distributions paid to the general partner as the holder of IDRs.
Derivative Financial Instruments
The Partnership use futures, swaps, and option contracts (collectively, derivatives) to hedge exposure to various risks, including natural gas commodity and interest rate risk. The effective portion of the related unrealized gains and losses resulting from changes in fair values of the derivatives contracts designated as cash flow hedges are deferred as a component of 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, 2013 and 2012.
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, 2013, 2012, and 2011.
Note 6 contains more information regarding the Partnership’s derivative financial instruments.
Note 3: Investments
Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects
In 2013, the Partnership executed an agreement with the Williams Companies, Inc (Williams) to develop the Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG Terminal Projects - projects that would transport NGLs from the Marcellus and Utica shale plays to the Lake Charles, Louisiana area, and the construction of related fractionation, storage and liquefied petroleum gas (LPG) terminal export facilities. The proposed project would include constructing a new pipeline, a new large-scale fractionation plant and related liquids storage and transport facilities and a new export LPG terminal and related facilities (collectively, the Bluegrass Project).
In connection with the Bluegrass Project, the Partnership executed agreements with BPHC to form Boardwalk Bluegrass Pipeline, LLC (Boardwalk Bluegrass) and Boardwalk Moss Lake, LLC (Boardwalk Moss Lake). Boardwalk Bluegrass and Boardwalk Moss Lake, together with affiliates of Williams, formed Bluegrass Pipeline Company LLC (Bluegrass Pipeline), Moss Lake Fractionation LLC (Moss Lake Fractionation) and Moss Lake LPG Terminal LLC (Moss Lake LPG) to pursue and, if approved, develop, own and construct the pipeline, fractionation and export LPG terminal facilities. Boardwalk Bluegrass currently owns 50% of the equity ownership interests in Bluegrass Pipeline, and Boardwalk Moss Lake currently owns 50% of the equity ownership interests in Moss Lake Fractionation and Moss Lake LPG with affiliates of Williams owning the other 50%. The parties have equal voting and participation rights.
Boardwalk Bluegrass and Boardwalk Moss Lake
The Partnership contributed a total of $10.0 million for initial equity ownership interests of 59% and 61% in Boardwalk Bluegrass and Boardwalk Moss Lake, respectively, with BPHC owning the remaining equity ownership interests. BPHC has agreed to contribute to these entities to fund certain agreed upon preconstruction development costs, with BPHC contributing all additional required capital until such time as BPHC has a 90% equity ownership interest in each entity. Additional capital required for Boardwalk Bluegrass and Boardwalk Moss Lake to continue to pursue the Bluegrass Project is subject to approval by the Partnership and BPHC. As of December 31, 2013, the Partnership held equity ownership interests of 10% and 23%, respectively, in Boardwalk Bluegrass and Boardwalk Moss Lake and has contributed $11.9 million to these entities.
The Partnership determined that Boardwalk Bluegrass and Boardwalk Moss Lake were VIEs due to disproportionate voting rights held by BPHC. In accordance with accounting literature applicable to consolidations, the Partnership is the primary beneficiary of Boardwalk Bluegrass and Boardwalk Moss Lake because the Partnership has the power to direct the significant activities related to each entity's investment decision in the underlying investment entities.
The financial information of Boardwalk Bluegrass and Boardwalk Moss Lake was reported at historical carrying amounts in accordance with the accounting requirements applicable to transactions between entities under common control. As of December 31, 2013, the Partnership included in its Consolidated Balance Sheet the following balances that represent amounts recorded by Boardwalk Bluegrass and Boardwalk Moss Lake (in millions):
Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG
Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG were determined to be VIEs, because the entities will require additional funding from each equity owner throughout the development and construction phases of the Bluegrass Project. Boardwalk Bluegrass and Boardwalk Moss Lake are not the primary beneficiaries of Bluegrass Pipeline, Moss Lake Fractionation or Moss Lake LPG, because the power to direct the activities that most significantly impact the entity's economic performance is shared between the equity owners. As a result, Boardwalk Bluegrass and Boardwalk Moss Lake account for the investments in Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG under the equity method of accounting. Boardwalk Bluegrass' and Boardwalk Moss Lake's maximum exposure to loss is limited to the carrying value of its investments in Bluegrass Pipeline, Moss Lake Fractionation and Moss Lake LPG, which was $78.6 million as of December 31, 2013. The Partnership's maximum exposure to loss is limited to the amount of the capital contributions it has made to Boardwalk Bluegrass and Boardwalk Moss Lake, or $11.9 million, as of December 31, 2013.
Note 4: Acquisitions
In late 2011 and in 2012, the Partnership completed the acquisitions of Louisiana Midstream and Petal. These acquisitions were made as part of the Partnership's long-term growth and diversification strategy and to complement the Partnership's existing midstream business.
Boardwalk Louisiana Midstream, LLC
In October 2012, the Partnership acquired Louisiana Midstream from PL Logistics LLC for $620.2 million in cash, after customary adjustments and net of cash acquired. The purchase price was funded through a $225.0 million, five year term loan, borrowings under the Partnership's revolving credit facility and the issuance and sale of common units. For the period from August 16, 2012 through October 15, 2012, the acquisition and related expenses were initially financed through a joint venture with BPHC, whereby BPHC owned 65% of the equity interests of the joint venture and the Partnership owned the remaining 35%. On October 15, 2012, the Partnership acquired BPHC’s 65% equity ownership interest for $269.2 million in cash, therefore, the assets and liabilities of the consolidated joint venture were recognized at the carrying amounts as the date of transfer and the $2.2 million difference between the purchase price and the $267.0 million carrying amount of the net assets acquired as the date of transfer was recognized as an adjustment to partners’ capital. The transaction was accounted for as a transaction between entities under common control, which required the Partnership to fully consolidate the joint venture from the date of its formation, or August 16, 2012.
In the second quarter 2013, the purchase price allocation for Louisiana Midstream was made final and was adjusted to reflect the amount of ethylene in storage at the purchase date. The Consolidated Balance Sheet at December 31, 2012, was adjusted to increase the fair value of Gas and liquids stored underground and reduce Goodwill by $3.8 million.
Petal Gas Storage, LLC
In February 2012, the Partnership acquired BPHC's 80% equity ownership interest in Petal (formerly referred to as Boardwalk HP Storage, LLC) for $284.8 million in cash, which was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities were recognized at their carrying amounts at the date of transfer and the $3.0 million difference between the purchase price and the $281.8 million carrying amount of the net assets acquired at the date of transfer was recognized as an adjustment to partners' capital.
Pro Forma Financial Information (Unaudited)
The following unaudited pro forma results of operations assume that the acquisitions had been included in the Partnership's results of operations for the periods indicated and assuming that the acquisitions occurred on January 1, 2011. Such results are not necessarily indicative of the actual results of operations that would have been realized nor are they necessarily indicative of future results of operations. These pro forma results also do not reflect any cost savings, operating synergies, or revenue enhancements that the Partnership may achieve or the costs necessary to achieve those cost savings, operating synergies or revenue enhancements (dollars in millions):
The pro forma information was adjusted for the following items:
•
Revenues and operating costs were based on actual results for the periods indicated, except that transaction costs related to the acquisitions of Louisiana Midstream and Petal were excluded;
•
Interest expense was based upon the amount of borrowings outstanding and the average cost of debt; and
•
Depreciation and amortization expense was calculated using PPE and intangible asset amounts as determined in the purchase price allocation and estimated useful lives.
Acquisition Costs
In connection with the acquisitions of Louisiana Midstream and Petal, the Partnership incurred $4.3 million of acquisition costs for each of the years ended December 31, 2012 and 2011. Acquisition costs were expensed as incurred and were recorded in administrative and general expenses.
Note 5: 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.
Whistler Junction Matter
The Partnership's Gulf South subsidiary and several other defendants, including Mobile Gas Service Corporation (MGSC), have been named as defendants in nine lawsuits, including one purported class action suit, commenced by multiple plaintiffs in the Circuit Court of Mobile County, Alabama. The plaintiffs seek unspecified damages for personal injury and property damage related to an alleged release of mercaptan at the Whistler Junction facilities in Eight Mile, Alabama. Gulf South delivers natural gas to MGSC, the local distribution company for that region, at Whistler Junction where MGSC odorizes the gas prior to delivery to end user customers by injecting mercaptan into the gas stream, as required by law. The cases are: Parker, et al. v. MGSC, et al. (Case No. CV-12-900711), Crum, et al. v. MGSC, et al. (Case No. CV-12-901057), Austin, et al. v. MGSC, et al. (Case No. CV-12-901133), Moore, et al. v. MGSC, et al. (Case No. CV-12-901471), Davis, et al. v. MGSC, et al. (Case No. CV-12-901490), Joel G. Reed, et al. v. MGSC, et al. (Case No. CV-2013-922265), The Housing Authority of the City of Prichard, Alabama v. MGSC, et al. (Case No. CV-2013-901002), Robert Evans, et al. v. MGSC, et al. (Case No. CV-2013-902627), and Devin Nobles, et al. v. MGSC, et al. (Case No. CV-2013-902786). Gulf South has denied liability. Gulf South has demanded that MGSC indemnify Gulf South against all liability related to these matters pursuant to a right-of-way agreement between Gulf South and MGSC, and has filed cross-claims against MGSC for any such liability. MGSC has also filed cross-claims against Gulf South seeking indemnity and other relief from Gulf South.
Southeast Louisiana Flood Protection Litigation
The Partnership and its subsidiary, Gulf South, along with approximately 100 other energy companies operating in Southern Louisiana, have been named as defendants in a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) by the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (Flood Protection Authority). The case was filed in state court, but was removed to the United States District Court for the Eastern District of New Orleans in August 2013. The plaintiff has moved for remand back to state court, which motion has been argued and is under consideration by the court. The lawsuit claims include negligence, strict liability, public nuisance, private nuisance, breach of contract, and breach of the natural servitude of drain against the defendants, alleging that the defendants’ drilling, dredging, pipeline and industrial operations since the 1930s have caused increased storm surge risk, increased flood protection costs and unspecified damages to the Flood Protection Authority. In addition to attorney fees and unspecified monetary damages, the lawsuit seeks abatement and restoration of the coastal lands, including backfilling and revegetating of canals dredged and used by the defendants, and abatement and restoration activities such as wetlands creation, reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, bank stabilization, and ridge restoration.
The outcome of these cases cannot be predicted at this time; however, based on the facts and circumstances presently known, in the opinion of management, these cases will not be material to the Partnership's or Gulf South'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, 2013, and 2012, the Partnership had an accrued liability of approximately $6.5 million and $7.8 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 eight years. As of December 31, 2013, and 2012, approximately $1.5 million and $2.2 million were recorded in Other current liabilities and approximately $5.0 million and $5.6 million were recorded in Other Liabilities and Deferred Credits.
Clean Air Act
The Partnership’s pipelines are subject to the Clean Air Act, as amended, (CAA) and the CAA Amendments of 1990, as amended, (Amendments) which added significant provisions to the CAA. The Amendments require the Environmental Protection Agency (EPA) to promulgate new regulations pertaining to mobile sources, air toxics, areas of ozone non-attainment, greenhouse gases and regulations affecting reciprocating engines subject to Maximum Achievable Control Technology (MACT). The operating subsidiaries presently operate two facilities in areas affected by non-attainment requirements for the current ozone standard (8-hour ozone standard). If the EPA designates additional new non-attainment areas or promulgates new air regulations where 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 identified in April 2012. The Partnership identified one facility which could require the installation of additional emission controls for compliance between 2014 and 2019. The 8-hour ozone standard is under review by the EPA with final rulemaking expected to be completed in 2014. Revisions to the regulation could lower the 8-hour ozone standard set in 2008 and include a compliance deadline between 2017 and 2031. The Partnership continues to monitor this regulation relative to potentially impacted facilities.
The Partnership is required to file annual reports with the EPA regarding greenhouse gas emissions from its compressor stations, pursuant to final rules issued by the EPA regarding the reporting of greenhouse gas emissions from sources in the United States (U.S.) that annually emit 25,000 or more metric tons of greenhouse gases, including carbon dioxide, methane and others. Additionally, the Partnership is required to conduct periodic and various facility surveys across its entire system to comply with the EPA's greenhouse gas emission calculations and reporting regulations. Some states have also adopted laws regulating greenhouse gas emissions, although none of the states in which the Partnership operates have adopted such laws. The federal rules and determinations regarding greenhouse gas emissions have not had, and are not expected to have, a material effect on the Partnership's financial condition, results of operations or cash flows.
Lease Commitments
The Partnership has various operating lease commitments extending through the year 2019 generally covering office space and equipment rentals. Total lease expense for the years ended December 31, 2013, 2012 and 2011 was approximately $8.6 million, $6.4 million and $4.5 million. The following table summarizes minimum future commitments related to these items at December 31, 2013 (in millions):
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, 2013, were approximately $86.1 million, all of which are expected to be settled in 2014.
Pipeline Capacity Agreements
The Partnership’s operating subsidiaries have entered into pipeline capacity agreements with third-party pipelines that allow the operating subsidiaries to transport gas to off-system markets on behalf of customers. The Partnership incurred expenses of $9.8 million, $9.1 million and $9.8 million related to pipeline capacity agreements for the years ended December 31, 2013, 2012 and 2011. The future commitments related to pipeline capacity agreements as of December 31, 2013, were (in millions):
Capital Lease
In 2012, the Partnership entered into an agreement to construct and lease an office building in Owensboro, Kentucky. The construction of the building was completed and the Partnership took possession of the building in the third quarter 2013, at which time the Partnership recorded a capital lease asset and obligation of $10.5 million. The office building lease has a term of fifteen years with two twenty-year renewal options. Future commitments under this capital lease are as follows (in millions):
Amortization of the office building under the capital lease of $0.3 million is included in depreciation expense. As of December 31, 2013, assets recorded under the capital lease were $10.5 million and the accumulated amortization was $0.3 million.
Note 6: Fair Value Measurements, Derivatives and Other Comprehensive Income (OCI)
The table below identifies the Partnership's assets that were recorded at fair value at December 31, 2013. There were no liabilities recorded at fair value at December 31, 2013 (in millions):
The table below identifies the Partnership's assets and liabilities that were recorded at fair value at December 31, 2012 (in millions):
(1)
In 2012, the Partnership determined that it would retire a number of small-diameter pipeline assets and recorded an asset impairment charge of $5.2 million comprised of the carrying amount of the assets and amounts related to asset retirement obligations for the assets. Additionally, in 2012, the Partnership recorded an asset impairment charge when it determined that it would retire a turbine associated with one of its compressor stations which had a carrying amount of $1.1 million.
(2)
In 2012, the Partnership recognized a $2.8 million impairment charge related to its Owensboro, Kentucky, office building. The office building was sold for an amount that equaled its carrying amount of $3.0 million in the third quarter 2012.
Derivatives
The Partnership uses futures, swaps and option contracts (collectively, derivatives) to hedge exposure to natural gas commodity price risk related to the future operational sales of natural gas and cash for fuel reimbursement where customers pay cash for the cost of fuel used in providing transportation services as opposed to having fuel retained in kind. This price risk exposure includes approximately $0.3 million and $7.0 million of gas stored underground at December 31, 2013, and 2012, which the Partnership owns and carries on its balance sheet as current Gas stored underground. At December 31, 2013, approximately 2.4 billion cubic feet (Bcf) of anticipated future sales of natural gas and cash for fuel reimbursement were hedged with derivatives having settlement dates in 2013 and 2014. The derivatives qualify for cash flow hedge accounting and are designated as such. The Partnership's natural gas derivatives are reported at fair value based on New York Mercantile Exchange (NYMEX) quotes for natural gas futures and options. The NYMEX quotes are deemed to be observable inputs in an active market for similar assets and liabilities and are considered Level 2 inputs for purposes of fair value disclosures.
In September 2012, the Partnership settled $100.0 million notional amount of interest rate swaps outstanding associated with a $200.0 million term loan. The swaps were not designated as cash flow hedges and changes in the fair value of the swaps were recognized as interest expense in the period that those changes occurred. For the year ended December 31, 2012 and 2011, the Partnership recognized interest expense of $2.7 million and $0.3 million related to the interest rate swaps.
In 2012, the Partnership entered into Treasury rate locks for notional amounts of $600.0 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates. The Treasury rate locks were designated as cash flow hedges. The Partnership settled the rate locks concurrently with the issuance of the 10-year notes described in Note 11 and paid the counterparties approximately $7.1 million. The losses were deferred as a component of Accumulated other comprehensive loss and will be amortized to interest expense over the 10-year terms of the notes.
The fair value of derivatives existing as of December 31, 2013 and 2012, were included in the following captions in the Consolidated Balance Sheets (in millions):
The amount of gains and losses from derivatives recognized in the Consolidated Statements of Income for the year ended December 31, 2013, were (in millions):
Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)
Location of gain/(loss) reclassified from AOCI into income (effective portion)
Amount of gain/(loss) reclassified from AOCI into income (effective portion)
Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts
$
1.6
Operating revenues
$
-
N/A
$
-
Net gain on disposal of operating assets
1.2
N/A
-
Interest rate contracts (1)
-
Interest expense
(2.4
)
N/A
-
$
1.6
$
(1.2
)
$
-
(1)
Related to amounts deferred in AOCI from Treasury rate locks used in hedging interest payments associated with debt offerings that were settled in current and previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.
The amount of gains and losses from derivatives recognized in the Consolidated Statements of Income for the year ended December 31, 2012, were (in millions):
Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)
Location of gain/(loss) reclassified from AOCI into income (effective portion)
Amount of gain/(loss) reclassified from AOCI into income (effective portion)
Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts
$
-
Operating revenues (2)
$
0.1
N/A
$
-
Interest rate contracts (1)
(7.1
)
Interest expense
(2.1
)
N/A
-
$
(7.1
)
$
(2.0
)
$
-
(1)
Related to amounts deferred in AOCI from Treasury rate locks used in hedging interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.
(2)
$0.1 million was recorded in Other revenues.
The amount of gains and losses from derivatives recognized in the Consolidated Statements of Income for the year ended December 31, 2011, were (in millions):
Amount of gain/(loss) recognized in AOCI on derivatives (effective portion)
Location of gain/(loss) reclassified from AOCI into income (effective portion)
Amount of gain/(loss) reclassified from AOCI into income (effective portion)
Location of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Amount of gain/(loss) recognized in income on derivative (in- effective portion and amount excluded from effectiveness testing)
Derivatives in Cash Flow Hedging Relationship
Commodity contracts
$
3.1
Operating revenues (2)
$
1.5
N/A
$
-
Interest rate contracts (1)
-
Interest expense
(1.7
)
N/A
-
$
3.1
$
(0.2
)
$
-
(1)
Related to amounts deferred in AOCI from Treasury rate locks used in hedging interest payments associated with debt offerings that were settled in previous periods and are being amortized to earnings over the terms of the related interest payments, generally the terms of the related debt.
(2)
$1.1 million was recorded in Transportation revenues and $0.4 million was recorded in Other revenues.
The Partnership has entered into master netting agreements to manage counterparty credit risk associated with its derivatives; however, it does not offset on its balance sheets fair value amounts recorded for derivative instruments under these agreements. At December 31, 2013, the Partnership's derivatives were with one counterparty. The net receivable position with the Partnership's counterparty was $0.5 million as of December 31, 2013.
In accordance with the contracts governing the Partnership's derivatives, the counterparty or the Partnership may be required to post cash collateral when credit risk exceeds certain thresholds. The threshold for posting collateral with the counterparty
varies based on the credit ratings of the contracting subsidiary of the Partnership or the counterparty. Based on credit ratings at December 31, 2013, the Partnership would be required to post cash collateral to the extent the fair value amount payable to the other party exceeds $10.0 million and the counterparty would be required to post cash collateral to the extent the fair value amount payable to the Partnership exceeds $25.0 million. Additionally, the outstanding derivative contracts contain ratings triggers which would require the Partnership's contracting subsidiary to immediately post collateral in the form of cash or a letter of credit for the full value of any of the derivatives that are in a liability position if the subsidiary's credit rating were reduced below investment grade. At December 31, 2013 and 2012, the Partnership was not required to post any collateral nor did it hold any collateral associated with its outstanding derivatives.
Nonfinancial Assets and Liabilities
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. Refer to the fair value measurements table above for more information.
Financial Assets and Liabilities
The following methods and assumptions were used in estimating the fair value disclosure amounts for financial assets and liabilities:
Cash and Cash Equivalents: For cash and short-term financial assets, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.
Long-Term Debt: The estimated fair value of the Partnership's publicly traded debt is based on quoted market prices at December 31, 2013 and 2012. The fair market value of the debt that is not publicly traded is based on market prices of similar debt at December 31, 2013, and 2012. The carrying amount of the Partnership's variable-rate debt approximates fair value because the instruments bear a floating market-based interest rate.
The carrying amount and estimated fair values of the Partnership's financial assets and liabilities which are not recorded at fair value on the Consolidated Balance Sheets as of December 31, 2013, and 2012, were as follows (in millions):
(1) The carrying amount of long-term debt excludes a $10.0 million capital lease obligation.
Other Comprehensive Income (OCI)
The Partnership estimates that approximately $4.3 million of net gains reported in AOCI as of December 31, 2013, are expected to be reclassified into earnings within the next twelve months. This amount is comprised of a $6.2 million increase to earnings related to net periodic benefit cost and a $1.9 million decrease to earnings related to cash flow hedges. The following table shows the components and reclassifications to net income of Accumulated other comprehensive loss which is included in Partners' Capital on the Consolidated Balance Sheets for the year ended December 31, 2013 (in millions):
The following table shows the components and reclassifications to net income of Accumulated other comprehensive loss which is included in Partners' Capital on the Consolidated Balance Sheets for the year ended December 31, 2012 (in millions):
Note 7: Property, Plant and Equipment (PPE)
The following table presents the Partnership’s PPE as of December 31, 2013 and 2012 (in millions):
The non-depreciable assets were not included in the calculation of the weighted-average useful lives.
The Partnership holds undivided interests in certain assets, including the Bistineau storage facility of which the Partnership owns 92%, the Mobile Bay Pipeline of which the Partnership owns 64% and offshore and other assets, comprised of pipeline and gathering assets in which the Partnership holds various ownership interests. Through the acquisition of Louisiana Midstream, the Partnership owns 83% of two ethylene wells and supporting surface facilities in Choctaw, Louisiana, and certain ethylene and propylene pipelines connecting Louisiana Midstream’s storage facilities in Choctaw to chemical manufacturing plants in Geismar, Louisiana.
The proportionate share of investment associated with these interests has been recorded as PPE on the balance sheets. The Partnership records its portion of direct operating expenses associated with the assets in Operation and maintenance expense. The following table presents the gross PPE investment and related accumulated depreciation for the Partnership’s undivided interests as of December 31, 2013 and 2012 (in millions):
Certain amounts shown in the tables above for 2012 have been corrected to conform to the 2013 presentation. General, Rights of way and other and Total utility depreciable plant were previously reported as $144.4 million, $121.6 million and $8,057.6
million, with weighted average useful lives of 14, 32 and 36 years. Non-depreciable other and total non-depreciable assets were reported as $1.0 million and $365.7 million. As of December 31, 2012, the gross PPE investment and related accumulated depreciation for the NGL pipelines and facilities were previously excluded from the table.
Asset Dispositions and Impairment Charges
The Partnership recognized $4.1 million, $9.1 million and $30.5 million of asset impairment charges for the years ended December 31, 2013, 2012 and 2011. Refer to Note 6 for more information or to Materials and Supplies below for further discussion of the 2011 asset impairment charge.
Gas Sales
For the year ended December 31, 2013, the Partnership recognized a gain of $29.9 million from the sale of approximately 14.9 Bcf of natural gas stored underground with a carrying amount of $26.0 million. The gas was sold as a result of a strategy to monetize storage base gas and provide capacity for additional parks of customer gas under PAL service as well as a result of a change in the storage gas needed to support operations and no-notice services.
In 2011, the Partnership recognized a gain of $9.2 million from the sale of approximately 4.5 Bcf of gas stored underground with a carrying amount of $10.3 million that became available for sale due to a change in the storage working gas needed to support operations and no-notice services.
The gains related to these gas sales were recorded in Net gain on disposal of operating assets.
Carthage Compressor Station Incident
In 2011, a fire occurred at one of the Partnership’s compressor stations near Carthage, Texas, which caused significant damage to the compressor building, the compressor units and related equipment housed in the building. In 2011, the Partnership recognized expenses of $5.0 million for the amounts of costs incurred which were subject to an insurance deductible and recorded a receivable of $8.8 million related to probable recoveries from insurance for expenses incurred that exceeded the deductible amount. The Partnership received a total of $11.7 million in insurance proceeds, of which $1.7 million and $1.2 million were recorded as a reduction in Operation and maintenance expense for the years ended December 31, 2013 and 2012.
Materials and Supplies
The Partnership holds materials and supplies comprised of pipe, valves, fittings and other materials to support its ongoing operations and for potential future growth projects. In 2011, the Partnership determined that a portion of the materials and supplies would not be used given the types of projects the Partnership would likely pursue under its growth strategy and the costs to carry and maintain the materials and recognized an impairment charge of $28.8 million to adjust the carrying amount of those materials and supplies to an estimated fair value of $6.4 million. The fair value of the materials was determined by obtaining information from brokers, resellers and distributors of these types of materials which are considered Level 3 inputs under the fair value hierarchy. The materials were subsequently sold, resulting in net realized gains of $0.5 million and $3.7 million and $2.9 million for the years ended December 31, 2013, 2012 and 2011. At December 31, 2013 and 2012, the Partnership held approximately $12.8 million and $17.8 million of materials and supplies which was reflected in Other Assets on the Consolidated Balance Sheets.
Bistineau Storage Gas Loss
In 2011, the Partnership completed a series of tests to verify the quantity of gas stored at its Bistineau storage facility. These tests indicated that a gas loss of approximately 6.7 Bcf occurred at the facility. As a result, the Partnership recorded a charge to Fuel and gas transportation expense of $3.7 million to recognize the loss in base gas which had a carrying amount of $0.53 per MMBtu.
Note 8: Goodwill and Intangible Assets
Goodwill
The Partnership performed its annual goodwill impairment test for its three reporting units as of November 30, 2013. The results of the quantitative goodwill impairment test indicated that the fair value of two of the Partnership’s reporting units significantly exceeded their carrying amounts and no goodwill impairment charges were recognized for those reporting units. The carrying amount of the third reporting unit, which included goodwill associated with the Petal acquisition, exceeded the estimated fair value and the second step of the goodwill impairment test was performed. In the fourth quarter 2013, the Partnership recognized a goodwill impairment charge of $51.5 million, representing the carrying amount of the goodwill for that reporting unit. The fair value of the reporting unit declined from the amount determined in 2012 due primarily to recent narrowing of time period price spreads and reduced volatility which negatively affects the value of the Partnership’s storage and PAL services and the cumulative effect of reduced basis spreads on the value of the Partnership’s transportation services. No impairment charge related to goodwill was recorded for any of the Partnership’s reporting units during 2012 or 2011.
Changes in the gross amounts of goodwill for the Partnership are summarized as follows (in millions):
(1) Refer to Note 4 for further information on the acquisition of Louisiana Midstream.
Intangible Assets
The following table contains information regarding the Partnership's intangible assets, which includes customer relationships acquired as part of the purchase of Louisiana Midstream and Petal (in millions):
For the year ended December 31, 2013 and 2012, amortization expense for intangible assets totaled $1.3 million and $0.8 million and was recorded in Depreciation and amortization on the Consolidated Statements of Income. Amortization expense for the year ended December 31, 2011, was less than $0.1 million. Amortization expense for the next five years and in total thereafter as of December 31, 2013, is expected to be as follows (in millions):
The weighted-average remaining useful life of the Partnership's intangible assets as of December 31, 2013 is 30 years.
Note 9: Asset Retirement Obligations (ARO)
The Partnership has identified and recorded legal obligations associated with the abandonment of certain pipeline and storage assets, brine ponds, offshore facilities and the abatement of asbestos consisting of removal, transportation and disposal when removed from certain compressor stations and meter station buildings. Legal obligations exist for the main pipeline and certain other Partnership assets; however, the fair value of the obligations cannot be determined because the lives of the assets are indefinite and therefore cash flows associated with retirement of the assets cannot be estimated with the degree of accuracy necessary to establish a liability for the obligations.
The following table summarizes the aggregate carrying amount of the Partnership’s ARO (in millions):
1)
Represents the fair value of the asset retirement obligations assumed through the acquisition of Louisiana Midstream.
For the Partnership’s operations where regulatory accounting is applicable, depreciation rates for PPE are comprised of two components. One component is based on economic service life (capital recovery) and the other is based on estimated costs of removal (as a component of negative salvage) which is collected in rates and does not represent an existing legal obligation. The Partnership has reflected $57.6 million and $57.4 million as of December 31, 2013 and 2012, in the accompanying Consolidated Balance Sheets as Provision for other asset retirement related to the estimated cost of removal collected in rates.
Note 10: Regulatory Assets and Liabilities
The amounts recorded as regulatory assets and liabilities in the Consolidated Balance Sheets as of December 31, 2013 and 2012, are summarized in the table below. The table also includes amounts related to unamortized debt expense and unamortized discount on long-term debt. While these amounts are not regulatory assets and liabilities, they are a critical component of the embedded cost of debt financing utilized in the Texas Gas rate proceedings. The tax effect of the equity component of AFUDC represents amounts recoverable from rate payers for the tax recorded in regulatory accounting. Certain amounts in the table are reflected as a negative, or a reduction, to be consistent with the regulatory books of account. The period of recovery for the regulatory assets included in rates varies from one to eighteen years. The remaining period of recovery for regulatory assets not yet included in rates would be determined in future rate proceedings. None of the regulatory assets shown below were earning a return as of December 31, 2013 and 2012 (in millions):
Note 11: Financing
Long-Term Debt
The following table presents all long-term debt issues outstanding as of December 31, 2013 and 2012 (in millions):
Maturities of the Partnership’s long-term debt for the next five years and in total thereafter are as follows (in millions):
Notes and Debentures
As of December 31, 2013 and 2012, the weighted-average interest rate of the Partnership's notes and debentures was 5.32%. For the years ended December 31, 2013, 2012 and 2011, the Partnership completed the following debt issuances (in millions, except interest rates):
(1)
The net proceeds of this offering were used to reduce borrowings under the Partnership’s revolving credit facility and Subordinated Loan.
(2)
The net proceeds of this offering were used to reduce borrowings under the Partnership’s revolving credit facility and to redeem $225.0 million of Gulf South's 5.75% notes due August 2012 (2012 Notes) discussed below.
(3)
The net proceeds of these offerings were used to reduce borrowings under the Partnership’s revolving credit facility and to redeem $250.0 million of Texas Gas’ 5.50% notes due April 2013 (2013 Notes) discussed below.
The Partnership’s notes and debentures are redeemable, in whole or in part, at the Partnership’s option at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes to be redeemed or a “make whole” redemption price based on the remaining scheduled payments of principal and interest discounted to the date of redemption at a rate equal to the Treasury rate plus 20 to 50 basis points depending upon the particular issue of notes, plus accrued and unpaid interest, if any. Other customary covenants apply, including those concerning events of default.
The indentures governing the notes and debentures have restrictive covenants which provide that, with certain exceptions, neither the Partnership nor any of its subsidiaries may create, assume or suffer to exist any lien upon any property to secure any indebtedness unless the debentures and notes shall be equally and ratably secured. All of the Partnership's debt obligations are unsecured. At December 31, 2013, Boardwalk Pipelines and its operating subsidiaries were in compliance with their debt covenants.
Redemption of Notes
In August 2012, the 2012 Notes matured and were retired in full. The retirement of this debt was financed through the issuance of the 4.00% Gulf South notes due 2022.
In 2011, the Partnership redeemed the 2013 Notes at a premium of $21.0 million. The Partnership had unamortized discounts and deferred offering costs of $1.1 million related to the 2013 Notes. Due to the application of regulatory accounting, approximately $8.9 million of the premium and unamortized discounts related to the 2013 Notes were recognized as a regulatory
asset, and will be amortized over the life of the Texas Gas 4.50% notes due 2021. The remaining $13.2 million was recognized as a loss on early extinguishment of debt.
Revolving Credit Facility
The Partnership has a revolving credit facility which has aggregate lending commitments of $1.0 billion. Outstanding borrowings under the credit facility as of December 31, 2013, and 2012, were $175.0 million and $302.0 million with a weighted-average borrowing rate of 1.29% and 1.34%. As of February 21, 2014, the Partnership had outstanding borrowings of $250.0 million, resulting in available borrowing capacity of $750.0 million.
In April 2012, the Partnership entered into a Second Amended and Restated Revolving Credit Agreement (Amended Credit Agreement) with Wells Fargo Bank, N.A., as Administrative Agent, having aggregate lending commitments of $1.0 billion, a maturity date of April 27, 2017, and including Gulf Crossing, Gulf South, Texas Gas, Boardwalk Pipelines and Boardwalk Midstream, LLC, as borrowers. Interest is determined, at the Partnership's election, by reference to (a) the base rate which is the highest of (1) the prime rate, (2) the federal funds rate plus 0.50%, and (3) the one month Eurodollar Rate plus 1.0%, plus an applicable margin, or (b) the LIBOR plus an applicable margin. The applicable margin ranges from 0.00% to 0.875% for loans bearing interest tied to the base rate and ranges from 1.00% to 1.875% for loans bearing interest based on the LIBOR rate, in each case determined based on the individual borrower's credit rating from time to time. The Amended Credit Agreement also provides for a quarterly commitment fee charged on the average daily unused amount of the revolving credit facility ranging from 0.125% to 0.30% and determined based on the individual borrower's credit rating from time to time.
The credit facility contains various restrictive covenants and other usual and customary terms and conditions, including restrictions regarding the incurrence of additional debt, the sale of assets and sale-leaseback transactions. The financial covenants under the credit facility require the Partnership and its subsidiaries to maintain, among other things, a ratio of total consolidated debt to consolidated EBITDA (as defined in the credit agreement) measured for the previous twelve months of not more than 5.0 to 1.0, or up to 5.5 to 1.0 for the three quarters following an acquisition. The Partnership and its subsidiaries were in compliance with all covenant requirements under the credit facility as of December 31, 2013.
Term Loan
The Partnership has a $225.0 million variable-rate term loan due October 1, 2017 (2017 Term Loan), which was used to fund the Louisiana Midstream acquisition. The 2017 Term Loan bears interest at a rate that is based on the one-month LIBOR plus an applicable margin. Outstanding borrowings as of December 31, 2013 and 2012, were $225.0 million, with a weighted-average borrowing interest rate of 1.92% and 1.96%.
The Partnership's Petal subsidiary had a $200.0 million variable-rate term loan due December 1, 2016 (Petal Term Loan) that was repaid in full in September 2012. Interest on the Petal Term Loan was payable monthly at a rate that was based on the one-month LIBOR rate plus an applicable margin. There is no further borrowing capacity under this term loan.
Long-Term Debt - Affiliate
At December 31, 2011, the Partnership had $100.0 million of long-term debt outstanding under a Subordinated Loan Agreement with BPHC (Subordinated Loan), with no additional borrowing capacity available. The Subordinated Loan bore interest at 8.00% per year, payable semi-annually in June and December. In the event the Partnership or its subsidiaries issued additional equity securities or incurred certain indebtedness, the Subordinated Loan was required to be repaid with the net cash proceeds from those issuances; although BPHC was entitled to waive such prepayment provision. In November 2012, the Partnership repaid the $100.0 million of Subordinated Loan outstanding and has no further borrowing capacity available. The retirement of this debt was financed using proceeds from the Partnership's November debt offering.
Common Unit Offering
For the years ended December 31, 2013, 2012 and 2011, the Partnership completed the following issuances and sales of common units (in millions, except the issuance price):
(1)
BPHC waived the prepayment provisions under the Subordinated Loans that would have required prepayment of the Subordinated Loans as a result of these issuances.
The proceeds of the May 2013, August 2012 and June 2011, offerings were used to reduce borrowings under the Partnership’s revolving credit facility; the proceeds of the February 2012 offering were used to purchase the remaining equity interests in Petal; and the proceeds of the October 2012 offering were used to purchase the remaining equity interests in Louisiana Midstream. In addition to funds received from the issuance and sale of common units, the general partner concurrently contributed amounts to maintain its 2% interest in the Partnership.
Summary of Changes in Outstanding Units
The following table summarizes changes in the Partnership’s common and class B units since January 1, 2011 (in millions):
(1)
On October 9, 2013, all of the 22.9 million class B units were converted into common units on a one-for-one basis, pursuant to the terms of the partnership agreement.
Registration Rights Agreement
The Partnership has entered into an Amended and Restated Registration Rights Agreement with BPHC under which the Partnership has agreed to register the resale by BPHC of 27.9 million common units and to reimburse BPHC up to a maximum amount of $0.914 per common unit for underwriting discounts and commissions. As of December 31, 2013 and 2012, the Partnership had an accrued liability of approximately $16.0 million for future underwriting discounts and commissions that would be reimbursed to BPHC and other registration and offering costs that are expected to be incurred by the Partnership.
Note 12: Employee Benefits
Retirement Plans
Defined Benefit Retirement Plans
Texas Gas employees hired prior to November 1, 2006, are covered under a non-contributory, defined benefit pension plan (Pension Plan). The Texas Gas Supplemental Retirement Plan (SRP) provides pension benefits for the portion of an eligible employee’s pension benefit under the Pension Plan that becomes subject to compensation limitations under the Internal Revenue Code. Collectively, the Partnership refers to the Pension Plan and the SRP as Retirement Plans. The Partnership uses a measurement date of December 31 for its Retirement Plans.
As a result of the Texas Gas rate case settlement in 2006, the Partnership is required to fund the amount of annual net periodic pension cost associated with the Pension Plan, including a minimum of $3.0 million which is the amount included in rates. In 2013 and 2012, the Partnership funded $3.0 million and $7.5 million to the Pension Plan and expects to fund approximately $3.0 million to the plan in 2014. The Partnership does not anticipate that any Pension Plan assets will be returned to the Partnership during 2014. In 2013 and 2012, there were no payments made under the SRP. The Partnership does not expect to fund the SRP until such time as benefits are paid.
The Partnership recognizes in expense each year the actuarially determined amount of net periodic pension cost associated with its Retirement Plans, including a minimum amount of $3.0 million related to its Pension Plan, in accordance with the 2006 rate case settlement. Texas Gas is permitted to seek future rate recovery for amounts of annual Pension Plan costs in excess of $6.0 million and is precluded from seeking future recovery of annual Pension Plan costs between $3.0 million and $6.0 million. As a result, the Partnership would recognize a regulatory asset for amounts of annual Pension Plan costs in excess of $6.0 million and would reduce its regulatory asset to the extent that annual Pension Plan costs are less than $3.0 million. Annual Pension Plan costs between $3.0 million and $6.0 million will be charged to expense.
Postretirement Benefits Other Than Pension (PBOP)
Texas Gas provides postretirement medical benefits and life insurance to retired employees who were employed full time, hired prior to January 1, 1996, and have met certain other requirements. In 2013 and 2012, the Partnership made $0.1 million and $0.2 million of contributions to the PBOP plan. The PBOP plan is currently in an overfunded status, therefore the Partnership does not expect to make any contributions to the plan in 2014. The Partnership does not anticipate that any plan assets will be returned to the Partnership during 2014. The Partnership uses a measurement date of December 31 for its PBOP plan.
Projected Benefit Obligation, Fair Value of Assets and Funded Status
The projected benefit obligation, fair value of assets, funded status and the amounts not yet recognized as components of net periodic pension and postretirement benefits cost for the Retirement Plans and PBOP at December 31, 2013 and 2012, were as follows (in millions):
At December 31, 2013 and 2012, the following aggregate information relates only to the underfunded plans (in millions):
Components of Net Periodic Benefit Cost
Components of net periodic benefit cost for both the Retirement Plans and PBOP for the years ended December 31, 2013, 2012 and 2011 were as follows (in millions):
Due to the Texas Gas rate case settlement in 2006, Texas Gas is permitted to seek future rate recovery for amounts of annual Pension Plan costs in excess of $6.0 million.
Estimated Future Benefit Payments
The following table shows benefit payments, which reflect expected future service, as appropriate, which are expected to be paid for both the Retirement Plans and PBOP (in millions):
Weighted -Average Assumptions
Weighted-average assumptions used to determine benefit obligations for the years ended December 31, 2013 and 2012, were as follows:
Weighted-average assumptions used to determine net periodic benefit cost for the periods indicated were as follows:
(1) Pension expense was remeasured at September 30, 2013, to reflect a settlement.
The long-term rate of return for plan assets was determined based on widely-accepted capital market principles, long-term return analysis for global fixed income and equity markets as well as the active total return oriented portfolio management style. Long-term trends are evaluated relative to market factors such as inflation, interest rates and fiscal and monetary policies, in order to assess the capital market assumptions as applied to the plan. Consideration of diversification needs and rebalancing is maintained.
PBOP Assumed Health Care Cost Trends
Assumed health care cost trend rates have a significant effect on the amounts reported for PBOP. A one-percentage-point change in assumed trend rates for health care costs would have had the following effects on amounts reported for the year ended December 31, 2013 (in millions):
For measurement purposes, for December 31, 2013, health care cost trend rates for the plans were assumed to remain at 8.5% for 2014-2015, grading down to 5.0% by 2022, assuming 0.5% annual increments for all participants. For December 31, 2012, health care cost trend rates for the plans were assumed to increase 8.5% for 2013-2014, grading down to 5.0% in 0.5% annual increments for all participants.
Pension Plan and PBOP Asset Allocation and Investment Strategy
Pension Plan
The Pension Plan investments are held in a trust account and consist of an undivided interest in an investment account of the Loews Corporation Employees Retirement Trust (Master Trust), established by Loews and its participating subsidiaries. Use of the Master Trust permits the commingling of trust assets of the Pension Plan with the assets of the Loews Corporation Cash Balance Retirement Plan for investment and administrative purposes. Although assets of all plans are commingled in the Master Trust, the custodian maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the participating plans. The net investment income of the investment assets is allocated by the custodian to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. The Master Trust assets are measured at fair value. The fair value of the interest in the assets of the Master Trust associated with the Pension Plan as of December 31, 2013 and 2012, was $131.4 million (or 51.0%) and $125.7 million (or 50.9%), of the total Master Trust assets.
Equity securities are publicly traded securities which are valued using quoted market prices and are considered a Level 1 investment under the fair value hierarchy. Short-term investments that are actively traded or have quoted prices, such as money
market funds, are considered a Level 1 investment. Fixed income mutual funds are actively traded and valued using quoted market prices and are considered a Level 1 investment. Corporate and other taxable bonds and asset-backed securities are valued using pricing for similar securities, recently executed transactions, cash flow models with yield curves, broker/dealer quotes and other pricing models utilizing observable inputs and are considered Level 2 investments. The limited partnership and other invested assets consist primarily of hedge funds, whose fair value represents the Master Trust’s share of the net asset value of each company, as determined by the general partner. Level 2 limited partnership and other invested assets include investments which can be redeemed at net asset value in 90 days or less. The limited partnership investments that contain withdrawal provisions greater than 90 days or at the termination of the partnership are considered Level 3 investments.
The following table sets forth by level within the fair value hierarchy a summary of the Master Trust’s investments measured at fair value on a recurring basis at December 31, 2013 (in millions):
The following table sets forth by level within the fair value hierarchy a summary of the Master Trust’s investments measured at fair value on a recurring basis at December 31, 2012 (in millions):
The following table presents a reconciliation of the beginning and ending balances of the fair value measurements using significant unobservable inputs (Level 3) for the Master Trust (in millions):
PBOP
The PBOP plan assets are held in a trust and are measured at fair value. Short-term investments that are actively traded or have quoted prices, such as money market or mutual funds, are considered a Level 1 investment. Fixed income mutual funds are actively traded and valued using quoted market prices and are considered Level 1 investments. Tax exempt securities, consisting of municipal securities, corporate and other taxable bonds and asset-backed securities are valued using pricing for similar securities, recently executed transactions, cash flow models with yield curves, broker/dealer quotes and other pricing models utilizing observable inputs and are considered Level 2 investments.
The following table sets forth by level within the fair value hierarchy a summary of the PBOP trust investments measured at fair value on a recurring basis at December 31, 2013 (in millions):
The following table sets forth by level within the fair value hierarchy a summary of the PBOP trust investments measured at fair value on a recurring basis at December 31, 2012 (in millions):
There were no Level 3 assets at December 31, 2013 and 2012.
Investment strategy
Pension Plan: The Partnership employs a total-return approach using a mix of equities and fixed income investments to maximize the long-term return on plan assets and generate cash flows adequate to meet plan requirements. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of the plan liabilities, plan funded status and corporate financial conditions. The investment strategy has been to allocate between 40% and 60% of the investment portfolio to equity and alternative investments, including limited partnerships, with consideration given to market conditions and target asset returns. The investment portfolio contains a diversified blend of fixed income, equity and short-term securities. Alternative investments, including limited partnerships, have been used to enhance risk adjusted long-term returns while improving portfolio diversification. At December 31, 2013, the pension trust had committed $5.8 million to future capital calls from various third party limited partnership investments in exchange for an ownership interest in the related partnerships. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset and liability studies and quarterly investment portfolio reviews.
PBOP: The investment strategy for the PBOP assets is to reduce the volatility of plan investments while protecting the initial investment given the overfunded status of the plan. At December 31, 2013 and 2012, all of the PBOP investments were in fixed income securities.
Defined Contribution Plans
Texas Gas employees hired on or after November 1, 2006, and other employees of the Partnership are provided retirement benefits under a defined contribution money purchase plan. The Partnership also provides 401(k) plan benefits to their employees. Costs related to the Partnership’s defined contribution plans were $8.6 million, $8.0 million and $7.4 million for the years ended December 31, 2013, 2012 and 2011.
Long-Term Incentive Compensation Plans
The Partnership grants to selected employees long-term compensation awards under the LTIP, the UAR and Cash Bonus Plan, and previously made grants under the Strategic Long-Term Incentive Plan (SLTIP). These awards are intended to align the interests of the employees with those of the Partnership’s unitholders, encourage superior performance, attract and retain employees who are essential for the Partnership’s growth and profitability and to encourage employees to devote their best efforts to advancing the Partnership’s business over both long and short-term time horizons. The Partnership also makes annual grants of common units to certain of its directors under the LTIP.
LTIP
The Partnership reserved 3,525,000 common units for grants of units, restricted units, unit options and unit appreciation rights to officers and directors of the Partnership’s general partner and for selected employees under the LTIP. The Partnership has outstanding phantom common units (Phantom Common Units) which were granted under the plan. Each such grant: includes a tandem grant of Distribution Equivalent Rights (DERs); vests on the third anniversary of the grant date; and will be payable to the grantee in cash, but may be settled in common units at the discretion of the Partnership’s Board of Directors, upon vesting in an amount equal to the sum of the fair market value of the units (as defined in the plan) that vest on the vesting date, less applicable taxes. The vested amount then credited to the grantee’s DER account is payable only in cash, less applicable taxes. The economic value of the Phantom Common Units is directly tied to the value of the Partnership’s common units, but these awards do not confer any rights of ownership to the grantee. The fair value of the awards will be recognized ratably over the vesting period and remeasured each quarter until settlement based on the market price of the Partnership’s common units and amounts credited under the DERs. The Partnership has not made any grants of units, restricted units, unit options or unit appreciation rights under the plan.
A summary of the status of the Phantom Common Units granted under the Partnership’s LTIP as of December 31, 2013 and 2012, and changes during the years ended December 31, 2013 and 2012, is presented below:
(1)
Represents fair value and remaining weighted-average vesting period of outstanding awards at the end of the period.
(2)
Includes 24,270 of Phantom Common Units with a total value of $0.8 million which vested on December 16, 2011 and were paid in cash on January 20, 2012.
The fair value of the awards at the date of grant was based on the closing market price of the Partnership’s common units on or directly preceding the date of grant. The fair value of the awards at December 31, 2013 and 2012 was based on the closing market price of the common unit on those dates of $25.52 and $24.90 plus the accumulated value of the DERs. The fair value of the awards will be recognized ratably over the vesting period and remeasured each quarter until settlement in accordance with the treatment of awards classified as liabilities. The Partnership recorded $3.2 million, $1.5 million and $0.3 million in Administrative and general expenses during 2013, 2012 and 2011 for the ratable recognition of the fair value of the Phantom Common Unit awards. The total estimated remaining unrecognized compensation expense related to the Phantom Common Units outstanding at December 31, 2013 and 2012, was $6.1 million and $3.1 million.
In 2013 and 2012 the general partner purchased 7,484 and 2,000 of the Partnership’s common units in the open market at a price of $26.72 and $27.24 per unit. These units were granted under the LTIP to the independent directors as part of their director compensation. At December 31, 2013, 3,506,224 units were available for grants under the LTIP.
UAR and Cash Bonus Plan
The UAR and Cash Bonus Plan provides for grants of UARs and Long-Term Cash Bonuses to selected employees of the Partnership. As of December 31, 2013, there were no Long-Term Cash Bonuses outstanding. The Partnership recorded compensation expense of $0.5 million, $0.6 million and $0.5 million for the years ended December 31, 2013, 2012 and 2011 related to the Long-Term Cash Bonuses.
The economic value of the UARs is tied to the value of the Partnership’s common units, but these awards do not confer any rights of ownership to the grantee. Under the terms of the UAR and Cash Bonus Plan, after the expiration of a restricted period (vesting period) each awarded UAR would become vested and payable in cash to the extent the fair market value (as defined in the plan) of a common unit on such date exceeds the exercise price. Each UAR includes a feature whereby the exercise price is reduced by the amount of any cash distributions made by the Partnership with respect to a common unit during the restricted period (DER Adjustment). Except in limited circumstances, upon termination of employment during the restricted period, any outstanding and unvested awards of UARs would be cancelled unpaid. The fair value of the UARs will be recognized ratably over the vesting period, and will be remeasured each quarter until settlement in accordance with the treatment of awards classified as liabilities.
A summary of the outstanding UARs granted under the Partnership’s UAR and Cash Bonus Plan as of December 31, 2013 and 2012, and changes during 2013 and 2012 is presented below:
(1)
Represents weighted-average exercise price, remaining weighted-average vesting period and total fair value of outstanding awards at the end of the period.
(2)
Represents the weighted-average exercise price and weighted-average vesting period of awards at grant date. The exercise price for each UAR granted was set at $26.46, the closing price of the Partnership’s common units on the New York Stock Exchange on the grant date on March 31, 2012.
(3)
Represents the weighted-average exercise price and weighted-average vesting period of awards at grant date. The exercise price for each UAR granted was set at $27.90, the closing price of the Partnership’s common units on the New York Stock Exchange on the grant date on September 30, 2012.
(4)
Represents the weighted-average exercise price and weighted-average vesting period of awards at grant date. The exercise price for each UAR granted was set at $27.57, the closing price of the Partnership’s common units on the New York Stock Exchange on the grant date on February 7, 2013.
The fair value of the UARs were based on the computed value of a call on the Partnership’s common units at the exercise price. The following assumptions were used as inputs to the Black-Scholes valuation model for grants made during 2013 and 2012:
(1)
Based on the U.S. Treasury yield curve corresponding to the remaining life of the UAR.
(2)
Based on the historical volatility of the Partnership’s common units.
The Partnership recorded compensation expense of $0.9 million, $0.3 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011 related to the UARs. As of December 31, 2013 and 2012, there was $0.9 million and $0.8 million of total unrecognized compensation cost related to the non-vested portion of the UARs.
SLTIP
The SLTIP provided for the issuance of up to 500 phantom general partner units (Phantom GP Units) to selected employees of the Partnership and its subsidiaries. The Partnership recorded $0.2 million, $2.3 million and $2.5 million in Administrative and general expenses during 2013, 2012 and 2011 for the ratable recognition of the fair value of the GP Phantom Unit awards. There are no GP Phantom Units outstanding at December 31, 2013, and no additional grants of Phantom GP Units are expected to be made under the SLTIP.
A summary of the status of the Partnership’s SLTIP as of December 31, 2013 and 2012, and changes during the years ended December 31, 2013 and 2012, is presented below:
(1)
Represents fair value and remaining weighted-average vesting period of outstanding awards at the end of the period.
Note 13: Cash Distributions and Net Income per Unit
Cash Distributions
The Partnership’s cash distribution policy requires that the Partnership distribute to its various ownership interests on a quarterly basis all of its available cash, as defined in its partnership agreement. IDRs, which represent a limited partner ownership interest and are currently held by the Partnership’s general partner, represent the contractual right to receive an increasing percentage of quarterly distributions of available cash as follows:
(1)
The class B unitholders participated in distributions on a pari passu basis with the Partnership’s common units up to $0.30 per unit per quarter. The class B units did not participate in quarterly distributions above $0.30 per unit and converted into common units on a one-for-one basis on October 9, 2013.
The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common and class B units and the 2% general partner interest and IDRs held by its general partner as follows (in millions, except distribution per unit):
(1)
In 2013, 2012 and 2011, the Partnership paid $34.6 million, $30.1 million and $22.3 million in distributions on behalf of IDRs.
(2)
On October 9, 2013, all of the 22.9 million Class B units were converted into common units on a one-for-one basis, pursuant to the terms of the partnership agreement.
In February 2014, the Partnership declared a quarterly cash distribution to unitholders of record of $0.10 per common unit.
Net Income per Unit
For purposes of calculating net income per unit, net income for the current period is reduced by the amount of available cash that will be distributed with respect to that period. Any residual amount representing undistributed net income (or loss) is assumed to be allocated to the various ownership interests in accordance with the contractual provisions of the partnership agreement.
Under the Partnership’s partnership agreement, for any quarterly period, the IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income or losses. Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro rata basis, except that the class B units’ participation in net income was limited to $0.30 per unit per quarter. The Class B units were converted to common units on a one-for-one basis in October 2013. Payments made on account of the Partnership’s various ownership interests are determined in relation to actual declared distributions, and are not based on the assumed allocations required under GAAP.
The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing basic and diluted net income per unit for the year ended December 31, 2013. Basic net income per unit is calculated based on the weighted average number of units outstanding for the period. Diluted net income per unit is calculated assuming that the class B units converted on the date that they became convertible, or July 1, 2013, (in millions, except per unit data):
The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing net income per unit for the year ended December 31, 2012, (in millions, except per unit data):
The following table provides a reconciliation of net income and the assumed allocation of net income to the common and class B units for purposes of computing net income per unit for the year ended December 31, 2011 (in millions, except per unit data):
Note 14: 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. The subsidiaries of the Partnership directly incur some income-based state taxes which are presented in Income taxes on the Consolidated Statements of Income.
Following is a summary of the provision for income taxes for the periods ended December 31, 2013, 2012 and 2011 (in millions):
The Partnership’s tax years 2010 through 2013 remain subject to examination by the Internal Revenue Service and the states in which it operates. There were no differences between the provision at the statutory rate to the income tax provision at December 31, 2013, 2012 and 2011. As of December 31, 2013 and 2012, there were no significant deferred income tax assets or liabilities.
Note 15: Credit Risk
Major Customers
Operating revenues received from the Partnership’s major customer (in millions) and the percentage of total operating revenues earned from that customer were:
Gas Loaned to Customers
Natural gas price volatility can cause changes in credit risk related to gas and NGLs loaned to customers. As of December 31, 2013, the amount of gas owed to the operating subsidiaries due to gas imbalances and gas loaned under PAL agreements was approximately 19.6 TBtu. Assuming an average market price during December 2013 of $4.17 per MMBtu, the market value of that gas was approximately $81.7 million. As of December 31, 2013, there were no outstanding imbalances owed to the operating subsidiaries from NGLs. As of December 31, 2012, the amount of gas owed to the operating subsidiaries due to gas imbalances and gas loaned under PAL agreements was approximately 11.7 TBtu. Assuming an average market price during December 2012 of $3.32 per MMBtu, the market value of this gas at December 31, 2012, would have been approximately $38.8 million. As of December 31, 2012, the amount of NGLs owed to the operating subsidiaries due to imbalances was approximately 0.1 MMbbls, which had a market value of approximately $6.8 million. If any significant customer should have credit or financial problems resulting in a delay or failure to repay the gas owed to the operating subsidiaries, it could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.
Note 16: Related Party Transactions
Loews provides a variety of corporate services to the Partnership under services agreements, including but not limited to, information technology, tax, risk management, internal audit and corporate development services, plus allocated overheads. The Partnership incurred charges related to these services of $8.3 million, $8.3 million and $18.3 million for the years ended December 31, 2013, 2012 and 2011.
Distributions paid related to limited partner units held by BPHC and the 2% general partner interest and IDRs held by Boardwalk GP were $296.8 million, $285.7 million and $273.3 million for the years ended December 31, 2013, 2012 and 2011.
In 2013, the Partnership entered into agreements with BPHC to form Boardwalk Bluegrass and Boardwalk Moss Lake. Refer to Note 3 for further information. For the year ended December 31, 2013, the Partnership contributed $11.9 million and BPHC contributed $90.0 million of cash and assets to these entities.
Note 17: Supplemental Disclosure of Cash Flow Information (in millions):
(1)
The 2012 period includes payments of $9.6 million related to the settlements of interest rate derivatives and the 2011 period includes premium payments of $21.0 million related to the 2013 Notes redemption.
(2)
The 2012 amount was restated to include $1.9 million previously excluded.
Note 18: Selected Quarterly Financial Data (Unaudited)
The following tables summarize selected quarterly financial data for 2013 and 2012 for the Partnership (in millions, except for earnings per unit):
Note 19: Guarantee of Securities of Subsidiaries
Boardwalk Pipelines (subsidiary issuer) has issued securities which have been fully and unconditionally guaranteed by the Partnership (parent guarantor). The Partnership's subsidiaries have no significant restrictions on their ability to pay distributions or make loans to the Partnership except as noted in the debt covenants and have no restricted assets at December 31, 2013 and 2012. Note 11 contains additional information regarding the Partnership's debt and related covenants.
The Partnership has provided the following condensed consolidating financial information in accordance with Regulation S-X Rule 3-10, Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered. The 2012 Condensed Consolidating Statements of Comprehensive Income Subsidiary Issuer and Elimination columns were increased by $6.7 million in the Gain (loss) on cash flow hedges line, increased by $0.3 million in the Reclassification adjustment transferred to Net Income from cash flow hedges line and changed by $6.4 million in the Total Comprehensive Income line to reflect the equity portion of the non-guarantor subsidiaries balances. In addition, for the 2011 Condensed Consolidating Statements of Comprehensive Income, the Subsidiary Issuer and Elimination columns were changed by $1.5 million in the Reclassification adjustment transferred to Net Income from cash flow hedges line and in the Total Comprehensive Income line to reflect the equity portion of the non-guarantor subsidiaries balances.
Condensed Consolidating Balance Sheets as of December 31, 2013
(Millions)
Condensed Consolidating Balance Sheets as of December 31, 2012
(Millions)
Condensed Consolidating Statements of Income for the Year Ended December 31, 2013
(Millions)
Condensed Consolidating Statements of Income for the Year Ended December 31, 2012
(Millions)
Condensed Consolidating Statements of Income for the Year Ended December 31, 2011
(Millions)
Condensed Consolidating Statements of Comprehensive Income for the Year Ended December 31, 2013
(Millions)
Condensed Consolidating Statements of Comprehensive Income for the Year Ended December 31, 2012
(Millions)
Condensed Consolidating Statements of Comprehensive Income for the Year Ended December 31, 2011
(Millions)
Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2013
(Millions)
Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2012
(Millions)
Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2011
(Millions)
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2013 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2013, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (1992). Based on this assessment, our management believes that, as of December 31, 2013, our internal control over financial reporting was effective. Deloitte & Touche LLP, the independent registered public accounting firm that audited our financial statements included in Item 8 of this Report, has issued a report on our internal control over financial reporting.
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 internal control over financial reporting of Boardwalk Pipeline Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Boardwalk Pipeline Partners, LP and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2013, of the Partnership and our report dated February 24, 2014 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ Deloitte & Touche LLP
Houston, Texas
February 24, 2014
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Management of Boardwalk Pipeline Partners, LP
Boardwalk GP manages our operations and activities on our behalf. The operations of Boardwalk GP are managed by its general partner, Boardwalk GP, LLC (BGL). We sometimes refer to Boardwalk GP and BGL collectively as “our general partner.” Our general partner is not elected by unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends that indebtedness or other obligations we incur are nonrecourse to it.
Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation to any limited partner and is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under any law. Examples include the exercise of its limited call rights on our units, as provided in our partnership agreement, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the Partnership, all of which are described in our partnership agreement. Actions of our general partner made in its individual capacity will be made by BPHC, the sole member of BGL, rather than by our Board.
BGL has a board of directors that oversees our management, operations and activities. We refer to the board of directors of BGL, the members of which are appointed by BPHC, as our Board. BPHC does not apply a formal diversity policy or set of guidelines in selecting and appointing directors that comprise the Board. However, when appointing new directors, BPHC does consider each individual director’s qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the Board as a whole.
Directors and Executive Officers
The following table shows information for the directors and executive officers of BGL:
Name
Age
Position
Stanley C. Horton
Chief Executive Officer, President and Director
Jamie L. Buskill
Senior Vice President, Chief Financial and Administrative Officer and Treasurer
Michael E. McMahon
Senior Vice President, General Counsel and Secretary
Jonathan E. Nathanson
Senior Vice President, Corporate Development
Kenneth I. Siegel
Director, Chairman of the Board
Arthur L. Rebell
Director
William R. Cordes
Director
Thomas E. Hyland
Director
Mark L. Shapiro
Director
Andrew H. Tisch
Director
All directors have served since our initial public offering in 2005 except for Messrs. Horton, Siegel and Cordes who were elected to the Board in 2011, 2009 and 2006, respectively. All directors serve until replaced or upon their voluntary resignation.
Stanley C. Horton-Mr. Horton has been the President and Chief Executive Officer (CEO) of BGL since May 2011. Prior thereto he was an independent energy consultant providing consulting services to clients in both Europe and the United States. From 2005 to 2008, Mr. Horton served as President and Chief Operating Officer of Cheniere Energy, Inc. From 2003 to 2005, he served as President and Chief Operating Officer of subsidiaries of Southern Union, including Panhandle Energy and CrossCountry Energy Services LLC. From 2001 to 2003, Mr. Horton served as Chairman and Chief Executive Officer of Enron Global Services. He has chaired the Gas Industry Standards Board, the Interstate Natural Gas Association of America and the Natural Gas Council. Mr. Horton also served on the Board of Directors for SemGroup Corporation from November 2009 until his resignation effective May 2, 2011. Mr. Horton was selected to serve as a director due to his extensive experience in the natural gas industry and his
position with the Registrant. He brings substantial operational experience gained from his executive-level leadership history and the perspective of a former chief executive officer.
Jamie L. Buskill-Mr. Buskill was named Senior Vice President, Chief Financial and Administrative Officer and Treasurer of BGL during 2012. Previously he had been the Senior Vice President, Chief Financial Officer and Treasurer of BGL since its inception in 2005 and served in the same capacity for the predecessor of BGL since May 2003. He has served in various management roles for Texas Gas since 1986. Mr. Buskill also serves on the board of various charitable organizations.
Michael E. McMahon-Mr. McMahon has been the Senior Vice President, General Counsel and Secretary of BGL since February 2007. Prior thereto he served as Senior Vice President and General Counsel of Gulf South since 2001. Mr. McMahon has been employed by Gulf South or its predecessors since 1989. Mr. McMahon also serves on the board of directors and legal committee of the Interstate Natural Gas Association of America.
Jonathan E. Nathanson-Mr. Nathanson became Senior Vice President of Corporate Development of BGL in February 2011. Prior to his employment at Boardwalk, Mr. Nathanson served as Vice President of Corporate Development for Loews Corporation from 2001 through February 2011 and was a director of Boardwalk GP, LLC from 2005 until he joined BGL in February 2011. Mr. Nathanson began his career as an investment banker in 1989 with a predecessor of Citigroup Inc.
Kenneth I. Siegel-Mr. Siegel has been employed as a Senior Vice President of Loews since June 2009. From 2008 to 2009 he was employed as a senior investment banker at Barclay’s Capital and from September 2000 to 2008 he was employed in a similar capacity at Lehman Brothers. Mr. Siegel was selected to serve as a director on our Board due to his valuable financial expertise, including extensive experience with capital markets transactions, knowledge of the energy industry and his familiarity with the Partnership due to his role in providing investment banking advice to the Partnership during his prior employment at Barclay’s Capital and Lehman Brothers.
Arthur L. Rebell-Mr. Rebell was a Senior Vice President of Loews from 1998 until his retirement in June 2010. Mr. Rebell was selected to serve as a director on our Board due to his judgment in assessing business strategies taking into account any accompanying risks, his knowledge of finance, mergers and acquisitions and the energy industry and his familiarity with the Partnership due to his role as a member of the Loews team responsible for the acquisitions of Gulf South and Texas Gas and the formation of the Partnership.
William R. Cordes-Mr. Cordes retired as President of Northern Border Pipeline Company in April 2007 after serving as President from October 2000 to April 2007. He also served as Chief Executive Officer of Northern Border Partners, LP from October 2000 to April 2006. Prior to that, he served as President of Northern Natural Gas Company from 1993 to 2000 and President of Transwestern Pipeline Company from 1996 to 2000. Mr. Cordes has more than 35 years of experience working in the natural gas industry. Mr. Cordes is also a member of the board of Kayne Anderson Energy Development Company and Kayne Anderson Midstream Energy Fund, Inc. Mr. Cordes brings to the Board significant pipeline industry experience as well as his extensive business and management expertise from his background as chief executive officer and president of several public companies.
Thomas E. Hyland-Mr. Hyland was a partner in the global accounting firm of PricewaterhouseCoopers, LLP from 1980 until his retirement in July 2005. Mr. Hyland was selected to serve as a director on our Board due to his extensive background in public accounting and auditing, which also qualifies him as an “audit committee financial expert” under SEC guidelines.
Mark L. Shapiro-Mr. Shapiro has been a private investor since 1998. From July 1997 through August 1998, Mr. Shapiro was a Senior Consultant to the Export-Import Bank of the United States. Prior to that position, he was a Managing Director in the investment banking firm of Schroder & Co. Inc. Mr. Shapiro also serves as a director for W.R. Berkley Corporation. Mr. Shapiro was selected to serve as a director on our Board due to his extensive knowledge and experience in corporate finance, acquisitions and financial matters from his career in investment banking.
Andrew H. Tisch-Mr. Tisch has been Co-Chairman of the Board of Directors of Loews since January 2006. He is also Chairman of the Executive Committee and a member of the Office of the President of Loews and has been a director of Loews since 1985. Mr. Tisch also serves as a director of CNA Financial Corporation, a subsidiary of Loews, and is Chairman of the Board of K12 Inc. Mr. Tisch’s qualifications to sit on our Board include his extensive experience on the board of our parent company, his extensive leadership skills and keen business and financial judgment, as well as his role in forming the Partnership.
Our Independent Directors
Our Board has determined that Thomas E. Hyland, Mark L. Shapiro, Arthur L. Rebell and William R. Cordes are independent directors under the listing standards of the New York Stock Exchange (NYSE). Our Board considered all relevant facts and circumstances and applied the independence guidelines described below in determining that none of these directors has any material relationship with us, our management, our general partner or its affiliates or our subsidiaries.
Our Board has established guidelines to assist it in determining director independence. Under these guidelines, a director would not be considered independent if any of the following relationships exists:
(i)
during the past three years the director has been an employee, or an immediate family member has been an executive officer, of us;
(ii)
the director or an immediate family member received, during any twelve month period within the past three years, more than $120,000 per year in direct compensation from us, excluding director and committee fees, pension payments and certain forms of deferred compensation;
(iii)
the director is a current partner or employee or an immediate family member is a current partner of a firm that is our internal or external auditor, or an immediate family member is a current employee of such a firm and personally works on our audit, or, within the last three years, the director or an immediate family member was a partner employee of such a firm and personally worked on our audit within that time;
(iv)
the director or an immediate family member has at any time during the past three years been employed as an executive officer of another company where any of our present executive officers at the same time serves or served on that company’s compensation committee; or
(v)
the director is a current employee, or an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, us for property or services in an amount which, in any of the last three years, exceeds the greater of $1.0 million, or 2% of the other company’s consolidated gross revenues.
Our Board is comprised of a majority of independent directors and our Audit Committee is comprised solely of independent directors. The NYSE does not require a listed limited partnership, or a listed company that is majority-owned by another listed company, such as us, to maintain a compensation or nominating/corporate governance committee. In reliance on this exemption, we do not maintain a compensation or nominating/corporate governance committee.
Audit Committee
Our Board’s Audit Committee presently consists of Thomas E. Hyland, Chairman, Mark L. Shapiro and William R. Cordes, each of whom is an independent director and satisfies the additional independence and other requirements for Audit Committee members provided for in the listing standards of the NYSE. The Board of Directors has determined that Mr. Hyland qualifies as an “audit committee financial expert” under Securities and Exchange Commission (SEC) rules.
The primary function of the Audit Committee is to assist our Board in fulfilling its responsibility to oversee management’s conduct of our financial reporting process, including review of our financial reports and other financial information, our system of internal accounting controls, our compliance with legal and regulatory requirements, the qualifications and independence of our independent registered public accounting firm (independent auditors) and the performance of our internal audit function and independent auditors. The Audit Committee has sole authority to appoint, retain, compensate, evaluate and terminate our independent auditors and to approve all engagement fees and terms for our independent auditors.
Conflicts Committee
Under our partnership agreement, our Board must have a Conflicts Committee consisting of two or more independent directors. Our Conflicts Committee presently consists of Mark L. Shapiro, Chairman, Thomas E. Hyland and William R. Cordes. The primary function of the Conflicts Committee is to determine if the resolution of any conflict of interest with our general partner or its affiliates is fair and reasonable. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable, approved by all of the partners and not a breach by our general partner of any duties it may owe to our unitholders.
Executive Sessions of Non-Management Directors
Our Board’s non-management directors, from time to time as such directors deem necessary or appropriate, meet in executive sessions without management participation. The Chairman of the Audit Committee and the Chairman of the Conflicts Committee alternate serving as the presiding director at these meetings.
Governance Structure and Risk Management
Our principal executive officer and Board chairman positions are held by separate individuals. We have taken this position to achieve an appropriate balance with regard to oversight of company and unitholder interests, Board member independence, power and guidance for the principal executive officer regarding business strategy, opportunities and risks.
Our Board is engaged in the oversight of risk through regular updates from Mr. Horton, in his role as our CEO, and other members of our management team, regarding those risks confronting us, the actions and strategies necessary to mitigate those risks and the status and effectiveness of those actions and strategies. The updates are provided at quarterly Board and Audit Committee meetings as well as through more frequent meetings that include the Board Chairman, other members of our Board, the CEO and members of our management team. The Board provides insight into the issues, based on the experience of its members, and provides constructive challenges to management’s assumptions and assertions.
Corporate Governance Guidelines and Code of Business Conduct and Ethics
Our Board has adopted Corporate Governance Guidelines to guide it in its operation and a Code of Business Conduct and Ethics applicable to all of the officers and directors of BGL, including the principal executive officer, principal financial officer, principal accounting officer, and all of the directors, officers and employees of our subsidiaries. The Corporate Governance Guidelines and Code of Business Conduct and Ethics can be found within the “Governance” section of our website. We intend to post changes to or waivers of this Code for BGL’s principal executive officer, principal financial officer and principal accounting officer on our website.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the SEC. Such persons are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2013, in a timely manner with the exception of one Form 4 filing for Messrs. Horton, Buskill, McMahon and Barkauskas.
Item 11.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Executive Summary
The objective of our executive compensation program is to attract and retain highly qualified executive officers and motivate them to provide a high level of performance for our Partnership. To meet this objective, we have established a compensation policy for our executive officers which offers elements of base salary, cash incentives, equity-based incentives and retirement and other benefits. Our strategy is to combine these elements at levels that provide our Named Executive Officers (as identified below) compensation that is competitive with that offered at similar companies in the energy industry, with particular emphasis on retention and rewarding performance by offering short and long-term incentive-based compensation. As determined annually by our Board, the Named Executive Officers that are discussed within this section for the 2013 year include Mr. Stanley C. Horton, our President, Chief Executive Officer and a director of BGL (CEO) (principal executive officer), Mr. Jamie L. Buskill, our Senior Vice President, Chief Financial and Administrative Officer and Treasurer (CFO) (principal financial officer), and our two other executive officers, Mr. Michael E. McMahon, Senior Vice President, General Counsel and Secretary and Mr. Jonathan E. Nathanson, Senior Vice President, Corporate Development.
We consider a number of factors in making our determinations of executive compensation, including compensation paid in prior years, whether the Partnership's financial, operating and growth objectives were achieved and the individual contributions of each executive officer to our overall business success for the year. As described below, we have periodically used and may use in the future executive compensation surveys as general guidelines for setting total executive compensation, but we do not benchmark our compensation to any particular group of companies.
In the development of our executive compensation programs, we have considered the compensation programs of various companies engaged in similar businesses with similar corporate structures to obtain a general understanding of compensation practices and industry trends. We have also considered the historical compensation policies and practices of our operating subsidiaries and, as discussed below under Risk Assessment, whether our compensation policies and practices could possibly introduce material risks to our business. In addition, in light of our structure as a publicly traded partnership, we have considered the applicable tax and accounting impacts of executive compensation, including the tax implications of providing equity-based compensation to our employees, all of whom are employed by our operating subsidiaries.
As discussed above, our compensation policy includes offering cash incentives to reward for performance. Annual bonus awards are a component of that policy. The annual bonus awards for 2013 were determined after we reviewed both the performance of our Partnership and the individual performance of each of the Named Executive Officers. With respect to Partnership performance, our 2013 results which significantly impacted the Board’s compensation decisions included the following:
•
we had no material safety or deliverability issues and we were in compliance with all federal and state laws and governmental rules and regulations;
•
we exceeded distributable cash amounts included in our plan although adjusted EBITDA was lower than expected primarily due to the unfavorable market conditions affecting our firm natural gas transportation and storage services and a goodwill impairment charge, as discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations;
•
we reduced our distribution with respect to the fourth quarter in order to utilize internally generated cash flows to fund growth and improve our leverage;
•
we were successful in finding potential opportunities to utilize our natural gas pipelines, such as with the proposed Bluegrass Pipeline and the Ohio to Louisiana Access Projects;
•
we completed the majority of our growth projects on time and on budget and our growth projects currently underway (other than the Bluegrass Project which is subject to ongoing discussions with potential customers and other considerations discussed elsewhere in this Report) are progressing as contemplated and are expected to be completed on time and on budget; and
•
we improved operational efficiency and reduced operating costs in several areas.
Based on these results and the leadership, performance and efforts of each of the Named Executive Officers toward the achievement of these results, the Board of Directors (Board) awarded to the Named Executive Officers individual annual cash bonus amounts that, on a combined basis, were slightly higher than the target amounts set for 2013.
As discussed elsewhere in this Report, our Board does not have a Compensation Committee. Therefore, the compensation for our Named Executive Officers, is reviewed with and is subject to the approval of our entire Board, with Mr. Horton not participating in those Board discussions with respect to his own compensation.
Compensation Philosophy
Our compensation philosophy is to reward our Named Executive Officers for achieving Partnership and individual performance objectives, align the interests of the Named Executive Officers with the interests of the Partnership and unitholders and provide competitive pay to attract and retain top talent.
Compensation Program Objectives
The objectives of our compensation program are to:
•
Attract, motivate and retain highly qualified Named Executive Officers with market-competitive compensation;
•
Create a strong link between pay and performance (both Partnership and individual performance);
•
Motivate the Named Executive Officers to achieve both short and long-term Partnership goals;
•
Align interests of Named Executive Officers with the interests of the Partnership; and
•
Encourage prudent business behavior and minimize inappropriate risk taking.
Compensation Program Elements
The following are the principal components of compensation for each of our Named Executive Officers:
Compensation
Element
Objectives
Design Elements
Base Salary
*
Attract and retain executives by providing compensation comparable with similar positions in the industry.
*
Base salary levels are reviewed annually and may be adjusted based both on individual performance and market competitiveness of total direct compensation (which is the sum of base salary, short-term incentive awards and long-term incentive awards).
Short-Term Incentive Award
*
Drive annual business performance by rewarding achievement of Partnership objectives.
*
Awards are comprised of annual cash bonus awards (STI Awards) under our Short Term Incentive Plan (STIP).
*
Drive individual performance by including an individual performance component.
*
Payout of awards can range from 0% to 200% of target, at the discretion of the Board, based both on Partnership and individual performance, with equal weighting on both.
*
Attract talent by providing competitive short-term cash incentives targets.
*
Target levels are reviewed annually and may be adjusted based on market competitiveness of total direct compensation.
*
Reinforce corporate values of safety and compliance as Partnership objectives.
Long-Term Incentive Award
*
Attract and retain talent, motivate top performance and provide opportunity to share in long-term success of the Partnership.
*
Awards consist of a combination of or any one of the following: phantom common units (Phantom Common Units) under our Long-Term Incentive Plan (LTIP) and unit appreciation rights (UARs) and long-term cash bonus (Long-Term Cash Bonus) awards under our Unit Appreciation Rights and Cash Bonus Plan (UAR and Cash Bonus Plan).
*
Minimize inappropriate risk-taking by providing the appropriate mix of award type.
*
Vesting at the end of three years achieves retention objectives and discourages unreasonable risk taking for short-term gain.
*
Drive long-term business performance by aligning reward with unit price, appreciation in unit price and distributions.
*
Phantom Common Units encourage retention and facilitate alignment with unitholders interests.
*
Drive individual performance by setting grant levels based on individual performance.
*
UARs encourage participants to increase the unit price and increase distributions, and provide upside opportunity.
*
Long-Term Cash Bonus awards support retention of executives and provide our Board flexibility to mix equity based and non-equity based long-term compensation to support its objectives.
*
Mix of award types is reviewed annually.
*
Award levels are reviewed annually and are based on individual performance and market competitiveness of total direct compensation.
Benefits
*
Attract and retain executives by providing market competitive benefits.
*
Reviewed annually to ensure competitiveness.
Market Analysis
When determining the appropriate amounts of individual compensation components, the Board considers a number of factors, including the individual officer’s skills, experience and responsibilities, the amounts of current and prior compensation as well as the appropriate amounts necessary to further our retention efforts. We do not determine compensation by benchmarking,
or targeting our compensation to fall within a specific percentile of compensation as reported in compensation surveys. However, as described above, a key objective of our Compensation program is to maintain market competitiveness in order to attract and retain executives with the ability and experience necessary to provide leadership and strong performance to the Partnership. Therefore, from time to time, we may review market compensation data to assess the reasonableness of our compensation practices.
With respect to our 2013 compensation decisions, we used the 2013 Towers Watson U.S. Compensation Data Bank Energy Services Executive Compensation Survey and the 2013 US Mercer Total Compensation Survey for the Energy Sector (Mercer Survey) to conduct a market-based review of total direct compensation, which we define as the sum of base salary, short-term incentives and long-term incentives. The compensation survey data we reviewed was from approximately 300 companies that are engaged in various segments of the energy industry, with revenues ranging from $1 billion to $3 billion.
Our general objective was to assess each officer’s total direct compensation for reasonableness in relation to the median amount for similarly situated officers. We did not set specific target percentiles for either total direct compensation or the individual compensation components and we determined a median market total direct compensation amount for each officer position.
When making compensation decisions, the Board considers all information available, including the factors listed above, with the final amounts of compensation to be ultimately determined at the discretion of the Board. This process allows us to achieve our primary objective of maintaining competitive compensation to ensure retention and rewarding the achievement of the Partnership's objectives to align with the interests of unitholders.
The following discussion addresses each of the individual components of compensation for our Named Executive Officers.
Compensation Attributable to the 2013 Calendar Year
In 2012, we changed the timing of the grant date of the short and long-term incentive awards from December of the current year to February of the following year so that the results for the Named Executive Officers and the Partnership could be reviewed upon completion of the full calendar year. The Board considers these awards to be related to 2013 even though the long-term incentive awards will not be reported in the Summary Compensation table until 2014 or later, depending on the type of the award. We consider compensation attributable to the 2013 calendar year to include the base salary paid during 2013, STI Awards awarded and paid in early 2014, but related to results achieved in 2013, and Long-Term Incentive Awards granted in early February 2014, but related to the results achieved in 2013. The table shown below summarizes the compensation for our Named Executive Officers that we consider to be related to the 2013 calendar year. These amounts differ from those reported in the Summary Compensation Table below due solely to the disclosure rules regarding the timing of reporting certain elements of compensation.
(1)
Represents the base salary for Messrs. Horton, Buskill and Nathanson effective for the entire year. Mr. McMahon’s salary was increased effective September 1, 2013, from his previous salary of $265,000.
(2)
Represents Long-Term Cash Bonuses granted under our UAR and Cash Bonus Plan on February 7, 2014.
For compensation attributable to the 2013 calendar year, approximately 74% of the total direct compensation awarded to our Named Executive Officers was based on incentive-based compensation elements, the majority of which was comprised of long-term incentive-based compensation.
Base Salary
We provide our Named Executive Officers with an annual base salary to compensate them for services rendered during the year. Our goal is to set base salaries for our Named Executive Officers at levels that make total direct compensation competitive with comparable companies for the skills, experience and requirements of similar positions in order to attract and retain top talent.
The base salaries of our Named Executive Officers have not changed during the past three years with the exception of Mr. McMahon. In September 2013, Mr. McMahon’s base salary was increased by $35,000. These determinations were made as a result of reviewing the market-competitiveness of total direct compensation, and taking into account previous base salary changes.
Incentive Compensation
The Board considers incentive compensation awards paid or granted in early 2014 to be related to 2013 performance even though the awards will not be reported in the Summary Compensation Table until 2014 or later, depending on the type of award. Our incentive compensation program is comprised of several components:
•
annual cash bonus awards under our STIP
•
long-term, equity-based awards under our LTIP or UAR and Cash Bonus Plan; and
•
Long-Term Cash Bonuses under our UAR and Cash Bonus Plan.
Our goal is to set incentive target awards at levels that make total direct compensation competitive with comparable companies for the skills, experience and requirements of similar positions in order to attract and retain top talent. The incentive target awards can differ from actual awards as a result of Partnership and/or individual performance, but the actual payout of any award is determined at the sole discretion of the Board.
In determining the amount of any incentive awards, the Board considers factors that include its view of our financial and operational performance for the most recently completed fiscal year, the performance of the individual, the responsibilities of the individual’s position and the individual’s contribution to our Partnership. The Board also gives consideration to external factors and market conditions experienced by the Partnership, such as either the favorable or unfavorable market conditions impacting our transportation and storage services. Except with regard to STI Awards made under the STIP, there is no specific weight assigned to any factor. Instead, the Board considers and balances the various performance objectives as it deems appropriate.
STI Awards. An STI Award is an annual cash bonus award under our STIP, the payout of which is based on the Board’s subjective analysis of our performance and the performance of our Named Executive Officers during the year. At the beginning of the year, each Named Executive Officer is assigned a target amount, which is established as a percentage of the officer’s base salary. The plan provides that payouts under the STIP can range from zero to 200% of the target amount, with 50% of the payout determined after taking into account our Partnership’s performance and 50% based on individual performance. The target and maximum potential payouts under the STIP as well as the allocation between Partnership and individual performance were determined at the discretion of the Board. In determining the target amount of the STI Awards, the Board considered (i) the value of each officer’s prior STI Awards, and (ii) the potential value of the STI Awards on the total direct compensation for each officer. The following are the target potential payout amounts that were established for 2013 for our Named Executive Officers:
When determining whether to pay an STI Award for the year, the Board considers recommendations made by the CEO which are based on his subjective evaluation of whether, and to what extent, our Partnership met its performance goals during the year. He also makes recommendations based on his subjective assessment of the individual performance of each of the other
Named Executive Officers. Any STI Award paid to the CEO is determined by the Board based upon a similar review performed by the Board without input from the CEO.
Our partnership performance goals are based on objectives that we believe reflect a well-rounded view of our performance. However, these goals are not tied to any specific targets and our achievement of these goals is ultimately determined by the Board in its sole discretion. For 2013, the following general objectives, which we refer to as Partnership Performance Goals, were established by the CEO and approved by the Board:
1.
Operate our assets safely, reliably and in compliance with all applicable federal and state laws and governmental rules and regulations.
2.
Focus on delivering financial results that are consistent with the Partnership's 2013 budget.
3.
Explore strategic acquisition opportunities that would support profitable diversification and/or growth of our business.
4.
Improve efficiency throughout the Partnership including operating within departmental budgets.
5.
Market firm transportation, storage, gathering and processing services.
6.
Complete all projects (pipeline, storage, gathering and processing) on-time and meet project schedules for the year.
7.
Remain within budgeted capital expenditures while meeting strict safety and compliance guidelines and business needs.
8.
Identify other new growth and/or efficiency projects during the year that will result in the Partnership meeting its long-term growth projections and financial performance.
As discussed under Executive Summary, in light of the Partnership's achievements in 2013, the Board determined that we met a significant portion of our Partnership Performance Goals, which resulted in the determination that 90% of the partnership performance portion of each STI Award should be paid.
The Board also subjectively considered the contributions of our Named Executive Officers, including the individual leadership, performance and efforts of each officer with respect to our achievement of these goals. The following is a discussion of the material factors that were considered by the Board in determining what percentage of the annual incentive award would be paid based on individual performance:
Stanley C. Horton: In assessing Mr. Horton’s individual performance, the Board considered the accomplishments mentioned above and the leadership that Mr. Horton provided for the senior management team and employee group in addressing the significant issues faced by the Partnership as a result of the difficult market conditions described elsewhere in this Report, as well as the continued implementation of the strategic direction he has communicated to the employee group in terms of growth, financial performance, diversification, customer service, operational excellence and ethics and integrity.
Jamie L. Buskill: In assessing Mr. Buskill’s performance, the Board considered his continued leadership of the finance and accounting organization, which provides reporting to regulatory agencies and communication to the financial community and rating agencies, ensures proper capitalization of the Partnership for both the near-term and long-term under reasonable terms and conditions, provides fiduciary oversight by ensuring effective controls, procedures and risk management practices are in place and manages cash balances to provide sufficient liquidity for executing the Partnership’s operating plans. As Chief Administrative Officer, Mr. Buskill had oversight over information technology, human resource practices, and other administrative functions of the Partnership and his oversight resulted in cost reductions, efficiencies, successful integration of Louisiana Midstream and improved communication within the Partnership.
Michael E. McMahon: In assessing Mr. McMahon’s performance, the Board considered his leadership of the legal and regulatory organizations, including his oversight in the Partnership’s compliance with applicable state and federal laws. Mr. McMahon represented the Partnership with regard to FERC matters, state and federal governmental affairs and within various industry associations, for example he served as a member of the board of directors of the Interstate Natural Gas Association of America. Additionally, Mr. McMahon was a significant contributor in negotiating and drafting of the documents related to the Bluegrass Project, as well as filing the FERC abandonment application and addressing state permitting and right of way issues associated with the Bluegrass project.
Jonathan E. Nathanson: In assessing Mr. Nathanson’s performance, the Board considered his analysis of various acquisition opportunities, his leadership of the corporate development organization which is responsible for analyzing economics for all major growth projects and the successful integration of Louisiana Midstream into the Partnership. The Board considered his knowledge of the industry and financial markets which is of major importance to the Partnership and Mr. Nathanson was also a major contributor to the joint venture agreements associated with the Bluegrass Project.
In light of these considerations, the Board approved the following payout of STI Awards for each Named Executive Officer:
Each of the STI awards above was determined as follows: 50% of the award was based on Partnership performance of 90% of target and 50% of the award was based on individual performance, as determined at the discretion of the Board.
Long-Term Incentive Awards - Phantom Common Units, UARs and Cash. We may grant a combination of cash and equity-based compensation awards, or any one of these awards individually, to our Named Executive Officers under our LTIP and our UAR and Cash Bonus Plan on an annual basis. The equity-based compensation awards are settled in cash rather than in the form of actual common units due to our structure as a limited partnership and certain tax matters associated with employee benefit plans. We currently limit the type of equity-based awards that we grant to Phantom Common Units under our LTIP and UARs under our UAR and Cash Bonus Plan, both of which are currently settled in cash.
Annually, we review the mix of long-term incentive award types granted to Named Executive Officers. In the past, the Board has awarded a mixture of long-term cash awards, Phantom Units and UARs, with the last two years consisting of only equity based awards. In an effort to diversify the mixture of awards, the Board approved Long-Term Cash Bonus Awards attributable to the 2013 compensation year so that approximately two-thirds of the current, outstanding long-term awards would be equity based and approximately one-third would be cash based. The mixture of equity-based and cash based awards supported the Compensation Program Objectives stated previously and would help to retain highly qualified named Executive Officers at a time when unfavorable market conditions were negatively impacting our business. All award types, whether cash or equity-based, typically vest after approximately three years which helps achieve our objectives of retention.
In 2014, Long-Term Cash Bonuses were granted to Messrs. Horton, Buskill, McMahon and Nathanson having stated amounts of $1,300,000, $500,000, $400,000 and $400,000, respectively. The awards will vest and become payable, subject to the terms of the plan and grant agreements, on December 16, 2016, which is approximately the three year vesting schedule that we currently use with our long-term incentive awards. A Phantom Common Unit converts into the right to receive the value of a common unit in cash or, at the option of the Board, a common unit, plus an amount in cash equal to the accumulated amount of cash distributions made during the vesting period with respect to a common unit, upon the satisfaction of the time-based vesting criteria specified in the grant. A UAR entitles the grantee to a payment in cash equal to the excess, if any, of the price of a common unit on the vesting date over the exercise price of the UAR (reduced by the accumulated amount of cash distributions made over the vesting period with respect to a common unit, or the DER Adjustment), upon satisfaction of the time-based vesting criteria specified in the grant. Specified events, such as certain employee terminations of employment or a change in control, will modify the general three-year, time-based vesting schedules of certain of the long-term incentive awards. See Potential Payments Upon Termination or Change of Control below for further details.
In determining the size of the annual long-term incentive awards granted to our Named Executive Officers and in assessing the reasonableness of those awards, the Board considered the value of each officer's prior long-term incentive awards, as well as the impact of the value of long-term incentive awards on total direct compensation.
Employee Benefits
Each Named Executive Officer participates in benefit programs available generally to salaried employees of the operating subsidiary which employs such officer, including health and welfare benefits and a qualified defined contribution 401(k) plan that includes a dollar-for-dollar match on elective deferrals of up to 6% of eligible compensation within Internal Revenue Code (IRC)
requirements. With the exception of Mr. Buskill, our Named Executive Officers participate in a defined contribution money purchase plan, which is available to employees of Gulf South and employees of Texas Gas hired on or after November 1, 2006. Our contributions to these defined contribution plans on behalf of the participating Named Executive Officers are reported in the Summary Compensation Table.
Mr. Buskill participates in a defined benefit cash balance pension plan available to employees of Texas Gas hired prior to November 1, 2006, and includes a non-qualified restoration plan for amounts earned in excess of IRC limits for qualified retirement plans. Mr. Buskill is also eligible for retiree medical benefits after reaching age 55 as part of a plan offered to Texas Gas employees hired prior to January 1, 1996. For more details regarding the pension benefits provided to Mr. Buskill, see Pension Benefits below.
All Other Compensation
There were no material perquisites or personal benefits paid to our Named Executive Officers in 2013.
Retention Program
Considering the risks impacting the Partnership, as discussed in Item 1A, Risk Factors, and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and in a continued effort to retain our Named Executive Officers and other key employees, in February 2014, the Board approved a retention program under which the Partnership can award up to an aggregate maximum of $12.0 million to key employees, which may include the Named Executive Officers. Each such award would be made pursuant to a Retention Payment agreement with the recipient and would, among other terms, provide for vesting and payment of the award over a three year period as follows: 25% vesting and becoming payable on February 28, 2015, 25% vesting and becoming payable on February 29, 2016, and the remaining 50% vesting and becoming payable on February 28, 2017. In order for an award to vest, the recipient must remain continuously employed by the Partnership or a subsidiary through the applicable vesting date. A pro rata portion of an award will vest and become payable if a recipient’s employment is terminated due to death or disability prior to the applicable vesting date. No retention awards have been made to date under this program.
Equity Ownership Guidelines
As discussed above, our executives would suffer significant negative tax consequences by owning our common units directly. As a result, we do not have a policy or any guidelines regarding required equity ownership by our management. We therefore seek to align the interests of management with our unitholders by periodically granting Phantom Common Units and UARs.
Clawbacks
The Long Term Cash Bonus awards contain a clawback provision that states that, in the event that an applicable law, including the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, any Securities and Exchange Commission rule or any applicable securities exchange listing standards, or any Partnership policy requires, the bonus amount will be subject to forfeiture or recoupment to the extent necessary to comply with such laws or policy.
Risk Assessment
We have reviewed our compensation policies and practices for all employees, including Named Executive Officers, and determined that our compensation programs are not reasonably likely to cause behaviors that would have a material adverse effect on the Partnership. In arriving at this determination, the Board considers potential risks when reviewing and approving both executive-level and broad-based compensation programs. We have designed our compensation programs, including our incentive compensation plans, to minimize potential risks while rewarding employees for achieving long-term financial and strategic objectives through prudent business judgment. In particular, the design of our compensation programs provide a balanced mix of cash and equity-based, annual and longer-term incentives, which are discretionary and subject to the Board’s evaluation of Partnership performance metrics as well as individual contributions to our performance. Further, awards of incentive compensation are not purely formula driven, and the Board retains full discretion with regard to increasing or decreasing total compensation or any element of total compensation.
Board of Directors Report on Executive Compensation
In fulfilling its responsibilities, our Board has reviewed and discussed the Compensation Discussion and Analysis with our management. Based on this review and discussion, the Board recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
By the members of the Board of Directors:
William R. Cordes
Stanley C. Horton
Thomas E. Hyland
Arthur L. Rebell
Kenneth I. Siegel, Chairman
Mark L. Shapiro
Andrew H. Tisch
Compensation Committee Interlocks and Insider Participation
As discussed above, our Board does not maintain a Compensation Committee. Our entire Board performs the functions of such a committee. None of our directors, except Mr. Horton, have been or are officers or employees of us or our subsidiaries. Mr. Horton participates in deliberations of our Board with regard to executive compensation generally, but does not participate in deliberations or Board actions with respect to his own compensation. None of our Named Executive Officers served as a director or member of a compensation committee of another entity that has or has had an executive officer who served as a member of our Board during 2013, 2012 or 2011.
Executive Compensation
Summary of Executive Compensation
In 2012, we changed the timing of the grant date of the short and long-term incentive awards from December of the current year to February of the following year. Refer to Compensation Attributable to the 2013 Calendar Year for further information. The following table shows a summary of total compensation earned by our Named Executive Officers during each of the 2013, 2012 and 2011 years that they were serving as a Named Executive Officer:
(1)
The amounts shown in this column represent cash STI Awards earned under our STIP for 2013, 2012 and 2011, and for which 2013 earned amounts have been disclosed in the Compensation Discussion and Analysis above. For Messrs. Horton and Nathanson, the bonus amount disclosed in 2013 also includes a $258,000 and a $105,000 payment, related to a Long-Term Cash Bonus that was granted to each executive in 2011 and which vested and was paid in 2013. For Messrs. Buskill and McMahon, the bonus amount disclosed in 2013 also includes a $150,000 and a $97,500 payment, related to a Long-Term Cash Bonus that was granted to each executive in 2010 and which vested and was paid in 2013.
(2)
Includes matching contributions under 401(k) plan ($15,300), employer contributions to the Boardwalk Money Purchase Plan ($10,200), imputed life insurance premiums ($3,564) and preferred parking.
(3)
Mr. Horton's salary for 2011 was pro-rated based on his hire date of May 2011.
(4)
Includes the change in qualified retirement plan account balance ($51,286) and interest and pay credits for the supplemental retirement plan ($103,476). Details about both pension plans are contained in the Pension Benefits section below.
(5)
Includes matching contributions under 401(k) plan ($15,300), imputed life insurance premiums ($1,958) and preferred parking.
(6)
Mr. McMahon's salary for 2013 was increased to $300,000 in September 2013.
(7)
Includes matching contributions under 401(k) plan ($15,300), employer contributions to the Boardwalk Money Purchase Plan ($10,200), imputed life insurance premiums ($3,301) and preferred parking.
(8)
Includes matching contributions under 401(k) plan ($15,300), employer contributions to the Boardwalk Money Purchase Plan ($10,200) and imputed life insurance premiums ($1,209).
(9)
In addition to the compensation reportable herein, in 2014, Long-Term Cash Bonuses were granted to Messrs. Horton, Buskill, McMahon and Nathanson having stated amounts of $1,300,000, $500,000, $400,000 and $400,000.The awards will vest and become payable, subject to the terms of the plan and grant agreements on December 16, 2016. See Compensation Discussion and Analysis for more information regarding the terms of the Long-Term Cash Bonus awards.
(10)
As discussed above, in 2012 we changed the grant date of the LTI awards from December of the current year to February of the following year. The change in the award dates has resulted in compensation that the Board considers to be related to 2012 to be reported in the compensation tables for 2013. The amounts in each respective column represent the aggregate grant date fair value for grants made during 2013. Note 12 in Item 8 of this Report contains more information regarding the assumptions we made in determining these values.
The following table sets forth the percentage of each Named Executive Officer’s total compensation that we paid in the form of salary and bonus:
Grants of Plan-Based Awards
The following table displays information regarding grants made during 2013 to our Named Executive Officers of plan-based awards under our UAR and Cash Bonus Plan and Phantom Common Unit awards under our LTIP:
(1)
Represents Phantom Common Units granted under our LTIP. The fair value of each unit was derived based on the closing price of $25.68 for our common units on the New York Stock Exchange (NYSE) on December 10, 2012. Each such grant includes a tandem grant of Distribution Equivalent Rights (DERs); vests 100% on the vesting date; and will be payable to the grantee in cash, or in common units at the Board’s option, upon vesting in an amount equal to the fair market value of the units (as defined in the plan) that vest on the vesting date. The vested amount then credited to the grantee’s DER account will be payable in cash.
(2)
Represents UARs granted under our UAR and Cash Bonus Plan. The exercise price for the UARs granted on February 7, 2013 is equal to the closing price of $27.57 for our common units on the NYSE on February 6, 2013. The UARs granted will vest and become payable in cash upon the expiration of a restricted period on December 11, 2015.
(3)
Each UAR includes a DER Adjustment, whereby the exercise price is reduced by the amount of any cash distributions made by us with respect to a common unit during the restricted period.
(4)
Note 12 in Item 8 of this Report contains information regarding the grant date fair value of the UARs and Phantom Common Units.
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table
In 2012, we changed the grant date of the LTI awards from December of the current year to February of the following year. See Compensation Attributable to the 2013 Calendar Year for more information on compensation that the Board awarded to the Named Executive Officers related to 2013. Relative to the components of compensation earned by the Named Executive Officers in 2013, the components have not changed from 2012 to 2013.
The following provides information regarding the equity-based compensation awards that were granted in February 2013, which the Board attributes to the 2012 performance year.
Phantom Common Units. Each outstanding Phantom Common Unit includes a tandem grant of Distribution Equivalent Rights (DERs). Each Phantom Common Unit granted in 2013 and 2011 vests on the third anniversary date of the grant date, and will be payable to the grantee in cash upon vesting, or in common units at the Board’s option, in an amount equal to the fair market value of the units (as defined in the plan) that vest on the vesting date. The vested amount then credited to the grantee’s DER account will be payable only in cash.
UARs. After the expiration of a restricted period, each awarded UAR vests and is payable to the holder in cash equal to the amount by which the fair market value (as defined in the plan) of a common unit on such date exceeds the exercise price of the UAR. Each outstanding UAR includes a feature whereby the exercise price is reduced by the amount of any cash distributions made by us with respect to a common unit during the restricted period (DER Adjustment).
In February 2014, the Board granted to the Named Executive Officers Long-Term Cash Bonus Awards. The Long-Term Cash Bonus Awards vest and become payable on December 16, 2016, after the expiration of a Restricted Period, subject to the Named Executive Officer remaining continuously employed until that date.
For more information about the components of compensation reported in the Summary Compensation Table and Grants of Plan-Based Awards, please read the Compensation Discussion and Analysis.
Outstanding Equity Awards at Fiscal Year-End
The table displayed below shows the total number of outstanding equity awards in the form of UARs under our UAR and Cash Bonus Plan and Phantom Common Units awarded under our LTIP held by our Named Executive Officers at December 31, 2013:
(1)
The exercise price for each UAR granted in February 2013 is $27.57, the closing price of our common units on the NYSE on February 6, 2013. Each of these UARs includes a DER adjustment, which was $2.13 through December 31, 2013. Note 12 in Item 8 of this Report contains more information regarding our UAR and Cash Bonus Plan.
(2)
The exercise price for each UAR granted in December 2011 is $27.30, the closing price of our common units on the NYSE on December 14, 2011. Each of these UARs includes a DER Adjustment, which was $4.26 through December 31, 2013. Note 12 in Item 8 of this Report contains more information regarding our UAR and Cash Bonus Plan.
(3)
These UARs will vest and become payable in cash to each Named Executive Officer upon the expiration of a restricted period, or December 11, 2015.
(4)
These UARs will vest and become payable in cash to each Named Executive Officer upon the expiration of a restricted period, or December 14, 2014.
(5)
The market value reported is based on the NYSE closing market price on December 31, 2013 of $25.52. These Phantom Common Units vest 100% on December 11, 2015. In addition to the Phantom Common Units, Messrs. Horton, Buskill, McMahon and Nathanson have accumulated non-vested amounts related to DERs that are tandem grants to the Phantom Common Units. Such DER amounts for Messrs. Horton, Buskill, McMahon and Nathanson were $80,870, $31,104, $21,773 and $21,773 as of December 31, 2013. Note 12 in Item 8 of this Report contains more information regarding our LTIP.
(6)
The market value reported is based on the NYSE closing market price on December 31, 2013 of $25.52. These Phantom Common Units vest 100% on December 14, 2014. In addition to the Phantom Common Units, Messrs. Horton, Buskill, McMahon and Nathanson have accumulated non-vested amounts related to DERs that are tandem grants to the Phantom Common Units. Such DER amounts for Messrs. Horton, Buskill, McMahon and Nathanson were $152,052, $58,481, $40,936 and $40,936 as of December 31, 2013. Note 12 in Item 8 of this Report contains more information regarding our LTIP.
Option Exercises and Stock Vested
The following table presents information regarding the vesting during 2013 of Phantom GP Units previously granted to our Named Executive Officers.
(1)
The SLTIP awards (Phantom GP Units) vested in February, 2013 and were paid out in a lump sum cash payment in April, 2013 in accordance with the plan provisions. At no time were our common units issued to or owned by the Named Executive Officers.
(2)
The UARs vested December 16, 2013, and were paid out in a lump sum December 27, 2013, in accordance with the plan provisions. The value of the UARs was determined by taking the average stock price for the thirty business days prior to vesting and comparing that to the exercise price less the DER Adjustment. The difference was then multiplied by the vested number of awards. At no time were our common units issued to or owned by the Named Executive Officers.
Pension Benefits
The table displayed below shows the present value of accumulated benefits for our Named Executive Officers. Only employees of our Texas Gas subsidiary hired prior to November 1, 2006, are eligible to receive the pension benefits discussed below. Messrs. Horton, McMahon and Nathanson are, and during 2013 were, employees of our Gulf South subsidiary and are not covered under any Texas Gas benefit plans. Pension benefits include both a qualified defined benefit cash balance plan and a non-qualified defined benefit supplemental cash balance plan (SRP).
The Texas Gas Retirement Plan (TGRP) is a qualified defined benefit cash balance plan that is eligible to all Texas Gas employees hired prior to November 1, 2006. Participants in the plan vest after three years of credited service. One year of vesting service is earned for each calendar year in which a participant completes 1,000 hours of service. Eligible compensation used in calculating the plan’s annual compensation credits include total salary and bonus paid. The credit rate on all eligible compensation is 4.5% prior to age 30, 6.0% age 30 through 39, 8.0% age 40 through 49 and 10.0% age 50 and older up to the Social Security Wage Base. Additional credit rates on annual pay above Social Security Wage Base is 1.0%, 2.0%, 3.0% and 5.0% for the same age categories. On April 1, 1998, the TGRP was converted to a cash balance plan. Credited service up to March 31, 1998, is eligible for a past service credit of 0.3%. Additionally, participants may qualify for an early retirement subsidy if their combined age and service at March 31, 1998, totaled at least 55 points. The amount of the subsidy is dependent on the number of points and the participant’s age of retirement. Mr. Buskill did not meet the eligibility requirements to qualify for the early retirement subsidy. Upon retirement, the retiree may choose to receive their benefit from a variety of payment options which include a single life annuity, joint and survivor annuity options and a lump-sum cash payment. Joint and survivor benefit elections serve to reduce the amount of the monthly benefit payment paid during the retiree’s life but the monthly payments continue for the life of the survivor after the death of the retiree. The TGRP has an early retirement provision that allows vested employees to retire early at age 55. Mr. Buskill is not yet eligible to receive an early retirement benefit pursuant to the TGRP.
The credited years of service appearing in the table above are the same as actual years of service. No payment was made to the Named Executive Officer during 2013. The present value of accumulated benefits payable to the Named Executive Officer, including the number of years of service credited to the Named Executive Officer, is determined using assumptions consistent with the assumptions used for financial reporting. Interest will be credited to the cash balance at December 31, 2013, commencing in 2014, using a quarterly compounding up to the normal retirement date of age 65. Salary and bonus pay credits, up to the IRC allowable limits, increase the accumulated cash balance in the year earned. Credited interest rates used to determine the accumulated cash balance at the normal retirement date as of December 31, 2013, 2012 and 2011 were 3.00%, 3.18% and 3.77% and for future years, 3.79%, 3.00% and 3.18%. The future normal retirement date accumulated cash balance was then discounted using an interest rate at December 31, 2013, 2012 and 2011 of 4.00%, 3.25% and 4.25%. The increase in the present value of accumulated benefit for the TGRP between December 31, 2012 and 2013 of $51,286 for Mr. Buskill is reported as compensation in the Summary Compensation Table above.
The Texas Gas SRP is a non-qualified defined benefit cash balance plan that provides supplemental retirement benefits on behalf of participating employees for earnings that exceed the IRC compensation limitations for qualified defined benefit plans, which for 2013 was $255,000. The SRP acts as a supplemental plan, therefore the eligibility and retirement provisions, the form and timing of distributions and the manner in which the present value of accumulated benefits are calculated, are identical to the same provisions as described above for the TGRP. The increase in the present value of accumulated benefit for the SRP between December 31, 2012 and 2013, of $103,476, for Mr. Buskill is reported as compensation in the Summary Compensation Table.
Potential Payments Upon Termination or Change of Control
As of December 31, 2013, we do not have employment agreements with our Named Executive Officers. Our Named Executive Officers are eligible to receive accelerated vesting of cash and equity-based awards under certain of our compensation plans. We have made grants of Phantom Common Units, UARs and Long-Term Cash Bonuses to our executives subject to specific vesting schedules and payment limitations, as discussed above. The Phantom Common Units, UARs and Long-Term Cash Bonuses will vest on a prorated basis under certain circumstances and will be payable in accordance with the provisions of the LTIP, UAR and Cash Bonus Plan and grant agreements, as applicable, as described below. A termination of employment may also trigger a distribution of retirement plan accounts from the TGRP or the SRP. Any retirement plan distributions would be no more than those amounts disclosed in the tables above; thus, the Potential Payments Upon Termination or Change of Control Table shown below does not include amounts attributable to the retirement plans disclosed above.
We believe that the acceleration and payment provisions contained in our various award agreements create important retention tools for us, because providing for accelerated vesting of equity-based awards upon a termination of employment for a death or disability provides employees with value in the event of a termination of employment that was beyond their control. Other companies in our industry and the general market where we compete for executive talent commonly have equity compensation plans that provide for accelerated vesting upon certain terminations of employment, and we have provided this benefit to our Named Executive Officers in order to remain competitive in attracting and retaining skilled professionals in our industry. In this discussion, prorated means the number of days in the period beginning on the grant date of the award through the termination date of the named executive officer's employment in relation to the total number of days in the vesting period.
Long-Term Incentive Plan. A prorated portion of unvested Phantom Common Units (and all DERs associated with such Phantom Common Units) will become vested upon our change of control in combination with a termination of employment by the Partnership for any reason other than for a material violation of the Partnership’s code of conduct policy or due to a diminution of the employee’s roles and responsibilities (a termination for cause). A change of control will be deemed to occur under our LTIP upon one or more of the following events: (a) any person or group, other than our general partner or its affiliates, becomes the owner of 50% or more of our equity interests; (b) any person, other than Loews Corporation or its affiliates, become our general partner; or (c) the sale or other disposition of all or substantially all of our assets or our general partner’s assets to any person that is not an affiliate of us or our general partner. However, in the event that any award granted under our LTIP is also subject to IRC section 409A, a change of control shall have the definition of such term as found in the treasury regulations with respect to IRC section 409A.
The unvested Phantom Common Units (and all DERs associated with such Phantom Common Units) will also become vested on a prorated basis upon an executive’s death, disability or retirement (unless the retirement occurs in the first year of the vesting period, in which case the units will be forfeited). Our individual form award agreements define a disability as an event that would entitle that individual to benefits under either our or one of our affiliates’ long-term disability plans (Disability). The award agreements define retirement as a termination on or after age 55, with at least 5 years of continuous service. In the cases of death or Disability, the value of any then vested awards would be determined and paid at the time of termination. In the case
of retirement or change of control, the value of any then vested awards would be determined and paid on the original scheduled payment date. Other than described above, unvested Phantom Common Units would be forfeited upon termination of employment.
Unit Appreciation Rights and Cash Bonus Plan. A prorated portion of unvested UARs will become vested upon our change of control in combination with a termination of employment by the Partnership for any reason other than for a material violation of the Partnership’s code of conduct policy or due to a diminution of the employee’s roles and responsibilities. A change of control will be deemed to occur under our UAR and Cash Bonus Plan upon a change in the possession, direct or indirect, of the power to direct or cause the direction of our management and policies, whether through ownership of voting securities, by contract or otherwise. However, in the event that any award granted under our UAR and Cash Bonus Plan is also subject to IRC section 409A, a change of control shall have the definition of such term as found in the treasury regulations with respect to IRC section 409A.
A prorated portion of any outstanding and unvested UARs would become vested upon an executive’s death, Disability or retirement (unless the retirement occurs in the first year of the vesting period, in which case the units will be forfeited). The award agreements define retirement as a termination one or more years after the date of grant, on or after reaching age 55 with at least 5 years of continuous service with us.
In the case of retirement or change of control combined with a termination of employment as discussed above, the value of any then vested awards would be determined and paid on the original scheduled payment date. Other than as described above, unvested UARs would be forfeited upon termination of employment.
While the Named Executive Officers did not have outstanding Long Term Cash Bonuses as of December 31, 2013, the terms and conditions of the awards granted in 2014 are similar to the UAR terms described above.
Paid Time Off (PTO). Upon any termination of employment, the Named Executive Officers would receive the remaining accrued paid time off that they accumulated during the year, if any.
Potential Payments Upon Termination or Change of Control Table
The following table represents our estimate of the amount each of our Named Executive Officers would have received upon the applicable termination or change of control event, if such event had occurred on December 31, 2013. The closing price of our common units on the NYSE on December 31, 2013, $25.52, was used to calculate these amounts. The amounts that any Named Executive Officer could receive upon a termination of employment or a change of control cannot be determined with any certainty until an actual termination of employment or a change of control occurs. For purposes of the below table, we have assumed all salary and bonuses were paid current as of December 31, 2013.
(1)
The amounts listed under the Change of Control column will apply only in the event that the change of control definition for that particular plan has been triggered.
(2)
As of December 31, 2013, only Mr. McMahon was eligible for retirement as defined in the LTIP and UAR and Cash Bonus Plan award agreements (each as defined above). The determination of amounts to be paid are the same as described in notes (3) for the UAR and Cash Bonus Plan and (4) for the LTIP below, but payment would not occur until the original scheduled payment date.
(3)
UAR and Cash Bonus Plan amounts were determined by multiplying the prorated number of unvested UARs each executive held on December 31, 2013, by the value obtained using the plan formula that would become vested and payable. The assumed proration factors at December 31, 2013, were 0.316 for UAR awards issued in February 2013, and 0.683 for UAR awards issued in December 2011. The DER Adjustments through December 31, 2013, applicable to each UAR granted in February 2013 and in December 2011 were $2.13 and $4.26, respectively. As of December 31, 2013, Messrs. Horton, Buskill, McMahon and Nathanson held 50,861, 19,562, 13,693 and 13,693 UARs which were granted in 2013 and 40,235, 15,475, 10,832 and 10,832 UARs which were granted in 2011.
(4)
LTIP amounts were determined by multiplying the prorated number of unvested Phantom Common Units each executive held on December 31, 2013, by the value of our common units on that date, or $25.52. The assumed proration factors at December 31, 2013 were 0.316 for awards issued in February 2013, and 0.683 for awards issued in December 2011. As of December 31, 2013, Messrs. Horton, Buskill, McMahon and Nathanson held Phantom Common Units of 37,967, 14,603, 10,222 and 10,222 LTIP which were granted in 2013 and 35,714, 13,736, 9,615 and 9,615 LTIP which were granted in 2011. The DER Adjustment through December 31, 2013 applicable to each Phantom Common Unit granted in February 2013 and December 2011 were $2.13 and $4.26, respectively.
(5)
Includes earned but unused paid time off at December 31, 2013. In order to receive PTO payments upon retirement, the employee must have provided us with at least a six month notice prior to the termination of his employment.
(6)
Mr. Buskill would also be entitled to receive payment under the SRP six months after termination for any reason, which amounts are reported in the Pension Benefits table.
Director Compensation
Each director of BGL who is not an officer or employee of us, our subsidiaries, our general partner or an affiliate of our general partner (an Eligible Director) is paid an annual cash retainer of $50,000 ($55,000 for the chairman of the Audit Committee) payable in equal quarterly installments. Additionally the Board Members will receive an annual grant of common units in an amount equal to $50,000. The number of common units will be calculated by using the average of the thirty days closing market price prior to issuance. Directors who are not Eligible Directors do not receive compensation from us for their services as directors. All directors are reimbursed for out-of-pocket expenses they incur in connection with attending Board and committee meetings and will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.
(1)
On March 6, 2013, Messrs. Rebell, Cordes, Hyland and Shapiro were each granted 1,871 common units. The total grant date fair value of the award for each Eligible Director, based on the closing market price of $26.72, was $199,969. Refer to Note 12 in Item 8 for further information on the issuance of these units.
(2)
Chairman of the Audit Committee.
(3)
Chairman of the Conflicts Committee.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth certain information, at February 24, 2014, as to the beneficial ownership of our common units by beneficial holders of 5% the outstanding common units, each member of our Board, each of the Named Executive Officers and all of our executive officers and directors as a group, based on data furnished by them. None of the parties listed in the table have the right to acquire units within 60 days:
*Represents less than 1% of the outstanding common units
(1)
As of February 24, 2014, we had 243,223,801 common units issued and outstanding.
(2)
2,000 units are owned by Mr. Horton’s spouse.
(3)
400 of these units are owned by Mr. Hyland’s spouse.
(4)
15,000 units are owned by Mr. Nathanson’s spouse.
(5)
32,984 of these units are owned by ARebell, LLC, a limited liability company controlled by Mr. Rebell.
(6)
Represents one quarter of the number of units owned by a general partnership in which a one-quarter interest is held by a trust of which Mr. Tisch is managing trustee.
(7)
Loews is the parent company of BPHC and may, therefore, be deemed to beneficially own the units held by BPHC. The address of BPHC is 9 Greenway Plaza, Suite 2800, Houston, TX 77046. The address of Loews is 667 Madison Avenue, New York, New York 10065. Boardwalk GP, an indirect, wholly-owned subsidiary of BPHC, also holds our 2% general partner interest and all of our IDRs. Including the general partner interest but excluding the impact of the IDRs, Loews indirectly owns approximately 53% of our total ownership interests. Our Partnership Interests in Item 5 contains more information regarding our calculation of BPHC’s equity ownership.
Securities Authorized for Issuance Under Equity Compensation Plans
In 2005, prior to the initial public offering of our common units, our Board adopted the Boardwalk Pipeline Partners, LP Long-Term Incentive Plan. The following table provides certain information as of December 31, 2013, with respect to this plan:
Plan category
Number of securities to be issued upon exercise of outstanding options, warrants and rights
Weighted-average exercise price of outstanding options, warrants and rights
Number of securities remaining available for future issuance under equity compensation plan (excluding securities reflected in the first column)
Equity compensation plans approved by security holders
-
N/A
-
Equity compensation plans not approved by security holders
-
N/A
3,506,224
Note 12 in Item 8 of this Report contains more information regarding our equity compensation plan.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
It is our Board’s written policy that any transaction, regardless of the size or amount involved, involving us or any of our subsidiaries in which any related person had or will have a direct or indirect material interest shall be reviewed by, and shall be subject to approval or ratification by our Conflicts Committee. “Related person” means our general partner and its directors and executive officers, holders of more than 5% of our units, and in each case, their “immediate family members,” including any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law, and any person (other than a tenant or employee) sharing their household. In order to effectuate this policy, our General Counsel reviews all such transactions and reports thereon to the Conflicts Committee for its consideration. Our General Counsel also determines whether any such transaction presents a potential conflict of interest under our partnership agreement and, if so, presents the transaction to our Conflicts Committee for its consideration. In the event of a continuing service provided by a related person, the transaction is initially approved by the Conflicts Committee but may not be subject to subsequent approval. However, the Board approves the Partnership’s annual operating budget which separately states the amounts expected to be charged by related parties or affiliates for the following year. No new service transactions were reviewed for approval by the Conflicts Committee during 2013 nor were there any service transactions where the policy was not followed.
Distributions are approved by the Board on a quarterly basis prior to declaration. Note 16 in Item 8 of this Report contains more information regarding our related party transactions.
See Item 10, Our Independent Directors for information regarding director independence.
Item 14.
Item 14. Principal Accounting Fees and Services
Audit Fees and Services
The following table presents fees billed by Deloitte & Touche LLP and its affiliates for professional services rendered to us and our subsidiaries in 2013 and 2012 by category as described in the notes to the table (in millions):
(1)
Includes the aggregate fees and expenses for annual financial statement audit and quarterly financial statement reviews.
(2)
Includes the aggregate fees and expenses for services that were reasonably related to the performance of the financial statement audits or reviews described above and not included under Audit fees above, mainly including due diligence, consents, comfort letters and audits of employee benefits plans.
Auditor Engagement Pre-Approval Policy
In order to assure the continued independence of our independent auditor, currently Deloitte & Touche LLP, the Audit Committee has adopted a policy requiring its pre-approval of all audit and non-audit services performed for us and our subsidiaries by the independent auditor. Under this policy, the Audit Committee annually pre-approves certain limited, specified recurring services which may be provided by Deloitte & Touche, subject to maximum dollar limitations. All other engagements for services to be performed by Deloitte & Touche must be specifically pre-approved by the Audit Committee, or a designated committee member to whom this authority has been delegated.
Since the formation of the Audit Committee and its adoption of this policy in November 2005, the Audit Committee, or a designated member, has pre-approved all engagements by us and our subsidiaries for services of Deloitte & Touche, including the terms and fees thereof, and the Audit Committee concluded that all such engagements were compatible with the continued independence of Deloitte & Touche in serving as our independent auditor.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) 1. Financial Statements
Included in Item 8 of this Report:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2013 and 2012
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Changes in Equity for the years ended December 31, 2013, 2012 and 2011
Notes to Consolidated Financial Statements
(a) 2. Financial Statement Schedules
Valuation and Qualifying Accounts
The following table presents those accounts that have a reserve as of December 31, 2013, 2012 and 2011 and are not included in specific schedules herein. These amounts have been deducted from the respective assets on the Consolidated Balance Sheets (in millions):
(a) 3. Exhibits
The following documents are filed as exhibits to this report:
(1) The Services Agreements between Gulf South Pipeline Company, LP and Loews Corporation and between Boardwalk Pipelines, LP (formerly known as Boardwalk Pipelines, LLC) and Loews Corporation are not filed because they are identical to exhibit 10.3 except for the identities of Gulf South Pipeline Company, LP and Boardwalk Pipelines, LLC and the date of the agreement.
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Boardwalk Pipeline Partners, LP
By: Boardwalk GP, LP
its general partner
By: Boardwalk GP, LLC
its general partner
Dated:
February 24, 2014
By:
/s/ Jamie L. Buskill
Jamie L. Buskill
Senior Vice President, Chief Financial and Administrative Officer and Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.